Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017shares | |
Document information line items | |
Document Type | 40-F |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | FY |
Current Fiscal Year End Date | --12-31 |
Entity Registrant Name | EMERA INC |
Entity Central Index Key | 1,127,248 |
Entity Current Reporting Status | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | No |
Entity Filer Category | Accelerated Filer |
Trading Symbol | EMA |
Common Stock | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 228,777,760 |
Series A Preferred Stock [Member] | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 3,864,636 |
Series B Preferred Stock [Member] | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 2,135,364 |
Series C Preferred Stock [Member] | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 10,000,000 |
Series E Preferred Stock [Member] | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 5,000,000 |
Series F Preferred Stock [Member] | |
Document information line items | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Consolidated Statements of Inco
Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Operating revenues | ||
Regulated electric | $ 4,721 | $ 3,437 |
Regulated Gas | 1,002 | 499 |
Non-regulated | 503 | 341 |
Total operating revenues | 6,226 | 4,277 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 1,638 | 1,283 |
Regulated cost of natural gas | 379 | 177 |
Non-regulated fuel for generation and purchased power | 209 | 313 |
Non-regulated direct costs | 28 | 29 |
Operating, maintenance and general | 1,399 | 1,137 |
Provincial, state, and municipal taxes | 326 | 195 |
Depreciation and amortization | 856 | 588 |
Total operating expenses | 4,835 | 3,722 |
Income from operations | 1,391 | 555 |
Income from equity investments | 124 | 100 |
Other income (expenses), net | 2 | 174 |
Interest expense, net | (698) | (585) |
Income before provision for income taxes | 819 | 244 |
Income tax expense (recovery) | 520 | (22) |
Net income | 299 | 266 |
Non-controlling interest in subsidiaries | 5 | 11 |
Preferred stock dividends | 28 | 28 |
Net income attributable to common shareholders | $ 266.1 | $ 227.2 |
Weighted average shares of common stock outstanding (in millions) | ||
Basic | 213.4 | 171.4 |
Diluted | 214.1 | 172.2 |
Earnings per common share (note 9) | ||
Basic | $ 1.25 | $ 1.33 |
Diluted | 1.24 | 1.32 |
Dividends per common share declared | $ 2.1325 | $ 1.995 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Consolidated Statements of Comprehensive Income [Abstract] | ||
Net income | $ 299 | $ 266 |
Foreign currency translation adjustment | (462) | 32 |
Unrealized gains (losses) on net investment hedges | 97 | (49) |
Cash flow hedges | ||
Net derivative gains (losses) | 10 | 11 |
Less: reclassification adjustment for losses (gains) included in income | 8 | 11 |
Net effects of cash flow hedges | 18 | 22 |
Unrealized gains on available-for-sale investment | ||
Unrealized gain (loss) arising during the period | 5 | 3 |
Less: reclassification adjustment for (gains) recognized in income | (1) | (4) |
Net unrealized holding gains (losses) | 4 | (1) |
Net change in unrecognized pension and post-retirement benefit obligation | 44 | 12 |
Other equity method reclassification adjustment | 0 | (46) |
Other comprehensive income (loss) | (299) | (30) |
Comprehensive income (loss) | 0 | 236 |
Comprehensive income (loss) attributable to non-controlling interest | 0 | 8 |
Comprehensive Income of Emera Incorporated | $ 0 | $ 228 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income (Parenthetical) $ in Millions, $ in Billions | 12 Months Ended | |||
Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2016USD ($) | |
Consolidated Statements of Comprehensive Income [Abstract] | ||||
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax | $ 0 | $ 3 | ||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $ 1.2 | $ 1.2 | ||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax | (9) | 0 | ||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 1 | 0 | ||
Other Comprehensive Income (Loss), Available-for-sale Securities, before Reclassification Adjustments, Tax | 1 | (3) | ||
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax | 0 | 9 | ||
Other Comprehensive Income Los sAvailable For Sale Securities Before Reclassification Adjustments Tax Other Equity Method | $ (7) | $ 9 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 438 | $ 404 |
Restricted cash | 65 | 87 |
Inventory | 418 | 472 |
Derivative instruments | 141 | 145 |
Regulatory assets | 138 | 80 |
Other current assets | 1,326 | 1,323 |
Total current assets | 2,526 | 2,511 |
Property, plant and equipment, net of accumulated depreciation and amortization of $7,787and $3,737, respectively | 16,995 | 17,290 |
Other assets | ||
Deferred income taxes | 138 | 125 |
Derivative instruments | 112 | 131 |
Regulatory assets | 1,238 | 1,242 |
Net investment in direct financing lease | 481 | 488 |
Investments subject to significant influence | 1,215 | 947 |
Goodwill | 5,805 | 6,213 |
Other long term assets | 261 | 274 |
Total other assets | 9,250 | 9,420 |
Total assets | 28,771 | 29,221 |
Current liabilities | ||
Short-term debt | 1,241 | 961 |
Current portion of long-term debt | 741 | 476 |
Accounts payable | 1,161 | 1,242 |
Derivative instruments | 227 | 325 |
Regulatory liabilities | 226 | 362 |
Other current liabilities | 350 | 358 |
Total current liabilities | 3,946 | 3,724 |
Long-term liabilities | ||
Long-term debt | 13,140 | 14,268 |
Deferred income taxes | 1,011 | 1,672 |
Derivative instruments | 83 | 150 |
Regulatory liabilities | 2,242 | 1,277 |
Pension and post-retirement liabilities | 559 | 669 |
Other long-term liabilities | 609 | 645 |
Total long-term liabilities | 17,644 | 18,681 |
Commitments and contingencies | ||
Equity | ||
Common stock | 5,601 | 4,738 |
Cumulative preferred stock | 709 | 709 |
Contributed surplus | 76 | 75 |
Accumulated other comprehensive Income | (188) | 106 |
Retained earnings | 891 | 1,076 |
Total Emera Incorporated equity | 7,089 | 6,704 |
Non-controlling interest in subsidiaries | 92 | 112 |
Total equity | 7,181 | 6,816 |
Total liabilities and equity | $ 28,771 | $ 29,221 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Consolidated Balance Sheets [Abstract] | ||
Accumulated depreciation on property, plant and equipment | $ 7,824 | $ 7,787 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities | ||
Net income | $ 299 | $ 266 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 851 | 593 |
Income from equity investments, net of dividends | (90) | (59) |
Allowance for equity funds used during construction | (9) | (22) |
Deferred income taxes, net | 469 | (67) |
Net change in pension and post-retirement obligations | (12) | 13 |
Regulated Fuel Adjustments Mechanism | 68 | 63 |
Net changes in fair value of derivative instruments | (157) | 258 |
Net change in regulatory assets and liabilities | (237) | (25) |
Net change in capitalized transportation capacity | 84 | 33 |
Foreign exchange loss (gain) | 1 | (43) |
Gain on APUC sale of common shares and conversion of subscription receipts | 0 | (223) |
Other operating activities, net | 32 | 46 |
Changes in non-cash working capital | (104) | 134 |
Net cash provided by operating activities | 1,193 | 1,053 |
Investing activities | ||
Acquisition, net of cash acquired | 0 | (8,409) |
Additions to property, plant and equipment | (1,529) | (1,080) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (213) | (276) |
Net proceeds on sale of investment | 0 | 665 |
Other investing activities | (19) | 63 |
Net cash used in investing activities | (1,761) | (9,037) |
Financing activities | ||
Change in short-term debt, net | (31) | 118 |
Proceeds from short term debt | 383 | 0 |
Proceeds from long-term debt | 129 | 6,423 |
Proceeds from convertible debentures, net of issuance costs (2015 represented by instalment receipts) | 0 | 1,413 |
Retirement of long-term debt | (453) | (273) |
Net repayments under committed credit facilities | 230 | (315) |
Issuance of common stock, net of issuance costs | 682 | 354 |
Dividends on common stock | (287) | (221) |
Dividends on preferred stock | (28) | (28) |
Dividends paid by subsidiaries to non-controlling interest | (6) | (5) |
Other financing activities | (26) | (18) |
Net cash provided by financing activities | 593 | 7,448 |
Effect of exchange rate changes on cash and cash equivalents | (13) | (65) |
Net increase (decrease) in cash and cash equivalents | 12 | (601) |
Cash and cash equivalents, beginning of period | 491 | 1,092 |
Cash and cash equivalents, end of period | 503 | 491 |
Cash and cash equivalents consists of: | ||
Cash | 216 | 221 |
Short-term investments | 222 | 183 |
Restricted cash | $ 65 | $ 87 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) $ in Millions | Total | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Loss ("AOCL") | Retained Earnings | Non- Controlling Interest |
Balance at Dec. 31, 2015 | $ 4,334 | $ 2,157 | $ 709 | $ 29 | $ 137 | $ 1,168 | $ 134 |
Net income | 266 | 0 | 0 | 0 | 0 | 255 | 11 |
Other Comprehensive Income (Loss), Net of Tax | (30) | 0 | 0 | 0 | (27) | 0 | (3) |
Issuance of stock, net of issuance costs | 2,450 | 2,450 | 0 | 0 | 0 | 0 | 0 |
Cash dividends declared on preferred stock | (28) | 0 | 0 | 0 | 0 | (28) | 0 |
Cash dividends declared on common stock | (324) | 0 | 0 | 0 | 0 | (324) | 0 |
Common stock issued under purchase plan | 110 | 110 | 0 | 0 | 0 | 0 | 0 |
Beneficial conversion feature, net of tax (note 8) | 43 | 0 | 0 | 43 | 0 | 0 | 0 |
Acquisition Non Controlling Interest | (15) | 3 | 0 | 7 | 0 | 0 | (25) |
Other | (9) | 0 | 0 | (5) | (4) | 5 | (5) |
Stock-based compensation | 19 | 18 | 0 | 1 | 0 | 0 | 0 |
Balance at Dec. 31, 2016 | 6,816 | 4,738 | 709 | 75 | 106 | 1,076 | 112 |
Net income | 299 | 0 | 0 | 0 | 0 | 294 | 5 |
Other Comprehensive Income (Loss), Net of Tax | (299) | 0 | 0 | 0 | (294) | 0 | (5) |
Issuance of stock, net of issuance costs | 686 | 686 | 0 | 0 | 0 | 0 | 0 |
Cash dividends declared on preferred stock | (28) | 0 | 0 | 0 | 0 | (28) | 0 |
Cash dividends declared on common stock | (451) | 0 | 0 | 0 | 0 | (451) | 0 |
Common stock issued under purchase plan | 173 | 173 | 0 | 0 | 0 | 0 | 0 |
Beneficial conversion feature, net of tax (note 8) | 0 | ||||||
Common Dividends paid by subsidiaries to non-controlling interest | 0 | 0 | 0 | 0 | 0 | 0 | |
Non-controlling interest investment | (14) | 0 | 0 | 0 | 0 | 0 | (14) |
Other | (5) | 1 | 0 | 0 | 0 | 0 | (6) |
Stock-based compensation | 4 | 3 | 0 | 1 | 0 | 0 | 0 |
Balance at Dec. 31, 2017 | $ 7,181 | $ 5,601 | $ 709 | $ 76 | $ (188) | $ 891 | $ 92 |
Consolidated Statements of Cha9
Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Cash dividends declared on common stock | $ 2.1325 | $ 1.995 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 1 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution and gas transmission and distribution. Emera’s primary rate-regulated subsidiaries and investments at December 31, 2017 included the following: Emera Florida and New Mexico represents T ECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico which was acquired on July 1, 2016. TECO Energy’s holdings include: Tampa Electric Company (“TEC”), which holds the Tampa Electric Divi sion (“Tampa Electric”), an integrated regulated electric utility, serving approximately 750,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 375,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 525,000 customers across New Mexico; and TECO Finance, Inc. (“TECO Finance”), a wholly owned finan cing subsidiary of TECO Energy. Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 515,000 customers; Emera Maine, an electric transmission and distribution utility, serving approximately 158,000 customers in Maine; Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company that includes: The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 129,000 customers; a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited) in Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers. On November 8, 2017 , the minority shareholders of ICDU approved Emera’s acquisition of their common shares for total consideration of approximately $35 million USD. The acquisition of the minority shareholder common shares was completed on January 15, 2018, increasing Emera’ s indirect ownership interest in GBPC to 100 per cent; a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers. On September 19, 2017 Dominica took a direct hit from Hurrican e Maria, causing extensive damage across the island. Refer to note 16 for additional information ; and a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034; Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 82 4 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be generating first power in 2019 and full power in 2020. ENL’s two investments are: a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project completed commissioning and entered service o n January 15, 2018; and a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Mus krat Falls energy between Labrador and the island of Newfoundland. Nalcor Energy has indicated that the LIL will be in service in Q2 2018. a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. Emera also owns investments in other energy-related non-regulated companies, including: Emera Energy, consists of: Emera Energy Services, a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), 1,115 MW of com bined-cycle gas-fired electricity generating capacity in the northeastern United States; Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; and a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera; Emera US Finance LP, a wholly owned financing subsidiary of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada; and other investments. Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless otherwise indicated. Principles of Consolidation The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary . The consolidated financial statements include TECO Energy from the July 1, 2016 acquisition date through December 31, 2017 . The Company performs ongoing analysis to assess whether it holds any variable interest entities VIEs. To identify potential VIEs, management reviews contracts under leases, long-term p urchase power agreements, tolling contracts and jointly owned facilities. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using th e equity method. Inter company balances and inter company transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues . An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonab le at the time the assumption is made, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates. Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover the costs of providing the regulated products or services and provide a reasonable rate of return on the equity invested or assets as applicable (refer to n ote 16 for additional details). Foreign Currency Translation Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en omina ted debt held in Canadian functional currency companies as hedges of net investments in United States dollar denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sh eet date, and the effective portion of the hedge , is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings. Revenue Recognition Operating revenues are recognized when electricity or gas is delivered to customers or when products are delivered and services are rendered. Regulated revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity or gas is recognized at rates approved by t he respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis. At the end of each month, the electricity or gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes. Non-regulated revenues are recorded when products have been delivered or services have been p erformed, the amount of revenue can be reliably measured and collectability is reasonably assured . Revenues for energy marketing and trading operations are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income. Other revenues are recognized when services are performed or goods delivered. Property, Plant and Equipment Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction. The cost of addi tions, including betterments and replacements of units of property, plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or dis posal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions oc cur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attribut able to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Exp enditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable asset s in each functional class of de preciable property. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets consist primarily of computer software, land rights and naming rights with definite lives. Amorti zation is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate regulated subsidiaries amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. The service lives of regulated intangible assets require the appropriate regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment. Under the applicable accounting guidanc e, goodwill is subject to an annual assessment for impairment at the reporting unit level. Refer to note 22 for further detail. Income Taxes and Investment Tax Credits Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Ba lance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realize d. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the bala nce at the amount expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credit s earned by TECO Energy and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by state regulatory practices. Emera’s rate-regulated subsidiaries recognize regulatory assets o r liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the reali zation of deferred income tax assets. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 9 for further details. Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial co ntracts are classified as held-for-trading (“HFT”). Collectively, these contracts are considered derivatives. The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal pur chases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to al low for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffectiv e portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting fr om settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classi fies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are n ot offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”. Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. To tal short-term investments of $222 million have an effective interest rate of 1 .4 per cent at December 31, 2017 ( 2016 – $ 183 million with an effective interest rate of 0.6 per cent). Amounts included in restricted cash represent funds required to be set aside for the BLPC Self-Insurance Fund (notes 6 and 32 ). Receivables and Allowance for Doubtful Accounts Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balance s after the due date. The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains p rovisions for potential credit losses, which are assessed on a regular basis. Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the characteristics of existing acco unts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. Inventory Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the we ighted-average cost will be recovered in future custo mer rates. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency. Asset Impairment Goodwill Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill . Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity chooses to bypass the qualitative assessment , a qu antitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded as a reducti on to goodwill and a charge to operating expense. Emera reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit, with interim impairment tests performed when impairment indicators are present. Refer to note 22 fo r further detail . Cost and Equity Method Investments The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a ch arge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value. Financial Assets The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, a n other than temporary decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt s ecurities classified as available-for-sale, a breach of contract , such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidenc e exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOC I and recognized in the Consolidated Statements of Income. Asset Retirement Obligation s An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sal e of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flow s necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prio r experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is dep reciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved b y the regulator recorded in “Property, plant and equipment” and included in the next depreciation study. Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional AR O refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a l iability is recognized at fair value whe n an amount can be determined. Cost of Removal Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal as regulatory liabilities. The non-ARO costs of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment upon retirement. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and f uture expectations, including expected timing and estimated future cash outlays. Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tam pa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statement of Income. Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based met hod of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income. Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plan s on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets . Computer software 3 to 15 Land rights 50 to 143 Naming rights 1 to 24 |
Change in Accounting Policy
Change in Accounting Policy | 12 Months Ended |
Dec. 31, 2017 | |
Change in Accounting Policy [Abstract] | |
Accounting Changes and Error Corrections [Text Block] | 2 . C HANGE IN ACCOUNTING POLICY The new US GAAP accounting polici es that are applicable to, and adopted by the Company in 2017 , are described as follows: Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows . The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidanc e is provided for issues not previously addressed. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach. The Company has early adopted the standard with no impact on the consolidated financial statements as a result of implementation of this standard. Restricted Cash on the Statement of Cash Flows In November 2016, the FASB issued ASU 2016-18, Restricted Cash on the Statement of Cash Flows . The standard requires the Company to show the changes in total cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. Transfers between cash and cash equivalents and restricted cash and restricted cash equivalents are no longer presented in the statement of cash flows. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after Decembe r 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach. The Company has early adopted this standard. This change in accounting policy has increased net cash used in investing activities by $22 million for the y ear ended December 31, 2017 (2016 – a decrease of $68 million) within the Consolidated Statement of Cash Flows. Changes in restricted cash are now disclosed within the Consolidated Statement of Cash Flows for all years presented. Restricted cash was $65 mi llion at December 31, 2017 (2016 – $87 million). Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment . The standard provides guidance to simplify the subsequent measuremen t of goodwill by eliminating the second step of the quantitative test. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This guidance is effective for annual reporting periods, including interim reporting within t hose periods, beginning after December 15, 2019, with early adoption permitted and is required to be applied prospectively. The Company has early adopted the standard with no impact on the consolidated financial statements as a result of implementation of this standard. |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
New Accounting Pronouncements [Abstract] | |
FUTURE ACCOUNTING PRONOUNCEMENTS | 3 . FU TURE ACCOUNTING PRONOUNCEMENTS The Comp any considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB, but have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or have insignificant impact on the consolidated financial statements. Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers , which creates a new, principle-based revenue recog nition framework, codified as Accounting Standards Codification (“ASC”) Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients. The guidance w ill require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting withi n those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018, using the modified retrospective approach. The C ompany implemented a revenue recognition project plan in 2016. In Q1 2017, the Company concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In Q2 2017, the Company completed an analysis of m aterial regulated revenue streams and collectability risk and concluded that there will be no material changes on adoption of this standard. In Q3 2017, the Company completed an analysis of material unregulated revenue streams and concluded that there wil l be no material changes on adoption of this standard. The Company also evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on the Company’s in formation gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by the Company for financial reporting purposes. The Company continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities . The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance will be effective for annual reporting periods, incl uding interim reporting within those periods, beginning after December 15, 2017. The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company will elect to measure equity securities that do not have a readily determinable fair value, at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar inv estment of the same issuer. The standard eliminates the available-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is not expected to be significant. The Company will adopt this guidance effective January 1, 2018 with a cumulative-effect adju stment of approximately $3 million to retained earnings in the Consolidated Balance Sheet. Leases In February 2016, the FASB issued ASU 2016-02, Leases . The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet. The effect of leases on the Conso lidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. I n November 2017, the FASB voted t o amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in Q1 2018. The Company is in the process of evaluating th e impact of adoption of this standard on its financial statements and disclosures. In Q3 2017, the Company implemented a project plan. In Q4 2017, the Company began execution of the project plan, including training sessions with key stakeholders throughou t the organization and gathering detailed information on existing lease arrangements. This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated with individual contractual arrangements and as sessing the disclosure requirements. The Company continues to monitor FASB amendments to ASC Topic 842. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments . The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investm ent in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical exp erience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective for ann ual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. E arly adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified re trospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements. Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business . The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 , with early adoption permitted and is required to be applied prospectively. The adoption of this standard will not have an impact on the Company’s consolidated financial statements. Improving the Presentation of Net Peri odic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost . The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization as property, plant and equipment under this guidance. This guidance will be effective for annual reporting periods , including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalizati on. In Q4, 2017 the Company completed an analysis of the impact of the adoption of this standard on the consolidated financial statements and concluded that the impact on the balance sheet will be minimal. The other components of net benefit cost that will be required to be presented outside of income from operations in the Consolidated Statements of Income on adoption are $28 million for the year ended December 31, 2017 . The Company will adopt this guidance effective January 1, 2018. Targeted Improvem ents to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. Th is guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach. The Compa ny is currently evaluating the impact of the adoption of this standard on the consolidated financial statements. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions [Abstract] | |
ACQUISITIONS | 4 . ACQUISITION TECO ENERGY INC. On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy for $ 27.55 US dollars (“ USD ”) per common share. The net cash purchase price total l ed $ 8.4 billion ($ 6.5 billion USD), with an aggregate purchase price of $ 13.9 billion ($ 10.7 billion USD), including the assumption of $ 5.5 billion ($ 4.2 billion USD) in US debt on closing. The majority of TECO Energy’s operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission (“FERC”), FPSC, and New Mexico Public Regulation Commission (“NMPRC”), and are accounted for pursuant to USGAAP, including the accounting guidance for regulated operations. Except for unregulated long-term debt ac quired and deferred taxes, fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values due to the fact that a market participant would not expect to recover any more or less than their net carrying value. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any adjustments related to these amounts. The acquisition is accounted for in accordance with the acquisition method of acc ounting. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed has been recognized as goodwill at the acquisition date of July 1, 2016. The goodwill reflects the value paid for access to regulated assets, net in come and cash flows in growth markets, opportunities for adjacency growth, long-term potential for enhanced access to capital as a result of increased scale and business diversity, and an improved earnings risk profile. The goodwill recognized as part of t his transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill. The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at July 1, 2016 based on their fair values, using the July 1, 2016 exchange rate of $1.00 USD = $ 1.3009 CAD. millions of Canadian dollars Purchase Consideration $ 8,447 Fair value assigned to net assets: Current assets (1) $ 619 Regulatory assets (including current portion) 624 Property, plant and equipment, net 10,023 Other long-term assets 71 Current liabilities (747) Assumed long-term debt (including current portion) (5,409) Regulatory liabilities (including current portion) (1,117) Deferred income taxes (800) Pension and post-retirement liabilities (including current portion) (480) Other long-term liabilities (146) $ 2,638 Cash and cash equivalents 38 Fair value of net assets acquired $ 2,676 Goodwill $ 5,771 (1) Includes accounts receivables with fair value of $334 million comprised of gross contract value of $337 million, and $3 million of contractual receivables not expected to be collected. Goodwill has been allocated to the TECO Energy reporting units as follows: millions of Canadian dollars Reporting Unit Goodwill Tampa Electric $ 4,552 PGS 744 New Mexico Gas 475 Goodwill $ 5,771 Goodwill is subject to an annual assessment for impairment at the reporting unit level. Adverse changes in assumptions could result in a material impairment of Emera’s goodwill (refer to note 22 ) . Acquisition Related Expenses There were no acquisition related expenses incurred for the year ended December 31, 2017 . A cquisition related expenses totalled $ 250 million ($ 166 million after tax) for the year ended December 31, 2016 . These acquisition related expenses were included in Interest expense, net and Operating, maintenance and general on the Consolidated Statements of Income . For the Year ended millions of Canadian dollars December 31 2017 2016 Operating revenues – regulated gas $ - $ (10) Operating, maintenance, and general - 89 Interest expense, net - 148 Other income (expenses), net - (3) Income tax expense (recovery) - (84) Acquisition related costs $ - $ 166 Supplemental Pro Forma Data The unaudited pro forma financial information below gives effect to the acquisition of TECO Energy as if the transaction had occu rred at the beginning of 2016. This pro forma data is presented for information purposes only, and does not purport to be indicative of the results that would have occurred had the acquisition taken place at the beginning of 2016 , nor is it indicative of the results that may be expected in future periods. Pro forma net income attributable to common shareholders excludes all non-recurring acquisition-related expenses incurred by TECO Energy and Emera and includes adjustments for pro forma financing costs associated with the acquisition. Total after-tax adjustments increased pro forma net income attr ibutable to common shareholders by $ 53 million for the year ended December 31, 2016 . For the millions of Canadian dollars Year ended December 31, 2016 Pro forma operating revenues $ 6,034 Pro forma net income attributable to common shareholders $ 386 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Information [Abstract] | |
SEGMENT INFORMATION | 5 . SEGMENT INFORMATION Emera manages its reportable segments separately due in part to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets as reported to the Company’s chief operating decision maker. Emera’s six reportable segments are Emera Florida and New Mexico, NSPI , Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other (i ncludes Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and holding companies). Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2017 Operating revenues from external customers (1) $ 3,623 $ 1,335 $ 297 $ 434 $ 451 $ 86 $ - $ 6,226 Inter-segment revenues (1) - 3 - - 14 41 (58) - Total operating revenues 3,623 1,338 297 434 465 127 (58) 6,226 Allowance for funds used during construction - debt and equity 5 8 3 - - - - 16 Regulated fuel and fixed cost deferral adjustments - 59 - - - - - 59 Depreciation and amortization 500 207 47 51 48 3 - 856 Interest expense (2) 248 134 20 25 2 276 - 705 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 1 3 24 96 - 124 Income tax expense (recovery) 529 - 27 - 18 (54) - 520 Net income attributable to common shareholders 99 129 46 31 93 (132) - 266 Capital expenditures 910 385 82 72 47 26 - 1,522 As at December 31, 2017 Total assets 17,216 4,979 1,505 1,251 1,575 2,331 (86) 28,771 Investments subject to significant influence - - 13 39 - 1,163 - 1,215 Goodwill 5,566 - 143 96 - - - 5,805 (1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Interest expense net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $24 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico (2) NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2016 Operating revenues from external customers (1) $ 1,839 $ 1,354 $ 297 $ 419 $ 298 $ 69 $ - $ 4,276 Inter-segment revenues (1) - 2 - - 11 24 (36) 1 Total operating revenues 1,839 1,356 297 419 309 93 (36) 4,277 Allowance for funds used during construction - debt and equity 28 6 1 - - - - 35 Regulated fuel and fixed cost deferral adjustments - 61 - - - - - 61 Depreciation and amortization 243 197 51 48 45 4 - 588 Interest expense (3) 125 127 19 15 1 311 - 598 Internally allocated interest (4) - - - - (24) 24 - - Income from equity investments - - - 3 11 86 - 100 Income tax expense (recovery) 100 12 23 14 (53) (118) - (22) Net income attributable to common shareholders 172 130 47 100 (110) (112) - 227 Capital expenditures 547 304 85 87 39 7 - 1,069 As at December 31, 2016 Total assets 18,016 4,776 1,543 1,331 1,702 1,966 (113) 29,221 Investments subject to significant influence - - 13 39 - 895 - 947 Goodwill 5,957 - 154 102 - - - 6,213 (1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Financial results of Emera Florida and New Mexico are from July 1, 2016, the date of the acquisition. (3) Interest expense net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $13 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (4) Segment net income is reported on a basis that includes internally allocated financing costs. Geographical Information Revenues(1): For the Year ended December 31 millions of Canadian dollars 2017 2016 Canada $ 1,464 $ 1,510 United States 4,328 2,348 Barbados 280 254 The Bahamas 119 121 Dominica 35 44 $ 6,226 $ 4,277 (1) Revenues are based on country of origin of the product or service sold Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2017 2016 Canada $ 3,995 $ 3,791 United States 12,257 12,724 Barbados 408 416 The Bahamas 276 295 Dominica 59 64 $ 16,995 $ 17,290 |
Investments Subject to Signific
Investments Subject to Significant Influence and Equity Income | 12 Months Ended |
Dec. 31, 2017 | |
Investments Subject to Significant Influence and Equity Earnings [Abstract] | |
INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME | 6 . INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME Investments subject to significant influence consisted of the following: Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2017 2016 2017 2016 2017 NSPML $ 510 $ 315 $ 36 $ 21 100.0 LIL (1) 492 400 37 24 49.5 M&NP (2) 156 175 23 23 12.9 Lucelec (2) 39 39 3 3 19.1 Bear Swamp (3) - - 23 11 50.0 APUC (4) - - - 18 - Other Investments 18 18 2 - $ 1,215 $ 947 $ 124 $ 100 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position, primarily a result of a $179 million distribution received in Q4 2015. Bear Swamp's credit investment balance of $188 million (2016 - $217 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. (4) In two separate transactions in 2016, Emera sold a total of 63 million common shares in APUC. Emera no longer holds any interest in APUC. Equity investments include a $13 million difference between the cost and the underlying fair value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2017 2016 Balance Sheets Current assets $ 225 $ 439 Property, plant and equipment 1,720 1,132 Non-current assets 74 276 Total assets $ 2,019 $ 1,847 Current liabilities $ 180 $ 219 Long-term debt 1,287 1,288 Non-current liabilities 42 25 Equity 510 315 Total liabilities and equity $ 2,019 $ 1,847 |
Other Income (Expenses), Net
Other Income (Expenses), Net | 12 Months Ended |
Dec. 31, 2017 | |
Other Income (Expenses), Net [Abstract] | |
OTHER INCOME (EXPENSES), NET | 7 . OTHER INCOME (EXPENSES), NET Other income (expenses), net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2017 2016 Gain on sale of APUC common shares (note 6) $ - $ 160 Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC (note 6) - 63 Gain on BLPC Self-Insurance Fund ("SIF") regulatory liability (1) - 53 Foreign exchange (losses) gains and mark-to-market adjustments related to the TECO Energy acquisition (2) - (135) Other 2 33 $ 2 $ 174 (1) In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $22 million USD. As a result, Emera reduced the SIF regulatory liability to $30 million ($22 million USD) and recorded a pre-tax gain of $53 million (after-tax gain of $43 million). (2) Mark-to-market adjustments included in Emera’s other income related to the effect of TECO Energy convertible debenture related USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion 4 per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the TECO Energy acquisition. |
Interest Expense, Net
Interest Expense, Net | 12 Months Ended |
Dec. 31, 2017 | |
Interest Income (Expense), Net [Abstract] | |
INTEREST EXPENSE, NET | 8 . INTEREST EXPENSE, NET Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest on debt $ 663 $ 443 Beneficial conversion feature (note 10) - 62 Interest on Convertible Debentures (note 10) - 65 Interest on acquisition credit facility related to the TECO Energy acquisition (note 4) - 11 Allowance for borrowed funds used during construction (7) (13) Other 42 17 $ 698 $ 585 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Taxes [Abstract] | |
INCOME TAXES | 9 . INCOME TAXES The income tax provision, for the years ended December 31, differs from that computed using the statutory income tax rate for the following reasons: millions of Canadian dollars 2017 2016 Income before provision for income taxes $ 819 $ 244 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 254 76 Revaluation of US non-regulated deferred income taxes 317 - Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (54) (47) Foreign tax rate variance 36 (5) Financing deductions (17) (17) Tax effect of equity earnings (12) (10) Manufacturing and investment allowances (8) (7) Non-taxable portion of gains on APUC transactions - (34) Non-deductible portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition - 21 Other 4 1 Income tax expense (recovery) $ 520 $ (22) Effective income tax rate 63% (9%) The statutory income tax rate of 31 per cent represents the combined Canadian federal and Nova Scotia and New Brunswick provincial corporate income tax rates, which are the relevant tax jurisdictions for Emera. On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 ( “ the Act”) was signed into legislation. The Act includes a broad range of legislative changes including a reduction of the US federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018, limitations on the deductibility of interest and 100 per cent expensing of qualified property. The Act provides an exemption to regulated electric and gas utilities from the limitations on the deductibility of interest and the 100 per cent expensing of qualified property. As a result of the Act being enacted during 2017, the Company is required to revalue its United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company has recognized a n estimated $ 317 million income tax expense in 2017 as a result of the revaluation of its US non-regulated net deferred income tax assets. T he Company has also reduced its US regulated net deferred income tax liabilities by an estimated $ 1.1 b illion and recorded an equiva lent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator. As discussed above, t he Company has provisionally revalued all of its US deferr ed tax assets and liabilities based on the rates they are expected to reverse at in th e future, which is generally 21 per cent for US federal tax purposes. The December 31, 2017 balances of deferred tax assets and deferred tax liabilities that have been r evalued are $1.3 bil lion and $1.8 billion , respectively . T he Company is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. The following reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2017 2016 Current income taxes Canada $ 24 $ 13 United States 24 18 Other 3 15 Deferred income taxes Canada 3 (113) United States 384 151 Other (1) - Operating loss carry forwards Canada (40) (2) United States (194) (104) Revaluation of US non-regulated deferred income taxes United States 317 - Income tax expense (recovery) $ 520 $ (22) The following reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2017 2016 Canada $ 88 $ 71 United States 693 44 Other 38 129 Income before provision for income taxes $ 819 $ 244 The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of Canadian dollars 2017 2016 Deferred income tax assets: Tax loss carry forwards $ 853 $ 1,036 Tax credit carry forwards 314 318 Regulatory liabilities - cost of removal 208 388 Pension and post-retirement liabilities 124 153 Derivative instruments 107 150 Other 394 490 Total deferred income tax assets before valuation allowance 2,000 2,535 Valuation allowance (105) (58) Total deferred income tax assets after valuation allowance $ 1,895 $ 2,477 Deferred income tax (liabilities): Property, plant and equipment $ (2,321) $ (3,553) Derivative instruments (155) (202) Other (292) (269) Total deferred income tax liabilities $ (2,768) $ (4,024) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 138 $ 125 Long-term deferred income tax liabilities (1,011) (1,672) Net deferred income tax liabilities $ (873) $ (1,547) For regulated entities, to the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. Emera’s gross net o perating loss (“NOL”) carry forwards , capital loss carry forwards and tax credit carry forwards as at December 31 , consisted of the following: millions of Canadian dollars 2017 2016 Canada NOL $ 532 $ 199 Capital loss 77 77 United States Federal NOL $ 2,926 $ 2,595 State NOL 1,271 1,183 Capital loss 13 14 Tax credit 314 318 Other NOL $ 29 $ 22 The following table summarizes as at December 31, 2017 the deferred tax assets associated with NOL, capital loss and tax credit carry forwards and the associated expiration periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain: Deferred Tax Valuation Net Deferred Expiration millions of Canadian dollars Asset Allowance Tax Asset Period Canada NOL $ 164 $ (80) $ 84 2027-2037 Capital loss 16 (16) - Indefinite United States Federal NOL $ 602 $ - $ 602 2024-2037 State NOL 65 (2) 63 2024-2037 Capital loss 2 (2) - 2018-2019 Tax credit 314 - 314 2019-Indefinite Other NOL $ 4 $ (4) $ - 2018-2024 Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for the loss carry forwards noted above and unrealized capital losses on certain investments. A valuation allowance of $ 105 million has been recorded as at December 31, 2017 (201 6 - $ 5 8 million) related to the loss carry forwards and investments. The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows: millions of Canadian dollars 2017 2016 Balance, January 1 $ 18 $ 6 Increases due to tax positions related to current year 1 12 Balance, December 31 $ 19 $ 18 Th e total amount of unrecognized tax benefits as at December 31, 2017 was $ 19 million ( 2016 - $ 18 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $ 1 million ( 2016 - $ 1 million). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next twelve months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time. The Company intends to indefinitely reinvest earnings from certa in foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries o f approximately $ 822 million as at December 31, 2017 ( 2016 - $ 66 7 million). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera files a Canadian federal income tax return, which includes its Nova Scotia and New Brunswick provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income tax returns. As at December 31, 2017 , the Company’s tax years still open to examination by ta xing authorities include 2005 and subsequent years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulativ e net amount in dispute to date is $ 62 million, including interest. NSPI has prepaid $ 23 million of the amount in dispute, as required by CRA. Should NSPI be successful in defending its position, all payments including applicable interest will be refunde d. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subseque nt years. Should NSPI receive similar notices of reassessment for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believ e NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute however the outcome of the Appeal process is not determinable at this t ime. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2017 | |
Common Stock [Abstract] | |
COMMON STOCK | 10 . COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2017 2016 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2016 210.02 $ 4,738 147.21 $ 2,157 Conversion of Convertible Debentures (1) 0.15 6 51.99 2,115 Issuance of common stock (2) 14.61 680 7.69 338 Issued for cash under Purchase Plans at market rate 3.89 182 2.51 115 Discount on shares purchased under Dividend Reinvestment Plan - (9) - (5) Options exercised under senior management share option plan 0.10 3 0.62 17 Employee share purchase plan - 1 - 1 Balance, December 31 2017 228.77 $ 5,601 210.02 $ 4,738 (1) As at December 31, 2017, a total of 52.14 million common shares of the Company were issued, representing conversion into common shares of more than 99.9% of the Convertible Debentures. (2) On December 28, 2017, Emera completed an offering of 14.6 million common shares, at $47.90 per common share, for gross proceeds of approximately $700 million. The net proceeds were $680 million after $20 million of issuance costs, net of taxes. As at December 31, 2017 , there were the following common shares reserved for issuance: 6.5 million ( 2016 – 6.6 million) under the senior management stock option plan, 1.3 million ( 2016 – 1.5 million) under the employee common share purchase plan and 4.2 million ( 2016 – 7.9 million) under the dividend reinvestment plan. The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 per cent of Emera's outstanding common shares . As at Dece mber 31, 2017 , Emera is in compliance with this requirement. Convertible Debentures In 2015, to finance a portion of the acquisition of TECO Energy, Emera completed the sale of $2.185 billion aggregate principal amount of 4 per cent convertible unsecured subordinated debentures, represented by instalment receipts. The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, maturing on September 29, 2025. As of August 2, 2016, the Final Instalment Date, the Debentures bear interest at 0 per cent. At maturity, Emera has the right to pay the pr incipal amount due in common shares to the debenture holders that have not converted, which will be valued at 95 per cent of the weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity d ate. As at December 31, 2017 , a total of 52.14 million common shares of the C ompany were issued, representing conversion in to common shares of more than 99.9 per cent of the Convertible Debentures. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | 11 . EARNINGS PER SHARE Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all po tentially dilutive securities. Such dilutive items include Company contributions to the sen ior management stock option plan, convertible debentures and shares issued under the dividend reinvestment plan. The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2017 2016 Numerator Net income attributable to common shareholders $ 266.1 $ 227.2 Convertible Debentures - 0.2 Diluted numerator 266.1 227.4 Denominator Weighted average shares of common stock outstanding 212.3 170.4 Weighted average deferred share units outstanding 1.1 1.0 Weighted average shares of common stock outstanding – basic 213.4 171.4 Stock-based compensation 0.6 0.6 Convertible Debentures 0.1 0.2 Weighted average shares of common stock outstanding – diluted 214.1 172.2 Earnings per common share Basic $ 1.25 $ 1.33 Diluted $ 1.24 $ 1.32 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 12 . ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of accumulated other comprehensive income are as follows: millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available-for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2017 Balance, January 1, 2017 $ 486 $ (49) $ (21) $ (1) $ (309) $ 106 Other comprehensive income (loss) before reclassifications (457) 97 10 5 - (345) Amounts reclassified from accumulated other comprehensive income loss - - 8 (1) 44 51 Net current period other comprehensive income (loss) (457) 97 18 4 44 (294) Other - - - - - - Balance, December 31, 2017 $ 29 $ 48 $ (3) $ 3 $ (265) $ (188) millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available-for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2016 Balance, January 1, 2016 $ 490 $ - $ (35) $ - $ (318) $ 137 Other comprehensive income (loss) before reclassifications 35 (49) 11 3 - - Amounts reclassified from accumulated other comprehensive income loss (gain) - - 11 (4) 12 19 Equity method reclassification adjustments (35) - (8) - (3) (46) Net current period other comprehensive income (loss) - (49) 14 (1) 9 (27) Other (4) - - - - (4) Balance, December 31, 2016 $ 486 $ (49) $ (21) $ (1) $ (309) $ 106 The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2017 2016 Affected line item in the Consolidated Financial Statements Amounts reclassified from AOCI Equity method reclassification adjustments Investments subject to significant influence $ - $ 54 Total before tax - 54 Deferred income taxes - (8) Total net of tax $ - $ 46 Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (3) $ (2) Interest rate swaps Income from equity investments - 1 Foreign exchange forwards Operating revenue - regulated 10 12 Total before tax 7 11 Income tax recovery (expense) 1 - Total net of tax $ 8 $ 11 Net change in available-for-sale investments Other income (expenses), net $ (1) $ (4) Total before tax (1) (4) Income tax recovery (expense) - - Total net of tax $ (1) $ (4) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 40 $ 41 Past service costs (gains) OM&G (8) (9) Amounts reclassified into obligations Pension and post-retirement benefits 11 (17) Total before tax 43 15 Income tax recovery (expense) 1 (3) Total net of tax $ 44 $ 12 Total reclassifications out of AOCI, net of tax, for the period $ 51 $ 65 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2017 | |
Inventory [Abstract] | |
INVENTORY | 13. INVENTORY Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Fuel $ 180 $ 235 Materials 216 215 Emission credits (1) 22 22 $ 418 $ 472 (1)The NEGG Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative for carbon dioxide emissions. The emissions credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments [Abstract] | |
DERIVATIVE INSTRUMENTS | 14 . DERIVATIVE INSTRUMENTS 16 . DERIVATIVE INSTRUMENTS The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to: commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; foreign exchange fluctuations on foreign currency denominated purchases and sales; and interest rate fluctuations on debt securities. The Company also enters into physical contracts for energy commodities. Collectively, these contra cts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches: Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recogniz ed in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physi cal delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of the se contracts under this exception if the criteria are no longer met. Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirement s and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI a nd recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period. Where the documentation or effectiveness require ments are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by Tampa Electric, PGS, NMGC, NS PI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of thes e derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatmen t would apply. Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2017 2016 2017 2016 Cash flow hedges Power swaps $ 5 $ 10 $ 2 $ 5 Foreign exchange forwards 2 - 5 22 7 10 7 27 Regulatory deferral Commodity swaps and forwards Coal purchases 137 83 10 9 Power purchases 5 7 3 4 Natural gas purchases and sales 6 33 7 2 Heavy fuel oil purchases 15 10 4 7 Foreign exchange forwards 32 106 4 - 195 239 28 22 HFT derivatives Power swaps and physical contracts 125 47 162 71 Natural gas swaps, futures, forwards, physical contracts 105 111 294 484 230 158 456 555 Other derivatives Interest rate swap 2 - - 1 Foreign exchange forwards - - - 1 2 - - 2 Total gross current derivatives 434 407 491 606 Impact of master netting agreements with intent to settle net or simultaneously (181) (131) (181) (131) 253 276 310 475 Current 141 145 227 325 Long-term 112 131 83 150 Total derivatives $ 253 $ 276 $ 310 $ 475 Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts. Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2017 2016 2017 2016 Regulatory deferral $ 14 $ 10 $ 14 $ 10 HFT derivatives 167 121 167 121 Total impact of master netting agreements with intent to settle net or simultaneously $ 181 $ 131 $ 181 $ 131 Cash Flow Hedges The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. The amounts related to cash flow hedges recorded in income and AOCI consisted of the following: For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Realized gain (loss) in non-regulated fuel for generation and purchased power 3 - - 2 - - Realized gain (loss) in operating revenue – Regulated - - (10) - - (12) Realized gain (loss) in income from equity investments - - - - (1) - Total gains (losses) in Net income $ 3 $ - $ (10) $ 2 $ (1) $ (12) As at December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ - $ - $ (3) $ 2 $ - $ (22) The Company expects $5 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle. As at December 31, 2017, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2018 2019 2020 2021 2022 Foreign exchange forwards (USD) sales $ 45 $ 30 $ 30 $ - $ - Regulatory Deferral The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral: For the Year ended December 31 millions of Canadian dollars 2017 2016 Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (33) $ (1) $ (4) $ 40 $ - $ (2) Unrealized gain (loss) in regulatory liabilities 83 1 (30) 101 (1) (30) Realized (gain) loss in regulatory assets - - - - - 12 Realized (gain) loss in regulatory liabilities (2) - - - - (8) Realized (gain) loss in inventory (1) (17) - (30) 5 - (44) Realized (gain) loss in regulated fuel for generation and purchased power (2) (3) - (14) 17 (1) (18) Total change derivative instruments $ 28 $ - $ (78) $ 163 $ (2) $ (90) (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable. Commodity Swaps and Forwards As at December 31, 2017 , the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below: 2018 2019-2021 millions Purchases Purchases Coal (metric tonnes) 1 1 Natural Gas (Mmbtu) 30 14 Heavy fuel oil (bbls) - 1 Foreign Exchange Swaps and Forwards As at December 31, 2017 , the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below: 2018 2019-2020 Foreign exchange contracts (millions of US dollars) $ 144 $ 156 Weighted average rate 1.1061 1.2001 % of USD requirements 79% 40% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required. Held-for-Trading Derivatives In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT. The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: For the Year ended December 31 millions of Canadian dollars 2017 2016 Power swaps and physical contracts in non-regulated operating revenues $ 7 $ (1) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 401 69 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 10 (7) Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 2 - Foreign exchange options in other income (expenses), net - (2) $ 420 $ 59 As at December 31, 2017 , the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: millions 2018 2019 2020 2021 2022 Natural gas purchases (Mmbtu) 325 134 62 44 41 Natural gas sales (Mmbtu) 250 56 21 8 2 Power purchases (MWh) 7 2 - - - Power sales (MWh) 8 1 - - - Foreign exchange options (USD) $ 2 $ 4 $ - $ - $ - Other Derivatives The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met: For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign rate exchange rate exchange swaps forwards swaps forwards Realized gain (loss) in other income (expense) $ - $ - $ - $ (87) Unrealized gain (loss) in interest expense, net 2 - 2 - Total gains (losses) in net income $ 2 $ - $ 2 $ (87) As at December 31, 2017, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019. Credit Risk The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral ar e requested on any high risk accounts. The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditwort hiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the co unterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated. As at December 31, 2017 , the maximum exposure the Company has to credit risk is $ 1,148 million ( 2016 - $ 1,019 million) , which incl udes accounts receivable net of collateral/deposits and assets related to derivatives. It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterpar ties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2017 was $ 247 million ( 2016 - $ 271 million) , which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company. The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivat ives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relatin g to creditworthiness, collateral, non-performance and default. As at December 31, 2017 , the Company had $ 90 million ( 2016 - $ 104 million) in financial assets, considered to be past due, which have been outstanding for an average 69 days. The fair value of these financial assets is $ 78 million ( 2016 - $ 91 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue. Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2017 December 31, 2016 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 326 23% $ 315 24% Commercial 161 11% 170 13% Industrial 46 3% 38 3% Other 96 7% 69 5% 629 44% 592 45% Trading group Credit rating of A- or above 55 4% 52 4% Credit rating of BBB- to BBB+ 61 4% 60 5% Not rated 96 7% 57 4% 212 15% 169 13% Other accounts receivable 300 22% 253 20% 1,141 81% 1,014 78% Derivative Instruments (current and long-term) Credit rating of A- or above 207 15% 252 20% Credit rating of BBB- to BBB+ 10 1% 1 0% Not rated 36 3% 23 2% 253 19% 276 22% $ 1,394 100% $ 1,290 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Cash collateral provided to others $ 119 $ 91 Cash collateral received from others 99 52 Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in t he senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full col lateralization. As at December 31, 2017 , the total fair value of these derivatives, in a l iability position, wa s $ 310 million ( December 31, 2016 – $ 475 million). If the credit ratings of the Company were reduced below investme nt grade the full value of the net liability position could be required to be posted as collateral for these derivatives. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Measurements [Abstract] | |
FAIR VALUE MEASUREMENTS | 15 . FAIR VALUE MEASUREMENTS The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (refer to note 1 ), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows: Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities. Level 2 - Where quoted pr ices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued usin g quotes from over-the-counter clearing houses. Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows: While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. The valuations of certain transactions were based on internal models, although quoted prices wer e utilized in the valuations. Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set out the classification of the methodology used by the Company to fair value its derivatives: As at December 31, 2017 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 2 - 2 5 2 - 7 Regulatory deferral Commodity swaps and forwards Coal purchases - 127 - 127 Power purchases 5 - - 5 Natural gas purchases and sales - 5 - 5 Heavy fuel oil purchases 4 8 - 12 Foreign exchange forwards - 32 - 32 9 172 - 181 HFT derivatives Power swaps and physical contracts - 3 9 12 Natural gas swaps, futures, forwards, physical contracts and related transportation - 26 25 51 - 29 34 63 Other derivatives Interest rate swap - 2 - 2 - 2 - 2 Total assets 14 205 34 253 Liabilities Cash flow hedges Power swaps 2 - - 2 Foreign exchange forwards - 5 - 5 2 5 - 7 Regulatory deferral Commodity swaps and forwards Power purchases 3 - - 3 Natural gas purchases and sales 5 1 - 6 Foreign exchange forwards - 4 - 4 8 5 - 13 HFT derivatives Power swaps and physical contracts 49 5 (4) 50 Natural gas swaps, futures, forwards and physical contracts 6 47 187 240 55 52 183 290 Total liabilities 65 62 183 310 Net assets (liabilities) $ (51) $ 143 $ (149) $ (57) As at December 31, 2016 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 10 $ - $ - $ 10 10 - - 10 Regulatory deferral Commodity swaps and forwards Coal purchases - 74 - 74 Power purchases 7 - - 7 Natural gas purchases and sales 8 25 - 33 Heavy fuel oil purchases 3 5 1 9 Foreign exchange forwards - 106 - 106 18 210 1 229 HFT derivatives Power swaps and physical contracts (7) 1 - (6) Natural gas swaps, futures, forwards, physical contracts and related transportation - 4 39 43 (7) 5 39 37 Total assets 21 215 40 276 Liabilities Cash flow hedges Power swaps 4 - - 4 Foreign exchange forwards - 23 - 23 4 23 - 27 Regulatory deferral Power purchases 4 - - 4 Heavy fuel oil purchases - 6 - 6 Natural gas purchases and sales 1 1 - 2 5 7 - 12 HFT derivatives Power swaps and physical contracts 12 5 - 17 Natural gas swaps, futures, forwards and physical contracts 4 24 389 417 16 29 389 434 Other derivatives Foreign exchange forwards - 1 - 1 Interest rate swaps - 1 - 1 - 2 - 2 Total liabilities 25 61 389 475 Net assets (liabilities) $ (4) $ 154 $ (349) $ (199) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2017 was as follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Oil financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2017 $ 1 $ - $ - $ 39 $ 40 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Unrealized gains (losses) included in regulatory assets or liabilities (1) 1 - - - Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 9 1 10 Net transfers out of Level 3 - - - (15) (15) Balance, December 31, 2017 $ - $ - $ 9 $ 25 $ 34 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2017 was as follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Oil financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2017 $ - $ - $ - $ 389 $ 389 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power - 1 - - 1 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - (5) (206) (211) Net transfers into Level 3 - - 1 4 5 Balance, December 31, 2017 $ - $ - $ (4) $ 187 $ 183 The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year e nded December 31, 2017 , transfers out of Level 3 were a result of a n in crease in observable inputs. For the year e nded December 31, 2017 , transfers into Level 3 were a result of a decrease in observable inputs. Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives i nclude third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may inc lude a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in dis cussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy: As at December 31, 2017 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – 1 Modelled pricing Third-party pricing $24.88-$117.90 $92.93 Power swaps and Probability of default 0.00%-0.01% 0.00% physical contracts Discount rate 0.00%-0.13% 0.00% 8 Modelled pricing Third-party pricing $63.48-$117.00 $102.68 Correlation factor 0.94%-0.99% 0.96% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.00% 0.00% HFT derivatives – 18 Modelled pricing Third-party pricing $2.06-$8.24 $3.61 Natural gas swaps, futures, Probability of default 0.00%-0.05% 0.00% forwards, physical contracts Discount rate 0.00%-0.29% 0.06% and related transportation 7 Modelled pricing Third-party pricing $2.04-$12.52 $6.42 Basis adjustment 0.08%-0.71% 0.52% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.09% 0.01% Total assets $ 34 Liabilities HFT derivatives – $ (6) Modelled pricing Third-party pricing $24.88-$117.90 $95.46 Power swaps and Own credit risk 0.00%-0.01% 0.00% physical contracts Discount rate 0.00%-0.13% 0.00% 2 Modelled pricing Third-party pricing $94.5-$117.00 $105.52 Correlation factor 0.94%-0.99% 0.96% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.00% 0.00% HFT derivatives – 172 Modelled pricing Third-party pricing $1.89-$11.81 $4.64 Natural gas swaps, futures, Own credit risk 0.00%-0.00% 0.00% forwards and physical contracts Discount rate 0.00%-0.12% 0.02% 15 Modelled pricing Third-party pricing $2.15-$12.52 $8.94 Basis adjustment 0.08%-0.71% 0.53% Own credit risk 0.00%-0.00% 0.00% Discount rate 0.00%-0.08% 0.01% Total liabilities $ 183 Net assets (liabilities) $ (149) As at December 31, 2016 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets Regulatory deferral – Financial $ 1 Modelled pricing Third-party pricing $69.64 $69.64 oil derivatives Probability of default 0.80% 0.80% HFT derivatives – 27 Modelled pricing Third-party pricing $1.41 - $11.87 $3.87 Natural gas swaps, Probability of default 0.00% - 0.07% 0.01% futures, forwards, Discount rate 0.00% - 0.32% 0.05% physical contracts 12 Modelled pricing Third-party pricing $1.83 - $11.87 $6.16 and related transportation Basis adjustment (0.11)% - 0.64% 0.39% Probability of default 0.00% - 0.05% 0.00% Discount rate 0.00% - 0.10% 0.00% Total assets $ 40 Liabilities HFT derivatives – $ 386 Modelled pricing Third-party pricing $1.55 - $11.87 $6.26 Natural gas swaps, futures, Own credit risk 0.00% - 0.07% 0.00% forwards and physical contracts Discount rate 0.00% - 0.14% 0.02% 3 Modelled pricing Third-party pricing $1.83 - $11.87 $5.93 Basis adjustment (0.11)% - 0.64% 0.27% Own credit risk 0.00% - 0.05% 0.01% Discount rate 0.00% - 0.10% 0.01% Total liabilities 389 Net assets (liabilities) $ (349) The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2017 $ 13,881 $ 15,217 $ 69 $ 14,346 $ 802 $ 15,217 December 31, 2016 $ 14,744 $ 15,723 $ 78 $ 14,843 $ 802 $ 15,723 Th e fair value of long-term debt instruments, classified as Level 1 in the fair value hierarchy, are valued using unadjusted quoted closing market prices that are traded in active markets. Those classified as L evel 2 are valued either by using recent quoted market prices for the instrument where the instrument is not frequently traded, by using quoted closing market prices for similar issues that are frequently traded in an active market or by using quoted market prices and applying estimated credit sp reads, provided by third-party pricing services, to the par value of the security. Those classified as L evel 3 are valued by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark gover nment bonds with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality. The Company has designated $ 1.2 billion United States dollar den ominated Hybrid Notes as a hedge of the foreign currency exposure of its ne t investment in United States dollar denominated oper ations. An after-tax foreign currency gain of $ 97 million was recorded in Other Comprehensive Income for the year ended December 31, 2017 ( 2016 – $ 49 million l oss after-tax ). There was no ineffect iveness for the year ended December 31, 2017 ( 2016 – nil ). All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried at cost. The carrying valu e approximates fair value due to the short-term nature of these financial instruments. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | 16 . REGULATORY Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs a re charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. Regulatory Assets and Liabilities Regulatory assets and liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Regulatory assets Deferred income tax regulatory assets $ 667 $ 632 Pension and post-retirement medical plan 345 373 Storm reserve 59 - Environmental remediations 41 49 Unamortized defeasance costs 32 39 2015 demand side management ("DSM") deferral 28 32 GBPC Hurricane Matthew restoration 28 28 Stranded cost recovery 25 27 Cost-recovery clauses 17 12 Deferrals related to derivative instruments 15 15 Debt basis adjustment 13 19 Deferred bond refinancing costs 7 9 Other 99 87 $ 1,376 $ 1,322 Current $ 138 $ 80 Long-term 1,238 1,242 Total regulatory assets $ 1,376 $ 1,322 Regulatory liabilities Deferred income tax regulatory liabilities 1,116 26 Accumulated reserve - cost of remova l 894 990 Deferrals related to derivative instruments 182 230 Regulated fuel adjustment mechanism 177 94 Cost-recovery clauses 51 153 Self-insurance fund (notes 7 and 32) 28 30 Bill reduction credit 4 10 Storm reserve - 75 Other 16 31 $ 2,468 $ 1,639 Current $ 226 $ 362 Long-term 2,242 1,277 Total regulatory liabilities $ 2,468 $ 1,639 Deferred Income Tax Regulatory Asset and Liability To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. As a result of the US Tax Cuts and Jobs Act of 2017 (“the Act”) being enacted during 2017, the Company has provisionally revalued its United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company has reduced its US regulated net deferred income tax liabilities by $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of t he applicable regulator. The Company is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred c osts of pension and post - retirement benefits at Emera Florida and New Mexico. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Storm Reserve The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $ 1 0 million USD of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million USD of storm costs to the storm reserve, reducing the balance in the storm reserve to $46 million USD. On September 10, 2017, Tampa Electric was impacted by Hurricane Irma. The estimated cost of restoration is $105 million USD, of which $ 93 million USD was charged to the storm reserve, $ 8 million USD was charged to capital expenditures and $ 4 million USD was charged to OM&G. The $93 million USD charged to the storm reserve exceeded the $46 million USD balance by $47 million USD, which h as been recorded as a regulatory asset on the balance sheet. This regulated asset is included in rate base. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory ass et. Tampa Electric petitioned the FPSC on December 28, 2017 for the recovery of the estimated storm costs in excess of the reserve for several named storms, including Hurricane Irma, and to replenish the balance in the reserve to the $56 million USD level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. Environmental Remediation s This asset is primarily related to PGS costs associated with the environmental remediation at manufactured gas plant sites . The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. Unamortized Defeasance Costs Up on privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as at December 31, 2017 , totalled $ 0.7 billion ( 2016 – $ 0.8 billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as approved by the UARB. 2015 DSM Deferral Effective January 1, 2015, NSPI must purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. 2015 Program Costs were deferred to a regulatory asset and are recoverable from customers over an eight-year period which began in 2016. The UARB directed EffficiencyOne to review the financing options through which they would borrow the 2015 deferral amount fr om a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. In December 2016, EffficiencyOne secured the financing and advanced funds to NSPI to finance the 2015 DSM deferral. This was set up as a payable on th e Consolidated Balance Sheets, included in current and long-term other liabilities. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne thereby reducing the liability. Hurricane Matth ew Restoration This asset represents restoration costs incurred by GBPC in 2016 associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The Grand Bahama Port Authority (“GBPA”) has approved full re covery of these storm restoration costs. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine during 2012, the GBPA approved the recovery of a $ 21 million USD stranded cost through electricity rates; it is included in rate base for 2016 to 2018. Cost Recovery Clauses These assets and liabilities are related to TEC and NM G C clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by FPSC or NMPRC, as applicable, on a dollar-for- dollar basis in the next year. Debt Basis Adjustment This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the date TECO Energy acquired NMGC. In accordance with purchase accounting standards, NMGC’s long-term debt was valued at fair value on the Consolidated Balance Sheets. In accordance with the stipulation agreement with the NMPRC, an offsetting regulatory asset was recorded in order to eliminate the effects of purchase accounting on rate payers. The asset does not earn a return and is not inclu ded in the regulatory capital structure. It is amortized over the term of the related debt instrument. Deferrals Related to Derivative Instruments Tampa Electric, PGS, NMGC, NSPI and GBPC defer changes in fair value of derivatives that are documented a s economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in fuel for generation and purchased power , inventory or property, plant and equipment , de pending on the nature of the item being economically hedged. Tampa Electric deferrals related to derivative instruments are recovered through cost-recovery mechanisms on a dollar-for-dollar basis in the year following the settlement of the derivative posi tion. Deferred Bond Refinancing Costs This asset represents Tampa Electric and NMGC costs associated with refinancing debt. It does not earn a return but is instead included in the capital structure, which is used in the calculation of the weighted aver age cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instruments . Accumulated Reserve – Cost of Removal This regulatory liability represents the non-ARO C ost of R emoval (“COR”) reserve in Tampa Electric and NSPI. AROs are costs for legally required removal of property, plant and equipment. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes . This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as ne w assets are put into service. Fuel Adjustment Mechanism Differences between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year are deferred to a fuel adjustment mechanism (“FAM”) regulatory asset or liability and recovered from or returned to customers in a subsequent year. For the years 2017 to 2019, differences between actual fuel costs and fue l revenues recovered from customers will be recovered or returned to customers after 2019, as required under the Electricity Plan Act . Bill Reduction Credit This regulatory liability represents NMGC’s stipulation agreement commitment to provide an annua l bill reduction credit to customers of $ 4 million USD per year through June 30, 2018, as part of Emera’s acquisition of TECO Energy. Regulatory Environments Emera Florida and New Mexico Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to c ollect total revenues equal to their cost of providing service, plus an appropriate return on invested capital. Base Rates - Tampa Electric Tampa Electric’s target regulated return on equity (“ROE”) range is 9.25 per cent to 11.25 per cent. B ased on a Stipulation and Settlement Agreement in 2013 Tampa Electric receive d a revenue increase of $ 110 million USD effective January 1 7, 2017, the date Tampa Electric’s Polk Power Station went into service. The agreement also provided that Tampa Electric could not file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE fell below 9.25 per cent before that time. If its earned ROE rose above 11.25 per cent any party to the agreement other than Tampa Ele ctric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54 per cent from investor sources of capital. In September 2017, Tampa Electric announced its intention to invest approximately $ 850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. A settlement agreement was filed with the FPSC requesting a solar base rate adjustment ("SoBRA") that provides for the recovery, upon in-service, of up to 60 0 MW of investments in utility-scale solar projects that will be phased in from late 2018 through early 2021. The Tampa Electric settlement agreement contains a provision whereby the impacts of tax reform will be offset by a reduction in base rates within 1 20 days of when tax reform becomes law. On November 6, 2017, the FPSC approved the settlement agreement that replaced the existing 2013 agreement and extended it another four year years through 2021. On December 12, 2017, TEC filed its petition along wit h supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $ 26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the sp ring of 2018 . On January 30, 2018, Tampa Electric filed with the FPSC a settlement agreement which, if approved, will allow Tampa Electric to net the estimated amount of storm cost recovery against the utility’s estimated 2018 tax reform benefits. Any di fference would be trued up and recovered from or returned to customers in 2019. Beginning in January 2019 Tampa Electric would reflect the full impact of tax reform on Tampa Electric’s base rates, provided that the FPSC’s determinations have been finalize d. A decision is expected in March 2018. Base Rates - PGS Prior to 2016, PGS’s base rates were based upon an ROE of 10.75 per cent, with a range between 9.75 per cent and 11.75 per cent. In December 2016, PGS entered into a settlement agreement with the Office of Public Counsel (“OPC”) regarding its filed depreciation study. The settlement agreement resulted in new depreciation rates that reduce annual depreciation by $ 16 million USD in 2016 and accelerated the amortization of the regulated asset rel ated to the Manufactured Gas Plant (“MGP”) environmental remediation costs. In addition, the bottom of the ROE range was decreased from 9.75 per cent to 9.25 per cent. The new bottom of the range will remain until the earlier of new base rates establishe d in PGS’s next general rate proceeding or December 31, 2020. The top of the range will continue to be 11.75 per cent and the ROE of 10.75 per cent will continue to be used for the calculation of return on investment for clauses. On February 7, 2017 the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement. As part of the settlement, PGS and OPC agreed that at least $ 32 million USD of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites will be amortized over the period 2016 through 2020. At least $ 21 million USD will be amortized over a two year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $ 5 million and $ 16 million, respectively, of this amortization expense. The PGS settlement does not contain a provision for US tax reform. On January 9, 2018, the OPC filed a gen eric docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS. Base Rates - NMGC NMGC’s base rates were established in 2012 through a settlement agreement. As a condition of the 2016 NMPRC order (the “Order”) approving the acquisition of TECO Energy, NMGC will not seek an increase in base rates to be effective prior to December 31, 2017, and NMGC will continue to provide an annual bill reduction credit of $ 4 million USD through June 30, 2018. NMGC plans to file a rate case in 2018 . NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “ Public Utilities Act”) and is subject to regulation under the Public Utilities Act by th e UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated ROE range for 2017 and 2016 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of f uel c osts through regularly scheduled rate adjustments. Differences between actual f uel c osts a nd amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. I n December 2 015, the Province enacted the Electricity Plan Imple mentation (2015) Act, (“Electricity Plan Act”) , which required NSPI to file a three-year stability plan for fuel c osts and a General Rate Application (“GRA”) for non-fuel costs if required . I n July 2016, the UARB approved a Consensus Agreement between NSP I and customer representatives related to the Rate Stability Plan for fuel costs for 2017 through 2019 which resulted in an average annual increase of 1.1 per cent for each of these three years. Subsequently, certain customer representatives requested cha nges resulting in amended rates t hat were approved by the UARB in November 2016 and result in an average annual rate increase of 1.5 per cent for each of these three years. In December 2016, the UARB approved NSPI’s applic ation to refund over-recovered f uel c osts from 2016 to customers. The over-recovered 2016 f uel c osts of $ 36 million were refunded to customers through a one-time credit on their bills in 2017 and allocated to customers based on their individual electricity usage in 2016. The amount ref unded to customers includes 2016 excess non-fuel revenues of $5 million. On September 11, 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link starting when the Maritime Link is in service. The Maritime Link completed commissioning and entered service on January 15, 2018. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects NSPML’s proposal to reduce the assessment by deferring $ 53 million in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being recovered from customers, NSPI will provide a one-time credit to customers, including interest, in 2018 of approximately $ 1 7 million, 2019 of approximately $36 million and 2020 of approximately $53 million, as the payments from NSPI to NSPML are not required. NSPI is also required to hold back $10 million from the interim assessment payment to NSPML in 2018 and 2019. The release of such amou nts is subject to providing evidence to the UARB that at least that amount of benefit from the Maritime Link has been realized for NSPI customers in that year. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. For the Year ended December 31 millions of Canadian dollars 2017 2016 (Over) under recovery of current period Fuel costs $ - $ 29 Recovery from customers of prior years’ Fuel costs - 12 Application of non-fuel revenues - 20 Regulated fuel adjustment mechanism $ - $ 61 Emera Maine Emera Maine’s distribution operations and stranded cost recoveries are regulated by the Maine Public Utilities Commission (“MPUC”). The transmission operations are regulated by the FERC. The rates for these three elements are established in distinct regulatory proceedings. Distribution Operations Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. On December 21, 2016, Emera Maine’s distribution rates increased by 3.75 per cent, including the recovery, over five years, of approximately $ 4 million USD of costs associated with a major storm in Maine in 2014. Also, effective December 21 , 2016 , the allowed ROE was reduced by 0.55 per cen t to 9.00 per cent on a common equity component of 49 per cent. Transmission Operations Emera Maine’s transmission operations are split between two districts; Bangor Hydro District and Maine Public Service (“MPS”). Bangor Hydro District local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE for Bangor Hydro District local transmission operations for 2017 and 2016 is 10.57 per cent. Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. The allowed ROE range for Bangor Hydro bulk transmissio n assets is 11.07 to 11.74 per cent for 2017 and 2016 . MPS District local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers based on a formula utilizing prior year actual transmi ssion investments and expenses. The current allowed ROE for transmission operations is 9.6 per cent (2016 – 10.2 per cent). Stranded Cost Recoveries Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and account ing orders issued by the MPUC. The Barbados Light & Power Company Limited BLPC is a vertically integrated utility and provider of electricity on the island of Barbados. BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 by the Fair Trading Commission (“The Rules”) , Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions. The government of Barbados has granted BLPC a franchise to generate , transmit and distribute electricity on t he island until 2028. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on r ate base was 10 per cent for 2017 and 2016 . All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner . The Fair Trading Commission, Barbados has a pproved the calculation of the fuel charge, which is adjusted on a monthly basis. Grand Bahama Power Company Limited GBPC is a vertically integrated utility and sole provider of electricity on Grand Bahama Island. The GBPA regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered a nd a reasonable return earned. GBPC’s approved regulated return on rate base was 8.8 per cent for 2017 and 2016 . In December 2017 the GBPA approved GBPC’s regulated return on rate base of 8.5 per cent for 2018. In December 2016, the GBPA approved t hat over a five-year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates. Dominica Electricity Services Ltd Domlec is an integrated utility on the island of Dominica and is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013 , the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on r ate base was 15 per cent for 2017 and 2016 . Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner . On September 19, 2017, Dominica experienced unprecedented damage as a result of Hurricane Maria, facing sustained winds of over 175 miles per hour. All 36,000 of Domlec’s customers lost power following the storm as the Company’s transmission and distribution assets were significantly im pacted. Domlec has implemented a restoration plan . Domlec maintains insurance for its generation fleet and, as with most utilities, transmission and distribution networks are self-insured. Management has completed its damage assessment and a n estimated impairment provision has been recorded at December 31, 2017 . Emera’s portion of the estimated impairment provision is immaterial. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Canaport™ re-gasified li quefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25 - year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is c onsidered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. millions of Canadian dollars 2017 2016 FAM regulatory asset – Balance as at January 1 $ (94) $ (28) Under (over) recovery of current year Fuel Costs (29) (29) Rebate to (recovery from) customers of prior years’ Fuel Costs (12) (12) FAM audit disallowance, including interest adjustment - - Excess non-fuel revenues (5) (27) Interest on FAM balance (5) 1 FAM regulatory asset (liability) – Balance as at December 31 $ (160) $ (113) |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | 17 . RELATED PARTY TRANSACTIONS In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and inter company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities , as discussed i n note 1 . All material amounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies are : Natural gas transportation capacity revenues from M&NP reported in the Consolidated Statements of Income . Revenues from M&NP , reported in Operating revenue - n on-regulated, total led $ 28 million for the year ended December 31, 2017 ( 2016 - $ 29 million). Transmission construction revenues from NSPML reported in the Consolidated Statements of Income. Revenues from NSPML, reported in Operating revenues, Non-regulated, tota lled $ 17 million for the year ende d December 31, 2017 ( 2016 - $ 18 million ). There are no significant receivables or payables between Emera and its associated companies reported on Emera’s C onso lidated Balance Sheets as at December 31, 2017 and December 31, 2016 . |
Receivables and Other Current A
Receivables and Other Current Assets | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract] | |
Prepayment and other current assets [Text Block] | 18. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Customer accounts receivable – billed $ 805 $ 715 Customer accounts receivable – unbilled 278 270 Allowance for doubtful accounts (12) (13) Other receivables 70 42 Capitalized transportation capacity (1) 89 190 Prepaid expenses 59 57 Due from related parties 5 16 Net investment in direct financing lease 8 8 Income tax receivable 24 33 Other - 5 $ 1,326 $ 1,323 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | 19 . PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of Canadian dollars Estimated useful life 2017 2016 Generation 3 to 131 $ 11,010 $ 10,553 Transmission 15 to 80 2,786 2,799 Distribution 4 to 80 5,660 5,715 Gas transmission and distribution 7 to 85 2,867 2,895 General plant and other 3 to 60 1,874 1,711 Total cost 24,197 23,673 Less: Accumulated depreciation (7,824) (7,787) 16,373 15,886 Construction work in progress 622 1,404 Net book value $ 16,995 $ 17,290 |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans [Abstract] | |
EMPLOYEE BENEFIT PLANS | 20 . EMPLOYEE BENEFIT PLANS Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island. Benefit Obligation and Plan Assets The changes in b enefit o bligation and p lan a ssets, and the f unded s tatus for all plans were as follows: For the Year ended December 31 millions of Canadian dollars 2017 2016 Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,607 $ 358 $ 1,520 $ 88 Addition of TECO Energy, July 1, 2016 - - 1,035 277 Service cost 49 5 35 4 Plan participant contributions 8 4 8 - Interest cost 99 14 79 9 Plan amendments - - - 2 Benefits paid (129) (27) (94) (16) Actuarial losses 171 25 (2) (12) Special termination (35) - - - Foreign currency translation adjustment (87) (23) 26 6 Balance, December 31 2,683 356 2,607 358 Change in plan assets Balance, January 1 2,208 39 1,300 6 Addition of TECO Energy, July 1, 2016 - - 830 29 Employer contributions 109 27 49 17 Plan participant contributions 8 4 8 - Benefits paid (129) (27) (94) (16) Actual return on assets, net of expenses 313 5 93 2 Special termination (34) - - - Foreign currency translation adjustment (67) (3) 22 1 Balance, December 31 2,408 45 2,208 39 Funded status, end of year $ (275) $ (311) $ (399) $ (319) Plans with PBO / APBO in excess of plan assets T he aggregate financial position for all pension plans where the PBO or, for post-retirement benefit plans, the APBO exceeds the plan assets for the years ended December 31 is as follows: millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,655 $ 325 $ 2,579 $ 358 Fair value of plan assets 2,370 6 2,171 39 Funded status $ (285) $ (319) $ (408) $ (319) Plans with Accumulated Benefit Obligation (“ABO”) in excess of plan assets The ABO for the defined benefit pension plans was $ 2,561 million as at December 31, 2017 ( 2016 – $ 2,489 million). T he aggregate financial position for those plan s with an ABO in excess of the p lan assets for the years ended December 31 is as follows : millions of Canadian dollars 2017 2016 Defined benefit pension plans Defined benefit pension plans ABO $ 1,608 $ 2,462 Fair value of plan assets 1,409 2,171 Funded status $ (199) $ (291) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Current liabilities $ (23) $ (18) $ (41) $ (17) Long-term liabilities (264) (295) (367) (302) Other asset (non-current) 10 - 9 - Amount included in deferred tax asset 15 1 16 (1) AOCL (AOCI) and regulatory assets after-tax adjustment 548 73 620 45 Net amount recognized at end of year $ 286 $ (239) $ 237 $ (275) Amounts recognized in AOCI and Regulatory assets Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets . Unamortized net losses and past service costs as at the acquisition date for TECO Energy’s regulated companies were recorded as r egulatory assets. The following table summarizes the change in A OCI and r egulatory assets: Regulatory assets Actuarial losses (gains) Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2017 $ 309 $ 330 $ (3) Amortized in current period (17) (38) - Current year addition to AOCL or regulatory assets (10) (8) - Balance, December 31, 2017 $ 282 $ 284 $ (3) Non-pension benefits plans Balance, January 1, 2017 $ 48 $ 15 $ (19) Amortized in current period 1 (2) 8 Current year addition to AOCL (AOCI) or regulatory assets 25 (2) - Balance, December 31, 2017 $ 74 $ 11 $ (11) 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 284 $ 11 $ 330 $ 15 Past service (gains) (3) (11) (3) (19) Regulatory assets 282 74 309 48 Total AOCL (AOCI) and regulatory assets on a pre-tax basis 563 74 636 44 Amount included in deferred tax asset (15) (1) (16) 1 Net amount in AOCL (AOCI) and regulatory assets after-tax adjustment $ 548 $ 73 $ 620 $ 45 Benefit cost components Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 49 $ 5 $ 35 $ 4 Interest cost 99 14 79 9 Expected return on plan assets (129) (3) (97) (1) Current year amortization of: Actuarial losses 38 2 42 2 Past service costs (gains) - (8) (1) (8) Regulatory assets (liability) 17 (1) 9 - Settlement, curtailments (1) - - - Total $ 73 $ 9 $ 67 $ 6 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,153 million as at January 1, 2017 ( 2016 – $ 1,180 million) , adjusted for interest on certa in cash flows during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of asset s over a five-year period. Pension Plan Asset Allocations Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumpt ions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad bas ket of investment and non-investme nt grade securities. Emera’s target asset allocation is as follows: Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 5% Fixed income 35% to 50% Equities: Canadian 12% to 22% Non-Canadian 30% to 55% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Short-term securities 47% to 52% Equities 48% to 53% Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies . All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company . The following tables set out the classification of the methodology used by the Company to fair value its investments : As at December 31, 2017 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 32 - $ 32 1 % Net in-transits - (36) - (36) (1) % Equity Securities: Canadian equity 214 - 214 9 % US equity - 390 - 390 16 % Other equity - 197 - 197 8 % Fixed income securities: Government - - $ 72 72 3 % Corporate - - 56 56 2 % Other - 5 - 5 - % Other - 4 4 - % Open-ended investments measured at NAV (1) $ 1,065 - - 1,065 44 % Common collective trusts measured at NAV (2) 409 - - 409 18 % Total $ 1,474 $ 802 $ 132 $ 2,408 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. As at December 31, 2016 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 31 $ - 31 1 % Net in-transits - (42) - (42) (2) % Equity securities: Canadian equity - 192 - 192 9 % US equity - 303 - 303 14 % Other equity - 243 - 243 11 % Fixed Income securities: Government - - 47 47 2 % Corporate - - 53 53 2 % Other - 5 14 19 1 % Open-ended investments measured at NAV (1) $ 1,132 - - 1,132 51 % Common collective trusts measured at NAV (2) 230 - - 230 11 % Total $ 1,362 $ 732 $ 114 2,208 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. Refer to note 15 for more information on the fair value hierarchy and inp uts used to measure fair value. Canadian Post - Retirement Benefit Plans There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required . US Post - Retirement Benefit Plans Emera’s US subsidiaries currently provide certain post-retirement health care and life insurance benefits for employees retiring after age 5 0 who meet eligibility requirements. Post-retirement benefit levels are substanti ally unrelated to salary. The C ompany reserves the right to termina te or modify plans in whole or in part at any time. Emera Maine provides retiree medical benefits to certain groups of employees. The Company's retiree medical expenses are incorporated into rate filings with its regulators and are recovered through its electric rates to customers. TECO Energy and NMGC offers retirees under age 65 and their dependents a self-funded HRA medical plan identical to that offered to active TECO Energy employees. TECO Energy retirees over the age of 65 are enrolled in a Medicare Advantage plan. NMGC retirees over age 65 and their dependents receive a fixed subsidy with which they can purchase additional coverage through a medical supplement program. NMGC also provides dental benefits to retirees and spouses. Asset Class Target Range at Market Short-term securities 0% to 0% Equities: US 0% to 0% Non-US 0% to 0% The fair values of investments as at December 31, 2017 , for all Post - Retirement Benefit Plans by asset category, are as follows: December 31,2017 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 2 % Life insurance policies (1) - - 39 39 87 % Other investments measured at NAV $ 5 - - 5 11 % Total $ 5 $ 1 $ 39 $ 45 100 % (1) For valuation purposes, the life insurance policies held for the NMGC retiree medical plan are valued at the cash surrender value and are considered Level 2 assets December 31,2016 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 3 % Life insurance policies (1) - - 33 33 85 % Other investments measured at NAV $ 5 - - 5 12 % Total $ 5 $ 1 $ 33 $ 39 100 % (1) For valuation purposes, the life insurance policies held for the NMGC retiree medical plan are valued at the cash surrender value and are considered Level 2 assets Refer to n ote 15 for more information on the fair value hierarchy and inputs used to measure fair value. Investments in Emera As at December 31, 2017 and 2016 , the assets related to the pension funds and post-retirement benefit plans do not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities. Cash Flows The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans: millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2018 $ 97 $ 25 Expected benefit payments 2018 147 22 2019 143 23 2020 148 23 2021 157 23 2022 165 24 2023 – 2027 912 124 Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2017 2016 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate 3.55 % 3.65 % 3.96 % 4.18 % Rate of compensation increase 3.12 % 3.28 % 2.82 % 2.54 % Health care trend - initial (next year) - 6.65 % - 6.78 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2036 - 2035 Benefit cost for year ended December 31: Discount rate 3.96 % 4.18 % 3.79 % 3.88 % Expected long-term return on plan assets 6.29 % 6.08 % 6.33 % 4.43 % Rate of compensation increase 2.82 % 2.54 % 2.88 % 2.56 % Health care trend - initial (current year) - 6.78 % - 6.76 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2020 Figures shown are weighted averages. Actual assumptions used differ by plan. The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan Sensitivity Analysis for Non-Pension Benefits Plans The health care cost trend significantly influences the am ounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2017 : millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 19 (16) Sensitivity Analysis for Defined Benefit Pension Plans The impact on the 2017 benefit cost of a 25 basis point change in the discount rate and asset return assumptions is as follows: millions of Canadian dollars Increase Decrease Discount rate assumption $ (9) $ 9 Asset rate assumption (6) 6 Amounts to be Amortized in the Next Fiscal Year The following table shows the amounts from the AOCL and regulatory assets, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2018: 2018 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (36) $ (2) Past service gains 1 6 Regulatory assets (21) (2) Total $ (56) $ 2 Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2017 was $ 23 million ( 2016 – $ 17 million) , with the increase due to TECO Energy contributions being included for the full year . |
Net Investment in Direct Financ
Net Investment in Direct Financing Lease | 12 Months Ended |
Dec. 31, 2017 | |
Net Investment in Direct Financing Lease [Abstract] | |
NET INVESTMENT IN DIRECT FINANCING LEASE | 21 . NET INVESTMENT IN DIRECT FINANCING LEASE Emera’s net investment in direct financing lease primarily relates to Brunswick Pipeline. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. Net investment in direct financing lease consists of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Total minimum lease payments to be received $ 1,126 $ 1,194 Less: amounts representing estimated executory costs (211) (223) Minimum lease payments receivable $ 915 $ 971 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (609) (658) Net investment in direct financing lease $ 489 $ 496 Principal due within one year (included in “Receivables and other current assets”) 8 8 Net investment in direct financing lease – long-term $ 481 $ 488 Future minimum lease payments to be received for the next five years: For the Year ended December 31 millions of Canadian dollars 2018 2019 2020 2021 2022 Minimum lease payments to be received $ 64 $ 64 $ 64 $ 65 $ 64 Less: amounts representing estimated executory costs (11) (11) (11) (12) (12) Minimum lease payments receivable $ 53 $ 53 $ 53 $ 53 $ 52 |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill [Abstract] | |
GOODWILL | 22. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2017 2016 Balance, January 1 $ 6,213 $ 264 Acquisition of TECO Energy as at July 1, 2016 (note 4) - 5,771 Change in foreign exchange rate (408) 178 Balance, December 31 $ 5,805 $ 6,213 G oodwill on Emera’s Consolidated B alance S heet s relates to the ac quisitions of TECO Energy (refer to n ote 4 ), Emera Maine and GBPC. Goodwill is subject to an annual assessment for impairment at the reporting unit level. Emera’s reporting units with goodwill are Tampa Electric, PGS , New Mexico Gas, Emera Maine and GBPC. A qualitative assessment was performed for Tampa Electric, PGS, New Mexico Gas, and GBPC, concluding that the fair value of the reporting units exceeded their carrying value, and as such, no quantitative assessment was performed. Emera elected to bypass the qualitative assessment for Emera Maine and used a discounted cash flow analysis to determine the fair value of the reporting unit. The discounted ca sh flow analysis relies on management’s best estimate of the reporting units’ projected cash flows. It includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annui ty based on the entity’s residual cash flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The C ompany determined the fair value of reporting units exceed their book value and related goodwill carrying amounts at December 31, 2017 and December 31, 2016 , resulting in no impairment charge. Significant assumptions used in estimating the fair value include discount and growth ra tes, valuation of NOLs, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the terminal value. Adverse changes in assumptions described above could result in a future material impairment of the goodwill assigned to Tampa Electric, PGS, New Mexico Gas, Emera Maine or GBPC. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT | 23 . SHORT-TERM DEBT Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rate s as at December 31 consisted of the following: millions of Canadian dollars 2017 Weighted-average interest rate 2016 Weighted-average interest rate TECO Energy/TECO Finance Advances on revolving credit and term facilities $ 820 2.58 % $ 685 1.74 % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 382 2.07 % 228 1.49 % NMGC Advances on revolving credit facilities 38 2.47 % 35 1.71 % NSPI Bank indebtedness 1 - % 1 - % GBPC Advances on revolving credit facilities - - % 12 5.75 % Short-term debt $ 1,241 $ 961 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2017 2016 TECO Energy/TECO Finance - term credit facility 2018 $ 502 $ 537 TECO Energy/TECO Finance - revolving credit facility 2022 376 403 Tampa Electric Company - revolving credit facility 2022 408 436 Tampa Electric Company - accounts receivable revolving credit facility 2018 188 201 Tampa Electric Company - term loan 2018 377 - NMGC - revolving credit facility 2022 157 168 GBPC - revolving credit facility Various 16 17 Total 2,024 1,762 Less: Advances under revolving credit and term facilities 1,241 960 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,244 963 Available capacity under existing agreements $ 780 $ 799 The weighted average interest rate on outstanding short-term debt at December 31, 2017 was 2.42 per cent ( 2016 – 1.73 per cent ). Recent financing activities TEC Non-revolving term loan On November 2, 2017, TEC entered into a $300 million USD non-revolving term loan with a maturity date of November 1, 2018. The loan contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR plus a margin. TECO Energy/TECO Finance Revolving Credit Facility On March 22, 2017, TECO Energy/Finance extended the maturity date of its $300 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement. TEC Credit Fa cility On March 22, 2017, TEC extended the maturity date of its $325 million USD bank credit facility from December 17, 2018 to March 22, 2022, and reduced the existing letter of credit facility to $50 million USD from $200 million USD. There were no other significant changes in commercial terms from the prior agreement. NMGC Credit Agreement On March 22, 2017, NMGC extended the maturity date of its $125 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant chan ge in commercial terms from the prior agreement. TECO Energy/TECO Finance Term Credit Facility On March 8, 2017, TECO Energy/Finance extended the maturity date of its $400 million USD term bank credit facility from March 14, 2017 to March 8, 2018 with no significant change in commercial terms from the prior agreement. |
Other Current Liabilities
Other Current Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Other Current Liabilities [Abstract] | |
OTHER CURRENT LIABILITIES | 24 . OTHER CURRENT LIABILITIES Other current liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Accrued charges $ 134 $ 137 Accrued interest on long-term debt 78 96 Income tax payable 1 19 Accrued pension liability 41 58 Sales and other taxes payable 11 16 Emission credits obligations (1) 21 10 Other 64 22 $ 350 $ 358 (1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt [Abstract] | |
LONG-TERM DEBT | 25 . L ONG-TERM DEBT Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. I ncluded are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 , 2017, consisted of the following: millions of Canadian dollars Weighted Average Interest Rate 2017 (1) Weighted Average Interest Rate 2016 (1) Maturity 2017 2016 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 133 $ 30 Unsecured fixed rate notes 3.50% 3.50% 2019-2023 725 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,505 1,611 $ 2,363 $ 2,366 Emera US Finance LP Unsecured senior notes (USD) 3.60% 3.60% 2019 - 2046 $ 4,077 $ 4,364 TECO Finance (2) Variable rate notes (USD) Variable Variable 2018 $ 314 $ 336 Fixed rate notes and bonds (USD) 5.15% 5.86% 2020 376 805 $ 690 $ 1,141 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.75% 4.90% 2018 - 2045 $ 2,410 $ 2,579 PGS Fixed rate notes and bonds (USD) 5.06% 5.06% 2018 - 2045 $ 328 $ 351 NMGC Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2026 $ 339 $ 363 NMGI Fixed rate notes and bonds (USD) 3.41% 3.41% 2019 - 2024 $ 251 $ 269 NSPI Commercial paper Variable Variable 2021 $ 364 $ 264 Medium term fixed rate notes 5.73% 5.73% 2019 - 2097 1,965 1,965 Fixed rate debenture 9.75% 9.75% 2019 95 95 $ 2,424 $ 2,324 Emera Maine LIBOR loans and demand loans Variable Variable 2019 $ 51 $ 32 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 63 67 Unsecured senior fixed rate notes (USD) 4.15% 4.28% 2018-2047 294 281 $ 408 $ 380 EBP Senior secured credit facility 3.08% 3.08% 2021 $ 248 $ 248 GBPC Amortizing fixed rate notes (USD) 3.77% 3.62% 2021-2022 $ 78 $ 63 Senior notes (USD) 7.07% 7.07% 2020-2023 88 67 $ 166 $ 130 BLPC & ECI Secured senior notes (USD) Variable Variable 2021 168 201 Secured fixed rate senior notes (4) 5.06% 5.65% 2020 - 2028 $ 76 $ 81 $ 244 $ 282 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 31 $ 58 Debt issuance costs (98) (111) Amount due within one year (741) (476) $ (808) $ (529) Long-Term Debt $ 13,140 $ 14,268 (1) Weighted average interest rate of fixed rate long-term debt. (2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2017 2016 Emera – revolving credit facility (1) June 2020 $ 900 $ 700 NSPI - revolving credit facility (1) October 2021 600 600 Emera Maine – revolving credit facility September 2019 100 107 BLPC – revolving credit facility 2018-2021 24 26 Total 1,624 1,433 Less: Borrowings under credit facilities 598 326 Letters of credit issued inside credit facilities 44 37 Use of available facilities 642 363 Available capacity under existing agreements $ 982 $ 1,070 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. Debt Covenants Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in complianc e with covenant requirements. Emera’s significa nt covenants are listed below: As at Financial Covenant Requirement December 31, 2017 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.61:1 Recent Financing Activity Recent Financing Activity Emera On December 12 , 2017, Emera exercised its accordion option under its revolving credit facility to increase the facility from $ 7 00 million to $ 9 00 million with no other change to existing terms. TECO Energy/TECO Finance On November 1, 2017, TECO Energy/Finance repaid a $300 million USD note upon maturity. The note was repaid using funds from existing credit facilities and cash on hand. Emera Maine On September 27, 2017 Emera Maine completed a 30-year $50 million USD seni or unsecured notes issuance. The notes bear interest at a rate of 4.36 per cent and will mature on September 27, 2047. Proceeds were used to repay maturing notes and for general corporate purposes. BLPC On September 1, 2017, BLPC’s interest rate on two $20 million BBD secured fixed rate senior notes maturing in 2020 and 2024 was reduced to 4.25 per cent and 5.875 per cent from 6.65 per cent and 6.875 per cent , respectively. Effective October 11, 2017, interest on their $12 million BBD demand loan facility w as reduced to 4 per cent from 6.5 per cent . Emera Brunswick Pipeline On July 4, 2017, Emera Brunswick Pipeline amended its credit agreement to extend the maturity from February 2019 to February 2021 with no change to commercial terms from the prior agreement. NSPI On June 28, 2017, NSPI amended its operating credit facility to extend the maturity from October 2020 to October 2021 and the debt to capitalization ratio from 0.65:1 to 0.70:1. All other terms of the agreement are the same. GBPC On Marc h 21, 2017, GBPC amended its loan agreement with the addition of two non-revolving term credit facilities. There were no significant changes in commercial terms from the prior agreement. The combined total of these new facilities is for up to $45 million USD. At December 31, 2017 the facilities were drawn in full . U.S. Notes On June 16, 2016, Emera US Finance LP, a limited partnership financing subsidiary, wholly owned directly and indirectly by Emera, completed the issuance of $3.25 billion USD senior unsecured notes (“U.S. Notes”) by way of private placement. The U.S. Notes were sold only to “qualified institutional buyers” under Rule 144A of the United States Securities Act of 1933, as amended (the “Securities Act”) and to non-U.S. persons under Regulation S of the Securities Act and were not offered for sale in Canada. The U.S. Notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary. The U.S. Notes bear interest semi-annually, in arrears, on June 15 and December 15 of each year, commencing on December 15, 2016. The U.S. No tes will not be listed on a securities exchange. The U.S. Notes issued are as follows: $500 million USD three year, 2.15 per cent Notes due 2019 $750 million USD five year 2.70 per cent Notes due 2021 $750 million USD ten year 3.55 per cent Notes due 20 26 $1.25 billion USD thirty year 4.75 per cent Notes due 2046 In connection with the initial issuance of the U.S. Notes, Emera US Finance LP entered into a registration rights agreement with the initial purchasers of the U.S. Notes in which it undertook t o offer to exchange the U.S. Notes for new notes, in an equal principal amount and under the same terms, registered under the Securities Act. On December 15, 2016, a registration statement on Form F-10/Form S-4 was declared effective by the United States Securities and Exchange Commission (the “SEC”). On January 17, 2017 the new notes were issued. Hybrid Notes On June 16, 2016, Emera completed the issuance of $1.2 billion USD unsecured, fixed-to-floating subordinated notes (“Hybrid Notes”). The Hybrid Notes were issued pursuant to a prospectus filed with the Nova Scotia Securities Commission (the “NSSC”) and a corresponding registration statement filed with the SEC under the United States / Canada Multijurisdictional Disclosure System. The Hybrid Notes will mature on June 15, 2076. Emera will pay interest on the Hybrid Notes at a fixed rate of 6.75 per cent per year in equal semi-annual instalments on June 15 and December 15 of each year until June 15, 2026. Beginning on June 15, 2026, and on every qua rter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076 (the “Interest Reset Date”), the interest rate on the Hybrid Notes will be reset. The Hybrid Notes are not currently listed and Emera does not intend to list them o n any securities exchange or include them on any automated quotation system. Beginning on June 15, 2026, and on every Interest Reset Date until June 15, 2046, the Hybrid Notes will be reset at an interest rate of the three month LIBOR plus 5.44 per cent , payable in arrears. Beginning on June 15, 2046, and on every Interest Reset Date until June 15, 2076, the Hybrid Notes will be reset at an interest rate of the three-month LIBOR plus 6.19 per cent, payable in arrears. Emera may elect, at its sole opti on, to defer the interest payable on the Hybrid Notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after June 15, 2026, Eme ra may, at its option, redeem the Hybrid Notes, at a redemption price equal to 100 per cent of the principal amount, together with accrued and unpaid interest. Canadian Notes On June 16, 2016, Emera completed the issuance of $500 million senior unsecured notes (“Canadian Notes”). The Canadian Notes were issued with a seven-year term to maturity and bear interest at a rate of 2.90 per cent. The notes will bear interest semi-annually in arrears on June 16 and December 16 of each ye ar, commencing on December 16, 2016. The Canadian Notes will not be listed on a securities exchange. The proceeds of the U.S. Notes, Hybrid Notes and Canadian Notes offerings were used to partially finance the purchase price for the Acquisition. Proceed s of the offerings, not otherwise required to complete the Acquisition, have been used for general corporate purposes. NSPI On April 28, 2016, NSPI increased its committed syndicated revolving bank line of credit to $600 million from $500 million. The i ncrease will support ongoing business requirements and general corporate purposes. On May 27, 2016, NSPI increased its commercial paper program to $500 million from $400 million, of which the full amount outstanding is backed by NSPI’s operating credit fa cility referred to above. The amount of commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable. ECI On November 29, 2016, ECI completed a senior, secured floating rate, non-revolving term loan of $150 million USD. The loan is for a five year term and matures on November 29, 2021. Interest is due semi-annually and is b ased on 6 month LIBOR plus 4.08 per cent weighted average . Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follow s: millions of Canadian dollars 2018 2019 2020 2021 2022 Thereafter Total Emera $ - $ 225 $ 133 $ - $ - $ 2,005 $ 2,363 Emera US Finance LP - 627 - 941 - 2,509 4,077 TECO Finance 314 - 376 - - - 690 Tampa Electric 319 - - 291 282 1,518 2,410 PGS 62 - - 59 31 176 328 NMGC - - - 251 - 88 339 NMGI - 63 - - - 188 251 NSPI - 95 - 364 - 1,965 2,424 Emera Maine 6 51 37 - 113 201 408 EBP - - - 248 - - 248 GBPC 12 15 45 22 31 41 166 BLPC and ECI 28 29 55 28 11 93 244 Total $ 741 $ 1,105 $ 646 $ 2,204 $ 468 $ 8,784 $ 13,948 |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATION | 26 . ASSET RETIREMENT OBLIGATIONS AROs mostly relate to the reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made. The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2017 2016 Balance, January 1 $ 170 $ 109 Additions (1) 2 48 Additions due to acquisition - 9 Liabilities settled (3) (2) Accretion included in depreciation expense 6 7 Accretion deferred to regulatory asset (included in property, plant and equipment) - (2) Other 1 1 Change in foreign exchange rate (4) - Balance, December 31 $ 172 $ 170 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2016 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed. As at December 31, 2017 and 2016 , some of the Company’s transmission and distribution assets may have additional conditional ARO which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. Management will continue to monitor these obligations and a liability will be recognized in the period in which an amount becomes determinable. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies [Abstract] | |
COMMITMENTS AND CONTINGENCIES | 27 . COMMITMENTS AND CONTINGENCIES Commitments As at December 31, 2017 , contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following: millions of Canadian dollars 2018 2019 2020 2021 2022 Thereafter Total Purchased power (1) $ 234 $ 216 $ 212 $ 209 $ 206 $ 2,148 $ 3,225 Transportation (2) 451 298 264 184 172 1,339 2,708 Fuel and gas supply 527 176 50 41 - - 794 Capital projects 413 88 - - - - 501 Long-term service agreements (3) 75 65 34 44 35 180 433 Equity investment commitments (4) 15 5 190 - - - 210 DSM 63 28 18 18 18 - 145 Leases and other (5) 43 12 10 7 4 61 137 $ 1,821 $ 888 $ 778 $ 503 $ 435 $ 3,728 $ 8,153 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. (4) Emera has a commitment in connection with the Federal Loan Guarantee to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction. (5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years. The UARB has approved NSPI to pay NSPML approximately $ 110 million and $ 111 million in 2018 and 2019, respectively. After 2019, the timing and amounts payable to NSPML will be subject to a regulatory filing with the UARB which will be filed no later than 2019 and closer to the timing of the Muskrat Falls project completion. Legal Proceedings Emera Florida and New Mexico TECO Coal TECO Coal was sold by TECO Energy on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”), prior to Emera’s acquisition of TECO Energy. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified. The claim asserted breach of certain representations, and fraud and willful misconduct in connection therewith, of the Securities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambria n related to the purchase of TECO Coal by Cambrian. While the outcome of such matter is uncertain, management does not believe its ultimate resolution will have a material adverse effect on the Company’s results of operations, financial condition or cash f lows. TECO Guatemala Holdings (“TGH”) In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatema la) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus intere st from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was orde red to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional int erest on the $ 21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding. On September 23, 2016, TGH filed a request for resubmission to arbitration. On October 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission. A new tribunal has been constituted and it issued its first procedural order. TGH’s memorial was filed on September 1, 2017. Guatemala’s counter-memorial was filed on February 2, 2018. In addition, TGH has sued Guat emala in Washington, D.C. court to enforce the $21 million USD due and owing. Results to date do not reflect any benefit. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a potentially responsible pa rty (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2017 , TEC has estimated its ultimate financial liability to be $ 38 million ($ 30 million USD), primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these si tes are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are li kely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates inclu de the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or ch anges in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. The FPSC has approved, as part of the PGS depreciation se ttlement, an agreement to accelerate the amortization of the regulated asset associated with this reserve . Emera Maine From 2011 to 2016, four separate complaints have been filed with the FERC to challenge the ISO-New England Open Access Transmission Tari ff-allowed based ROE. The first complaint, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, has been remanded to the FERC by the US Court of Appeals for further pro ceedings. A decision by FERC on the second and third complaints, brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively (“the ENE and MA AG II Cases”), is expected in 2018. The four th complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”). Emera Maine has recorded a reserve of $ 4 million USD for the ENE and MA AG II Cases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Bal ance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome. No reserve has been made in relation to the fir st complaint or the EMCOS complaint due to the uncertainty of the outcomes. Other Legal Proceedings Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. Principal Financial Risks and Uncertainties In this section, Emera describes some of the principal financial risks management believes could materially affect the Company in the normal course of business . Risks associated with derivative i nstruments and fair value measurements are discussed further in note 14 and note 15 . Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk ma nagement process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management . Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates globally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and projects. The regulatory framework for the Company’s rate-regulated subsidiaries per mits the recovery of prudently incurred costs, including foreign exchange. The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes, or to hedge the value of its investments in foreign subsidiaries . Exchange gains and losses on net investments in foreign su bsidiaries are included in AOCI. Capital Market and Liquidity Risk Emera’s operations and projects in development require significant capital investments in property, plant and equipment. Conseq uently, Emera is an active participant in the debt and equity markets. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events thro ughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera is subject to financial risk associated with changes in it s credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A change to a credit rating as a result of changes in any of these items could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit th e availability of adequate credit support for subsidiary operations. Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated ca sh flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs. Interest Rate Risk Emera utilizes a combination of fixed and floating rate debt finan cing for operations and capital expenditures , resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Compa ny will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. While regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates , albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. Commodity Price Risk A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be ex posed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractua l protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regul ated subsidiaries permits the recovery of prudently incurred fuel costs. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such chang es could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Although a reduct ion in the corporate income tax rate could result in lower future tax expense and tax payments, it would also reduce the value of the Company’s existing deferred tax assets and could result in a charge to earnings if written down. US tax reform legislatio n was enacted on December 22, 2017. Although some of the specific details have yet to b e clarified, this legislation has had a negative impact on the Company’s 2017 financial results. Refer to the note 9 for further details. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. Guarantees and Letters of Credit As at December 31 , 2017, Emera had several significant guarantees and letters of credit on behalf of third parties outstanding. The following guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2017 . TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate g overnmental entities. As each application is approved, Cambrian is required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at December 31, 2017, TECO Ener gy had remaining indemnified bonds totaling $ 6 million ($ 5 million USD). The amounts outlined above represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. The C ompany is working with Cambrian on the process to replace the remaining bonds. Pursuant to the securities purchase agreement, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained. As at December 31, 2017, Emera ha s a standby letter of credit in the amount of $ 21 million for the benefit of NSP Maritime Link Inc. (“NSPML”) to guarantee the performance of the obligations of the EUS-Rokstad joint venture. Rokstad Power has issued a separate letter of credit for the benefit of Emera for their portion of the work to be performed under the contract. EUS-Rokstad is a joint venture b etween EUS and Rokstad Power, formed for the purpose of constructing the high voltage direct current components of NSPML’s transmission line. EUS and Rokstad Power are jointly and severally liable for completion of the project. Subsequent to year end, N SPML has drawn the full amount of the letter of credit, which was funded without recourse to Emera. Emera has standby letters of credit in the amount of $ 28 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required. Emera Reinsurance Limited has issued a standby letter of credit to secure its obligations under reinsurance agreements. The letter of credit expires in December 2018 and is renewed annually . The amount committed as of December 31, 2017 was $ 6 million USD. Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under an unfunded pension plan. The letter of credit expires in June 2018 and is renewed annually. The amount committed as at December 31, 2017 was $ 51 million. Collaborative Arrangement s For the years ended December 31, 2017 and 2016 , the Company has identified the following material collaborative arrangements: Through NSPI, t he Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G expenses. In 2017, NSPI rec ognized $18 million net expense (2016 - $18 million) in “Regulated fuel for generation and purchased power” and $3 million (2016 - $5 million) in OM&G . |
Cumulative Preferred Stock
Cumulative Preferred Stock | 12 Months Ended |
Dec. 31, 2017 | |
Cumulative Preferred Stock [Abstract] | |
CUMULATIVE PREFERRED STOCK | 28 . CUMULATIVE PREFERRED STOCK Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2017 December 31, 2016 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 3,864,636 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 2,135,364 $ 52 2,135,364 $ 52 Series C $ 1.0250 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 26.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0625 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Total 29,000,000 $ 709 29,000,000 $ 709 The First Preferred Shares, Series A, C and F are entitled to receive fixed cumulative cash dividends as and when declared by the Board of Directors of the Corporation in the amounts of $ 0.6388 , $ 1.025 and $ 1.0625 per share per annum, respectively for each year up to and excluding August 15, 2020, August 15, 2018, and February 15, 2020, respectively. As at August 15, 2020, August 15, 2018, and February 15, 2020, the holders of the First Preferred Shares Series A, C and F, respectively, are entitled to receive reset fixed cumulative cash dividends. The reset annual dividend per share will be determined by multiplying $ 25.00 per share by the annual fixed dividend rate of the First Preferred Shares, Series A, C and F , respectively, which is the sum of the five-year Government of Canada Bond - Yield on the application reset date plus 1.84 per cent, 2.65 per cent, and 2.63 per cent, respectively. The First Preferred Shares, Series B, are entitled to receive floating rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation in the amount determined by multiplying $ 25.00 by the three month Government of Canada Treasury Bill rate plus 1.84 per cent. The 2017 dividends for the Series B shares were $ 0.6032 per share ( 2016 – $ 0.5724 ). The First Preferred Shares, Series E, are entitled to receive fixed rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation in the amount $1.1250 per share per annum. The holders of First Preferred Shares, Series A, C and F will have the right, at their option, to convert their shares into an equal number of Cumulative Floating Rate First Preferred Shares, Series B, D, and G, of the Company, respectively, on Au gust 15, 2020 , August 15, 2018, and February 15, 2020, respectively, and every five years thereafter. The holders of the First Preferred Shares, Series B will have the right, at their option, to convert their shares into an equal number of Series A shares of the Company on August 15, 2020 and every five years thereafter. The Company has the right to redeem the outstanding Preferred Shares, Series A, C, and F shares without the consent of the holder on August 15, 2020, August 15, 2018, and February 15, 202 0 respectivel y and on August 15, August 15 and February 15 respectively every five years thereafter for cash, in whole or in part at a price of $ 25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. The Company has the right to redeem the outstanding Preferred Shares, Series B, Series D and Series G shares without the consent of the holder on August 15, 2020, August 15, 2023 and February 15, 2025 respectively and on August 15, August 15 and February 15 e very five years thereafter for cash, in whole or in part at a price of $ 25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $ 25.50 per share plus all accrued and unpaid dividends up to but excluding t he date fixed for redemption in the case of redemptions on any other date after August 15, 2015, August 15, 2018 and February 15, 2020, respectively. The Company has the right to redeem the outstanding First Preferred Shares, Series E on or after August 1 5, 2018 in whole or in part, at the Company’s option, by the payment in cash of $ 26.00 per Series E Preferred Share if redeemed prior to August 15, 2019; at $ 25.75 per Series E Preferred Share if redeemed on or after August 15, 2019, but prior to August 15 , 2020; at $ 25.50 per Series E Preferred Share if redeemed on or after August 15, 2020, but prior to August 15, 2021; at $ 25.25 per Series E Preferred Share if redeemed on or after August 15, 2021, but prior to August 15, 2022; and at $ 25.00 per Series E P referred Share if redeemed on or after August 15, 2022, in each case together with all accrued and unpaid dividends up to but excluding the date fixed for redemption. As the First Preferred Shares, Series A, B, C, E and F are neither redeemable at the op tion of the shareholder nor have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the C onsolidated S tatements of Income immediately before arriving at “Net earnings attributable to common sharehold ers” and will be shown on the C onsolidated S tatement of E quity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First P referred Shares of every other series and are entitled to a preference over t he Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the l iquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares , for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in Sub
Non-Controlling Interest in Subsidiaries | 12 Months Ended |
Dec. 31, 2017 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Noncontrolling Interest Disclosure [Text Block] | 29. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 ICDU $ 52 $ 53 Preferred shares of GBPC 19 34 Domlec 21 25 $ 92 $ 112 Preferred shares of GBPC: Authorized: 35,000 non-voting cumulative redeemable variable perpetual preferred shares 2017 2016 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 20,000 $ 19 35,000 $ 34 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: On December 12, 2017, GBPC redeemed 15,000 perpetual preferred shares at $1,000 Bahamian per share. The Preferred Stock is redeemable by GBPC , in whole at any time or in part from time to time , at $ 1,000 Bahamian per share plus accrued and unpaid dividends. The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016 , 8.50 per cent per annum fixed cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue. The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock and ahead of all of GBPC’s current and future common stock. |
Supplemental Information to Con
Supplemental Information to Consolidated Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS | 30 . SUPPLEMENTARY INFORMATIO N TO CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year ended December 31 millions of Canadian dollars 2017 2016 Changes in non-cash working capital: Receivables, net $ (176) $ (104) Income taxes receivable 8 (23) Inventory 31 88 Prepayments and other current assets 14 (18) Accounts payable 3 162 Income taxes payable (17) 14 Other current liabilities 33 15 Total non-cash working capital $ (104) $ 134 Supplemental disclosure of cash paid: Interest $ 689 $ 480 Income taxes $ 63 $ 57 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 166 $ 103 Beneficial Conversion Feature of the convertible debentures $ - $ 43 |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Stock-Based Compensation [Abstract] | |
STOCK-BASED COMPENSATION | 31 . S TOCK-BASED COMPENSATION EMPLOYEE COMMON S HARE PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN Eligible employees may participate in Emera’s Employee Common Share Purchase Plan to which employees make cash contributions of a minimum of $ 25 to a maximum of $ 8,000 per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employee s’ contributions. If an employee contributes any am ount up to $ 3,000 to employees p lan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $ 3,000 , up to the $ 8,000 maximum, the Company will contribu te 10 per cent of that amount. The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common shares. The Company also has a Common Shareholders Dividend Rein vestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and for the purpose of purchasing common shares. This plan pr ovides for a discount of up to 5 per cent from the average m arket price of Emera’s common shares for common shares purchased in connection with th e reinvestment of cash dividend . Compensation cost for shares issued by Emera for the year ended December 31, 2017 under the Employee Common Share Purchase Plan was $ 1 million ( 2016 – $ 1 million) and is included in “Opera ting, maintenance and general” on the Consolidated Statements of Income. STOCK-BASED COMPENSATION PLANS Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares. All options granted to date are exercisable on a graduated basis with up to 25 per cent of options exercisable on the first anniversary date and further 25 per cent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is grante d. If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the 24 months following the date the optionee retires, but in any case prior to the expiry of the option in accordance with its terms. If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the six months following the date the optionee is terminat ed, resigns or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms. The Company uses the fair value based method to measure the compensation expense related to its stock-based compensation and recognizes th e expense over the vesting period on a straight-line basis. The fair value of stock option awards granted was estimated on the date of grant using a Black-Scholes valuation model. The expected term of the option awards is calculated based on historical e xercise behaviour and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the Bank of Canada five-year government bond yields. The expected dividend yield incorporates current dividend rates as well as historical dividend increase patterns. Emera’s expected stock price volatility was estimated using its five -year historical volatility. The fol lowing table shows the weighted average fair values per stock option along with the assumptions in corporated into the valuation models for options granted: For the year ended December 31, 2017 2016 Weighted average fair value per option $ 2.37 $ 2.80 Expected term 5 years 5 years Risk-free interest rate 1.22 % 0.66 % Expected dividend yield 4.60 % 4.08 % Expected volatility 14.41 % 15.45 % The following table summarizes information related to the stock options for 2017 : Total Options Non-Vested Options (1) Number of Options Weighted average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2016 2,920,000 $ 37.42 1,520,125 $ 2.69 Granted 827,400 45.16 827,400 2.37 Exercised (103,825) 28.91 N/A N/A Forfeited - - (607,875) 2.73 Options outstanding December 31, 2017 3,643,575 $ 39.42 1,739,650 $ 2.52 Options exercisable December 31, 2017 (2)(3) 1,903,925 $ 35.37 (1) As at December 31, 2017 there was $3 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.5 years (2016 - $3 million, 2.4 years). (2) As at December 31, 2017, the weighted average remaining term of vested options was 5.4 years with an aggregate intrinsic value of $22 million (2016 - 5.7 years, $17 million). (3) As at December 31, 2017 the fair value of options that vested in the year was $2 million (2016 - $2 million). Compensation cost recognized for stock options for the year ended December 31, 2017 was $ 2 m illion ( 2016 – $ 2 million) , which is included in “Operating, maintenance and general” on the Consolidated Statements of Income. As at December 31, 2017 , cash received from option exercises was $ 3 million ( 2016 – $ 16 million). The total intrinsic value of options exercised for the year ended December 31, 2017 was $ 2 million ( 2016 – $ 13 million). The range of exercise prices for the options outst anding as at December 31, 2017 was $ 21.58 to $ 46.19 ( 2016 – $ 20.42 to $ 46.19 ). Share Unit Plans The Company has deferred share unit (“DSU”) and performance share unit (“PSU”) plans. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, referred to as the D ividend Reinvestment Plan (“DRIP”), the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market valu e of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s accoun t by the average of Emera’s stock closing price during the ten trading days ending on the tenth trading day prior to the payment date. Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their ann ual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 % of the value of their actual annual incentive award ( 25 % in the first year of the program) will be pa yable in DSUs until the applicable guidelines are met. When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation da te. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares. In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives. A summary of the activity related to employee and director DSUs for the year ended December 31, 2017 is presented in the followi ng table: Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2016 680,931 $ 27.50 395,798 $ 33.88 Granted including DRIP 73,185 37.74 86,281 42.96 Exercised (2,482) 46.58 (9,486) 44.00 Forfeited (34) 46.58 (108) 45.39 Outstanding and exercisable as at December 31, 2017 751,600 $ 28.44 472,485 $ 35.33 Compensation cost recognized for employee and director DSU for the year ended December 31, 2017 was $ 7 million ( 2016 – $ 8 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2017 were $ 2 million ( 2016 – $ 3 million). Performance Share Unit Plan Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as DRIP. The PSU value varies according to the Emera common sh are market price and corporate performance. PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death. A summary of the activity related to employee PSUs for the year ended December 31, 2017 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2016 560,880 $ 37.55 $ 25.5 Granted including DRIP 519,789 44.35 Exercised (220,075) 30.67 Forfeited (30,596) 43.66 Outstanding as at December 31, 2017 829,998 $ 43.41 $ 41.1 Compensation cost recognized for the PSU plan for the year ended December 31, 2017 was $ 14 million ( 2016 – $ 11 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2017 were $ 4 million ( 2016 – $ 4 million). |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entities [Abstract] | |
VARIABLE INTEREST ENTITIES | 32 . VARIABLE INTEREST ENTITIES The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities. VIEs of which the company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obliga tion to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For the years ended, December 31, 2017 and 2016 , the Company has identified the following material VIEs: Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera i s not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q 2 2014, when the critical milestones were achieved , Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera began recording the Maritime Link Project as an equity investment. BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmissio n and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI . I n its determination that ECI controls the SIF, management considered that , in substance , the activities of the SIF are being conducted on behalf of ECI ’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, becaus e ECI , through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF . Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Investment securities”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC S IF. The Company has identified certa in long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary benefici ary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIE s: As at December 31, 2017 December 31, 2016 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets exposure to loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 510 $ 67 $ 315 $ 577 |
Comparative Information
Comparative Information | 12 Months Ended |
Dec. 31, 2017 | |
Comparative Information [Abstract] | |
COMPARATIVE INFORMATION | 33 . COMPARATIVE INFORMATION These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | 34 . SUBSEQUENT EVENTS These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 9, 2018, the date the financial statements were issued. |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ||
Condensed Financial Information of Parent Company Only Disclosure [Text Block] | 35 . SUPPLEMENTAL FINANCIAL INFORMATION On June 16, 2016, Emera US Finance LP, (in such capacity, the “Issuer”), issued $3.25 billion USD senior unsecured notes (“U.S. Notes”). The U.S Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera (in such capacity, the “Parent Company”) and EUSHI (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP. The following con densed consolidated financial statements present the results of operations, financial position and ca sh flows of the Parent Company , Subsidiary Issuer , Guarantor Subsidiaries and all other Non-guarantor Subsidiaries independently and on a consolidated basis. Our guarantors were not determined using geographic, service line or other similar criteria, and as a result, the “Parent ”, “Subsidiary Issuer”, “Gu arantor Subsidiaries ” and “Non-guarantor Subsidiaries” columns each include portions of our domestic and international operations. Accordingly, this basis of presentation is not intended to present our financial condition, results of operations or cash flows for any purpose other than to comply with the specific requ irements for guarantor reporting . Emera Incorporated C ondensed C o nsolidated Statements of Income For the year ended December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues $ - $ - $ 4,165 $ 2,118 $ (57) $ 6,226 Operating expenses 41 - 3,241 1,610 (57) 4,835 Income (loss) from operations (41) - 924 508 - 1,391 Income (loss) from equity investments in subsidiaries 336 - - - (336) - Income from equity investments 1 - 1 122 - 124 Intercompany income (expenses), net 92 195 (204) (45) (38) - Other income (expenses), net - - 16 (19) 5 2 Interest expense, net 138 155 242 163 - 698 Income (loss) before provision for income taxes 250 40 495 403 (369) 819 Income tax expense (recovery) (44) 17 511 36 - 520 Net income (loss) 294 23 (16) 367 (369) 299 Non-controlling interest in subsidiaries - - - 1 4 5 Preferred stock dividends 28 - 29 13 (42) 28 Net income (loss) attributable to common shareholders $ 266 $ 23 $ (45) $ 353 $ (331) $ 266 Comprehensive income (loss) of Emera Incorporated $ - $ 3 $ (392) $ 372 $ 17 $ - Emera Incorporated C ondensed C o nsolidated Statements of Income For the year ended December 31, 2016 Emera Incorporated Condensed Consolidated Balance Sheets As at December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Assets Current assets Cash and cash equivalents $ 276 $ 21 $ 47 $ 94 $ - $ 438 Restricted cash - - 1 64 - 65 Inventory - - 243 175 - 418 Derivative instruments 5 - 11 131 (6) 141 Regulatory assets - - 114 24 - 138 Intercompany receivables 74 9 4 108 (195) - Receivables and other current assets 3 - 546 777 - 1,326 Total current assets 358 30 966 1,373 (201) 2,526 Property, plant and equipment, net of accumulated depreciation 17 - 12,258 4,720 - 16,995 Other assets Deferred income taxes 70 - (10) 71 7 138 Derivative instruments 4 - 2 110 (4) 112 Regulatory assets - - 552 686 - 1,238 Net investment in direct financing lease - - 12 469 - 481 Investments in subsidiaries accounted for using the equity method 8,490 - - - (8,490) - Investments subject to significant influence 5 - 13 1,197 - 1,215 Goodwill - - 5,709 96 - 5,805 Intercompany notes receivable 1,140 4,285 1 955 (6,381) - Other investments - intercompany - - - 70 (70) - Other long-term assets 29 - 68 184 (20) 261 Total other assets 9,738 4,285 6,347 3,838 (14,958) 9,250 Total assets $ 10,113 $ 4,315 $ 19,571 $ 9,931 $ (15,159) $ 28,771 Emera Incorporated Condensed Consolidated Balance Sheets – Continued As at December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ - $ - $ 1,241 $ - $ - $ 1,241 Current portion of long-term debt - - 701 40 - 741 Accounts payable 9 - 620 532 - 1,161 Intercompany payable 55 6 90 74 (225) - Derivative instruments 5 - 52 175 (5) 227 Regulatory liabilities - - 91 136 (1) 226 Other current liabilities 60 6 137 147 - 350 Total current liabilities 129 12 2,932 1,104 (231) 3,946 Long-term liabilities Long-term debt 2,205 4,034 3,741 3,160 - 13,140 Intercompany long-term debt 656 - 4,582 1,139 (6,377) - Deferred income taxes - 4 435 565 7 1,011 Derivative instruments 4 - 4 79 (4) 83 Regulatory liabilities - - 1,889 353 - 2,242 Pension and post-retirement liabilities 21 - 341 197 - 559 Other long-term liabilities 9 - 267 352 (19) 609 Total long-term liabilities 2,895 4,038 11,259 5,845 (6,393) 17,644 Equity Common stock 5,601 242 4,311 2,136 (6,689) 5,601 Cumulative preferred stock 709 - 620 76 (696) 709 Contributed surplus 76 - 110 148 (258) 76 Accumulated other comprehensive income (loss) (188) (9) (36) (185) 230 (188) Retained earnings 891 32 375 735 (1,142) 891 Total Emera Incorporated equity 7,089 265 5,380 2,910 (8,555) 7,089 Non-controlling interest in subsidiaries - - - 72 20 92 Total equity 7,089 265 5,380 2,982 (8,535) 7,181 Total liabilities and equity $ 10,113 $ 4,315 $ 19,571 $ 9,931 $ (15,159) $ 28,771 Emera Incorporated Condensed Consolidated Balance Sheets – Continued As at December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ - $ - $ 948 $ 13 $ - $ 961 Current portion of long-term debt - - 436 40 - 476 Accounts payable 6 - 756 480 - 1,242 Intercompany payable 534 6 81 25 (646) - Derivative instruments 14 - 10 314 (13) 325 Regulatory liabilities - - 225 137 - 362 Other current liabilities 54 13 130 161 - 358 Total current liabilities 608 19 2,586 1,170 (659) 3,724 Long-term liabilities Long-term debt 2,338 4,314 4,687 2,929 - 14,268 Intercompany long-term debt 366 - 4,778 1,357 (6,501) - Deferred income taxes - 1 1,193 516 (38) 1,672 Derivative instruments 12 - - 150 (12) 150 Regulatory liabilities - - 973 304 - 1,277 Pension and post-retirement liabilities 17 - 433 219 - 669 Other long-term liabilities 13 - 274 377 (19) 645 Total long-term liabilities 2,746 4,315 12,338 5,852 (6,570) 18,681 Equity Common stock 4,738 242 4,177 3,997 (8,416) 4,738 Cumulative preferred stock 709 - 620 271 (891) 709 Contributed surplus 75 - 45 106 (151) 75 Accumulated other comprehensive income (loss) 106 10 340 (191) (159) 106 Retained earnings 1,076 9 420 610 (1,039) 1,076 Total Emera Incorporated equity 6,704 261 5,602 4,793 (10,656) 6,704 Non-controlling interest in subsidiaries - - - 78 34 112 Total equity 6,704 261 5,602 4,871 (10,622) 6,816 Total liabilities and equity $ 10,058 $ 4,595 $ 20,526 $ 11,893 $ (17,851) $ 29,221 Emera Incorporated Condensed Consolidated Statements of Cash Flows For the year ended December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) by operating activities $ 195 $ 22 $ 712 $ 1,125 $ (861) $ 1,193 Investing activities Additions to property, plant and equipment (5) - (1,031) (480) (13) (1,529) Net purchase of investments subject to significant influence, inclusive of acquisition costs - - - (213) - (213) Other intercompany investing activities (708) (26) 15 1,818 (1,099) - Other investing activities (34) - (20) 32 3 (19) Net cash provided by (used in) investing activities (747) (26) (1,036) 1,157 (1,109) (1,761) Financing activities Change in short-term debt, net - - 365 (13) - 352 Proceeds from long-term debt, net of issuance costs - - 147 (131) 113 129 Retirement of long-term debt - - (413) (55) 15 (453) Net borrowings (repayments) under committed credit facilities (30) - 21 233 6 230 Issuance of common stock, net of issuance costs 682 - 134 (1,837) 1,703 682 Issuance of preferred stock, net of issuance costs - - - (195) 195 - Dividends on common stock (287) - - (272) 272 (287) Dividends on preferred stock (28) - (29) (13) 42 (28) Dividends paid by subsidiaries to non-controlling interest - - - (2) (4) (6) Other financing activities 290 - 96 (40) (372) (26) Net cash provided by (used in) financing activities 627 - 321 (2,325) 1,970 593 Effect of exchange rate changes on cash and cash equivalents 1 (3) 2 (13) - (13) Net increase (decrease) in cash and cash equivalents 76 (7) (1) (56) - 12 Cash, cash equivalents and restricted cash, beginning of year 200 28 49 214 - 491 Cash, cash equivalents and restricted cash, end of year $ 276 $ 21 $ 48 $ 158 $ - $ 503 Emera Incorporated Condensed Consolidated Statements of Cash Flows For the year ended December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) operating activities $ 265 $ 29 $ 481 $ 107 $ 171 $ 1,053 Investing activities Acquisitions, net of cash acquired - - (8,409) - - (8,409) Additions to property, plant and equipment (2) - (673) (405) - (1,080) Net purchase of investments subject to significant influence, inclusive of acquisition costs - - - (276) - (276) Net proceeds on sale of investment subject to significant influence and held-for-trading common shares 665 - - - - 665 Other intercompany investing activities (2,348) (4,416) (18) (2,397) 9,179 - Other investing activities - - (3) 66 - 63 Net cash provided by (used in) investing activities (1,685) (4,416) (9,103) (3,012) 9,179 (9,037) Financing activities Change in short-term debt, net (14) - 122 (4) 14 118 Proceeds from long-term debt, net of issuance costs 2,037 4,187 4,516 764 (5,081) 6,423 Proceeds from convertible debentures represented by instalment receipts, net of issuance costs (44) - - 1,457 - 1,413 Retirement of long-term debt (250) - (6) (36) 19 (273) Net borrowings (repayments) under committed credit facilities (210) - - (99) (6) (315) Issuance of common stock, net of issuance costs 354 242 3,865 95 (4,202) 354 Issuance of preferred stock, net of issuance costs - - 195 - (195) - Dividends on common stock (221) - - (254) 254 (221) Dividends on preferred stock (28) - (31) (18) 49 (28) Dividends paid by subsidiaries to non-controlling interest - - - (2) (3) (5) Other financing activities - - (18) 185 (185) (18) Net cash provided by (used in) financing activities 1,624 4,429 8,643 2,088 (9,336) 7,448 Effect of exchange rate changes on cash and cash equivalents (4) (14) 7 (54) - (65) Net increase (decrease) in cash and cash equivalents 200 28 28 (871) 14 (601) Cash, cash equivalents and restricted cash, beginning of year - - 21 1,085 (14) 1,092 Cash, cash equivalents and restricted cash, end of year $ 200 $ 28 $ 49 $ 214 $ - $ 491 | Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues $ - $ - $ 2,494 $ 1,818 $ (35) $ 4,277 Operating expenses 39 - 2,127 1,591 (35) 3,722 Income (loss) from operations (39) - 367 227 - 555 Income (loss) from equity investments in subsidiaries 150 - - - (150) - Income from equity investments 18 - - 82 - 100 Intercompany income (expenses), net 203 101 (107) (151) (46) - Other income (expenses), net 135 - 24 15 - 174 Interest expense, net 226 85 127 147 - 585 Income (loss) before provision for income taxes 241 16 157 26 (196) 244 Income tax expense (recovery) (14) 7 48 (63) - (22) Net income (loss) 255 9 109 89 (196) 266 Non-controlling interest in subsidiaries - - - 7 4 11 Preferred stock dividends 28 - 31 19 (50) 28 Net income (loss) attributable to common shareholders $ 227 $ 9 $ 78 $ 63 $ (150) $ 227 Comprehensive income (loss) of Emera Incorporated $ 228 $ 19 $ 205 $ 59 $ (283) $ 228 |
Summary of Significant Accoun45
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Nature of Operations [Text Block] | Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution and gas transmission and distribution. Emera’s primary rate-regulated subsidiaries and investments at December 31, 2017 included the following: Emera Florida and New Mexico represents T ECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico which was acquired on July 1, 2016. TECO Energy’s holdings include: Tampa Electric Company (“TEC”), which holds the Tampa Electric Divi sion (“Tampa Electric”), an integrated regulated electric utility, serving approximately 750,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 375,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 525,000 customers across New Mexico; and TECO Finance, Inc. (“TECO Finance”), a wholly owned finan cing subsidiary of TECO Energy. Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 515,000 customers; Emera Maine, an electric transmission and distribution utility, serving approximately 158,000 customers in Maine; Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company that includes: The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 129,000 customers; a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited) in Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers. On November 8, 2017 , the minority shareholders of ICDU approved Emera’s acquisition of their common shares for total consideration of approximately $35 million USD. The acquisition of the minority shareholder common shares was completed on January 15, 2018, increasing Emera’ s indirect ownership interest in GBPC to 100 per cent; a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers. On September 19, 2017 Dominica took a direct hit from Hurrican e Maria, causing extensive damage across the island. Refer to note 16 for additional information ; and a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034; Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 82 4 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be generating first power in 2019 and full power in 2020. ENL’s two investments are: a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project completed commissioning and entered service o n January 15, 2018; and a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Mus krat Falls energy between Labrador and the island of Newfoundland. Nalcor Energy has indicated that the LIL will be in service in Q2 2018. a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. Emera also owns investments in other energy-related non-regulated companies, including: Emera Energy, consists of: Emera Energy Services, a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), 1,115 MW of com bined-cycle gas-fired electricity generating capacity in the northeastern United States; Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick; Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; and a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera; Emera US Finance LP, a wholly owned financing subsidiary of Emera; Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada; and other investments. |
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars, unless otherwise indicated. |
Consolidation, Policy [Policy Text Block] | Principles of Consolidation The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary . The consolidated financial statements include TECO Energy from the July 1, 2016 acquisition date through December 31, 2017 . The Company performs ongoing analysis to assess whether it holds any variable interest entities VIEs. To identify potential VIEs, management reviews contracts under leases, long-term p urchase power agreements, tolling contracts and jointly owned facilities. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using th e equity method. Inter company balances and inter company transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues . An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. |
Use of Estimates, Policy [Policy Text Block] | Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonab le at the time the assumption is made, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates. |
Regulatory Matters Policy [Policy Text Block] | Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover the costs of providing the regulated products or services and provide a reasonable rate of return on the equity invested or assets as applicable (refer to n ote 16 for additional details). |
Foreign Currency Transactions and Translations Policy [Policy Text Block] | Foreign Currency Translation Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain United States dollar d en omina ted debt held in Canadian functional currency companies as hedges of net investments in United States dollar denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sh eet date, and the effective portion of the hedge , is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings. |
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition Operating revenues are recognized when electricity or gas is delivered to customers or when products are delivered and services are rendered. Regulated revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity or gas is recognized at rates approved by t he respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis. At the end of each month, the electricity or gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes. Non-regulated revenues are recorded when products have been delivered or services have been p erformed, the amount of revenue can be reliably measured and collectability is reasonably assured . Revenues for energy marketing and trading operations are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers. The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income. Other revenues are recognized when services are performed or goods delivered. |
Property, Plant and Equipment, Policy [Policy Text Block] | Property, Plant and Equipment Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction. The cost of addi tions, including betterments and replacements of units of property, plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or dis posal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions oc cur. The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attribut able to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Exp enditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. D epreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable asset s in each functional class of de preciable property. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval. Intangible assets consist primarily of computer software, land rights and naming rights with definite lives. Amorti zation is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate regulated subsidiaries amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. The service lives of regulated intangible assets require the appropriate regulatory approval. |
Goodwill Policy [Policy Text Block] | Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment. Under the applicable accounting guidanc e, goodwill is subject to an annual assessment for impairment at the reporting unit level. Refer to note 22 for further detail. |
Income Tax, Policy [Policy Text Block] | Income Taxes and Investment Tax Credits Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Ba lance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realize d. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the bala nce at the amount expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credit s earned by TECO Energy and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by state regulatory practices. Emera’s rate-regulated subsidiaries recognize regulatory assets o r liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the reali zation of deferred income tax assets. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 9 for further details. |
Derivatives, Hedge Discontinuances [Policy Text Block] | Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial co ntracts are classified as held-for-trading (“HFT”). Collectively, these contracts are considered derivatives. The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal pur chases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to al low for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffectiv e portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to re gulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting fr om settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classi fies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are n ot offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets ” and obligations to return cash collateral are recognized in “Accounts payable”. |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash , Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. To tal short-term investments of $222 million have an effective interest rate of 1 .4 per cent at December 31, 2017 ( 2016 – $ 183 million with an effective interest rate of 0.6 per cent). Amounts included in restricted cash represent funds required to be set aside for the BLPC Self-Insurance Fund (notes 6 and 32 ). |
Receivables, Policy [Policy Text Block] | Receivables and Allowance for Doubtful Accounts Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balance s after the due date. The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains p rovisions for potential credit losses, which are assessed on a regular basis. Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the characteristics of existing acco unts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. |
Inventory, Policy [Policy Text Block] | Inventory Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the we ighted-average cost will be recovered in future custo mer rates. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency. |
Asset Retirement Obligations, Policy [Policy Text Block] | Asset Retirement Obligation s An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sal e of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flow s necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prio r experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is dep reciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved b y the regulator recorded in “Property, plant and equipment” and included in the next depreciation study. Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional AR O refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a l iability is recognized at fair value whe n an amount can be determined. Cost of Removal Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal as regulatory liabilities. The non-ARO costs of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment upon retirement. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and f uture expectations, including expected timing and estimated future cash outlays. |
Franchise Fees Gross Receipts Policy [Policy Text Block] | Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tam pa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statement of Income. |
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based met hod of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income. |
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block] | Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plan s on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets |
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block] | Asset Impairment Goodwill Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill . Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity chooses to bypass the qualitative assessment , a qu antitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded as a reducti on to goodwill and a charge to operating expense. Emera reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit, with interim impairment tests performed when impairment indicators are present. Refer to note 22 fo r further detail . Cost and Equity Method Investments The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a ch arge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value. Financial Assets The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, a n other than temporary decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt s ecurities classified as available-for-sale, a breach of contract , such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidenc e exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOC I and recognized in the Consolidated Statements of Income. |
Summary of Significant Accoun46
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Schedule of Finite-Lived Intangible Assets [Table Text Block] | Computer software 3 to 15 Land rights 50 to 143 Naming rights 1 to 24 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] |
Acquisition (Tables)
Acquisition (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions [Abstract] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | millions of Canadian dollars Purchase Consideration $ 8,447 Fair value assigned to net assets: Current assets (1) $ 619 Regulatory assets (including current portion) 624 Property, plant and equipment, net 10,023 Other long-term assets 71 Current liabilities (747) Assumed long-term debt (including current portion) (5,409) Regulatory liabilities (including current portion) (1,117) Deferred income taxes (800) Pension and post-retirement liabilities (including current portion) (480) Other long-term liabilities (146) $ 2,638 Cash and cash equivalents 38 Fair value of net assets acquired $ 2,676 Goodwill $ 5,771 (1) Includes accounts receivables with fair value of $334 million comprised of gross contract value of $337 million, and $3 million of contractual receivables not expected to be collected. |
Business Combination, Segment Allocation [Table Text Block] | Goodwill has been allocated to the TECO Energy reporting units as follows: millions of Canadian dollars Reporting Unit Goodwill Tampa Electric $ 4,552 PGS 744 New Mexico Gas 475 Goodwill $ 5,771 |
Business Combination, Separately Recognized Transactions [Table Text Block] | For the Year ended millions of Canadian dollars December 31 2017 2016 Operating revenues – regulated gas $ - $ (10) Operating, maintenance, and general - 89 Interest expense, net - 148 Other income (expenses), net - (3) Income tax expense (recovery) - (84) Acquisition related costs $ - $ 166 |
Business Acquisition, Pro Forma Information [Table Text Block] | For the millions of Canadian dollars Year ended December 31, 2016 Pro forma operating revenues $ 6,034 Pro forma net income attributable to common shareholders $ 386 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Information [Abstract] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2017 Operating revenues from external customers (1) $ 3,623 $ 1,335 $ 297 $ 434 $ 451 $ 86 $ - $ 6,226 Inter-segment revenues (1) - 3 - - 14 41 (58) - Total operating revenues 3,623 1,338 297 434 465 127 (58) 6,226 Allowance for funds used during construction - debt and equity 5 8 3 - - - - 16 Regulated fuel and fixed cost deferral adjustments - 59 - - - - - 59 Depreciation and amortization 500 207 47 51 48 3 - 856 Interest expense (2) 248 134 20 25 2 276 - 705 Internally allocated interest (3) - - - - (24) 24 - - Income from equity investments - - 1 3 24 96 - 124 Income tax expense (recovery) 529 - 27 - 18 (54) - 520 Net income attributable to common shareholders 99 129 46 31 93 (132) - 266 Capital expenditures 910 385 82 72 47 26 - 1,522 As at December 31, 2017 Total assets 17,216 4,979 1,505 1,251 1,575 2,331 (86) 28,771 Investments subject to significant influence - - 13 39 - 1,163 - 1,215 Goodwill 5,566 - 143 96 - - - 5,805 (1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Interest expense net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $24 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (3) Segment net income is reported on a basis that includes internally allocated financing costs. Emera Florida Corporate Inter- and New Emera Emera Emera and segment millions of Canadian dollars Mexico (2) NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2016 Operating revenues from external customers (1) $ 1,839 $ 1,354 $ 297 $ 419 $ 298 $ 69 $ - $ 4,276 Inter-segment revenues (1) - 2 - - 11 24 (36) 1 Total operating revenues 1,839 1,356 297 419 309 93 (36) 4,277 Allowance for funds used during construction - debt and equity 28 6 1 - - - - 35 Regulated fuel and fixed cost deferral adjustments - 61 - - - - - 61 Depreciation and amortization 243 197 51 48 45 4 - 588 Interest expense (3) 125 127 19 15 1 311 - 598 Internally allocated interest (4) - - - - (24) 24 - - Income from equity investments - - - 3 11 86 - 100 Income tax expense (recovery) 100 12 23 14 (53) (118) - (22) Net income attributable to common shareholders 172 130 47 100 (110) (112) - 227 Capital expenditures 547 304 85 87 39 7 - 1,069 As at December 31, 2016 Total assets 18,016 4,776 1,543 1,331 1,702 1,966 (113) 29,221 Investments subject to significant influence - - 13 39 - 895 - 947 Goodwill 5,957 - 154 102 - - - 6,213 (1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. (2) Financial results of Emera Florida and New Mexico are from July 1, 2016, the date of the acquisition. (3) Interest expense net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $13 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy. (4) Segment net income is reported on a basis that includes internally allocated financing costs. Geographical Information Revenues(1): For the Year ended December 31 millions of Canadian dollars 2017 2016 Canada $ 1,464 $ 1,510 United States 4,328 2,348 Barbados 280 254 The Bahamas 119 121 Dominica 35 44 $ 6,226 $ 4,277 (1) Revenues are based on country of origin of the product or service sold Property Plant and Equipment: As at December 31 December 31 millions of Canadian dollars 2017 2016 Canada $ 3,995 $ 3,791 United States 12,257 12,724 Barbados 408 416 The Bahamas 276 295 Dominica 59 64 $ 16,995 $ 17,290 |
INVESTMENTS SUBJECT TO SIGNIF49
INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Investments Subject to Significant Influence and Equity Earnings [Abstract] | |
Equity Method Investments [Table Text Block] | Investments subject to significant influence consisted of the following: Equity Income Percentage Carrying Value For the year ended of millions of Canadian dollars As at December 31 December 31 Ownership 2017 2016 2017 2016 2017 NSPML $ 510 $ 315 $ 36 $ 21 100.0 LIL (1) 492 400 37 24 49.5 M&NP (2) 156 175 23 23 12.9 Lucelec (2) 39 39 3 3 19.1 Bear Swamp (3) - - 23 11 50.0 APUC (4) - - - 18 - Other Investments 18 18 2 - $ 1,215 $ 947 $ 124 $ 100 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. (2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position, primarily a result of a $179 million distribution received in Q4 2015. Bear Swamp's credit investment balance of $188 million (2016 - $217 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. (4) In two separate transactions in 2016, Emera sold a total of 63 million common shares in APUC. Emera no longer holds any interest in APUC. Equity investments include a $13 million difference between the cost and the underlying fair value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill. |
Variable Interest Investment As An Equity Investment Consolidated Summarized Balance Sheet [Table Text Block] | Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2017 2016 Balance Sheets Current assets $ 225 $ 439 Property, plant and equipment 1,720 1,132 Non-current assets 74 276 Total assets $ 2,019 $ 1,847 Current liabilities $ 180 $ 219 Long-term debt 1,287 1,288 Non-current liabilities 42 25 Equity 510 315 Total liabilities and equity $ 2,019 $ 1,847 |
Other Income (Expenses), Net (T
Other Income (Expenses), Net (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Income (Expenses), Net [Abstract] | |
Interest and Other Income [Table Text Block] | Other income (expenses), net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2017 2016 Gain on sale of APUC common shares (note 6) $ - $ 160 Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC (note 6) - 63 Gain on BLPC Self-Insurance Fund ("SIF") regulatory liability (1) - 53 Foreign exchange (losses) gains and mark-to-market adjustments related to the TECO Energy acquisition (2) - (135) Other 2 33 $ 2 $ 174 (1) In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $22 million USD. As a result, Emera reduced the SIF regulatory liability to $30 million ($22 million USD) and recorded a pre-tax gain of $53 million (after-tax gain of $43 million). (2) Mark-to-market adjustments included in Emera’s other income related to the effect of TECO Energy convertible debenture related USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion 4 per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the TECO Energy acquisition. |
Interest Expense, Net (Tables)
Interest Expense, Net (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Interest Income (Expense), Net [Abstract] | |
Interest Income and Interest Expense Disclosure [Table Text Block] | Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest on debt $ 663 $ 443 Beneficial conversion feature (note 10) - 62 Interest on Convertible Debentures (note 10) - 65 Interest on acquisition credit facility related to the TECO Energy acquisition (note 4) - 11 Allowance for borrowed funds used during construction (7) (13) Other 42 17 $ 698 $ 585 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Taxes [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The income tax provision, for the years ended December 31, differs from that computed using the statutory income tax rate for the following reasons: millions of Canadian dollars 2017 2016 Income before provision for income taxes $ 819 $ 244 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rate 254 76 Revaluation of US non-regulated deferred income taxes 317 - Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (54) (47) Foreign tax rate variance 36 (5) Financing deductions (17) (17) Tax effect of equity earnings (12) (10) Manufacturing and investment allowances (8) (7) Non-taxable portion of gains on APUC transactions - (34) Non-deductible portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition - 21 Other 4 1 Income tax expense (recovery) $ 520 $ (22) Effective income tax rate 63% (9%) |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | millions of Canadian dollars 2017 2016 Current income taxes Canada $ 24 $ 13 United States 24 18 Other 3 15 Deferred income taxes Canada 3 (113) United States 384 151 Other (1) - Operating loss carry forwards Canada (40) (2) United States (194) (104) Revaluation of US non-regulated deferred income taxes United States 317 - Income tax expense (recovery) $ 520 $ (22) The following reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of Canadian dollars 2017 2016 Canada $ 88 $ 71 United States 693 44 Other 38 129 Income before provision for income taxes $ 819 $ 244 |
Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block] | The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of Canadian dollars 2017 2016 Deferred income tax assets: Tax loss carry forwards $ 853 $ 1,036 Tax credit carry forwards 314 318 Regulatory liabilities - cost of removal 208 388 Pension and post-retirement liabilities 124 153 Derivative instruments 107 150 Other 394 490 Total deferred income tax assets before valuation allowance 2,000 2,535 Valuation allowance (105) (58) Total deferred income tax assets after valuation allowance $ 1,895 $ 2,477 Deferred income tax (liabilities): Property, plant and equipment $ (2,321) $ (3,553) Derivative instruments (155) (202) Other (292) (269) Total deferred income tax liabilities $ (2,768) $ (4,024) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 138 $ 125 Long-term deferred income tax liabilities (1,011) (1,672) Net deferred income tax liabilities $ (873) $ (1,547) |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | millions of Canadian dollars 2017 2016 Canada NOL $ 532 $ 199 Capital loss 77 77 United States Federal NOL $ 2,926 $ 2,595 State NOL 1,271 1,183 Capital loss 13 14 Tax credit 314 318 Other NOL $ 29 $ 22 |
Summary of Tax Credit Carryforwards [Table Text Block] | The following table summarizes as at December 31, 2017 the deferred tax assets associated with NOL, capital loss and tax credit carry forwards and the associated expiration periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain: Deferred Tax Valuation Net Deferred Expiration millions of Canadian dollars Asset Allowance Tax Asset Period Canada NOL $ 164 $ (80) $ 84 2027-2037 Capital loss 16 (16) - Indefinite United States Federal NOL $ 602 $ - $ 602 2024-2037 State NOL 65 (2) 63 2024-2037 Capital loss 2 (2) - 2018-2019 Tax credit 314 - 314 2019-Indefinite Other NOL $ 4 $ (4) $ - 2018-2024 |
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | millions of Canadian dollars 2017 2016 Balance, January 1 $ 18 $ 6 Increases due to tax positions related to current year 1 12 Balance, December 31 $ 19 $ 18 |
Common Stock (Tables)
Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Common Stock [Abstract] | |
Schedule of Common Stock Outstanding Roll Forward [Table Text Block] | Authorized : Unlimited number of non-par value common shares. 2017 2016 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, December 31, 2016 210.02 $ 4,738 147.21 $ 2,157 Conversion of Convertible Debentures (1) 0.15 6 51.99 2,115 Issuance of common stock (2) 14.61 680 7.69 338 Issued for cash under Purchase Plans at market rate 3.89 182 2.51 115 Discount on shares purchased under Dividend Reinvestment Plan - (9) - (5) Options exercised under senior management share option plan 0.10 3 0.62 17 Employee share purchase plan - 1 - 1 Balance, December 31 2017 228.77 $ 5,601 210.02 $ 4,738 (1) As at December 31, 2017, a total of 52.14 million common shares of the Company were issued, representing conversion into common shares of more than 99.9% of the Convertible Debentures. (2) On December 28, 2017, Emera completed an offering of 14.6 million common shares, at $47.90 per common share, for gross proceeds of approximately $700 million. The net proceeds were $680 million after $20 million of issuance costs, net of taxes. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of Canadian dollars (except per share amounts) 2017 2016 Numerator Net income attributable to common shareholders $ 266.1 $ 227.2 Convertible Debentures - 0.2 Diluted numerator 266.1 227.4 Denominator Weighted average shares of common stock outstanding 212.3 170.4 Weighted average deferred share units outstanding 1.1 1.0 Weighted average shares of common stock outstanding – basic 213.4 171.4 Stock-based compensation 0.6 0.6 Convertible Debentures 0.1 0.2 Weighted average shares of common stock outstanding – diluted 214.1 172.2 Earnings per common share Basic $ 1.25 $ 1.33 Diluted $ 1.24 $ 1.32 |
Accumulated Other Comprehensi55
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The components of accumulated other comprehensive income are as follows: millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available-for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2017 Balance, January 1, 2017 $ 486 $ (49) $ (21) $ (1) $ (309) $ 106 Other comprehensive income (loss) before reclassifications (457) 97 10 5 - (345) Amounts reclassified from accumulated other comprehensive income loss - - 8 (1) 44 51 Net current period other comprehensive income (loss) (457) 97 18 4 44 (294) Other - - - - - - Balance, December 31, 2017 $ 29 $ 48 $ (3) $ 3 $ (265) $ (188) millions of Canadian dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges (Losses) gains on derivatives recognized as cash flow hedges Net change on available-for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2016 Balance, January 1, 2016 $ 490 $ - $ (35) $ - $ (318) $ 137 Other comprehensive income (loss) before reclassifications 35 (49) 11 3 - - Amounts reclassified from accumulated other comprehensive income loss (gain) - - 11 (4) 12 19 Equity method reclassification adjustments (35) - (8) - (3) (46) Net current period other comprehensive income (loss) - (49) 14 (1) 9 (27) Other (4) - - - - (4) Balance, December 31, 2016 $ 486 $ (49) $ (21) $ (1) $ (309) $ 106 |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2017 2016 Affected line item in the Consolidated Financial Statements Amounts reclassified from AOCI Equity method reclassification adjustments Investments subject to significant influence $ - $ 54 Total before tax - 54 Deferred income taxes - (8) Total net of tax $ - $ 46 Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (3) $ (2) Interest rate swaps Income from equity investments - 1 Foreign exchange forwards Operating revenue - regulated 10 12 Total before tax 7 11 Income tax recovery (expense) 1 - Total net of tax $ 8 $ 11 Net change in available-for-sale investments Other income (expenses), net $ (1) $ (4) Total before tax (1) (4) Income tax recovery (expense) - - Total net of tax $ (1) $ (4) Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) Operating, maintenance and general (“OM&G”) $ 40 $ 41 Past service costs (gains) OM&G (8) (9) Amounts reclassified into obligations Pension and post-retirement benefits 11 (17) Total before tax 43 15 Income tax recovery (expense) 1 (3) Total net of tax $ 44 $ 12 Total reclassifications out of AOCI, net of tax, for the period $ 51 $ 65 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Inventory [Abstract] | |
Schedule of Inventory, Current [Table Text Block] | 13. INVENTORY Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Fuel $ 180 $ 235 Materials 216 215 Emission credits (1) 22 22 $ 418 $ 472 (1)The NEGG Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative for carbon dioxide emissions. The emissions credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments [Abstract] | |
Schedule of Derivative Instruments [Table Text Block] | Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2017 2016 2017 2016 Cash flow hedges Power swaps $ 5 $ 10 $ 2 $ 5 Foreign exchange forwards 2 - 5 22 7 10 7 27 Regulatory deferral Commodity swaps and forwards Coal purchases 137 83 10 9 Power purchases 5 7 3 4 Natural gas purchases and sales 6 33 7 2 Heavy fuel oil purchases 15 10 4 7 Foreign exchange forwards 32 106 4 - 195 239 28 22 HFT derivatives Power swaps and physical contracts 125 47 162 71 Natural gas swaps, futures, forwards, physical contracts 105 111 294 484 230 158 456 555 Other derivatives Interest rate swap 2 - - 1 Foreign exchange forwards - - - 1 2 - - 2 Total gross current derivatives 434 407 491 606 Impact of master netting agreements with intent to settle net or simultaneously (181) (131) (181) (131) 253 276 310 475 Current 141 145 227 325 Long-term 112 131 83 150 Total derivatives $ 253 $ 276 $ 310 $ 475 Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts. |
Offsetting Liabilities [Table Text Block] | Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of Canadian dollars 2017 2016 2017 2016 Regulatory deferral $ 14 $ 10 $ 14 $ 10 HFT derivatives 167 121 167 121 Total impact of master netting agreements with intent to settle net or simultaneously $ 181 $ 131 $ 181 $ 131 |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Realized gain (loss) in non-regulated fuel for generation and purchased power 3 - - 2 - - Realized gain (loss) in operating revenue – Regulated - - (10) - - (12) Realized gain (loss) in income from equity investments - - - - (1) - Total gains (losses) in Net income $ 3 $ - $ (10) $ 2 $ (1) $ (12) As at December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign Power rate exchange Power rate exchange swaps swaps forwards swaps swaps forwards Total unrealized gain (loss) in AOCI – effective portion, net of tax $ - $ - $ (3) $ 2 $ - $ (22) The Company expects $5 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle. As at December 31, 2017, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2018 2019 2020 2021 2022 Foreign exchange forwards (USD) sales $ 45 $ 30 $ 30 $ - $ - |
Schedule Of Regulatory Deferred Gain Losses Derivatives [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Commodity swaps and forwards Physical natural gas purchases and sales Foreign exchange forwards Unrealized gain (loss) in regulatory assets $ (33) $ (1) $ (4) $ 40 $ - $ (2) Unrealized gain (loss) in regulatory liabilities 83 1 (30) 101 (1) (30) Realized (gain) loss in regulatory assets - - - - - 12 Realized (gain) loss in regulatory liabilities (2) - - - - (8) Realized (gain) loss in inventory (1) (17) - (30) 5 - (44) Realized (gain) loss in regulated fuel for generation and purchased power (2) (3) - (14) 17 (1) (18) Total change derivative instruments $ 28 $ - $ (78) $ 163 $ (2) $ (90) (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable. |
Schedule Of Regulatory Commody Swaps Forwards [Table Text Block] | 2018 2019-2021 millions Purchases Purchases Coal (metric tonnes) 1 1 Natural Gas (Mmbtu) 30 14 Heavy fuel oil (bbls) - 1 2018 2019-2020 Foreign exchange contracts (millions of US dollars) $ 144 $ 156 Weighted average rate 1.1061 1.2001 % of USD requirements 79% 40% The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required. |
Unrealized Gain (Loss) on Investments [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 Power swaps and physical contracts in non-regulated operating revenues $ 7 $ (1) Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 401 69 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 10 (7) Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power 2 - Foreign exchange options in other income (expenses), net - (2) $ 420 $ 59 |
Offsetting Liabilities Expected To Settle [Table Text Block] | millions 2018 2019 2020 2021 2022 Natural gas purchases (Mmbtu) 325 134 62 44 41 Natural gas sales (Mmbtu) 250 56 21 8 2 Power purchases (MWh) 7 2 - - - Power sales (MWh) 8 1 - - - Foreign exchange options (USD) $ 2 $ 4 $ - $ - $ - |
Derivative Documentation Unmet [Table Text Block] | Other Derivatives The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met: For the Year ended December 31 millions of Canadian dollars 2017 2016 Interest Foreign Interest Foreign rate exchange rate exchange swaps forwards swaps forwards Realized gain (loss) in other income (expense) $ - $ - $ - $ (87) Unrealized gain (loss) in interest expense, net 2 - 2 - Total gains (losses) in net income $ 2 $ - $ 2 $ (87) As at December 31, 2017, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019. |
Schedules of Concentration of Risk, by Risk Factor [Table Text Block] | Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2017 December 31, 2016 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 326 23% $ 315 24% Commercial 161 11% 170 13% Industrial 46 3% 38 3% Other 96 7% 69 5% 629 44% 592 45% Trading group Credit rating of A- or above 55 4% 52 4% Credit rating of BBB- to BBB+ 61 4% 60 5% Not rated 96 7% 57 4% 212 15% 169 13% Other accounts receivable 300 22% 253 20% 1,141 81% 1,014 78% Derivative Instruments (current and long-term) Credit rating of A- or above 207 15% 252 20% Credit rating of BBB- to BBB+ 10 1% 1 0% Not rated 36 3% 23 2% 253 19% 276 22% $ 1,394 100% $ 1,290 100% |
Schedule of Financial Instruments Owned and Pledged as Collateral [Table Text Block] | As at December 31 December 31 millions of Canadian dollars 2017 2016 Cash collateral provided to others $ 119 $ 91 Cash collateral received from others 99 52 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Measurements [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | As at December 31, 2017 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 2 - 2 5 2 - 7 Regulatory deferral Commodity swaps and forwards Coal purchases - 127 - 127 Power purchases 5 - - 5 Natural gas purchases and sales - 5 - 5 Heavy fuel oil purchases 4 8 - 12 Foreign exchange forwards - 32 - 32 9 172 - 181 HFT derivatives Power swaps and physical contracts - 3 9 12 Natural gas swaps, futures, forwards, physical contracts and related transportation - 26 25 51 - 29 34 63 Other derivatives Interest rate swap - 2 - 2 - 2 - 2 Total assets 14 205 34 253 Liabilities Cash flow hedges Power swaps 2 - - 2 Foreign exchange forwards - 5 - 5 2 5 - 7 Regulatory deferral Commodity swaps and forwards Power purchases 3 - - 3 Natural gas purchases and sales 5 1 - 6 Foreign exchange forwards - 4 - 4 8 5 - 13 HFT derivatives Power swaps and physical contracts 49 5 (4) 50 Natural gas swaps, futures, forwards and physical contracts 6 47 187 240 55 52 183 290 Total liabilities 65 62 183 310 Net assets (liabilities) $ (51) $ 143 $ (149) $ (57) As at December 31, 2016 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 10 $ - $ - $ 10 10 - - 10 Regulatory deferral Commodity swaps and forwards Coal purchases - 74 - 74 Power purchases 7 - - 7 Natural gas purchases and sales 8 25 - 33 Heavy fuel oil purchases 3 5 1 9 Foreign exchange forwards - 106 - 106 18 210 1 229 HFT derivatives Power swaps and physical contracts (7) 1 - (6) Natural gas swaps, futures, forwards, physical contracts and related transportation - 4 39 43 (7) 5 39 37 Total assets 21 215 40 276 Liabilities Cash flow hedges Power swaps 4 - - 4 Foreign exchange forwards - 23 - 23 4 23 - 27 Regulatory deferral Power purchases 4 - - 4 Heavy fuel oil purchases - 6 - 6 Natural gas purchases and sales 1 1 - 2 5 7 - 12 HFT derivatives Power swaps and physical contracts 12 5 - 17 Natural gas swaps, futures, forwards and physical contracts 4 24 389 417 16 29 389 434 Other derivatives Foreign exchange forwards - 1 - 1 Interest rate swaps - 1 - 1 - 2 - 2 Total liabilities 25 61 389 475 Net assets (liabilities) $ (4) $ 154 $ (349) $ (199) |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The change in the fair value of the Level 3 financial assets for the year ended December 31, 2017 was as follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Oil financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2017 $ 1 $ - $ - $ 39 $ 40 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Unrealized gains (losses) included in regulatory assets or liabilities (1) 1 - - - Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 9 1 10 Net transfers out of Level 3 - - - (15) (15) Balance, December 31, 2017 $ - $ - $ 9 $ 25 $ 34 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2017 was as follows: Regulatory Deferral HFT Derivatives millions of Canadian dollars Oil financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2017 $ - $ - $ - $ 389 $ 389 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power - 1 - - 1 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - (5) (206) (211) Net transfers into Level 3 - - 1 4 5 Balance, December 31, 2017 $ - $ - $ (4) $ 187 $ 183 |
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | As at December 31, 2017 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets HFT derivatives – 1 Modelled pricing Third-party pricing $24.88-$117.90 $92.93 Power swaps and Probability of default 0.00%-0.01% 0.00% physical contracts Discount rate 0.00%-0.13% 0.00% 8 Modelled pricing Third-party pricing $63.48-$117.00 $102.68 Correlation factor 0.94%-0.99% 0.96% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.00% 0.00% HFT derivatives – 18 Modelled pricing Third-party pricing $2.06-$8.24 $3.61 Natural gas swaps, futures, Probability of default 0.00%-0.05% 0.00% forwards, physical contracts Discount rate 0.00%-0.29% 0.06% and related transportation 7 Modelled pricing Third-party pricing $2.04-$12.52 $6.42 Basis adjustment 0.08%-0.71% 0.52% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.09% 0.01% Total assets $ 34 Liabilities HFT derivatives – $ (6) Modelled pricing Third-party pricing $24.88-$117.90 $95.46 Power swaps and Own credit risk 0.00%-0.01% 0.00% physical contracts Discount rate 0.00%-0.13% 0.00% 2 Modelled pricing Third-party pricing $94.5-$117.00 $105.52 Correlation factor 0.94%-0.99% 0.96% Probability of default 0.00%-0.00% 0.00% Discount rate 0.00%-0.00% 0.00% HFT derivatives – 172 Modelled pricing Third-party pricing $1.89-$11.81 $4.64 Natural gas swaps, futures, Own credit risk 0.00%-0.00% 0.00% forwards and physical contracts Discount rate 0.00%-0.12% 0.02% 15 Modelled pricing Third-party pricing $2.15-$12.52 $8.94 Basis adjustment 0.08%-0.71% 0.53% Own credit risk 0.00%-0.00% 0.00% Discount rate 0.00%-0.08% 0.01% Total liabilities $ 183 Net assets (liabilities) $ (149) As at December 31, 2016 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets Regulatory deferral – Financial $ 1 Modelled pricing Third-party pricing $69.64 $69.64 oil derivatives Probability of default 0.80% 0.80% HFT derivatives – 27 Modelled pricing Third-party pricing $1.41 - $11.87 $3.87 Natural gas swaps, Probability of default 0.00% - 0.07% 0.01% futures, forwards, Discount rate 0.00% - 0.32% 0.05% physical contracts 12 Modelled pricing Third-party pricing $1.83 - $11.87 $6.16 and related transportation Basis adjustment (0.11)% - 0.64% 0.39% Probability of default 0.00% - 0.05% 0.00% Discount rate 0.00% - 0.10% 0.00% Total assets $ 40 Liabilities HFT derivatives – $ 386 Modelled pricing Third-party pricing $1.55 - $11.87 $6.26 Natural gas swaps, futures, Own credit risk 0.00% - 0.07% 0.00% forwards and physical contracts Discount rate 0.00% - 0.14% 0.02% 3 Modelled pricing Third-party pricing $1.83 - $11.87 $5.93 Basis adjustment (0.11)% - 0.64% 0.27% Own credit risk 0.00% - 0.05% 0.01% Discount rate 0.00% - 0.10% 0.01% Total liabilities 389 Net assets (liabilities) $ (349) |
Fair Value, Estimate Not Practicable [Table Text Block] | The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: As at millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total December 31, 2017 $ 13,881 $ 15,217 $ 69 $ 14,346 $ 802 $ 15,217 December 31, 2016 $ 14,744 $ 15,723 $ 78 $ 14,843 $ 802 $ 15,723 |
Regulatory Assets and Liabili59
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule Of Regulatory Assets and Liabilities [Table Text Block] | As at December 31 December 31 millions of Canadian dollars 2017 2016 Regulatory assets Deferred income tax regulatory assets $ 667 $ 632 Pension and post-retirement medical plan 345 373 Storm reserve 59 - Environmental remediations 41 49 Unamortized defeasance costs 32 39 2015 demand side management ("DSM") deferral 28 32 GBPC Hurricane Matthew restoration 28 28 Stranded cost recovery 25 27 Cost-recovery clauses 17 12 Deferrals related to derivative instruments 15 15 Debt basis adjustment 13 19 Deferred bond refinancing costs 7 9 Other 99 87 $ 1,376 $ 1,322 Current $ 138 $ 80 Long-term 1,238 1,242 Total regulatory assets $ 1,376 $ 1,322 Regulatory liabilities Deferred income tax regulatory liabilities 1,116 26 Accumulated reserve - cost of remova l 894 990 Deferrals related to derivative instruments 182 230 Regulated fuel adjustment mechanism 177 94 Cost-recovery clauses 51 153 Self-insurance fund (notes 7 and 32) 28 30 Bill reduction credit 4 10 Storm reserve - 75 Other 16 31 $ 2,468 $ 1,639 Current $ 226 $ 362 Long-term 2,242 1,277 Total regulatory liabilities $ 2,468 $ 1,639 |
Fuel Adjustment Mechanism [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 (Over) under recovery of current period Fuel costs $ - $ 29 Recovery from customers of prior years’ Fuel costs - 12 Application of non-fuel revenues - 20 Regulated fuel adjustment mechanism $ - $ 61 |
Schedule of Regulatory Assets [Table Text Block] | millions of Canadian dollars 2017 2016 FAM regulatory asset – Balance as at January 1 $ (94) $ (28) Under (over) recovery of current year Fuel Costs (29) (29) Rebate to (recovery from) customers of prior years’ Fuel Costs (12) (12) FAM audit disallowance, including interest adjustment - - Excess non-fuel revenues (5) (27) Interest on FAM balance (5) 1 FAM regulatory asset (liability) – Balance as at December 31 $ (160) $ (113) |
Receivables and Other Current60
Receivables and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract] | |
Receivables and other current assets [ Table Text Block] | 18. RECEIVABLES AND OTHER CURRENT ASSETS Receivables and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Customer accounts receivable – billed $ 805 $ 715 Customer accounts receivable – unbilled 278 270 Allowance for doubtful accounts (12) (13) Other receivables 70 42 Capitalized transportation capacity (1) 89 190 Prepaid expenses 59 57 Due from related parties 5 16 Net investment in direct financing lease 8 8 Income tax receivable 24 33 Other - 5 $ 1,326 $ 1,323 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment [Table Text Block] | Property, plant and equipment consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of Canadian dollars Estimated useful life 2017 2016 Generation 3 to 131 $ 11,010 $ 10,553 Transmission 15 to 80 2,786 2,799 Distribution 4 to 80 5,660 5,715 Gas transmission and distribution 7 to 85 2,867 2,895 General plant and other 3 to 60 1,874 1,711 Total cost 24,197 23,673 Less: Accumulated depreciation (7,824) (7,787) 16,373 15,886 Construction work in progress 622 1,404 Net book value $ 16,995 $ 17,290 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans [Abstract] | |
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,607 $ 358 $ 1,520 $ 88 Addition of TECO Energy, July 1, 2016 - - 1,035 277 Service cost 49 5 35 4 Plan participant contributions 8 4 8 - Interest cost 99 14 79 9 Plan amendments - - - 2 Benefits paid (129) (27) (94) (16) Actuarial losses 171 25 (2) (12) Special termination (35) - - - Foreign currency translation adjustment (87) (23) 26 6 Balance, December 31 2,683 356 2,607 358 Change in plan assets Balance, January 1 2,208 39 1,300 6 Addition of TECO Energy, July 1, 2016 - - 830 29 Employer contributions 109 27 49 17 Plan participant contributions 8 4 8 - Benefits paid (129) (27) (94) (16) Actual return on assets, net of expenses 313 5 93 2 Special termination (34) - - - Foreign currency translation adjustment (67) (3) 22 1 Balance, December 31 2,408 45 2,208 39 Funded status, end of year $ (275) $ (311) $ (399) $ (319) |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block] | millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,655 $ 325 $ 2,579 $ 358 Fair value of plan assets 2,370 6 2,171 39 Funded status $ (285) $ (319) $ (408) $ (319) millions of Canadian dollars 2017 2016 Defined benefit pension plans Defined benefit pension plans ABO $ 1,608 $ 2,462 Fair value of plan assets 1,409 2,171 Funded status $ (199) $ (291) |
Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | As at December 31 December 31 millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Current liabilities $ (23) $ (18) $ (41) $ (17) Long-term liabilities (264) (295) (367) (302) Other asset (non-current) 10 - 9 - Amount included in deferred tax asset 15 1 16 (1) AOCL (AOCI) and regulatory assets after-tax adjustment 548 73 620 45 Net amount recognized at end of year $ 286 $ (239) $ 237 $ (275) |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block] | Regulatory assets Actuarial losses (gains) Past service (gains) costs millions of Canadian dollars Defined Benefit Pension Plans Balance, January 1, 2017 $ 309 $ 330 $ (3) Amortized in current period (17) (38) - Current year addition to AOCL or regulatory assets (10) (8) - Balance, December 31, 2017 $ 282 $ 284 $ (3) Non-pension benefits plans Balance, January 1, 2017 $ 48 $ 15 $ (19) Amortized in current period 1 (2) 8 Current year addition to AOCL (AOCI) or regulatory assets 25 (2) - Balance, December 31, 2017 $ 74 $ 11 $ (11) 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 284 $ 11 $ 330 $ 15 Past service (gains) (3) (11) (3) (19) Regulatory assets 282 74 309 48 Total AOCL (AOCI) and regulatory assets on a pre-tax basis 563 74 636 44 Amount included in deferred tax asset (15) (1) (16) 1 Net amount in AOCL (AOCI) and regulatory assets after-tax adjustment $ 548 $ 73 $ 620 $ 45 |
Schedule of Net Benefit Costs [Table Text Block] | As at Year ended December 31 millions of Canadian dollars 2017 2016 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 49 $ 5 $ 35 $ 4 Interest cost 99 14 79 9 Expected return on plan assets (129) (3) (97) (1) Current year amortization of: Actuarial losses 38 2 42 2 Past service costs (gains) - (8) (1) (8) Regulatory assets (liability) 17 (1) 9 - Settlement, curtailments (1) - - - Total $ 73 $ 9 $ 67 $ 6 |
Schedule of Allocation of Plan Assets [Table Text Block] | Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 5% Fixed income 35% to 50% Equities: Canadian 12% to 22% Non-Canadian 30% to 55% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Short-term securities 47% to 52% Equities 48% to 53% As at December 31, 2016 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 31 $ - 31 1 % Net in-transits - (42) - (42) (2) % Equity securities: Canadian equity - 192 - 192 9 % US equity - 303 - 303 14 % Other equity - 243 - 243 11 % Fixed Income securities: Government - - 47 47 2 % Corporate - - 53 53 2 % Other - 5 14 19 1 % Open-ended investments measured at NAV (1) $ 1,132 - - 1,132 51 % Common collective trusts measured at NAV (2) 230 - - 230 11 % Total $ 1,362 $ 732 $ 114 2,208 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. Asset Class Target Range at Market Short-term securities 0% to 0% Equities: US 0% to 0% Non-US 0% to 0% December 31,2017 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 2 % Life insurance policies (1) - - 39 39 87 % Other investments measured at NAV $ 5 - - 5 11 % Total $ 5 $ 1 $ 39 $ 45 100 % (1) For valuation purposes, the life insurance policies held for the NMGC retiree medical plan are valued at the cash surrender value and are considered Level 2 assets December 31,2016 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 3 % Life insurance policies (1) - - 33 33 85 % Other investments measured at NAV $ 5 - - 5 12 % Total $ 5 $ 1 $ 33 $ 39 100 % (1) For valuation purposes, the life insurance policies held for the NMGC retiree medical plan are valued at the cash surrender value and are considered Level 2 assets |
Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | As at December 31, 2017 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 32 - $ 32 1 % Net in-transits - (36) - (36) (1) % Equity Securities: Canadian equity 214 - 214 9 % US equity - 390 - 390 16 % Other equity - 197 - 197 8 % Fixed income securities: Government - - $ 72 72 3 % Corporate - - 56 56 2 % Other - 5 - 5 - % Other - 4 4 - % Open-ended investments measured at NAV (1) $ 1,065 - - 1,065 44 % Common collective trusts measured at NAV (2) 409 - - 409 18 % Total $ 1,474 $ 802 $ 132 $ 2,408 100 % (1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly. (2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly. |
Schedule of Expected Benefit Payments [Table Text Block] | millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2018 $ 97 $ 25 Expected benefit payments 2018 147 22 2019 143 23 2020 148 23 2021 157 23 2022 165 24 2023 – 2027 912 124 |
Schedule of Assumptions Used [Table Text Block] | Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2017 2016 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate 3.55 % 3.65 % 3.96 % 4.18 % Rate of compensation increase 3.12 % 3.28 % 2.82 % 2.54 % Health care trend - initial (next year) - 6.65 % - 6.78 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2036 - 2035 Benefit cost for year ended December 31: Discount rate 3.96 % 4.18 % 3.79 % 3.88 % Expected long-term return on plan assets 6.29 % 6.08 % 6.33 % 4.43 % Rate of compensation increase 2.82 % 2.54 % 2.88 % 2.56 % Health care trend - initial (current year) - 6.78 % - 6.76 % - ultimate - 4.45 % - 4.45 % - year ultimate reached - 2035 - 2020 Figures shown are weighted averages. Actual assumptions used differ by plan. |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block] | millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 19 (16) millions of Canadian dollars Increase Decrease Discount rate assumption $ (9) $ 9 Asset rate assumption (6) 6 |
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block] | Amounts to be Amortized in the Next Fiscal Year The following table shows the amounts from the AOCL and regulatory assets, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2018: 2018 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (36) $ (2) Past service gains 1 6 Regulatory assets (21) (2) Total $ (56) $ 2 |
Net Investment in Direct Fina63
Net Investment in Direct Financing Lease (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Net Investment in Direct Financing Lease [Abstract] | |
Schedule of Components of Leveraged Lease Investments [Table Text Block] | As at December 31 December 31 millions of Canadian dollars 2017 2016 Total minimum lease payments to be received $ 1,126 $ 1,194 Less: amounts representing estimated executory costs (211) (223) Minimum lease payments receivable $ 915 $ 971 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (609) (658) Net investment in direct financing lease $ 489 $ 496 Principal due within one year (included in “Receivables and other current assets”) 8 8 Net investment in direct financing lease – long-term $ 481 $ 488 |
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block] | Future minimum lease payments to be received for the next five years: For the Year ended December 31 millions of Canadian dollars 2018 2019 2020 2021 2022 Minimum lease payments to be received $ 64 $ 64 $ 64 $ 65 $ 64 Less: amounts representing estimated executory costs (11) (11) (11) (12) (12) Minimum lease payments receivable $ 53 $ 53 $ 53 $ 53 $ 52 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill [Abstract] | |
Schedule of Goodwill [Table Text Block] | 22. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2017 2016 Balance, January 1 $ 6,213 $ 264 Acquisition of TECO Energy as at July 1, 2016 (note 4) - 5,771 Change in foreign exchange rate (408) 178 Balance, December 31 $ 5,805 $ 6,213 |
Short-Term Debt (Tables)
Short-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
Schedule of Short-term Debt [Table Text Block] | millions of Canadian dollars 2017 Weighted-average interest rate 2016 Weighted-average interest rate TECO Energy/TECO Finance Advances on revolving credit and term facilities $ 820 2.58 % $ 685 1.74 % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 382 2.07 % 228 1.49 % NMGC Advances on revolving credit facilities 38 2.47 % 35 1.71 % NSPI Bank indebtedness 1 - % 1 - % GBPC Advances on revolving credit facilities - - % 12 5.75 % Short-term debt $ 1,241 $ 961 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2017 2016 TECO Energy/TECO Finance - term credit facility 2018 $ 502 $ 537 TECO Energy/TECO Finance - revolving credit facility 2022 376 403 Tampa Electric Company - revolving credit facility 2022 408 436 Tampa Electric Company - accounts receivable revolving credit facility 2018 188 201 Tampa Electric Company - term loan 2018 377 - NMGC - revolving credit facility 2022 157 168 GBPC - revolving credit facility Various 16 17 Total 2,024 1,762 Less: Advances under revolving credit and term facilities 1,241 960 Letters of credit issued within the credit facilities 3 3 Total advances under available facilities 1,244 963 Available capacity under existing agreements $ 780 $ 799 |
Other Current Liabilities (Tabl
Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Current Liabilities [Abstract] | |
Other Current Liabilities [Table Text Block] | Other current liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 Accrued charges $ 134 $ 137 Accrued interest on long-term debt 78 96 Income tax payable 1 19 Accrued pension liability 41 58 Sales and other taxes payable 11 16 Emission credits obligations (1) 21 10 Other 64 22 $ 350 $ 358 (1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | millions of Canadian dollars Weighted Average Interest Rate 2017 (1) Weighted Average Interest Rate 2016 (1) Maturity 2017 2016 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 133 $ 30 Unsecured fixed rate notes 3.50% 3.50% 2019-2023 725 725 Fixed to floating subordinated notes (USD) 6.75% 6.75% 2076 1,505 1,611 $ 2,363 $ 2,366 Emera US Finance LP Unsecured senior notes (USD) 3.60% 3.60% 2019 - 2046 $ 4,077 $ 4,364 TECO Finance (2) Variable rate notes (USD) Variable Variable 2018 $ 314 $ 336 Fixed rate notes and bonds (USD) 5.15% 5.86% 2020 376 805 $ 690 $ 1,141 Tampa Electric (3) Fixed rate notes and bonds (USD) 4.75% 4.90% 2018 - 2045 $ 2,410 $ 2,579 PGS Fixed rate notes and bonds (USD) 5.06% 5.06% 2018 - 2045 $ 328 $ 351 NMGC Fixed rate notes and bonds (USD) 4.53% 4.53% 2021 - 2026 $ 339 $ 363 NMGI Fixed rate notes and bonds (USD) 3.41% 3.41% 2019 - 2024 $ 251 $ 269 NSPI Commercial paper Variable Variable 2021 $ 364 $ 264 Medium term fixed rate notes 5.73% 5.73% 2019 - 2097 1,965 1,965 Fixed rate debenture 9.75% 9.75% 2019 95 95 $ 2,424 $ 2,324 Emera Maine LIBOR loans and demand loans Variable Variable 2019 $ 51 $ 32 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 63 67 Unsecured senior fixed rate notes (USD) 4.15% 4.28% 2018-2047 294 281 $ 408 $ 380 EBP Senior secured credit facility 3.08% 3.08% 2021 $ 248 $ 248 GBPC Amortizing fixed rate notes (USD) 3.77% 3.62% 2021-2022 $ 78 $ 63 Senior notes (USD) 7.07% 7.07% 2020-2023 88 67 $ 166 $ 130 BLPC & ECI Secured senior notes (USD) Variable Variable 2021 168 201 Secured fixed rate senior notes (4) 5.06% 5.65% 2020 - 2028 $ 76 $ 81 $ 244 $ 282 Adjustments Fair market value adjustment - TECO Energy acquisition (5) $ 31 $ 58 Debt issuance costs (98) (111) Amount due within one year (741) (476) $ (808) $ (529) Long-Term Debt $ 13,140 $ 14,268 (1) Weighted average interest rate of fixed rate long-term debt. (2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. (4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of Canadian dollars Maturity 2017 2016 Emera – revolving credit facility (1) June 2020 $ 900 $ 700 NSPI - revolving credit facility (1) October 2021 600 600 Emera Maine – revolving credit facility September 2019 100 107 BLPC – revolving credit facility 2018-2021 24 26 Total 1,624 1,433 Less: Borrowings under credit facilities 598 326 Letters of credit issued inside credit facilities 44 37 Use of available facilities 642 363 Available capacity under existing agreements $ 982 $ 1,070 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. |
Schedule of Debt Conversions [Table Text Block] | As at Financial Covenant Requirement December 31, 2017 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.61:1 |
Schedule of Maturities of Long-term Debt [Table Text Block] | millions of Canadian dollars 2018 2019 2020 2021 2022 Thereafter Total Emera $ - $ 225 $ 133 $ - $ - $ 2,005 $ 2,363 Emera US Finance LP - 627 - 941 - 2,509 4,077 TECO Finance 314 - 376 - - - 690 Tampa Electric 319 - - 291 282 1,518 2,410 PGS 62 - - 59 31 176 328 NMGC - - - 251 - 88 339 NMGI - 63 - - - 188 251 NSPI - 95 - 364 - 1,965 2,424 Emera Maine 6 51 37 - 113 201 408 EBP - - - 248 - - 248 GBPC 12 15 45 22 31 41 166 BLPC and ECI 28 29 55 28 11 93 244 Total $ 741 $ 1,105 $ 646 $ 2,204 $ 468 $ 8,784 $ 13,948 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Asset Retirement Obligations [Table Text Block] | The change in ARO for the years ended December 31 is as follows: millions of Canadian dollars 2017 2016 Balance, January 1 $ 170 $ 109 Additions (1) 2 48 Additions due to acquisition - 9 Liabilities settled (3) (2) Accretion included in depreciation expense 6 7 Accretion deferred to regulatory asset (included in property, plant and equipment) - (2) Other 1 1 Change in foreign exchange rate (4) - Balance, December 31 $ 172 $ 170 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2016 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies [Abstract] | |
Other Commitments [Table Text Block] | millions of Canadian dollars 2018 2019 2020 2021 2022 Thereafter Total Purchased power (1) $ 234 $ 216 $ 212 $ 209 $ 206 $ 2,148 $ 3,225 Transportation (2) 451 298 264 184 172 1,339 2,708 Fuel and gas supply 527 176 50 41 - - 794 Capital projects 413 88 - - - - 501 Long-term service agreements (3) 75 65 34 44 35 180 433 Equity investment commitments (4) 15 5 190 - - - 210 DSM 63 28 18 18 18 - 145 Leases and other (5) 43 12 10 7 4 61 137 $ 1,821 $ 888 $ 778 $ 503 $ 435 $ 3,728 $ 8,153 (1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. (2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. (3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. (4) Emera has a commitment in connection with the Federal Loan Guarantee to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction. (5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. |
Cumulative Preferred Stock (Tab
Cumulative Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Cumulative Preferred Stock [Abstract] | |
Schedule of Stock by Class [Table Text Block] | Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2017 December 31, 2016 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.6388 $ 25.00 3,864,636 $ 95 3,864,636 $ 95 Series B Floating $ 25.00 2,135,364 $ 52 2,135,364 $ 52 Series C $ 1.0250 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 26.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0625 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Total 29,000,000 $ 709 29,000,000 $ 709 |
Non-Controlling Interest in S71
Non-Controlling Interest in Subsidiaries (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Noncontrolling Interest [Table Text Block] | 29. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2017 2016 ICDU $ 52 $ 53 Preferred shares of GBPC 19 34 Domlec 21 25 $ 92 $ 112 |
Schedule of Sale of Stock by Subsidiary or Equity Method Investee Disclosure [Table Text Block] | Preferred shares of GBPC: Authorized: 35,000 non-voting cumulative redeemable variable perpetual preferred shares 2017 2016 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 20,000 $ 19 35,000 $ 34 |
Supplemental Information to C72
Supplemental Information to Consolidated Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2017 2016 Changes in non-cash working capital: Receivables, net $ (176) $ (104) Income taxes receivable 8 (23) Inventory 31 88 Prepayments and other current assets 14 (18) Accounts payable 3 162 Income taxes payable (17) 14 Other current liabilities 33 15 Total non-cash working capital $ (104) $ 134 Supplemental disclosure of cash paid: Interest $ 689 $ 480 Income taxes $ 63 $ 57 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 166 $ 103 Beneficial Conversion Feature of the convertible debentures $ - $ 43 |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stock-Based Compensation [Abstract] | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value [Table Text Block] | For the year ended December 31, 2017 2016 Weighted average fair value per option $ 2.37 $ 2.80 Expected term 5 years 5 years Risk-free interest rate 1.22 % 0.66 % Expected dividend yield 4.60 % 4.08 % Expected volatility 14.41 % 15.45 % |
Schedule of Stock Options Roll Forward [Table Text Block] | Total Options Non-Vested Options (1) Number of Options Weighted average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2016 2,920,000 $ 37.42 1,520,125 $ 2.69 Granted 827,400 45.16 827,400 2.37 Exercised (103,825) 28.91 N/A N/A Forfeited - - (607,875) 2.73 Options outstanding December 31, 2017 3,643,575 $ 39.42 1,739,650 $ 2.52 Options exercisable December 31, 2017 (2)(3) 1,903,925 $ 35.37 (1) As at December 31, 2017 there was $3 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.5 years (2016 - $3 million, 2.4 years). (2) As at December 31, 2017, the weighted average remaining term of vested options was 5.4 years with an aggregate intrinsic value of $22 million (2016 - 5.7 years, $17 million). (3) As at December 31, 2017 the fair value of options that vested in the year was $2 million (2016 - $2 million). |
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block] | Employee DSU Weighted Average Grant Date Fair Value Director DSU Weighted Average Grant Date Fair Value Outstanding as at December 31, 2016 680,931 $ 27.50 395,798 $ 33.88 Granted including DRIP 73,185 37.74 86,281 42.96 Exercised (2,482) 46.58 (9,486) 44.00 Forfeited (34) 46.58 (108) 45.39 Outstanding and exercisable as at December 31, 2017 751,600 $ 28.44 472,485 $ 35.33 Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2016 560,880 $ 37.55 $ 25.5 Granted including DRIP 519,789 44.35 Exercised (220,075) 30.67 Forfeited (30,596) 43.66 Outstanding as at December 31, 2017 829,998 $ 43.41 $ 41.1 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entities [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | As at December 31, 2017 December 31, 2016 Maximum Maximum millions of Canadian dollars Total assets exposure to loss Total assets exposure to loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 510 $ 67 $ 315 $ 577 |
Supplemental Financial Inform75
Supplemental Financial Information (Tables) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ||
Condensed Income Statement [Table Text Block] | Emera Incorporated C ondensed C o nsolidated Statements of Income For the year ended December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues $ - $ - $ 4,165 $ 2,118 $ (57) $ 6,226 Operating expenses 41 - 3,241 1,610 (57) 4,835 Income (loss) from operations (41) - 924 508 - 1,391 Income (loss) from equity investments in subsidiaries 336 - - - (336) - Income from equity investments 1 - 1 122 - 124 Intercompany income (expenses), net 92 195 (204) (45) (38) - Other income (expenses), net - - 16 (19) 5 2 Interest expense, net 138 155 242 163 - 698 Income (loss) before provision for income taxes 250 40 495 403 (369) 819 Income tax expense (recovery) (44) 17 511 36 - 520 Net income (loss) 294 23 (16) 367 (369) 299 Non-controlling interest in subsidiaries - - - 1 4 5 Preferred stock dividends 28 - 29 13 (42) 28 Net income (loss) attributable to common shareholders $ 266 $ 23 $ (45) $ 353 $ (331) $ 266 Comprehensive income (loss) of Emera Incorporated $ - $ 3 $ (392) $ 372 $ 17 $ - Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues $ - $ - $ 2,494 $ 1,818 $ (35) $ 4,277 Operating expenses 39 - 2,127 1,591 (35) 3,722 Income (loss) from operations (39) - 367 227 - 555 Income (loss) from equity investments in subsidiaries 150 - - - (150) - Income from equity investments 18 - - 82 - 100 Intercompany income (expenses), net 203 101 (107) (151) (46) - Other income (expenses), net 135 - 24 15 - 174 Interest expense, net 226 85 127 147 - 585 Income (loss) before provision for income taxes 241 16 157 26 (196) 244 Income tax expense (recovery) (14) 7 48 (63) - (22) Net income (loss) 255 9 109 89 (196) 266 Non-controlling interest in subsidiaries - - - 7 4 11 Preferred stock dividends 28 - 31 19 (50) 28 Net income (loss) attributable to common shareholders $ 227 $ 9 $ 78 $ 63 $ (150) $ 227 Comprehensive income (loss) of Emera Incorporated $ 228 $ 19 $ 205 $ 59 $ (283) $ 228 | Emera Incorporated C ondensed C o nsolidated Statements of Income For the year ended December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues $ - $ - $ 2,494 $ 1,818 $ (35) $ 4,277 Operating expenses 39 - 2,127 1,591 (35) 3,722 Income (loss) from operations (39) - 367 227 - 555 Income (loss) from equity investments in subsidiaries 150 - - - (150) - Income from equity investments 18 - - 82 - 100 Intercompany income (expenses), net 203 101 (107) (151) (46) - Other income (expenses), net 135 - 24 15 - 174 Interest expense, net 226 85 127 147 - 585 Income (loss) before provision for income taxes 241 16 157 26 (196) 244 Income tax expense (recovery) (14) 7 48 (63) - (22) Net income (loss) 255 9 109 89 (196) 266 Non-controlling interest in subsidiaries - - - 7 4 11 Preferred stock dividends 28 - 31 19 (50) 28 Net income (loss) attributable to common shareholders $ 227 $ 9 $ 78 $ 63 $ (150) $ 227 Comprehensive income (loss) of Emera Incorporated $ 228 $ 19 $ 205 $ 59 $ (283) $ 228 |
Condensed Balance Sheet [Table Text Block] | Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Assets Current assets Cash and cash equivalents $ 276 $ 21 $ 47 $ 94 $ - $ 438 Restricted cash - - 1 64 - 65 Inventory - - 243 175 - 418 Derivative instruments 5 - 11 131 (6) 141 Regulatory assets - - 114 24 - 138 Intercompany receivables 74 9 4 108 (195) - Receivables and other current assets 3 - 546 777 - 1,326 Total current assets 358 30 966 1,373 (201) 2,526 Property, plant and equipment, net of accumulated depreciation 17 - 12,258 4,720 - 16,995 Other assets Deferred income taxes 70 - (10) 71 7 138 Derivative instruments 4 - 2 110 (4) 112 Regulatory assets - - 552 686 - 1,238 Net investment in direct financing lease - - 12 469 - 481 Investments in subsidiaries accounted for using the equity method 8,490 - - - (8,490) - Investments subject to significant influence 5 - 13 1,197 - 1,215 Goodwill - - 5,709 96 - 5,805 Intercompany notes receivable 1,140 4,285 1 955 (6,381) - Other investments - intercompany - - - 70 (70) - Other long-term assets 29 - 68 184 (20) 261 Total other assets 9,738 4,285 6,347 3,838 (14,958) 9,250 Total assets $ 10,113 $ 4,315 $ 19,571 $ 9,931 $ (15,159) $ 28,771 Emera Incorporated Condensed Consolidated Balance Sheets – Continued As at December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ - $ - $ 1,241 $ - $ - $ 1,241 Current portion of long-term debt - - 701 40 - 741 Accounts payable 9 - 620 532 - 1,161 Intercompany payable 55 6 90 74 (225) - Derivative instruments 5 - 52 175 (5) 227 Regulatory liabilities - - 91 136 (1) 226 Other current liabilities 60 6 137 147 - 350 Total current liabilities 129 12 2,932 1,104 (231) 3,946 Long-term liabilities Long-term debt 2,205 4,034 3,741 3,160 - 13,140 Intercompany long-term debt 656 - 4,582 1,139 (6,377) - Deferred income taxes - 4 435 565 7 1,011 Derivative instruments 4 - 4 79 (4) 83 Regulatory liabilities - - 1,889 353 - 2,242 Pension and post-retirement liabilities 21 - 341 197 - 559 Other long-term liabilities 9 - 267 352 (19) 609 Total long-term liabilities 2,895 4,038 11,259 5,845 (6,393) 17,644 Equity Common stock 5,601 242 4,311 2,136 (6,689) 5,601 Cumulative preferred stock 709 - 620 76 (696) 709 Contributed surplus 76 - 110 148 (258) 76 Accumulated other comprehensive income (loss) (188) (9) (36) (185) 230 (188) Retained earnings 891 32 375 735 (1,142) 891 Total Emera Incorporated equity 7,089 265 5,380 2,910 (8,555) 7,089 Non-controlling interest in subsidiaries - - - 72 20 92 Total equity 7,089 265 5,380 2,982 (8,535) 7,181 Total liabilities and equity $ 10,113 $ 4,315 $ 19,571 $ 9,931 $ (15,159) $ 28,771 | Emera Incorporated Condensed Consolidated Balance Sheets As at December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Assets Current assets Cash and cash equivalents $ 200 $ 28 $ 48 $ 128 $ - $ 404 Restricted cash - - 1 86 - 87 Inventory - - 273 199 - 472 Derivative instruments 13 - 33 112 (13) 145 Regulatory assets - - 54 26 - 80 Intercompany receivable 57 9 11 569 (646) - Prepayments and other current assets 3 - 478 842 - 1,323 Total current assets 273 37 898 1,962 (659) 2,511 Property, plant and equipment, net of accumulated depreciation 14 - 12,724 4,552 - 17,290 Other assets Deferred income taxes 31 - 18 114 (38) 125 Derivative instruments 12 - 2 129 (12) 131 Regulatory assets - - 647 595 - 1,242 Net investment in direct financing lease - - 13 475 - 488 Investments in subsidiaries accounted for using the equity method 8,349 - - - (8,349) - Investments subject to significant influence 5 - 13 929 - 947 Goodwill - - 6,110 103 - 6,213 Intercompany notes receivable 1,341 4,558 16 589 (6,504) - Other investments - intercompany - - - 2,270 (2,270) - Other long-term assets 33 - 85 175 (19) 274 Total other assets 9,771 4,558 6,904 5,379 (17,192) 9,420 Total assets $ 10,058 $ 4,595 $ 20,526 $ 11,893 $ (17,851) $ 29,221 Emera Incorporated Condensed Consolidated Balance Sheets – Continued As at December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ - $ - $ 948 $ 13 $ - $ 961 Current portion of long-term debt - - 436 40 - 476 Accounts payable 6 - 756 480 - 1,242 Intercompany payable 534 6 81 25 (646) - Derivative instruments 14 - 10 314 (13) 325 Regulatory liabilities - - 225 137 - 362 Other current liabilities 54 13 130 161 - 358 Total current liabilities 608 19 2,586 1,170 (659) 3,724 Long-term liabilities Long-term debt 2,338 4,314 4,687 2,929 - 14,268 Intercompany long-term debt 366 - 4,778 1,357 (6,501) - Deferred income taxes - 1 1,193 516 (38) 1,672 Derivative instruments 12 - - 150 (12) 150 Regulatory liabilities - - 973 304 - 1,277 Pension and post-retirement liabilities 17 - 433 219 - 669 Other long-term liabilities 13 - 274 377 (19) 645 Total long-term liabilities 2,746 4,315 12,338 5,852 (6,570) 18,681 Equity Common stock 4,738 242 4,177 3,997 (8,416) 4,738 Cumulative preferred stock 709 - 620 271 (891) 709 Contributed surplus 75 - 45 106 (151) 75 Accumulated other comprehensive income (loss) 106 10 340 (191) (159) 106 Retained earnings 1,076 9 420 610 (1,039) 1,076 Total Emera Incorporated equity 6,704 261 5,602 4,793 (10,656) 6,704 Non-controlling interest in subsidiaries - - - 78 34 112 Total equity 6,704 261 5,602 4,871 (10,622) 6,816 Total liabilities and equity $ 10,058 $ 4,595 $ 20,526 $ 11,893 $ (17,851) $ 29,221 |
Condensed Cash Flow Statement [Table Text Block] | Emera Incorporated Condensed Consolidated Statements of Cash Flows For the year ended December 31, 2017 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) by operating activities $ 195 $ 22 $ 712 $ 1,125 $ (861) $ 1,193 Investing activities Additions to property, plant and equipment (5) - (1,031) (480) (13) (1,529) Net purchase of investments subject to significant influence, inclusive of acquisition costs - - - (213) - (213) Other intercompany investing activities (708) (26) 15 1,818 (1,099) - Other investing activities (34) - (20) 32 3 (19) Net cash provided by (used in) investing activities (747) (26) (1,036) 1,157 (1,109) (1,761) Financing activities Change in short-term debt, net - - 365 (13) - 352 Proceeds from long-term debt, net of issuance costs - - 147 (131) 113 129 Retirement of long-term debt - - (413) (55) 15 (453) Net borrowings (repayments) under committed credit facilities (30) - 21 233 6 230 Issuance of common stock, net of issuance costs 682 - 134 (1,837) 1,703 682 Issuance of preferred stock, net of issuance costs - - - (195) 195 - Dividends on common stock (287) - - (272) 272 (287) Dividends on preferred stock (28) - (29) (13) 42 (28) Dividends paid by subsidiaries to non-controlling interest - - - (2) (4) (6) Other financing activities 290 - 96 (40) (372) (26) Net cash provided by (used in) financing activities 627 - 321 (2,325) 1,970 593 Effect of exchange rate changes on cash and cash equivalents 1 (3) 2 (13) - (13) Net increase (decrease) in cash and cash equivalents 76 (7) (1) (56) - 12 Cash, cash equivalents and restricted cash, beginning of year 200 28 49 214 - 491 Cash, cash equivalents and restricted cash, end of year $ 276 $ 21 $ 48 $ 158 $ - $ 503 | Emera Incorporated Condensed Consolidated Statements of Cash Flows For the year ended December 31, 2016 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) operating activities $ 265 $ 29 $ 481 $ 107 $ 171 $ 1,053 Investing activities Acquisitions, net of cash acquired - - (8,409) - - (8,409) Additions to property, plant and equipment (2) - (673) (405) - (1,080) Net purchase of investments subject to significant influence, inclusive of acquisition costs - - - (276) - (276) Net proceeds on sale of investment subject to significant influence and held-for-trading common shares 665 - - - - 665 Other intercompany investing activities (2,348) (4,416) (18) (2,397) 9,179 - Other investing activities - - (3) 66 - 63 Net cash provided by (used in) investing activities (1,685) (4,416) (9,103) (3,012) 9,179 (9,037) Financing activities Change in short-term debt, net (14) - 122 (4) 14 118 Proceeds from long-term debt, net of issuance costs 2,037 4,187 4,516 764 (5,081) 6,423 Proceeds from convertible debentures represented by instalment receipts, net of issuance costs (44) - - 1,457 - 1,413 Retirement of long-term debt (250) - (6) (36) 19 (273) Net borrowings (repayments) under committed credit facilities (210) - - (99) (6) (315) Issuance of common stock, net of issuance costs 354 242 3,865 95 (4,202) 354 Issuance of preferred stock, net of issuance costs - - 195 - (195) - Dividends on common stock (221) - - (254) 254 (221) Dividends on preferred stock (28) - (31) (18) 49 (28) Dividends paid by subsidiaries to non-controlling interest - - - (2) (3) (5) Other financing activities - - (18) 185 (185) (18) Net cash provided by (used in) financing activities 1,624 4,429 8,643 2,088 (9,336) 7,448 Effect of exchange rate changes on cash and cash equivalents (4) (14) 7 (54) - (65) Net increase (decrease) in cash and cash equivalents 200 28 28 (871) 14 (601) Cash, cash equivalents and restricted cash, beginning of year - - 21 1,085 (14) 1,092 Cash, cash equivalents and restricted cash, end of year $ 200 $ 28 $ 49 $ 214 $ - $ 491 |
Summary of Significant Accoun76
Summary of Significant Accounting Policies (Nature of Operations Narrative) (Details) $ in Millions | Dec. 31, 2017CAD ($)MWCustomerskm |
Emera Maine [Member] | Maine | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 158,000 |
Nova Scotia Power Inc. [Member] | Nova Scotia [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 515,000 |
Emera (Caribbean) Incorporated Parent [Member] | Dominica Electricity Services Ltd. [Member] | BAHAMAS | |
Public Utilities, General Disclosures [Line Items] | |
Controlling Interest Ownership Percentage By Parent | 51.90% |
Number Of Customers | 36,000 |
Emera (Caribbean) Incorporated Parent [Member] | Grand Bahama Power Company Limited [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Controlling Interest Ownership Percentage By Parent | 50.00% |
Indirect Ownership Percentage By Parent | 30.40% |
Number Of Customers | 19,000 |
Emera (Caribbean) Incorporated Parent [Member] | St. Lucia Electricity Services Limited [Member] | SAINT LUCIA | |
Public Utilities, General Disclosures [Line Items] | |
Indirect Ownership Percentage By Parent | 19.10% |
Emera (Caribbean) Incorporated Parent [Member] | The Barbados Light and Power Company Limited [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 129,000 |
Emera Inc | Bayside Power Limited Partnership [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 290 |
Emera Inc | Brooklyn Power Corporation [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 30 |
Emera Inc | Emera Brunswick Pipeline Company Limited [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Length Of Pipeline | km | 145 |
Emera Inc | Emera Energy Services [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 1,115 |
Emera Inc | Bear Swamp Power Company LLC [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 600 |
Emera Inc | Bear Swamp Power Company LLC [Member] | Massachusetts | |
Public Utilities, General Disclosures [Line Items] | |
Equity Method Investment, Ownership Percentage | 50.00% |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Emera Newfoundland and Labrador Holdings Inc. [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 824 |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Maritimes and Northeast Pipline [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Length Of Pipeline | km | 1,400 |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Maritimes and Northeast Pipline [Member] | Newfoundland and Labrador [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Controlling Interest Ownership Percentage By Parent | 12.90% |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | NSP Maritime Link Inc. [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Length Of Pipeline | km | 170 |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | NSP Maritime Link Inc. [Member] | Newfoundland and Labrador [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Equity Method Investment, Ownership Percentage | 100.00% |
Public Utilities, Property, Plant and Equipment, Transmission and Distribution | $ | $ 1,560 |
Emera Newfoundland & Labrador Holdings Inc. Parent [Member] | Labrador-Island Link Limited Partnership [Member] | Newfoundland and Labrador [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Equity Method Investment, Ownership Percentage | 49.50% |
Public Utilities, Property, Plant and Equipment, Transmission and Distribution | $ | $ 3,700 |
TECO Energy Inc Parent [Member] | New Mexico Gas Company [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 525,000 |
TECO Energy Inc Parent [Member] | Peoples Gas System Division [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 375,000 |
TECO Energy Inc Parent [Member] | Tampa Electric Division [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Customers | 750,000 |
Icd Utilities Limited Parent [Member] | Grand Bahama Power Company Limited [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Equity Method Investment, Ownership Percentage | 60.70% |
Summary of Significant Accoun77
Summary of Significant Accounting Policies (Nature of Operations, Business Acquisition) (Details) | Jan. 15, 2018 |
GBPC [Member] | |
Business Acquisition [Line Items] | |
Ownership interest | 100.00% |
Summary of Significant Accoun78
Summary of Significant Accounting Policies (Cash, Short-term Investments and Receivables) (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Cash and Cash Equivalents [Abstract] | ||
Short-term Investments | $ 222 | $ 183 |
Investment Interest Rate | 1.40% | 0.60% |
Summary of Significant Accoun79
Summary of Significant Accounting Policies (Intangible Assets) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($) | |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,017 | $ 8 |
2,018 | 8 |
2,019 | 8 |
2,020 | 8 |
2,021 | 8 |
Computer Software, Intangible Asset [Member] | |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,017 | 6 |
2,018 | 6 |
2,019 | 6 |
2,020 | 6 |
2,021 | 6 |
Use Rights [Member] | |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,017 | 1 |
2,018 | 1 |
2,019 | 1 |
2,020 | 1 |
2,021 | 1 |
Naming Rights [Member] | |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,017 | 1 |
2,018 | 1 |
2,019 | 1 |
2,020 | 1 |
2,021 | $ 1 |
Minimum [Member] | Computer Software, Intangible Asset [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 3 years |
Minimum [Member] | Use Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 50 years |
Minimum [Member] | Naming Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 1 year |
Maximum [Member] | Computer Software, Intangible Asset [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 15 years |
Maximum [Member] | Use Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 143 years |
Maximum [Member] | Naming Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 24 years |
Acquisition (Purchase Considera
Acquisition (Purchase Consideration) (Details) - Jul. 01, 2016 - TECO Energy Inc [Member] $ / shares in Units, $ in Billions, $ in Billions | CAD ($) | USD ($)$ / shares |
Business Combination, Consideration Transferred [Abstract] | ||
Business Acquisition, Share Price | $ 27.55 | |
Payments to Acquire Businesses, Gross | $ 8.4 | $ 6.5 |
Business Combination, Consideration Transferred, Liabilities Incurred | 5.5 | 4.2 |
Business Combination, Consideration Transferred | $ 13.9 | $ 10.7 |
Acquision (Purchase Considerati
Acquision (Purchase Consideration) (Details) $ in Millions | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Jul. 01, 2016CAD ($) | Dec. 31, 2015CAD ($) |
Fair value assigned to net assets: | ||||
Goodwill | $ 5,805 | $ 6,213 | $ 264 | |
TECO Energy Inc [Member] | ||||
Multiple Foreign Currency Exchange Rates [Abstract] | ||||
Foreign Currency Exchange Rate, Translation | 1.3009 | |||
Purchase Consideration | $ 8,447 | |||
Fair value assigned to net assets: | ||||
Current Assets | 619 | |||
Regulatory assets (including current portion) | 624 | |||
Property, plant and equipment, net | 10,023 | |||
Other long-term assets | 71 | |||
Current libabilities | (747) | |||
Assumed long-term debt (including current portion) | (5,409) | |||
Regulatory liabilities (including current portion) | (1,117) | |||
Deferred Income Taxes | (800) | |||
Pension and post-retirement liabilities (including current portion) | (480) | |||
Other long-term liabilities | (146) | |||
Net: Less Cash And Cash Equivalents | 2,638 | |||
Cash and cash equivalents | 38 | |||
Fair value of net assets acquired | 2,676 | |||
Goodwill | 5,771 | |||
Business Combination, Acquired Receivables [Abstract] | ||||
Fair Value, Acounts Receiveable | 334 | |||
Gross Contractual Amount | 337 | |||
Estimated Uncollectible | (3) | |||
Tampa Electric Division [Member] | ||||
Fair value assigned to net assets: | ||||
Goodwill | 4,552 | |||
Peoples Gas System Division [Member] | ||||
Fair value assigned to net assets: | ||||
Goodwill | 744 | |||
New Mexico Gas Company [Member] | ||||
Fair value assigned to net assets: | ||||
Goodwill | $ 475 |
Acquision (Related Expenses and
Acquision (Related Expenses and Pro Forma Data) (Details) - TECO Energy Inc [Member] - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | $ 0 | |
Business Combination, Acquisition Related Costs, Net of Tax | $ 166 | |
Business Acquisition, Pro Forma Information [Abstract] | ||
Pro forma operating revenues | 6,034 | |
Prop forma net income attributable to common shareholders | 386 | |
Business Acquisitions Pro Forma Increase To Net Income Loss | 53 | |
Sales [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | 0 | (10) |
Operating Expense [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | 0 | 89 |
Interest Expense [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | 0 | 148 |
Other Operating Income (Expense) [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | 0 | (3) |
Income Tax Expense [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Combination, Acquisition Related Costs | $ 0 | $ (84) |
Segment Information (Reportable
Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | $ 6,226 | $ 4,277 | |
Allowance for Funds Used During Construction, Investing Activities | 16 | 35 | |
Regulated Fuel Adjustment | 59 | 61 | |
Depreciation, Depletion and Amortization | 856 | 588 | |
Interest Expense | 705 | 598 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 124 | 100 | |
Income tax expense (recovery) | 520 | (22) | |
Net Income (Loss) Attributable to Parent | 266 | 227 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 1,522 | 1,069 | |
Assets, Total | 28,771 | 29,221 | |
Goodwill | 5,805 | 6,213 | $ 264 |
Investments subject to significant influence | 1,215 | 947 | |
All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 6,226 | 4,276 | |
Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 1 | |
Intersegment Eliminations [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | (58) | (36) | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 0 | 0 | |
Interest Expense | 0 | 0 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 0 | 0 | |
Net Income (Loss) Attributable to Parent | 0 | 0 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 0 | 0 | |
Assets, Total | (86) | (113) | |
Goodwill | 0 | ||
Investments subject to significant influence | 0 | ||
Intersegment Eliminations [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 0 | |
Intersegment Eliminations [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | (58) | (36) | |
Emera Florida And New Mexico Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 3,623 | 1,839 | |
Allowance for Funds Used During Construction, Investing Activities | 5 | 28 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 500 | 243 | |
Interest Expense | 248 | 125 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 529 | 100 | |
Net Income (Loss) Attributable to Parent | 99 | 172 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 910 | 547 | |
Assets, Total | 17,216 | 18,016 | |
Goodwill | 5,566 | 5,957 | |
Investments subject to significant influence | 0 | 0 | |
Emera Florida And New Mexico Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 3,623 | 1,839 | |
Emera Florida And New Mexico Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 0 | |
Nova Scotia Power Inc Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 1,338 | 1,356 | |
Allowance for Funds Used During Construction, Investing Activities | 8 | 6 | |
Regulated Fuel Adjustment | 59 | 61 | |
Depreciation, Depletion and Amortization | 207 | 197 | |
Interest Expense | 134 | 127 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 0 | 12 | |
Net Income (Loss) Attributable to Parent | 129 | 130 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 385 | 304 | |
Assets, Total | 4,979 | 4,776 | |
Goodwill | 0 | 0 | |
Investments subject to significant influence | 0 | 0 | |
Nova Scotia Power Inc Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 1,335 | 1,354 | |
Nova Scotia Power Inc Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 3 | 2 | |
Emera Maine Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 297 | 297 | |
Allowance for Funds Used During Construction, Investing Activities | 3 | 1 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 47 | 51 | |
Interest Expense | 20 | 19 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 1 | 0 | |
Income tax expense (recovery) | 27 | 23 | |
Net Income (Loss) Attributable to Parent | 46 | 47 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 82 | 85 | |
Assets, Total | 1,505 | 1,543 | |
Goodwill | 143 | 154 | |
Investments subject to significant influence | 13 | 13 | |
Emera Maine Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 297 | 297 | |
Emera Maine Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 0 | |
Emera Caribbean Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 434 | 419 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 51 | 48 | |
Interest Expense | 25 | 15 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 3 | 3 | |
Income tax expense (recovery) | 0 | 14 | |
Net Income (Loss) Attributable to Parent | 31 | 100 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 72 | 87 | |
Assets, Total | 1,251 | 1,331 | |
Goodwill | 96 | 102 | |
Investments subject to significant influence | 39 | 39 | |
Emera Caribbean Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 434 | 419 | |
Emera Caribbean Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 0 | |
Emera Energy Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 465 | 309 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 48 | 45 | |
Interest Expense | 2 | 1 | |
Internally Allocated Interest | (24) | (24) | |
Income (Loss) from Equity Method Investments | 24 | 11 | |
Income tax expense (recovery) | 18 | (53) | |
Net Income (Loss) Attributable to Parent | 93 | (110) | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 47 | 39 | |
Assets, Total | 1,575 | 1,702 | |
Goodwill | 0 | 0 | |
Investments subject to significant influence | 0 | 0 | |
Emera Energy Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 451 | 298 | |
Emera Energy Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 14 | 11 | |
Corporate and Other [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 127 | 93 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 3 | 4 | |
Interest Expense | 276 | 311 | |
Internally Allocated Interest | 24 | 24 | |
Income (Loss) from Equity Method Investments | 96 | 86 | |
Income tax expense (recovery) | (54) | (118) | |
Net Income (Loss) Attributable to Parent | (132) | (112) | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 26 | 7 | |
Assets, Total | 2,331 | 1,966 | |
Goodwill | 0 | 0 | |
Investments subject to significant influence | 1,163 | 895 | |
Amortization Related to Unregulated Long Term Debt | 24 | 13 | |
Corporate and Other [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 86 | 69 | |
Corporate and Other [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | $ 41 | $ 24 |
Segment Information (Geographic
Segment Information (Geographical) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | $ 6,226 | $ 4,277 |
Noncurrent Assets | 16,995 | 17,290 |
CA | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 1,464 | 1,510 |
Noncurrent Assets | 3,995 | 3,791 |
UNITED STATES | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 4,328 | 2,348 |
Noncurrent Assets | 12,257 | 12,724 |
BARBADOS | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 280 | 254 |
Noncurrent Assets | 408 | 416 |
BAHAMAS | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 119 | 121 |
Noncurrent Assets | 276 | 295 |
DOMINICA | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 35 | 44 |
Noncurrent Assets | $ 59 | $ 64 |
Investments Subject to Signif85
Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - CAD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | $ 1,215 | $ 947 | |
Income (Loss) from Equity Method Investments | 124 | 100 | |
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investments | 1,215 | 947 | |
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 13 | ||
Other Liabilities, Noncurrent | 609 | 645 | |
Labrador-Island Link Limited Partnership [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 492 | 400 | |
Income (Loss) from Equity Method Investments | $ 37 | 24 | |
Equity Method Investment, Ownership Percentage | 49.50% | ||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Indirect Ownership Percentage By Parent | 24.90% | ||
Equity Method Investments | $ 492 | 400 | |
NSP Maritime Link Inc. [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 510 | 315 | |
Income (Loss) from Equity Method Investments | $ 36 | 21 | |
Equity Method Investment, Ownership Percentage | 100.00% | ||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investments | $ 510 | 315 | |
Maritimes and Northeast Pipline [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 156 | 175 | |
Income (Loss) from Equity Method Investments | $ 23 | 23 | |
Equity Method Investment, Ownership Percentage | 12.90% | ||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investments | $ 156 | 175 | |
Saint Lucia Electricity Services Limited [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 39 | 39 | |
Income (Loss) from Equity Method Investments | $ 3 | 3 | |
Equity Method Investment, Ownership Percentage | 19.10% | ||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investments | $ 39 | 39 | |
Algonquin Power and Utilities Corporation [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Income (Loss) from Equity Method Investments | 0 | 18 | |
Bear Swamp Power Company Limited Liability Company [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 0 | 0 | |
Income (Loss) from Equity Method Investments | $ 23 | 11 | |
Equity Method Investment, Ownership Percentage | 50.00% | ||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital | $ 179 | ||
Equity Method Investments | $ 0 | 0 | |
Other Liabilities, Noncurrent | 188 | 217 | |
Other Investments | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investments | 18 | 18 | |
Income (Loss) from Equity Method Investments | 2 | 0 | |
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investments | $ 18 | $ 18 |
Investments Subject to Signif86
Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Consolidated Balance Sheets [Abstract] | |||
Assets, Current, Total | $ 2,526 | $ 2,511 | |
Property, Plant and Equipment, Net | 16,995 | 17,290 | |
Other Assets, Noncurrent, Total | 9,250 | 9,420 | |
Assets, Total | 28,771 | 29,221 | |
Liabilities, Current, Total | 3,946 | 3,724 | |
Liabilities, Noncurrent, Total | 17,644 | 18,681 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total | 7,181 | 6,816 | $ 4,334 |
Liabilities and Equity, Total | 28,771 | 29,221 | |
NSPML [Member] | |||
Consolidated Balance Sheets [Abstract] | |||
Assets, Current, Total | 225 | 439 | |
Property, Plant and Equipment, Net | 1,720 | 1,132 | |
Other Assets, Noncurrent, Total | 74 | 276 | |
Assets, Total | 2,019 | 1,847 | |
Liabilities, Current, Total | 180 | 219 | |
Long-term Debt | 1,287 | 1,288 | |
Liabilities, Noncurrent, Total | 42 | 25 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total | 510 | 315 | |
Liabilities and Equity, Total | $ 2,019 | $ 1,847 |
Other Income (Expenses), Net (D
Other Income (Expenses), Net (Details) $ in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2016CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Jun. 30, 2016USD ($) | |
Foreign Currency Transaction Gain (Loss), before Tax | $ (1) | $ 43 | ||
Other | 2 | 33 | ||
Other Nonoperating Income (Expense) | 2 | 174 | ||
Algonquin Power and Utilities Corporation [Member] | ||||
Gain (Loss) on Investments | 0 | 160 | ||
Gain Loss On Conversion Of Subscription Receipts | 0 | 63 | ||
The Barbados Light and Power Company Limited [Member] | ||||
Gain (Loss) on Investments | $ 53 | |||
Increase (Decrease) in Self Insurance Reserve | 0 | 53 | ||
Self Insurance Reserve | 30 | $ 22 | ||
Gain (Loss) On Investments After Tax | $ 43 | |||
TECO Energy Inc [Member] | ||||
Foreign Currency Transaction Gain (Loss), before Tax | $ 0 | (135) | ||
Convertible Subordinated Debt | $ 2,185 | |||
Convertible debenture interest rate | 4.00% |
Interest Expense, Net (Details)
Interest Expense, Net (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Interest on debt | $ 663 | $ 443 |
Beneficial Conversion Feature, net of tax | 0 | (43) |
Beneficial Conversion Feature, before tax | 0 | 62 |
Allowance for Funds Used During Construction | (7) | (13) |
Other | 42 | 17 |
Interest Expense (Income), Net | 698 | 585 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Interest on debt | 0 | 11 |
Convertible Debt [Member] | ||
Debt Instrument [Line Items] | ||
Interest on debt | $ 0 | $ 65 |
Income Taxes (Effective Tax Rat
Income Taxes (Effective Tax Rate) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income before provision for income taxes | $ 819 | $ 244 |
Statutory income tax rate | 31.00% | 31.00% |
Income taxes, at statutory income tax rates | $ 254 | $ 76 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (54) | (47) |
Financing deductions | (17) | (17) |
Manufacturing And Investment Allowances | (8) | (7) |
Foreign tax rate variance | 36 | (5) |
Tax effect of equity earnings | (12) | (10) |
Other | 4 | 1 |
Income Tax Expense (Benefit), Total | $ 520 | $ (22) |
Effective Income Tax Rate Reconciliation, Percent | 63.00% | (9.00%) |
Change in US Tax Reform [Abstract] | ||
Income Tax Reconciliation Revaluation Of US Non Regulated Deferred Income Taxes | $ 317 | |
Statutory income tax rate | 31.00% | 31.00% |
Deferred tax assets | $ 1,895 | $ 2,477 |
2018 tax rate [Member] | ||
Statutory income tax rate | 21.00% | |
Change in US Tax Reform [Abstract] | ||
Income Tax Reconciliation Revaluation Of US Non Regulated Deferred Income Taxes | $ 1,100 | |
Statutory income tax rate | 21.00% | |
TECO Energy Inc [Member] | ||
Non-taxable portion of mark-to-market gains related to pending TECO Energy acquisition | $ 0 | (21) |
Algonquin Power and Utilities Corporation [Member] | ||
Non-taxable portion of gains on transactions | $ 0 | $ 34 |
Income Taxes (Components) (Deta
Income Taxes (Components) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | $ 469 | $ (67) |
Income tax expense (recovery) | 520 | (22) |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 819 | 244 |
Income taxes, at statutory income tax rates | 254 | 76 |
Canada [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 24 | 13 |
Deferred income taxes | 3 | (113) |
Operating loss carry forwards | (40) | (2) |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 88 | 71 |
United States [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 24 | 18 |
Deferred income taxes | 384 | 151 |
Operating loss carry forwards | (194) | (104) |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 693 | 44 |
Other [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 3 | 15 |
Deferred income taxes | (1) | 0 |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | $ 38 | $ 129 |
Income Taxes (Deferred) (Detail
Income Taxes (Deferred) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Components of Deferred Tax Assets [Abstract] | ||
Deferred Tax Assets, Tax Loss Carry Forwards | $ 853 | $ 1,036 |
Tax credit carry forwards | 314 | 318 |
Regulatory liabilities - cost of removal | 208 | 388 |
Deferred Tax Assets, Derivative Instruments | 107 | 150 |
Pension and post-retirement liabilities | 124 | 153 |
Deferred Tax Assets, Other | 394 | 490 |
Deferred Tax Assets, Gross, Total | 2,000 | 2,535 |
Deferred Tax Assets, Valuation Allowance | (105) | (58) |
Deferred Tax Assets, Net of Valuation Allowance, Total | 1,895 | 2,477 |
Components of Deferred Tax Liabilities [Abstract] | ||
Deferred Tax Liabilities, Property, Plant and Equipment | (2,321) | (3,553) |
Deferred Tax Liabilities, Derivatives | (155) | (202) |
Deferred Tax Liabilities, Other | (292) | (269) |
Deferred Tax Liabilities, Gross, Total | (2,768) | (4,024) |
Noncurrent Deferred Tax Liabilities And Assets [Abstract] | ||
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent | 138 | 125 |
Deferred Tax Liabilities, Net, Noncurrent | (1,011) | (1,672) |
Deferred Tax Assets (Liabilities), Net, Noncurrent, Total | $ (873) | $ (1,547) |
Income Taxes (Carry Overs) (Det
Income Taxes (Carry Overs) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Tax Credit Carryforwards | $ 314 | $ 318 |
Tax Loss Carry Forwards Valuation Allowance [Abstract] | ||
Deferred Tax Assets, Valuation Allowance | 105 | 58 |
Domestic Tax Authority [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | 532 | 199 |
Deferred Tax Assets, Tax Credit Carryforwards | 0 | 0 |
Domestic Tax Authority [Member] | Capital Loss Carryforward [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | 77 | 77 |
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 16 | |
Valuation Allowance | (16) | |
Net Deferred Tax Assets | 0 | |
Domestic Tax Authority [Member] | Operating Loss Carryforward [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 164 | |
Valuation Allowance | (80) | |
Net Deferred Tax Assets | $ 84 | |
Domestic Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,037 | |
Domestic Tax Authority [Member] | Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,027 | |
Foreign Tax Authority [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 2,926 | 2,595 |
Deferred Tax Assets, Tax Credit Carryforwards | 314 | 318 |
Foreign Tax Authority [Member] | Capital Loss Carryforward [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | 13 | 14 |
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 2 | |
Valuation Allowance | (2) | |
Net Deferred Tax Assets | $ 0 | |
Foreign Tax Authority [Member] | Capital Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,019 | |
Foreign Tax Authority [Member] | Capital Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,018 | |
Foreign Tax Authority [Member] | Operating Loss Carryforward [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | $ 602 | |
Valuation Allowance | 0 | |
Net Deferred Tax Assets | $ 602 | |
Foreign Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,037 | |
Foreign Tax Authority [Member] | Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,024 | |
Foreign Tax Authority [Member] | State Operating Loss Carryforward [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 1,271 | 1,183 |
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 65 | |
Valuation Allowance | (2) | |
Net Deferred Tax Assets | $ 63 | |
Foreign Tax Authority [Member] | State Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,037 | |
Foreign Tax Authority [Member] | State Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,024 | |
Foreign Tax Authority [Member] | Tax credit carry forwards [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | $ 314 | |
Valuation Allowance | 0 | |
Net Deferred Tax Assets | $ 314 | |
Foreign Tax Authority [Member] | Tax credit carry forwards [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,019 | |
Other Tax Authority [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 29 | $ 22 |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 4 | |
Valuation Allowance | (4) | |
Net Deferred Tax Assets | $ 0 | |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,024 | |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,018 |
Income Taxes (Unrecognized Bene
Income Taxes (Unrecognized Benefits) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning, January 1 | $ 18 | $ 6 |
Increases due to tax positions related to current year | 1 | 12 |
Balance, December 31 | $ 19 | $ 18 |
Income Taxes (Reasonable Probab
Income Taxes (Reasonable Probablity of Tax Benefit) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract] | ||
Accrued interest | $ 1 | $ 1 |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Temporary Differences/Potential change | 822 | $ 667 |
Settlement with Taxing Authority [Member] | 2006 through 2010 years [Member] | Nova Scotia Power Inc. [Member] | Canada Revenue Agency [Member] | ||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Net amount in dispute | 62 | |
Prepaid amount in dispute | $ 23 |
Common Stock (Common Stock Roll
Common Stock (Common Stock Rollfoward) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) In Common Stock Shares [Roll Forward] | ||
Balance, January 1 | 210,020,000 | 147,210,000 |
Conversion of Convertible Debentures | 150,000 | 51,990,000 |
Issuance of common stock | 14,610,000 | 7,690,000 |
Issued for cash under Purchase Plans at market rate | 3,890,000 | 2,510,000 |
Discount on shares purchased under Dividend Reinvestment Plan | 0 | 0 |
Options exercised under senior management share option plan | 100,000 | 620,000 |
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period | 0 | 0 |
Balance, December 31 | 228,770,000 | 210,020,000 |
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Common Stock, Value, Issued, Beginning Balance | $ 4,738 | $ 2,157 |
Conversion of Convertible Debentures | 6 | 2,115 |
Issuance of common shares | 680 | 338 |
Issued for cash under Purchase Plans at market rate | 182 | 115 |
Discount on shares purchased under Dividend Reinvestment Plan Value | (9) | (5) |
Options exercised under senior management share option plan | 3 | 17 |
Stock-based compensation | 1 | 1 |
Common Stock, Value, Issued, Ending Balance | $ 5,601 | $ 4,738 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Percentage of Outstanding Stock Maximum | 10.00% | |
Employee Stock Option [Member] | ||
Increase (Decrease) In Common Stock Shares [Roll Forward] | ||
Options exercised under senior management share option plan | (103,825) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 1,300,000 | 1,500,000 |
Stock Compensation Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 6,500,000 | 6,600,000 |
Dividend Reinvestment [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 4,200,000 | 7,900,000 |
Common Stock (Narrative) (Detai
Common Stock (Narrative) (Details) - Emera Inc - Convertible Subordinated Debt [Member] $ / shares in Units, shares in Thousands, $ in Millions | Aug. 02, 2016 | Sep. 28, 2015CAD ($)$ / shares | Dec. 31, 2017NumberOfDaysshares |
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Sep. 29, 2025 | ||
Convertible debenture interest rate | 0.00% | ||
Common Stock, Shares, Issued | shares | 52,140 | ||
Common Stock, Conversion Rate | 95.00% | ||
Debt Instrument, Convertible, Threshold Trading Days | NumberOfDays | 20 | ||
Debentures Converted (%) | 99.90% | ||
TECO Energy Inc [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Convertible, Conversion Percent | 4.00% | ||
Aggregate proceeds of the Debenture Offering | $ | $ 2,185 | ||
Debt Instrument, Convertible, Conversion Per Share | $ / shares | $ 1,000 |
Earnings Per Share (Reconciliat
Earnings Per Share (Reconciliation of Basic and Diluted Earnings Per Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Earnings Per Share Reconciliation [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 266.1 | $ 227.2 |
Interest on Convertible Debt, Net of Tax | 0 | 0.2 |
Net Income (Loss) Available to Common Stockholders, Diluted, Total | $ 266.1 | $ 227.4 |
Weighted Average Number of Shares Outstanding Reconciliation [Abstract] | ||
Weighted Average Number of Shares Issued, Basic | 212.3 | 170.4 |
Weighted Average Number of Shares deferred share units outstanding | 1.1 | 1 |
Weighted Average Number of Shares Outstanding, Basic, Total | 213.4 | 171.4 |
Incremental Weighted Average Shares Attributable to Dilutive Effect [Abstract] | ||
IncrementalCommonSharesAttributableToShareBasedPaymentArrangements | 0.6 | 0.6 |
IncrementalCommonSharesAttributableToConversionOfDebtSecurities | 0.1 | 0.2 |
Weighted Average Number of Shares Outstanding, Diluted, Total | 214.1 | 172.2 |
Basic | $ 1.25 | $ 1.33 |
Diluted | $ 1.24 | $ 1.32 |
Accumulated Other Comprehensi98
Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | $ 106 | $ 137 |
Other comprehensive income (loss) before reclassifications | (345) | 0 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 51 | 19 |
Other equity method reclassification adjustment | 0 | (46) |
Net current period other comprehensive income (loss) | (294) | (27) |
Other | 0 | (4) |
Ending Balance | (188) | 106 |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (21) | (35) |
Other comprehensive income (loss) before reclassifications | 10 | 11 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 8 | 11 |
Other equity method reclassification adjustment | 0 | (8) |
Net current period other comprehensive income (loss) | 18 | 14 |
Other | 0 | 0 |
Ending Balance | (3) | (21) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (309) | (318) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 44 | 12 |
Other equity method reclassification adjustment | 0 | (3) |
Net current period other comprehensive income (loss) | 44 | 9 |
Other | 0 | 0 |
Ending Balance | (265) | (309) |
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (49) | 0 |
Other comprehensive income (loss) before reclassifications | 97 | (49) |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 0 | 0 |
Other equity method reclassification adjustment | 0 | 0 |
Net current period other comprehensive income (loss) | 97 | (49) |
Other | 0 | 0 |
Ending Balance | 48 | (49) |
Accumulated Net Available For Sale Securities Gain (Loss) [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (1) | 0 |
Other comprehensive income (loss) before reclassifications | 5 | 3 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | (1) | (4) |
Other equity method reclassification adjustment | 0 | 0 |
Net current period other comprehensive income (loss) | 4 | (1) |
Other | 0 | 0 |
Ending Balance | 3 | (1) |
Accumulated Foreign Currency Adjustment Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 486 | 490 |
Other comprehensive income (loss) before reclassifications | (457) | 35 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 0 | 0 |
Other equity method reclassification adjustment | 0 | (35) |
Net current period other comprehensive income (loss) | (457) | 0 |
Other | 0 | (4) |
Ending Balance | $ 29 | $ 486 |
Accumulated Other Comprehensi99
Accumulated Other Comprehensive Income (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Non-regulated fuel for generation and purchased power | $ 209 | $ 313 |
Income (Loss) from Equity Method Investments | 124 | 100 |
Operating, maintenance and general | 1,399 | 1,137 |
Other Income (Expense) | 2 | 174 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 819 | 244 |
Income tax expense (recovery) | 520 | (22) |
Net income | 299 | 266 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Net income | 51 | 65 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 7 | 11 |
Income tax expense (recovery) | 1 | 0 |
Net income | 8 | 11 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Power and Gas Swaps [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Non-regulated fuel for generation and purchased power | (3) | (2) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Income (Loss) from Equity Method Investments | 0 | 1 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Foreign Exchange Forward [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Regulated | 10 | 12 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 43 | 15 |
Income tax expense (recovery) | 1 | (3) |
Net income | 44 | 12 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Operating, maintenance and general | 40 | 41 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Operating, maintenance and general | (8) | (9) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Transition Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Pension and Other Postretirement Benefit Expense | 11 | (17) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Available For Sale Securities Gain Loss Including Portion Attributable To Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Other Income (Expense) | (1) | (4) |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | (1) | (4) |
Income tax expense (recovery) | 0 | 0 |
Net income | (1) | (4) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Equity Method Investment, Realized Gain (Loss) on Disposal | 0 | 54 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 0 | 54 |
Income tax expense (recovery) | 0 | (8) |
Net income | $ 0 | $ 46 |
Inventory (Details)
Inventory (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Inventory [Abstract] | ||
Fuel | $ 180 | $ 235 |
Raw Materials | 216 | 215 |
Emission Credits | 22 | 22 |
Inventory, Net, Total | $ 418 | $ 472 |
Derivatives (Derivative Assets
Derivatives (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | $ 434 | $ 407 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (181) | (131) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 491 | 606 |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (181) | (131) |
Current Derivative Assets or Liabilities [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Total | 141 | 145 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Total | 227 | 325 |
Long term derivative assets or liabilities [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Total | 112 | 131 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Total | 83 | 150 |
Cash Flow Hedging [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 7 | 10 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 7 | 27 |
Cash Flow Hedging [Member] | Power swaps [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 10 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 2 | 5 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 5 | 22 |
Regulatory Deferral Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 195 | 239 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 28 | 22 |
Regulatory Deferral Hedge [Member] | Power swaps [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 7 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 4 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 32 | 106 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 4 | 0 |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 137 | 83 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 10 | 9 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 6 | 33 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 7 | 2 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | 10 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 4 | 7 |
Held for Trading Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 230 | 158 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 456 | 555 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 125 | 47 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 162 | 71 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 105 | 111 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 294 | 484 |
Other Derivatives Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 2 |
Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 1 |
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 1 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (14) | (10) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (14) | (10) |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (167) | (121) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ (167) | $ (121) |
Derivatives (Master Netting Agr
Derivatives (Master Netting Agreements) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 181 | $ 131 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 181 | 131 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 14 | 10 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 14 | 10 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 167 | 121 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ 167 | $ 121 |
Derivatives (Derivative Cash Fl
Derivatives (Derivative Cash Flow Hedges Recorded in Income and AOCI and Notional Volumes of Outstanding Derivatives Designated as Cash Flow Hedges) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | |
Cash Flow Hedging [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $ 5 | ||
Cash Flow Hedging [Member] | Power swaps [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 3 | $ 2 | |
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | 0 | 2 | |
Cash Flow Hedging [Member] | Power swaps [Member] | Non-regulated fuel for generation and purchased power [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments | 0 | 0 | |
Derivative, Gain (Loss) on Derivative, Net | 3 | 2 | |
Cash Flow Hedging [Member] | Power swaps [Member] | Regulated [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Power swaps [Member] | GainLossOnInvestmentsMember1 | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Power swaps [Member] | Other Operating Income (Expense) [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Power swaps [Member] | Interest Expense [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | (1) | |
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | 0 | 0 | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Non-regulated fuel for generation and purchased power [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments | 0 | 0 | |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Regulated [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | GainLossOnInvestmentsMember1 | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | (1) | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Other Operating Income (Expense) [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | (10) | (12) | |
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | (3) | (22) | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Non-regulated fuel for generation and purchased power [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments | 0 | 0 | |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Regulated [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | (10) | (12) | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | GainLossOnInvestmentsMember1 | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Other Operating Income (Expense) [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Interest Expense [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2018 [Member} | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Notional Amount | $ 45 | ||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2019 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Notional Amount | 30 | ||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2020 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Notional Amount | 30 | ||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2021 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Notional Amount | 0 | ||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2022 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Notional Amount | $ 0 | ||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 2 | $ 2 |
Derivatives (Changes in Realize
Derivatives (Changes in Realized and Unrealized Gains (Losses) with Respect to Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | $ 157 | $ (258) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | 28 | 163 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Regulatory Assets [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | (33) | 40 |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Regulatory Liabilities [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | 83 | 101 |
Derivative, Gain (Loss) on Derivative, Net | (2) | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Inventory [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | (17) | 5 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Non-regulated fuel for generation and purchased power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | (3) | 17 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | 0 | (2) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Assets [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | (1) | 0 |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Liabilities [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | 1 | (1) |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Inventory [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Non-regulated fuel for generation and purchased power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | 0 | (1) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | (78) | (90) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Regulatory Assets [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | (4) | (2) |
Derivative, Gain (Loss) on Derivative, Net | 0 | 12 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Regulatory Liabilities [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | (30) | (30) |
Derivative, Gain (Loss) on Derivative, Net | 0 | (8) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Inventory [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | (30) | (44) |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Non-regulated fuel for generation and purchased power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | $ (14) | $ (18) |
Derivatives (Notional Volumes o
Derivatives (Notional Volumes of Commodity Swaps and Forward Contracts Designated for Regulatory Deferral) (Details) - Designated as Hedging Instrument [Member] - Regulatory Deferral Hedge [Member] - Commodity swaps and forwards [Member] bbl in Millions, T in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2017MMBTUTbbl | |
Coal [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Mass | T | 1 |
Coal [Member] | 2019-2021 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Mass | T | 1 |
Fuel [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 30 |
Fuel [Member] | 2019-2021 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 14 |
CrudeOilMember | 2018 [Member} | |
Derivative [Line Items] | |
DerivativeNonmonetaryNotionalAmountVolume | bbl | 0 |
CrudeOilMember | 2019-2021 [Member} | |
Derivative [Line Items] | |
DerivativeNonmonetaryNotionalAmountVolume | bbl | 1 |
Derivatives (Notional Volume106
Derivatives (Notional Volumes of Foreign Exchange Swaps and Forward Contracts Related to Commodity Contracts) (Details) - Regulatory Deferral Hedge [Member] - Foreign Exchange Swaps and Forward Contracts [Member] - Fuel [Member] $ in Millions | Dec. 31, 2017USD ($) |
2018 [Member} | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 144 |
Derivative, Average Forward Exchange Rate | 1.1061 |
Derivative, Percent of USD Required to Purchase | 79.00% |
2019-2021 [Member} | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 156 |
Derivative, Average Forward Exchange Rate | 1.2001 |
Derivative, Percent of USD Required to Purchase | 40.00% |
Derivatives (Realized and Unrea
Derivatives (Realized and Unrealized Gains (Losses) with Respect to HFT Derivatives) (Details) - Designated as Hedging Instrument [Member] - Held for Trading Hedge [Member] - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | $ 420 | $ 59 |
Power swaps and physical contracts [Member] | Non-regulated fuel for generation and purchased power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | 2 | 0 |
Power swaps and physical contracts [Member] | Other Operating Income (Expense) [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | 7 | (1) |
Natural gas swaps, futures, forwards, physical contracts [Member] | Non-regulated fuel for generation and purchased power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | 10 | (7) |
Natural gas swaps, futures, forwards, physical contracts [Member] | Other Operating Income (Expense) [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | 401 | 69 |
Foreign Exchange Option [Member] | Other Operating Income (Expense) [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | $ 0 | $ (2) |
Derivatives (Notional Volume108
Derivatives (Notional Volumes of Outstanding HFT Derivatives) (Details) MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)MMBTUMWh | |
Foreign Exchange Option [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ | $ 2 |
Foreign Exchange Option [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ | 4 |
Foreign Exchange Option [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ | 0 |
Foreign Exchange Option [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ | 0 |
Foreign Exchange Option [Member] | 2022 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ | $ 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 250 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 56 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 21 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 8 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Sales [Member] | 2022 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 2 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 325 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 134 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 62 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 44 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Natural Gas [Member] | Cost of Sales [Member] | 2022 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 41 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 8 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 1 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Sales [Member] | 2022 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2018 [Member} | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 7 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 2 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2020 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2021 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Designated as Hedging Instrument [Member] | Held for Trading Hedge [Member] | Power [Member] | Cost of Sales [Member] | 2022 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Derivatives (Realized and Un109
Derivatives (Realized and Unrealized Gains (Losses) with Respect to Cash Flow Hedges) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2016USD ($) | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | $ 157 | $ (258) | ||
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | Line of Credit [Member] | Brunswick Pipeline [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Line of Credit Facility, Expiration Date | Dec. 31, 2019 | Dec. 31, 2019 | ||
Convertible Subordinated Debt | $ 250 | |||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 2 | $ 2 | ||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Operating Income (Expense) [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | $ 0 | $ 0 | ||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | 2 | 2 | ||
Designated as Hedging Instrument [Member] | Foreign Exchange Option [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | 0 | (87) | ||
Designated as Hedging Instrument [Member] | Foreign Exchange Option [Member] | Other Operating Income (Expense) [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | 0 | (87) | ||
Designated as Hedging Instrument [Member] | Foreign Exchange Option [Member] | Interest Expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | $ 0 | $ 0 |
Derivatives (Credit Risk Exposu
Derivatives (Credit Risk Exposure) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Credit Derivatives [Line Items] | ||
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure | $ 1,394 | $ 1,290 |
Total cash deposits/collateral on hand | 119 | 91 |
Accounts Receivable [Member] | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure | 1,148 | 1,019 |
Total cash deposits/collateral on hand | 247 | 271 |
Financial assets, considered to be past due | $ 90 | 104 |
Derivative, Credit Risk, Past Due Days Outstanding | 69 days | |
Fair Value of assets | $ 78 | $ 91 |
Derivatives (Concentration Risk
Derivatives (Concentration Risk) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 100.00% | 100.00% |
Concentration Risk | $ 1,394 | $ 1,290 |
Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 81.00% | 78.00% |
Concentration Risk | $ 1,141 | $ 1,014 |
Accounts Receivable [Member] | A- Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 4.00% | 4.00% |
Concentration Risk | $ 55 | $ 52 |
Accounts Receivable [Member] | BBB- to BBB+ Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 4.00% | 5.00% |
Concentration Risk | $ 61 | $ 60 |
Accounts Receivable [Member] | Not Rated [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 7.00% | 4.00% |
Concentration Risk | $ 96 | $ 57 |
Accounts Receivable, Residential [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 23.00% | 24.00% |
Concentration Risk | $ 326 | $ 315 |
Accounts Receivable, Commercial [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 11.00% | 13.00% |
Concentration Risk | $ 161 | $ 170 |
Accounts Receivable, Industrial [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 3.00% | 3.00% |
Concentration Risk | $ 46 | $ 38 |
Accounts Receivable, Other [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 7.00% | 5.00% |
Concentration Risk | $ 96 | $ 69 |
Regulated utilities [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 44.00% | 45.00% |
Concentration Risk | $ 629 | $ 592 |
Trading group [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 15.00% | 13.00% |
Concentration Risk | $ 212 | $ 169 |
Other Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 22.00% | 20.00% |
Concentration Risk | $ 300 | $ 253 |
Derivative [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 19.00% | 22.00% |
Concentration Risk | $ 253 | $ 276 |
Derivative [Member] | A- Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 15.00% | 20.00% |
Concentration Risk | $ 207 | $ 252 |
Derivative [Member] | BBB- to BBB+ Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 1.00% | 0.00% |
Concentration Risk | $ 10 | $ 1 |
Derivative [Member] | Not Rated [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 3.00% | 2.00% |
Concentration Risk | $ 36 | $ 23 |
Derivatives (Cash Collateral) (
Derivatives (Cash Collateral) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments [Abstract] | ||
Derivative, Collateral, Obligation to Return Cash | $ 119 | $ 91 |
Derivative, Collateral, Right to Reclaim Cash | 99 | 52 |
Collateral Already Posted, Aggregate Fair Value | $ 310 | $ 475 |
Fair Values (Fair Value - Deriv
Fair Values (Fair Value - Derivatives) (Details) - Fair Value, Measurements, Recurring [Member] - Designated as Hedging Instrument [Member] - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | $ 253 | $ 276 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 310 | 475 |
Fair Value, Net Asset (Liability), Total | (57) | (199) |
Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 7 | 10 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 7 | 27 |
Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 10 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 4 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | 23 |
Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 181 | 229 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 13 | 12 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 32 | 106 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 4 | |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 127 | 74 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 33 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | 2 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 12 | 9 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | |
Regulatory Deferral Hedge [Member] | Power purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 7 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 3 | 4 |
Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 63 | 37 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 290 | 434 |
Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 12 | (6) |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 17 | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 50 | |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 51 | 43 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 240 | 417 |
Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | |
Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Inputs, Level 1 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 14 | 21 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 65 | 25 |
Fair Value, Net Asset (Liability), Total | (51) | (4) |
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Forward [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 10 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 4 |
Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 10 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 4 |
Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 9 | 18 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 8 | 5 |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 8 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 4 | 3 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 7 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 3 | 4 |
Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | (7) |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 55 | 16 |
Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | (7) |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 12 | |
Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 49 | |
Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | 4 |
Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 2 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 205 | 215 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 62 | 61 |
Fair Value, Net Asset (Liability), Total | 143 | 154 |
Fair Value, Inputs, Level 2 [Member] | Foreign Exchange Forward [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | 23 |
Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | 23 |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 172 | 210 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | 7 |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 32 | 106 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 4 | |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 127 | 74 |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 25 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | 1 |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 8 | 5 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | |
Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 29 | 5 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 52 | 29 |
Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 3 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | |
Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | |
Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 26 | 4 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 47 | 24 |
Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | |
Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 2 | |
Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Inputs, Level 3 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 34 | 40 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 183 | 389 |
Fair Value, Net Asset (Liability), Total | (149) | (349) |
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Forward [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Power purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 34 | 39 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 183 | 389 |
Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 9 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | (4) | |
Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 25 | 39 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 187 | 389 |
Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | $ 0 | |
Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | $ 0 |
Fair Values (fair value of the
Fair Values (fair value of the Level 3 financial assets) (Details) - Designated as Hedging Instrument [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 40 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 10 |
Net transfers out of Level 3 | 15 |
Ending Balance | 34 |
Regulated fuel for generation and purchased power [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated anmd non-gulated fuel for generation and purchased power | (1) |
Regulatory Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Unrealized gains (losses) included in regulatory assets or liabilities | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulated fuel for generation and purchased power [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated anmd non-gulated fuel for generation and purchased power | (1) |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Unrealized gains (losses) included in regulatory assets or liabilities | 1 |
Regulatory Deferral Hedge [Member] | Oil Financial Derivatives [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 1 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
Regulatory Deferral Hedge [Member] | Oil Financial Derivatives [Member] | Regulatory Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated anmd non-gulated fuel for generation and purchased power | 0 |
Unrealized gains (losses) included in regulatory assets or liabilities | (1) |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 39 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 1 |
Net transfers out of Level 3 | 15 |
Ending Balance | 25 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated anmd non-gulated fuel for generation and purchased power | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Regulatory Assets [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Unrealized gains (losses) included in regulatory assets or liabilities | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 9 |
Net transfers out of Level 3 | 0 |
Ending Balance | 9 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated anmd non-gulated fuel for generation and purchased power | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Regulatory Assets [Member] | Derivative Financial Instruments, Assets [Member] | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Unrealized gains (losses) included in regulatory assets or liabilities | $ 0 |
Fair Values (fair value of t115
Fair Values (fair value of the Level 3 financial Liabilities) (Details) - Designated as Hedging Instrument [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($) | |
Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 389 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (211) |
Net transfers out of Level 3 | 5 |
Ending Balance | 183 |
Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | (1) |
Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 1 |
Oil Financial Derivatives [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
Oil Financial Derivatives [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Oil Financial Derivatives [Member] | Regulated fuel for generation and purchased power [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 0 |
Oil Financial Derivatives [Member] | Non-regulated fuel for generation and purchased power [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulated fuel for generation and purchased power [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | (1) |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Non-regulated fuel for generation and purchased power [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 1 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 389 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (206) |
Net transfers out of Level 3 | 4 |
Ending Balance | 187 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Natural Gas [Member] | Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (5) |
Net transfers out of Level 3 | 1 |
Ending Balance | (4) |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | 0 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Non-regulated fuel for generation and purchased power [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Increase (reduction) in benefit included in regulated and nonregulated fuel for generation and purchased power | $ 0 |
Fair Values (Quantitative Infor
Fair Values (Quantitative Information Significant Unobservable Inputs - Assets & Liabilities) (Details) - Designated as Hedging Instrument [Member] - Fair Value, Inputs, Level 3 [Member] - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 183 | $ 389 |
Derivative Assets (Liabilities), at Fair Value, Net, Total | (149) | (349) |
Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | 34 | 40 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ (6) | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 24.88 | |
Fair Value Inputs, Entity Credit Risk | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 117.9 | |
Fair Value Inputs, Entity Credit Risk | 0.01% | |
Fair Value Inputs, Discount Rate | 0.13% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 95.46 | |
Fair Value Inputs, Entity Credit Risk | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 1 | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 24.88 | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 117.9 | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.13% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 92.93 | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 2 | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 94.5 | |
Fair Value Inputs, Correlation factor | 0.94% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 117 | |
Fair Value Inputs, Correlation factor | 0.99% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 105.52 | |
Fair Value Inputs, Correlation factor | 0.96% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 8 | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 63.48 | |
Fair Value Inputs, Correlation factor | 0.94% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 117 | |
Fair Value Inputs, Correlation factor | 0.99% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Modelled pricing with correlation factor [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 102.68 | |
Fair Value Inputs, Correlation factor | 0.96% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 172 | $ 386 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 1.89 | $ 1.55 |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.00% | 0.00% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 11.81 | $ 11.87 |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.07% |
Fair Value Inputs, Discount Rate | 0.12% | 0.14% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 4.64 | $ 6.26 |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.02% | 0.02% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 18 | $ 27 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 2.06 | $ 1.41 |
Fair Value Inputs, Probability of Default | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.00% | 0.00% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 8.24 | $ 11.87 |
Fair Value Inputs, Probability of Default | 0.05% | 0.07% |
Fair Value Inputs, Discount Rate | 0.29% | 0.32% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 3.61 | $ 3.87 |
Fair Value Inputs, Probability of Default | 0.00% | 0.01% |
Fair Value Inputs, Discount Rate | 0.06% | 0.05% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 15 | $ 3 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 2.15 | $ 1.83 |
Fair Value Inputs, Comparability Adjustments | 0.08% | (0.11%) |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.00% | 0.00% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 12.52 | $ 11.87 |
Fair Value Inputs, Comparability Adjustments | 0.71% | 0.64% |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.05% |
Fair Value Inputs, Discount Rate | 0.08% | 0.10% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 8.94 | $ 5.93 |
Fair Value Inputs, Comparability Adjustments | 0.53% | 0.27% |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.01% |
Fair Value Inputs, Discount Rate | 0.01% | 0.01% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 7 | $ 12 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 2.04 | $ 1.83 |
Fair Value Inputs, Comparability Adjustments | 0.08% | (0.11%) |
Fair Value Inputs, Probability of Default | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.00% | 0.00% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 12.52 | $ 11.87 |
Fair Value Inputs, Comparability Adjustments | 0.71% | 0.64% |
Fair Value Inputs, Probability of Default | 0.00% | 0.05% |
Fair Value Inputs, Discount Rate | 0.09% | 0.10% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Modelled pricing with basis adjustments [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 6.42 | $ 6.16 |
Fair Value Inputs, Comparability Adjustments | 0.52% | 0.39% |
Fair Value Inputs, Probability of Default | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.01% | 0.00% |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 1 | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | $ 69.64 | |
Fair Value Inputs, Probability of Default | 0.80% |
Fair Values (Assets and Liabili
Fair Values (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Measurement [Domain] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | $ 15,217 | $ 15,723 |
Reported Value Measurement [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 13,881 | 14,744 |
Long-term Debt, Fair Value | 15,217 | 15,723 |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 69 | 78 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 14,346 | 14,843 |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | $ 802 | $ 802 |
Fair Values (Hybrid Notes) (Det
Fair Values (Hybrid Notes) (Details) - Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - Foreign Currency Gain (Loss) [Member] $ in Billions | 12 Months Ended | ||
Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | |
Hybrid Instruments [Line Items] | |||
Hybrid Instruments at Fair Value, Net | $ 1.2 | ||
Other Comprehensive Income (Loss) [Member] | |||
Hybrid Instruments [Line Items] | |||
Unrealized Gain (Loss) on Foreign Currency Derivatives, Net, before Tax | $ 97,000,000 | $ 49,000,000 | |
Gain (Loss) on Foreign Currency Cash Flow Hedge Ineffectiveness | $ 0 | $ 0 |
Regulatory Assets and Liabil119
Regulatory Assets and Liabilities (ROE of Tampa Electric) (Details) - Tampa Electric Division [Member] - Florida Public Service Commission [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 110 |
Public Utilities Approved Return On Equity Percentage Trigger Rate Minimum | 9.25% |
Public Utilities Approved Return On Equity Percentage Trigger Rate Maximum | 11.25% |
Public Utilities, Approved Equity Capital Structure, Percentage | 54.00% |
Minimum [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Return on Equity, Percentage | 9.25% |
Maximum [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Return on Equity, Percentage | 11.25% |
Regulatory Assets and Liabil120
Regulatory Assets and Liabilities (ROE of People Gas System Division) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2016USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||||
Regulatory Assets | $ 1,376 | $ 1,322 | |||
Regulatory Assets, Current | 138 | 80 | |||
Environmental remediations [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Regulatory Assets | $ 41 | $ 49 | |||
Peoples Gas System Division [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public Utilities, Approved Return on Equity, Percentage | 10.75% | ||||
Peoples Gas System Division [Member] | Environmental remediations [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Reduction in annual depreciation | $ 16 | ||||
Regulatory Assets | $ 32 | ||||
Regulatory Assets, Current | $ 21 | ||||
Depreciation | $ 5 | $ 16 | |||
Peoples Gas System Division [Member] | Maximum [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public Utilities, Approved Return on Equity, Percentage | 11.75% | ||||
Public Utilities, Approved Equity Capital Structure, Percentage | 11.75% | ||||
Peoples Gas System Division [Member] | Minimum [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public Utilities, Approved Return on Equity, Percentage | 9.75% | ||||
Public Utilities, Approved Equity Capital Structure, Percentage | 9.25% | ||||
Peoples Gas System Division [Member] | Mid Point [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public Utilities, Approved Equity Capital Structure, Percentage | 10.75% |
Regulatory Assets and Liabil121
Regulatory Assets and Liabilities (ROE of New Mexico Gas Company) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($) | |
New Mexico Gas Company [Member] | New Mexico Public Regulatory [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Bill Reduction | $ 4 |
Regulatory Assets and Liabil122
Regulatory Assets and Liabilities (ROE of NSPI) (Details) - CAD ($) $ in Millions | Jul. 19, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities refunds payable to customers | $ 17 | ||
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes | 53 | ||
Regulatory Liabilities | 2,468 | $ 1,639 | |
Regulatory Assets | $ 1,376 | 1,322 | |
Fuel Adjustment Mechanism Liability Deferral Account [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities refunds payable to customers | $ 36 | ||
Nova Scotia Power Inc. [Member] | Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulated common equity component | 40.00% | ||
Nova Scotia Power Inc. [Member] | Rate Stability Plan fuel costs for 2017 through 2019 [Member] | Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved average annual increase | 1.10% | ||
Nova Scotia Power Inc. [Member] | Minimum [Member] | Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Return on Equity, Percentage | 8.75% | ||
Nova Scotia Power Inc. [Member] | Maximum [Member] | Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Return on Equity, Percentage | 9.25% |
Regulatory Assets and Liabil123
Regulatory Assets and Liabilities (Emera Maine ) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017CAD ($)km | Dec. 31, 2016USD ($) | Dec. 31, 2016CAD ($) | |
Public Utilities, General Disclosures [Line Items] | ||||
Regulatory Assets | $ 1,376 | $ 1,322 | ||
Emera Maine [Member] | Maine Public Utilities Commission (MPUC) [Member] | Electric Distribution [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 9.00% | |||
Public Utilities, Approved Equity Capital Structure, Percentage | 49.00% | |||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.75% | |||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 4 | |||
Bangor Hydro District [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Electric Transmission [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 10.57% | 10.57% | ||
Bangor Hydro District [Member] | Minimum [Member] | Federal Energy Regulatory Commission (FERC) [Member] | ISO-New England (ISO-NE) [Member] | Electric Transmission [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 11.07% | 11.07% | ||
Bangor Hydro District [Member] | Maximum [Member] | Federal Energy Regulatory Commission (FERC) [Member] | ISO-New England (ISO-NE) [Member] | Electric Transmission [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 11.74% | 11.74% | ||
Maine Public Service District [Member] | Federal Energy Regulatory Commission (FERC) [Member] | Electric Transmission [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 9.60% | 10.20% | ||
Barbados Light & Power Company Limited [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 10.00% | 10.00% | ||
Dominica Electricity Services Ltd. [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 15.00% | 15.00% | ||
Grand Bahama Power Company Limited [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Approved Return on Equity, Percentage | 8.50% | 8.80% | 8.80% | |
Brunswick Pipeline [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Length Of Pipeline | km | 145 |
Regulatory Assets and Liabil124
Regulatory Assets and Liabilities (Unamortized Defeance Costs and Standard Cost Recovery) (Details) $ in Thousands, $ in Billions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | |
Nova Scotia Power Inc. [Member] | Defeased Debt [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Long-term Debt | $ 0.7 | $ 0.8 | |
Grand Bahama Power Company Limited [Member] | Steam Plant [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment | $ 21,000 |
Regulatory Assets and Liabil125
Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | $ 138 | $ 80 |
Regulatory Assets, Noncurrent | 1,238 | 1,242 |
Regulatory Assets, Total | 1,376 | 1,322 |
Deferred income tax regulatory assets [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 667 | 632 |
Pension and post-retirement medical plan [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 345 | 373 |
Storm Reserve [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 59 | 0 |
Environmental remediations [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 41 | 49 |
Unamortized Defeasance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 32 | 39 |
Demand Side Management [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 28 | 32 |
GBPC Hurricane Matthew restoration [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 28 | 28 |
Stranded cost recovery [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 25 | 27 |
Cost Recovery Clauses [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 15 | 15 |
Deferrals related to derivative instruments [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 13 | 19 |
Debt Basis Adjustment [Member] [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 17 | 12 |
Deferred Bond Refinancing Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 7 | 9 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | $ 99 | $ 87 |
Regulatory Assets and Liabil126
Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Liabilities [Line Items] | ||
Regulatory Liability, Current | $ 226 | $ 362 |
Regulatory Liability, Noncurrent | 2,242 | 1,277 |
Regulatory Liabilities, Total | 2,468 | 1,639 |
Deferred income tax regulatory assets [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 1,116 | 26 |
Accumulated reserve - cost of removal [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 894 | 990 |
Deferrals related to derivative instruments [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 182 | 230 |
Fuel Adjustment Mechanism Liability [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 177 | 94 |
Cost Recovery Clauses Liability [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 51 | 153 |
Self Insurance Fund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 28 | 30 |
Bill Reduction Credit [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 4 | 10 |
Storm Reserve [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 0 | 75 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | $ 16 | $ 31 |
Regulatory Assets and Liabil127
Regulatory Assets and Liabilities (FAM Roll Forward) (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fuel Adjustment Mechanism [Roll Forward] | ||||
Beginning balance | $ 80 | |||
Over Under Recovery Of Current Period Fuel Costs | 0 | $ 29 | ||
Recovery From Rebate | 0 | 12 | ||
Regulated fixed cost deferral related to 2015 demand side management | 0 | 0 | ||
Interest On Fuel Adjustment Mechanism Balance | 0 | 61 | ||
Ending balance | 138 | 80 | ||
Regulatory Assets, Current | 138 | 80 | $ 138 | $ 80 |
Regulatory Liability, Current | 226 | 362 | ||
Regulatory Liability, Noncurrent | 2,242 | $ 1,277 | ||
FAM [Member] | ||||
Fuel Adjustment Mechanism [Roll Forward] | ||||
Beginning balance | (28) | |||
Over Under Recovery Of Current Period Fuel Costs | (29) | (29) | ||
Recovery From Rebate | (12) | (12) | ||
Fuel Adjustment Mechanism Audit Disallowance | 0 | 0 | ||
Non Fuel Revenues To Offset Potential Fuel Related Rate Increase | (5) | (27) | ||
Interest On Fuel Adjustment Mechanism Balance | (5) | 1 | ||
Ending balance | (160) | |||
Regulatory Assets, Current | $ (160) | $ (28) | $ (160) |
Regulatory Assets and Liabil128
Regulatory Assets and Liabilities (Other) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | |
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 1,376 | $ 1,322 | |
TECO Energy Inc [Member] | |||
Regulatory Assets [Line Items] | |||
Public Utilities Annual Bill Reduction To Customers | $ 4 |
Regulatory Assets and Liabil129
Regulatory Assets and Liabilities (Storm reserve & Solar investment) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | Sep. 10, 2017USD ($) | Dec. 31, 2016CAD ($) | |
Regulatory Assets [Line Items] | ||||||
Regulatory Assets | $ 1,376 | $ 1,322 | ||||
Tampa Electric Division [Member] | Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew Restoration [Member] | OM&G [Member] | Other Regulatory Assets (Liabilities) [Member] | LossFromCatastrophesMember | ||||||
Regulatory Assets [Line Items] | ||||||
Storm cost | $ 10 | |||||
Tampa Electric Division [Member] | Hurricane Irma Restoration [Member] | OM&G [Member] | Capital Expenditures [Member] | LossFromCatastrophesMember | ||||||
Regulatory Assets [Line Items] | ||||||
Storm Reserve | $ 8 | |||||
Tampa Electric Division [Member] | Hurricane Irma Restoration [Member] | OM&G [Member] | Other Regulatory Assets (Liabilities) [Member] | LossFromCatastrophesMember | ||||||
Regulatory Assets [Line Items] | ||||||
Storm cost | $ 4 | |||||
Storm Reserve | $ 93 | |||||
Tampa Electric Division [Member] | SoBRA [Member] | Capital Expenditures [Member] | ||||||
Regulatory Assets [Line Items] | ||||||
Estimated Investement in projects | $ 850 | |||||
Capacity Of Utility Project | MW | 600 | |||||
Estimated revenue | $ 26 | |||||
Estimated revenue in MW | MW | 145 |
Related Paty Transactions (Tran
Related Paty Transactions (Transactions Between Emera and Associated Parties) (Details) - Natural gas transportation capacity [Member] - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
NSP Maritime Link Inc. [Member] | ||
Related Party Transaction [Line Items] | ||
Revenue from Related Parties | $ 17 | $ 18 |
Maritimes and Northeast Pipline [Member] | ||
Related Party Transaction [Line Items] | ||
Revenue from Related Parties | $ 28 | $ 29 |
Receivables And Other Curren131
Receivables And Other Current Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Costs Capitalized Prepaid Expense and Other Assets, Current [Abstract] | ||
Customer accounts receivable | $ 985 | |
Other | 42 | |
Capitalized transportation capacity | $ 89 | 190 |
Prepaid expenses | 59 | 57 |
Due From Related Parties | 5 | 16 |
Net investment in direct financing lease | 8 | 8 |
Income Taxes Receivable, Current | 24 | 33 |
Other | 0 | 5 |
Receivables and other current assets | $ 1,326 | $ 1,323 |
Property, plant and equipment
Property, plant and equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 24,197 | $ 23,673 |
Less: Accumulated depreciation | (7,824) | (7,787) |
Property, Plant and Equipment, Net | 16,995 | 17,290 |
Net Book Value | 16,373 | 15,886 |
Electric Generation Equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 11,010 | 10,553 |
Electric Generation Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 3 years | |
Electric Generation Equipment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 131 years | |
Electric Transmission [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 2,786 | 2,799 |
Electric Transmission [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 15 years | |
Electric Transmission [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 80 years | |
Electric Distribution [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 5,660 | 5,715 |
Electric Distribution [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 4 years | |
Electric Distribution [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 80 years | |
Gas, Transmission and Distribution Equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 2,867 | 2,895 |
Gas, Transmission and Distribution Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 7 years | |
Gas, Transmission and Distribution Equipment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 85 years | |
Other Energy Equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 1,874 | 1,711 |
Other Energy Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 3 years | |
Other Energy Equipment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 60 years | |
Construction in Progress [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | $ 622 | $ 1,404 |
Employee Benefit Plans (Changes
Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and the Funded Status) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | $ 2,208 | |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 2,408 | $ 2,208 |
Pension Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 2,607 | 1,520 |
Addition of Teco | 0 | 1,035 |
Defined Benefit Plan, Service Cost | 49 | 35 |
Defined Benefit Plan, Contributions by Plan Participants | 8 | 8 |
Defined Benefit Plan, Interest Cost | 99 | 79 |
Defined Benefit Plan, Plan Amendments | 0 | 0 |
Benefits Paid | (129) | (94) |
Defined Benefit Plan, Actuarial Gain (Loss) | 171 | (2) |
Special Termination | (35) | 0 |
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss) | (87) | 26 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 2,683 | 2,607 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | 2,208 | 1,300 |
Addition of Teco | 0 | 830 |
Defined Benefit Plan, Contributions by Employer | 109 | 49 |
Defined Benefit Plan, Contributions by Plan Participants | 8 | 8 |
Benefits Paid | (129) | (94) |
Defined Benefit Plan, Actual Return on Plan Assets | 313 | 93 |
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets | (67) | 22 |
Special Termination | (34) | 0 |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 2,408 | 2,208 |
Defined Benefit Plan, Funded Status of Plan [Abstract] | ||
Defined Benefit Plan, Funded Status of Plan | (275) | (399) |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 358 | 88 |
Addition of Teco | 0 | 277 |
Defined Benefit Plan, Service Cost | 5 | 4 |
Defined Benefit Plan, Contributions by Plan Participants | 4 | 0 |
Defined Benefit Plan, Interest Cost | 14 | 9 |
Defined Benefit Plan, Plan Amendments | 0 | 2 |
Benefits Paid | (27) | (16) |
Defined Benefit Plan, Actuarial Gain (Loss) | 25 | (12) |
Special Termination | 0 | 0 |
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss) | (23) | 6 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 356 | 358 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | 39 | 6 |
Addition of Teco | 0 | 29 |
Defined Benefit Plan, Contributions by Employer | 27 | 17 |
Defined Benefit Plan, Contributions by Plan Participants | 4 | 0 |
Benefits Paid | (27) | (16) |
Defined Benefit Plan, Actual Return on Plan Assets | 5 | 2 |
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets | (3) | 1 |
Special Termination | 0 | 0 |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 45 | 39 |
Defined Benefit Plan, Funded Status of Plan [Abstract] | ||
Defined Benefit Plan, Funded Status of Plan | $ (311) | $ (319) |
Employee Benefit Plans (Plans w
Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Aggregate Projected Benefit Obligation | $ 2,655 | $ 2,579 |
Aggregate Fair Value of Plan Assets | 2,370 | 2,171 |
Funded Status | (285) | (408) |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Aggregate Projected Benefit Obligation | 325 | 358 |
Aggregate Fair Value of Plan Assets | 6 | 39 |
Funded Status | $ (319) | $ (319) |
Employee Benefit Plans (Accumul
Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - Pension Plan [Member] - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | ||
ABO | $ 1,608 | $ 2,462 |
Fair Value of Plan Assets | 1,409 | 2,171 |
Funded Status | $ (199) | $ (291) |
Employee Benefit Plans (Amounts
Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets ) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | $ (41) | $ (58) |
Liabilities, Noncurrent | (559) | (669) |
Pension Plan [Member] | ||
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | (23) | (41) |
Liabilities, Noncurrent | (264) | (367) |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 10 | 9 |
Deferred Tax Assets, Defined Benefit Plan | (15) | (16) |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 548 | 620 |
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total | 286 | 237 |
Non-pension Benefit Plans [Member | ||
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | (18) | (17) |
Liabilities, Noncurrent | (295) | (302) |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 0 | 0 |
Deferred Tax Assets, Defined Benefit Plan | (1) | 1 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 73 | 45 |
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total | $ (239) | $ (275) |
Employee Benefit Plans (Change
Employee Benefit Plans (Change in AOCI ) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($) | |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | $ 636 |
Balance, December 31 | 563 |
Pension Plan [Member] | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 330 |
Amortized in current period, Net Actuarial Gain (Loss) | (38) |
Current year addition to AOCI | (8) |
Balance, December 31 | 284 |
Pension Plan [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | (3) |
Amortized in current period, Net Prior Service Cost (Credit) | 0 |
Current year addition to AOCI | 0 |
Balance, December 31 | (3) |
Pension Plan [Member] | Regulatory Assets [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 309 |
Amortized in current period, Net Actuarial Gain (Loss) | (17) |
Current year addition to AOCI | (10) |
Balance, December 31 | 282 |
Non-pension Benefit Plans [Member | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 44 |
Balance, December 31 | 74 |
Non-pension Benefit Plans [Member | Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 15 |
Amortized in current period, Net Actuarial Gain (Loss) | (2) |
Current year addition to AOCI | (2) |
Balance, December 31 | 11 |
Non-pension Benefit Plans [Member | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | (19) |
Amortized in current period, Net Prior Service Cost (Credit) | 8 |
Current year addition to AOCI | 0 |
Balance, December 31 | (11) |
Non-pension Benefit Plans [Member | Regulatory Assets [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 48 |
Amortized in current period, Net Actuarial Gain (Loss) | 1 |
Current year addition to AOCI | 25 |
Balance, December 31 | $ 74 |
Employee Benefit Plans (AOCI )
Employee Benefit Plans (AOCI ) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses | $ (284) | $ (330) |
Past service (gains) | (3) | (3) |
Regulatory Assets | 282 | 309 |
Accumulated Other Comprehensive Income (Loss), before Tax, Total | 563 | 636 |
Deferred Tax Assets, Defined Benefit Plan | (15) | (16) |
Net amount in AOCI after tax adjustment | 548 | 620 |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses | (11) | (15) |
Past service (gains) | (11) | (19) |
Regulatory Assets | 74 | 48 |
Accumulated Other Comprehensive Income (Loss), before Tax, Total | 74 | 44 |
Deferred Tax Assets, Defined Benefit Plan | (1) | 1 |
Net amount in AOCI after tax adjustment | $ 73 | $ 45 |
Employee Benefit Plans (Benefit
Employee Benefit Plans (Benefit Cost Components) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Service Cost | $ 49 | $ 35 |
Defined Benefit Plan, Interest Cost | 99 | 79 |
Defined Benefit Plan, Expected Return on Plan Assets | (129) | (97) |
Defined Benefit Plan, Amortization of Gains (Losses) | 38 | 42 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | (1) |
Current year amortization of regulatory asset liabilities | 17 | 9 |
Settlement, curtailment | (1) | 0 |
Net Periodic Benefit Cost, Total | 73 | 67 |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Service Cost | 5 | 4 |
Defined Benefit Plan, Interest Cost | 14 | 9 |
Defined Benefit Plan, Expected Return on Plan Assets | (3) | (1) |
Defined Benefit Plan, Amortization of Gains (Losses) | 2 | 2 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | (8) | (8) |
Current year amortization of regulatory asset liabilities | (1) | 0 |
Settlement, curtailment | 0 | 0 |
Net Periodic Benefit Cost, Total | $ 9 | $ 6 |
Employee Benefit Plans (Asset C
Employee Benefit Plans (Asset Class) (Details) | Dec. 31, 2017 |
Pension Plan [Member] | Short-term securities | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 5.00% |
Pension Plan [Member] | Short-term securities | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 0.00% |
Pension Plan [Member] | Fixed Income Funds [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 50.00% |
Pension Plan [Member] | Fixed Income Funds [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 35.00% |
Pension Plan [Member] | Equity Securities, Canadian [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 22.00% |
Pension Plan [Member] | Equity Securities, Canadian [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 12.00% |
Pension Plan [Member] | Equity Securities, Non Canadian [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 55.00% |
Pension Plan [Member] | Equity Securities, Non Canadian [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 30.00% |
Non-pension Benefit Plans [Member | Short-term securities | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 52.00% |
Non-pension Benefit Plans [Member | Short-term securities | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 47.00% |
Non-pension Benefit Plans [Member | Equity Securities [Member] | Maximum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 53.00% |
Non-pension Benefit Plans [Member | Equity Securities [Member] | Minimum [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations | 48.00% |
Employee Benefit Plans (Fair Va
Employee Benefit Plans (Fair Value of Investments) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 2,408 | $ 2,208 | |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 802 | 732 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 132 | $ 114 | |
Cash and cash equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 1.00% | 1.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 32 | $ 31 | |
Cash and cash equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 32 | 31 | |
Cash and cash equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Net In Transit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | (1.00%) | (2.00%) | |
Defined Benefit Plan, Fair Value of Plan Assets | $ (36) | $ (42) | |
Net In Transit [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | (36) | (42) | |
Net In Transit [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Net Asset Value Member [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 1,474 | $ 1,362 | |
Open Ended Invesments Measured at NAV [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 44.00% | 51.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 1,065 | $ 1,132 | |
Open Ended Invesments Measured at NAV [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Open Ended Invesments Measured at NAV [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Collective Trust Measured at NAV [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 18.00% | 11.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 409 | $ 230 | |
Collective Trust Measured at NAV [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Collective Trust Measured at NAV [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Equity Securities, Canadian [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 9.00% | 9.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 214 | $ 192 | |
Equity Securities, Canadian [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 214 | 192 | |
Equity Securities, Canadian [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Equity Securities, United States [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 16.00% | 14.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 390 | $ 303 | |
Equity Securities, United States [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 390 | 303 | |
Equity Securities, United States [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Equity Securities, Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 8.00% | 11.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 197 | $ 243 | |
Equity Securities, Other [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 197 | 243 | |
Equity Securities, Other [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Government Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 3.00% | 2.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 72 | $ 47 | |
Government Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Government Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 72 | $ 47 | |
Corporate Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 2.00% | 2.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 56 | $ 53 | |
Corporate Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Corporate Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 56 | $ 53 | |
Other Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 0.00% | 1.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 5 | $ 19 | |
Other Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 5 | 5 | |
Other Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | 14 | |
Other Investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 0.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 4 | ||
Other Investments | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Investments | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4 | ||
Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 2,408 | $ 2,208 | $ 1,300 |
Postretirement Benefit Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 45 | $ 39 | $ 6 |
Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | 1 | |
Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 39 | $ 33 | |
Postretirement Benefit Plan [Member] | Cash and cash equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 2.00% | 3.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 1 | $ 1 | |
Postretirement Benefit Plan [Member] | Cash and cash equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | 1 | |
Postretirement Benefit Plan [Member] | Cash and cash equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | |
Postretirement Benefit Plan [Member] | Life insurance policies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 87.00% | 85.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 39 | $ 33 | |
Postretirement Benefit Plan [Member] | Life insurance policies [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Postretirement Benefit Plan [Member] | Life insurance policies [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 39 | 33 | |
Postretirement Benefit Plan [Member] | Net Asset Value Member [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 5 | $ 5 | |
Postretirement Benefit Plan [Member] | Other investments measured at Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 11.00% | 12.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 5 | $ 5 |
Employee Benefit Plans (Expecte
Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) $ in Millions | Dec. 31, 2017CAD ($) |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plans, Estimated Future Employer Contributions in 2017 | $ 97 |
Defined Benefit Plan, Expected Future Benefit Payments 2018 [Member] | 147 |
Defined Benefit Plan, Expected Future Benefit Payments 2019 [Member] | 143 |
Defined Benefit Plan, Expected Future Benefit Payments 2020 [Member] | 148 |
Defined Benefit Plan, Expected Future Benefit Payments 2021 [Member] | 157 |
Defined Benefit Plan, Expected Future Benefit Payments 2022 [Member] | 165 |
Defined Benefit Plan, Expected Future Benefit Payments 2023-2027 [Member] | 912 |
Non-pension Benefit Plans [Member | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plans, Estimated Future Employer Contributions in 2017 | 25 |
Defined Benefit Plan, Expected Future Benefit Payments 2018 [Member] | 22 |
Defined Benefit Plan, Expected Future Benefit Payments 2019 [Member] | 23 |
Defined Benefit Plan, Expected Future Benefit Payments 2020 [Member] | 23 |
Defined Benefit Plan, Expected Future Benefit Payments 2021 [Member] | 23 |
Defined Benefit Plan, Expected Future Benefit Payments 2022 [Member] | 24 |
Defined Benefit Plan, Expected Future Benefit Payments 2023-2027 [Member] | $ 124 |
Employee Benefit Plans (Assumpt
Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | ||
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components | $ 1 | |
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components | 1 | |
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation | 19 | |
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation | 16 | |
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Increase | (9) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Decrease | (9) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Increase | (6) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Decrease | $ (6) | |
Pension Plan [Member] | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.55% | 3.96% |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.12% | 2.82% |
Defined Benefit Plan, Benefit Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 0.00% | 0.00% |
Defined Benefit Plan, Benefit Obligation, Ultimate Health Care Cost Trend Rate | 0.00% | 0.00% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.96% | 3.79% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.29% | 6.33% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 2.82% | 2.88% |
Defined Benefit Plan, Net Periodic Benefit Cost, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 0.00% | 0.00% |
Defined Benefit Plan, Net Periodic Benefit Cost, Ultimate Health Care Cost Trend Rate | 0.00% | 0.00% |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.65% | 4.18% |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.28% | 2.54% |
Defined Benefit Plan, Benefit Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 6.65% | 6.78% |
Defined Benefit Plan, Benefit Obligation, Ultimate Health Care Cost Trend Rate | 4.45% | 4.45% |
Defined Benefit Plan, Benefit Obligation, Year that Rate Reaches Ultimate Trend Rate | 2,036 | 2,035 |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.18% | 3.88% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.08% | 4.43% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 2.54% | 2.56% |
Defined Benefit Plan, Net Periodic Benefit Cost, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 6.78% | 6.76% |
Defined Benefit Plan, Net Periodic Benefit Cost, Ultimate Health Care Cost Trend Rate | 4.45% | 4.45% |
Defined Benefit Plan, Net Periodic Benefit Cost, Year that Rate Reaches Ultimate Trend Rate | 2,035 | 2,020 |
Employee Benefit Plans (Amou144
Employee Benefit Plans (Amounts to be Amortized in the Next Fiscal Year) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Future Amortization of Gain (Loss) | $ 36 |
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | 1 |
Regulated assets | (21) |
Total | (56) |
Non-pension Benefit Plans [Member | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Future Amortization of Gain (Loss) | 2 |
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | 6 |
Regulated assets | (2) |
Total | $ 2 |
Employee Benefit Plans narrativ
Employee Benefit Plans narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 2,408 | $ 2,208 | |
TECO Energy Inc [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,153 | 1,180 | |
Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
ABO for defined pension plans | 2,561 | 2,489 | |
Defined Benefit Plan, Fair Value of Plan Assets | 2,408 | 2,208 | $ 1,300 |
Pension Plan [Member] | TECO Energy Inc [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Contribution Amount | 23 | 17 | |
Other Postretirement Benefit Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 45 | $ 39 | $ 6 |
Net Investment in Direct Fin146
Net Investment in Direct Financing Lease (Direct Financing Lease and Future Minimum Capital Lease Payments) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ||
Capital Leases, Net Investment in Direct Financing Leases, Minimum Payments to be Received | $ 1,126 | $ 1,194 |
Capital Leases, Net Investment in Direct Financing Leases, Executory Costs | (211) | (223) |
Minimum lease payments receivable | 915 | 971 |
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property | 183 | 183 |
Capital Leases, Net Investment in Direct Financing Leases, Deferred Income | (609) | (658) |
Capital Leases, Net Investment in Direct Financing Leases, Total | 489 | 496 |
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Current | 8 | 8 |
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent | 481 | $ 488 |
Capital Leases, Future Minimum Payments Receivable, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments, Receivable in 2018 | 64 | |
Capital Leases, Future Minimum Payments, Receivable in 2019 | 64 | |
Capital Leases, Future Minimum Payments, Receivable in 2020 | 64 | |
Capital Leases, Future Minimum Payments, Receivable in 2021 | 65 | |
Capital Leases, Future Minimum Payments, Receivable in 2022 | 64 | |
Capital Leases, Future Minimum Payments, estimated executory costs, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments, estimated executory costs 2018 | (11) | |
Capital Leases, Future Minimum Payments, estimated executory costs 2019 | (11) | |
Capital Leases, Future Minimum Payments, estimated executory costs 2020 | (11) | |
Capital Leases, Future Minimum Payments, estimated executory costs 2021 | (12) | |
Capital Leases, Future Minimum Payments, estimated executory costs 2022 | (12) | |
Capital Leases, Future Minimum Payments, estimated executory costs 2021 | ||
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2018 | 53 | |
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2019 | 53 | |
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2020 | 53 | |
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2021 | 53 | |
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs 2022 | $ 52 |
Goodwill (Details)
Goodwill (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | $ 6,213 | $ 264 |
Goodwill, Acquired During Period | 0 | 5,771 |
Goodwill, Foreign Currency Translation Gain (Loss) | (408) | 178 |
Goodwill, Ending Balance | $ 5,805 | $ 6,213 |
Short Term Debt (Short-term deb
Short Term Debt (Short-term debt and the related weighted-average interest rates) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Short-term Debt [Line Items] | ||
Short-term Debt | $ 1,241 | $ 961 |
Short-term Debt, Weighted Average Interest Rate | 2.42% | 1.73% |
TECO Energy Inc. and TECO Finance Inc. [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | $ 820 | $ 685 |
Short-term Debt, Weighted Average Interest Rate | 2.58% | 1.74% |
Tampa Electric Division [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | $ 382 | $ 228 |
Short-term Debt, Weighted Average Interest Rate | 2.07% | 1.49% |
New Mexico Gas Company [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | $ 38 | $ 35 |
Short-term Debt, Weighted Average Interest Rate | 2.47% | 1.71% |
Nova Scotia Power Inc. [Member] | Notes Payable to Banks [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | $ 1 | $ 1 |
Short-term Debt, Weighted Average Interest Rate | 0.00% | 0.00% |
Grand Bahama Power Company Limited [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | $ 0 | $ 12 |
Short-term Debt, Weighted Average Interest Rate | 0.00% | 5.75% |
Short Term Debt (short-term rev
Short Term Debt (short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Short term debt revolving and non revolving credit facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,024 | $ 1,762 |
Credit Facility Advances | 1,241 | 960 |
Letters of Credit Outstanding, Amount | 3 | 3 |
Total advances under available facilities | 1,244 | 963 |
Available capacity under existing agreements | 780 | 799 |
TECO Energy Inc. and TECO Finance Inc. [Member] | Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 376 | $ 403 |
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Dec. 17, 2018 |
TECO Energy Inc. and TECO Finance Inc. [Member] | Finance Term Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 502 | $ 537 |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | |
Tampa Electric Division [Member] | Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 408 | 436 |
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | |
Tampa Electric Division [Member] | Accounts Receivable Revolving Credit Facility | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 188 | 201 |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | |
Tampa Electric Division [Member] | Finance Term Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 377 | 0 |
Line of Credit Facility, Expiration Date | Nov. 1, 2018 | |
New Mexico Gas Company [Member] | Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 157 | $ 168 |
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Dec. 17, 2018 |
Grand Bahama Power Company Limited [Member] | Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 16 | $ 17 |
Short Term Debt (Narrative) (De
Short Term Debt (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Nov. 02, 2017 | Mar. 22, 2017 | Mar. 08, 2017 | |
Revolving Credit Facility [Member] | New Mexico Gas Company [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 125 | ||||
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Dec. 17, 2018 | |||
Revolving Credit Facility [Member] | TECO Energy Inc. and TECO Finance Inc. [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 300 | ||||
Revolving Credit Facility [Member] | TECO Energy Inc. and TECO Finance Inc. [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Dec. 17, 2018 | |||
Letter of Credit [Member] | Tampa Electric Division [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 50 | ||||
Finance Term Credit Facility [Member] | Tampa Electric Division [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 325 | ||||
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Dec. 17, 2018 | |||
Finance Term Credit Facility [Member] | Tampa Electric Division [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 300 | ||||
Line of Credit Facility, Expiration Date | Nov. 1, 2018 | ||||
Finance Term Credit Facility [Member] | TECO Energy Inc. and TECO Finance Inc. [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | ||||
Line of Credit Facility, Expiration Date | Mar. 8, 2018 | Mar. 14, 2017 |
Other Current Liabilities (Deta
Other Current Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other Current Liabilities [Abstract] | ||
Accrued Liabilities, Current | $ 134 | $ 137 |
Accrued interest on long-term debt | 78 | 96 |
Income taxes payable | 1 | 19 |
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities | 41 | 58 |
Sales and Excise Tax Payable, Current | 11 | 16 |
Deferred Emission Credits, Current | 21 | 10 |
Other Sundry Liabilities, Current | 64 | 22 |
Other Liabilities, Current, Total | $ 350 | $ 358 |
Long Term Debt (Long-term Debt)
Long Term Debt (Long-term Debt) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | |
Debt Instrument [Line Items] | |||
Fair Market Value Adjustments to Debt | $ 31 | $ 58 | |
Debt issuance costs | (98) | (111) | |
Amount due within one year | (741) | (476) | |
Long Term Debt, Adjustments | (808) | (529) | |
Long-term Debt and Capital Lease Obligations | 13,140 | 14,268 | |
Emera Inc | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 2,363 | $ 2,366 | |
Emera Inc | Bankers Acceptances, LIBOR Loans [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | Variable | Variable | |
Long-term Debt, Gross | $ 133 | $ 30 | |
Emera Inc | Bankers Acceptances, LIBOR Loans [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2020 | ||
Emera Inc | Unsecured fixed rate notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.50% | 3.50% | 3.50% |
Long-term Debt, Gross | $ 725 | $ 725 | |
Emera Inc | Unsecured fixed rate notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2019 | ||
Emera Inc | Unsecured fixed rate notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2023 | ||
Emera Inc | Fixed to floating subordinated notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 6.75% | 6.75% | 6.75% |
Long-term Debt, Gross | $ 1,505 | $ 1,611 | |
Emera Inc | Fixed to floating subordinated notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2076 | ||
Emera US Finance LP [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 4,077 | $ 4,364 | |
Emera US Finance LP [Member] | Unsecured senior notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.60% | 3.60% | 3.60% |
Long-term Debt, Gross | $ 4,077 | $ 4,364 | |
Emera US Finance LP [Member] | Unsecured senior notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2019 | ||
Emera US Finance LP [Member] | Unsecured senior notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2046 | ||
TECO Finance, Inc. [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 690 | $ 1,141 | |
TECO Finance, Inc. [Member] | Variable rate notes [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | Variable | Variable | |
Long-term Debt, Gross | $ 314 | $ 336 | |
TECO Finance, Inc. [Member] | Variable rate notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2018 | ||
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 5.15% | 5.86% | 5.15% |
Long-term Debt, Gross | $ 376 | $ 805 | |
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Jan. 1, 2020 | ||
Tampa Electric Division [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 2,410 | $ 2,579 | |
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 4.75% | 4.90% | 4.75% |
Long-term Debt, Gross | $ 2,410 | $ 2,579 | |
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2018 | ||
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2045 | ||
Peoples Gas System Division [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 328 | $ 351 | |
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 5.06% | 5.06% | 5.06% |
Long-term Debt, Gross | $ 328 | $ 351 | |
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2018 | ||
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2045 | ||
New Mexico Gas Company [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 363 | $ 339 | |
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 4.53% | 4.53% | 4.53% |
Long-term Debt, Gross | $ 339 | $ 363 | |
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2021 | ||
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2026 | ||
New Mexico Gas Incorporate [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 251 | $ 269 | |
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.41% | 3.41% | 3.41% |
Long-term Debt, Gross | $ 251 | $ 269 | |
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2019 | ||
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2024 | ||
Nova Scotia Power Inc. [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 2,424 | $ 2,324 | |
Nova Scotia Power Inc. [Member] | Commercial Paper [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | Variable | Variable | |
Long-term Debt, Gross | $ 364 | $ 264 | |
Nova Scotia Power Inc. [Member] | Commercial Paper [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2021 | ||
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 5.73% | 5.73% | 5.73% |
Long-term Debt, Gross | $ 1,965 | $ 1,965 | |
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2019 | ||
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2097 | ||
Nova Scotia Power Inc. [Member] | Fixed rate debenture [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 9.75% | 9.75% | 9.75% |
Long-term Debt, Gross | $ 95 | $ 95 | |
Nova Scotia Power Inc. [Member] | Fixed rate debenture [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2019 | ||
Emera Maine [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 408 | $ 380 | |
Emera Maine [Member] | LIBOR loans and demand loans [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | Variable | Variable | |
Long-term Debt, Gross | $ 51 | $ 32 | |
Emera Maine [Member] | LIBOR loans and demand loans [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | 2,019 | ||
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 9.74% | 9.74% | 9.74% |
Long-term Debt, Gross | $ 63 | $ 67 | |
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2020 | ||
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2022 | ||
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 4.15% | 4.28% | 4.15% |
Long-term Debt, Gross | $ 294 | $ 281 | |
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2018 | ||
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2047 | ||
Emera Brunswick Pipeline Company Limited [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 248 | $ 248 | |
Emera Brunswick Pipeline Company Limited [Member] | Senior secured credit facility [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.08% | 3.08% | 3.08% |
Long-term Debt, Gross | $ 248 | $ 248 | |
Debt Instrument, Maturity Date | Dec. 31, 2021 | ||
Grand Bahama Power Company Limited [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 166 | $ 130 | |
Grand Bahama Power Company Limited [Member] | Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 7.07% | 7.07% | 7.07% |
Long-term Debt, Gross | $ 88 | $ 67 | |
Grand Bahama Power Company Limited [Member] | Senior Notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2020 | ||
Grand Bahama Power Company Limited [Member] | Senior Notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2023 | ||
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 3.77% | 3.62% | 3.77% |
Long-term Debt, Gross | $ 78 | $ 63 | |
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2021 | ||
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2022 | ||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 244 | $ 282 | |
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured senior notes [Member] | |||
Debt Instrument [Line Items] | |||
Variable rate | Variable | Variable | |
Long-term Debt, Gross | $ 168 | $ 201 | |
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured senior notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2021 | ||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member] | |||
Debt Instrument [Line Items] | |||
Weighted average interest rate | 5.06% | 5.65% | 5.06% |
Long-term Debt, Gross | $ 76 | $ 81 | |
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2020 | ||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured fixed rate senior notes [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Dec. 31, 2028 |
Long Term Debt (Credit Faciliti
Long Term Debt (Credit Facilities) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 12, 2017 | Dec. 31, 2016 | |
Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,624 | $ 1,433 | |
Long-term Line of Credit | 598 | 326 | |
Letters of Credit Outstanding, Amount | 44 | 37 | |
Use Of Available Facilities | 642 | 363 | |
Line of Credit Facility, Remaining Borrowing Capacity | 982 | 1,070 | |
Emera Inc | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 900 | ||
Emera Inc | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 900 | 700 | |
Line of Credit Facility, Expiration Date | Jun. 30, 2020 | ||
Overdraft limit on lines of credit accounts | $ 50 | ||
Nova Scotia Power Inc. [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 600 | 600 | |
Line of Credit Facility, Expiration Date | Oct. 31, 2021 | ||
Overdraft limit on lines of credit accounts | $ 50 | ||
Emera Maine [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 100 | 107 | |
Line of Credit Facility, Expiration Date | Sep. 30, 2019 | ||
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 24 | $ 26 | |
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Expiration Date | Dec. 31, 2021 | ||
The Barbados Light and Power Company Limited [Member] | Revolving Credit Facility [Member] | Minimum [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Expiration Date | Dec. 31, 2018 |
Long Term Debt (Debt Covenants)
Long Term Debt (Debt Covenants) (Details) - Syndicated Credit Facilities [Member] | Dec. 31, 2017 |
Debt Instrument [Line Items] | |
Debt Instrument Covenant Requirement | 0.7 |
Ratio of Indebtedness to Net Capital | 0.61 |
Long Term Debt (Long Term Matur
Long Term Debt (Long Term Maturities) (Details) $ in Millions | Dec. 31, 2017CAD ($) |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | $ 741 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 1,105 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 646 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 2,204 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 468 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 8,784 |
Total debt maturities including current portion | 13,948 |
Emera Inc | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 225 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 133 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 2,005 |
Total debt maturities including current portion | 2,363 |
Emera US Finance LP [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 627 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 941 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 2,509 |
Total debt maturities including current portion | 4,077 |
TECO Finance, Inc. [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 314 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 376 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 0 |
Total debt maturities including current portion | 690 |
Emera Maine [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 6 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 51 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 37 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 113 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 201 |
Total debt maturities including current portion | 408 |
Nova Scotia Power Inc. [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 95 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 364 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 1,965 |
Total debt maturities including current portion | 2,424 |
EBP [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 248 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 0 |
Total debt maturities including current portion | 248 |
Grand Bahama Power Company Limited [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 12 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 15 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 45 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 22 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 31 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 41 |
Total debt maturities including current portion | 166 |
The Barbados Light and Power Company Limited [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 28 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 29 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 55 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 28 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 11 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 93 |
Total debt maturities including current portion | 244 |
Tampa Electric Division [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 319 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 291 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 282 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 1,518 |
Total debt maturities including current portion | 2,410 |
New Mexico Gas Company [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 251 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 88 |
Total debt maturities including current portion | 339 |
Peoples Gas System Division [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 62 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 59 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 31 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 176 |
Total debt maturities including current portion | 328 |
New Mexico Gas Incorporate [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 63 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2022 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal Thereafter | 188 |
Total debt maturities including current portion | $ 251 |
Long Term Debt (Narrative) (Det
Long Term Debt (Narrative) (Details) $ in Millions, $ in Millions, $ in Millions | 12 Months Ended | |||||||||||
Dec. 31, 2017CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | Dec. 12, 2017CAD ($) | Oct. 11, 2017BBD ($) | Oct. 11, 2017USD ($) | Sep. 27, 2017USD ($) | Sep. 01, 2017BBD ($) | Sep. 01, 2017USD ($) | Mar. 22, 2017USD ($) | Mar. 21, 2017USD ($) | |
Debt Instrument [Line Items] | ||||||||||||
Proceeds from Issuance of Common Stock | $ 682 | $ 354 | ||||||||||
Repayments of Long-term Debt | $ 453 | $ 273 | ||||||||||
Senior secured credit facility [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Maturity Date | Feb. 1, 2021 | Feb. 1, 2021 | Feb. 1, 2019 | |||||||||
Emera Inc | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 900 | |||||||||||
Long-term Debt, Gross | $ 2,363 | $ 2,366 | ||||||||||
Nova Scotia Power Inc. [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,424 | 2,324 | ||||||||||
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 1,965 | $ 1,965 | ||||||||||
Nova Scotia Power Inc. [Member] | Line of Credit [Member] | Revolving term credit facility [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Expiration Date | Oct. 1, 2021 | Oct. 1, 2021 | Oct. 1, 2020 | |||||||||
Capitalization ratio | 0.70% | 0.70% | 0.65% | |||||||||
Emera Brunswick Pipeline Company Limited [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 248 | $ 248 | ||||||||||
Emera US Finance LP [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 4,077 | 4,364 | ||||||||||
Tampa Electric Division [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,410 | 2,579 | ||||||||||
TECO Finance, Inc. [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 690 | $ 1,141 | ||||||||||
TECO Finance, Inc. [Member] | U.S. Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Repayments of Long-term Debt | $ 300 | |||||||||||
The Barbados Light And Power Company Limited [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 20 | |||||||||||
The Barbados Light And Power Company Limited [Member] | BLPC BBD Secured fixed rate senior notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.65% | 4.25% | 4.25% | |||||||||
Debt Instrument, Face Amount | $ 20 | |||||||||||
Debt Instrument, Maturity Date | Dec. 31, 2024 | Dec. 31, 2024 | Dec. 31, 2024 | |||||||||
The Barbados Light And Power Company Limited [Member] | BLPC BBD Secured fixed rate senior notes [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 687.50% | 5.875% | 5.875% | |||||||||
Debt Instrument, Face Amount | $ 20 | |||||||||||
Debt Instrument, Maturity Date | Dec. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2020 | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 20 | |||||||||||
The Barbados Light And Power Company Limited [Member] | BBD Demand loan facility [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | 4.00% | 4.00% | |||||||||
Debt Instrument, Face Amount | $ 12 | |||||||||||
The Barbados Light And Power Company Limited [Member] | BBD Demand loan facility [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 12 | |||||||||||
Emera Maine [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 408 | $ 380 | ||||||||||
Emera Maine [Member] | USD senior unsecured notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 436.00% | |||||||||||
Debt Instrument, Face Amount | $ 50 | |||||||||||
Debt Instrument, Maturity Date | Sep. 27, 2047 | Sep. 27, 2047 | ||||||||||
Grand Bahama Power Company Limited [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 166 | 130 | ||||||||||
Grand Bahama Power Company Limited [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 45 | |||||||||||
New Mexico Gas Company [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | $ 363 | $ 339 | ||||||||||
New Mexico Gas Company [Member] | Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 125 | |||||||||||
Line of Credit Facility, Expiration Date | Mar. 22, 2022 | Mar. 22, 2022 | Dec. 17, 2018 |
Asset Retirement Obligation (AR
Asset Retirement Obligation (ARO Roll Forward) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance, January 1 | $ 170 | $ 109 | |
Additions | 2 | 48 | [1] |
Additions due to acquisition | 0 | 9 | |
Liabilities settled | (3) | (2) | |
Asset Retirement Obligation, Accretion Expense | 6 | 7 | |
Asset Retirement Obligation, Accretion Expense Deferred To Regulatory Asset | 0 | (2) | |
Asset Retirement Obligation, Revision of Estimate | 1 | 1 | |
ForeignCurrencyTranslationGainLoss | (4) | 0 | |
Balance, December 31 | $ 172 | $ 170 | |
[1] | Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2016 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed. |
Commitments and Contingencie158
Commitments and Contingencies (Contractual Obligations) (Details) $ in Millions | Dec. 31, 2017CAD ($) | |
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | $ 1,821 | |
Contractual Obligation, Due in Second Year | 888 | |
Contractual Obligation, Due in Third Year | 778 | |
Contractual Obligation, Due in Fourth Year | 503 | |
Contractual Obligation, Due in Fifth Year | 435 | |
Contractual Obligation, Due after Fifth Year | 3,728 | |
Contractual Obligation | 8,153 | |
Nova Scotia Power Inc. [Member] | Maritime Link Project [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 110 | |
Contractual Obligation, Due in Second Year | 111 | |
Purchased Power [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 234 | [1] |
Contractual Obligation, Due in Second Year | 216 | [1] |
Contractual Obligation, Due in Third Year | 212 | [1] |
Contractual Obligation, Due in Fourth Year | 209 | [1] |
Contractual Obligation, Due in Fifth Year | 206 | [1] |
Contractual Obligation, Due after Fifth Year | 2,148 | [1] |
Contractual Obligation | 3,225 | [1] |
Fuel And Gas Supply [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 527 | |
Contractual Obligation, Due in Second Year | 176 | |
Contractual Obligation, Due in Third Year | 50 | |
Contractual Obligation, Due in Fourth Year | 41 | |
Contractual Obligation, Due in Fifth Year | 0 | |
Contractual Obligation, Due after Fifth Year | 0 | |
Contractual Obligation | 794 | |
Demand Side Management [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 63 | |
Contractual Obligation, Due in Second Year | 28 | |
Contractual Obligation, Due in Third Year | 18 | |
Contractual Obligation, Due in Fourth Year | 18 | |
Contractual Obligation, Due in Fifth Year | 18 | |
Contractual Obligation, Due after Fifth Year | 0 | |
Contractual Obligation | 145 | |
Transportation [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 451 | [2] |
Contractual Obligation, Due in Second Year | 298 | [2] |
Contractual Obligation, Due in Third Year | 264 | [2] |
Contractual Obligation, Due in Fourth Year | 184 | [2] |
Contractual Obligation, Due in Fifth Year | 172 | [2] |
Contractual Obligation, Due after Fifth Year | 1,339 | [2] |
Contractual Obligation | 2,708 | [2] |
Long-term service agreements [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 75 | [3] |
Contractual Obligation, Due in Second Year | 65 | [3] |
Contractual Obligation, Due in Third Year | 34 | [3] |
Contractual Obligation, Due in Fourth Year | 44 | [3] |
Contractual Obligation, Due in Fifth Year | 35 | [3] |
Contractual Obligation, Due after Fifth Year | 180 | [3] |
Contractual Obligation | 433 | [3] |
Capital projects [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 413 | |
Contractual Obligation, Due in Second Year | 88 | |
Contractual Obligation, Due in Third Year | 0 | |
Contractual Obligation, Due in Fourth Year | 0 | |
Contractual Obligation, Due in Fifth Year | 0 | |
Contractual Obligation, Due after Fifth Year | 0 | |
Contractual Obligation | 501 | |
Equity investment commitments [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 15 | [4] |
Contractual Obligation, Due in Second Year | 5 | [4] |
Contractual Obligation, Due in Third Year | 190 | [4] |
Contractual Obligation, Due in Fourth Year | 0 | [4] |
Contractual Obligation, Due in Fifth Year | 0 | [4] |
Contractual Obligation, Due after Fifth Year | 0 | [4] |
Contractual Obligation | 210 | [4] |
Leases and other [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 43 | [5] |
Contractual Obligation, Due in Second Year | 12 | [5] |
Contractual Obligation, Due in Third Year | 10 | [5] |
Contractual Obligation, Due in Fourth Year | 7 | [5] |
Contractual Obligation, Due in Fifth Year | 4 | [5] |
Contractual Obligation, Due after Fifth Year | 61 | [5] |
Contractual Obligation | $ 137 | [5] |
[1] | Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. | |
[2] | Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. | |
[3] | Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. | |
[4] | Emera has a commitment in connection with the Federal Loan Guarantee to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction. | |
[5] | Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. |
Commitments and Contingencie159
Commitments and Contingencies (Legal Proceedings) (Details) - 12 months ended Dec. 31, 2017 $ in Millions, $ in Millions | USD ($) | CAD ($) | USD ($) |
Tampa Electric And Peoples Gas Division [Member] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Estimate of Possible Loss | $ 38 | $ 30 | |
Emera Maine [Member] | ISO New England OATT [Member] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Estimate of Possible Loss | $ 4 | ||
TECO Guatemala Holdings [Member] | Prime Rate [Member] | |||
Loss Contingencies [Line Items] | |||
Litigation Settlement, Amount | $ 21 |
Commitments and Contingencie160
Commitments and Contingencies (Guarantees and Letters of Credit) (Details) - Dec. 31, 2017 | CAD ($) | USD ($) |
TECO Energy Inc [Member] | Jointly Owned Electricity Generation Plant [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | $ 5,000,000 | |
Financial Standby Letter of Credit [Member] | Nova Scotia Power Inc. [Member] | ||
Guarantor Obligations [Line Items] | ||
Guaranty Liabilities | $ 51,000,000 | |
Financial Standby Letter of Credit [Member] | NSP Maritime Link Inc. [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | 21,000,000 | |
Financial Standby Letter of Credit [Member] | Bear Swamp Power Company LLC [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | 28,000,000 | |
Pension plan [Member] | Nova Scotia Power Inc. [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | 51,000,000 | |
Reinsurance agreements [Member] | Emera Reinsurance Limited [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | 6,000,000 | |
Indemnified bonds [Member] | TECO Energy Inc [Member] | ||
Guarantor Obligations [Line Items] | ||
Letters of Credit Outstanding, Amount | $ 6,000,000 | $ 5,000,000 |
Cumulative Preferred Stock (Nar
Cumulative Preferred Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 709 | $ 709 |
Number of shares issued and outstanding | 29,000,000 | 29,000,000 |
Series A Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 95 | |
Number of shares issued and outstanding | 3,864,636 | 3,864,636 |
Annual Dividend Per Share | $ 0.6388 | |
Amount per share used to determine dividend per share | $ 25 | |
Term of Canada government bond yield | 5 years | |
Outstanding share redemption price per share | $ 25 | |
Series A Preferred Stock [Member] | Up To And Excluding August 15, 2020 [Member] | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 0.6388 | |
Percentage rate used to determine dividend rate | 1.84% | |
Outstanding share redemption price per share | $ 25 | |
Series B Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 52 | |
Number of shares issued and outstanding | 2,135,364 | 2,135,364 |
Annual Dividend Per Share | $ 0.6032 | $ 0.5724 |
Amount per share used to determine dividend per share | $ 25 | |
Percentage rate used to determine dividend rate | 1.84% | |
Outstanding share redemption price per share | $ 25 | |
Series B Preferred Stock [Member] | August 15, 2020 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25 | |
Series B Preferred Stock [Member] | After August 15, 2015 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | $ 25.5 | |
Series C Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 245 | |
Number of shares issued and outstanding | 10,000,000 | 10,000,000 |
Annual Dividend Per Share | $ 1.025 | |
Amount per share used to determine dividend per share | $ 25 | |
Term of Canada government bond yield | 5 years | |
Outstanding share redemption price per share | $ 25 | |
Series C Preferred Stock [Member] | Up To And Excluding August 15, 2018 [Member] | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.025 | |
Percentage rate used to determine dividend rate | 2.65% | |
Outstanding share redemption price per share | $ 25 | |
Series F Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 195 | |
Number of shares issued and outstanding | 8,000,000 | 8,000,000 |
Annual Dividend Per Share | $ 1.0625 | |
Amount per share used to determine dividend per share | $ 25 | |
Term of Canada government bond yield | 5 years | |
Outstanding share redemption price per share | $ 25 | |
Series F Preferred Stock [Member] | Up To And Excluding February 15, 2020 [Member] | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.0625 | |
Percentage rate used to determine dividend rate | 2.63% | |
Outstanding share redemption price per share | $ 25 | |
Series D Preferred Stock [Member] | August 15, 2023 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25 | |
Series D Preferred Stock [Member] | After August 15, 2018 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25.5 | |
Series G Preferred Stock [Member] | February 15, 2025 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25 | |
Series G Preferred Stock [Member] | After February 15, 2020 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | $ 25.5 | |
Series E Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Net Proceeds from Issuance of Redeemable Preferred Stock | $ 122 | |
Number of shares issued and outstanding | 5,000,000 | 5,000,000 |
Annual Dividend Per Share | $ 1.125 | |
Outstanding share redemption price per share | $ 26 | |
Series E Preferred Stock [Member] | If Redeemed Prior To August 15, 2019 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 26 | |
Series E Preferred Stock [Member] | If Redeemed On Or After August 15, 2019, But Prior To August 15, 2020 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25.75 | |
Series E Preferred Stock [Member] | If Redeemed On Or After August 15, 2020, But Prior To August 15, 2021 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25.5 | |
Series E Preferred Stock [Member] | If Redeemed On Or After August 15, 2021, But Prior To August 15, 2022 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | 25.25 | |
Series E Preferred Stock [Member] | If Redeemed On Or After August 15, 2022 [Member] | ||
Class of Stock [Line Items] | ||
Outstanding share redemption price per share | $ 25 |
Cumulative Preferred Stock (Det
Cumulative Preferred Stock (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | ||
Preferred Stock, Shares Outstanding | 29,000,000 | 29,000,000 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 709 | $ 709 |
Series A Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred Stock, Dividends Per Share, Declared | $ 0.6388 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Preferred Stock, Shares Outstanding | 3,864,636 | 3,864,636 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 95 | |
Series B Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred Stock, Dividends Per Share, Declared | $ 0.6032 | $ 0.5724 |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Preferred Stock, Shares Outstanding | 2,135,364 | 2,135,364 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 52 | |
Series C Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred Stock, Dividends Per Share, Declared | $ 1.025 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Preferred Stock, Shares Outstanding | 10,000,000 | 10,000,000 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 245 | |
Series E Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred Stock, Dividends Per Share, Declared | $ 1.125 | |
Preferred Stock, Redemption Price Per Share | $ 26 | |
Preferred Stock, Shares Outstanding | 5,000,000 | 5,000,000 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 122 | |
Series F Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred Stock, Dividends Per Share, Declared | $ 1.0625 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Preferred Stock, Shares Outstanding | 8,000,000 | 8,000,000 |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | $ 195 |
Non-controlling Interest In 163
Non-controlling Interest In Subsidiaries (Narrative) (Details) - Grand Bahama Power Company Limited [Member] - Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares [Member] | 12 Months Ended |
Dec. 31, 2017$ / shares | |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Redemption Price Per Share | $ 1,000 |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend 2013 to 2016 | 7.25% |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, 2017 to 2019 | 8.50% |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, 2020 and Thereafter | 10.00% |
Non-controlling Interest In 164
Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries ) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 92 | $ 112 |
Icd Utilities Limited [Member] | ||
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | 52 | 53 |
Grand Bahama Power Company Limited [Member] | ||
Noncontrolling Interest [Line Items] | ||
Noncontrolling Interest, Amount Represented by Preferred Stock | 19 | 34 |
Dominica Electricity Services Ltd. [Member] | ||
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 21 | $ 25 |
Non-controlling Interest In 165
Non-controlling Interest In Subsidiaries (Preferred Shares Authorized) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Noncontrolling Interest [Line Items] | ||
Number of shares issued and outstanding | 29,000,000 | 29,000,000 |
Grand Bahama Power Company Limited [Member] | Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares [Member] | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized | 35,000 | |
Number of shares issued and outstanding | 20,000 | 35,000 |
Preferred Stock Value Outstanding | $ 19 | $ 34 |
Supplementary Information To Co
Supplementary Information To Consolidated Statements Of Cash Flows (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Operating Capital [Abstract] | ||
Increase (Decrease) in Accounts Receivable | $ (176) | $ (104) |
Increase (Decrease) in Income Taxes Receivable | 8 | (23) |
Increase (Decrease) in Inventories | 31 | 88 |
Increase (Decrease) in Other Current Assets | 14 | (18) |
Increase (Decrease) in Accounts Payable | 3 | 162 |
Increase (Decrease) in Income Taxes Payable | (17) | 14 |
Increase (Decrease) in Other Current Liabilities | 33 | 15 |
Increase (Decrease) in Operating Capital, Total | 104 | (134) |
Interest Paid | 689 | 480 |
Income Taxes Paid, Net | 63 | 57 |
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | ||
Stock Issued During Period, Value, Dividend Reinvestment Plan | 166 | 103 |
Debt Instrument, Convertible, Beneficial Conversion Feature | $ 0 | $ 43 |
Stock-based Compensation (Narra
Stock-based Compensation (Narrative) (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock Issued During Period, Shares, Conversion of Units | 150,000 | 51,990,000 |
Employee Common Share Purchase Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 4,000,000 | |
Allocated Share-based Compensation Expense | $ 1,000,000 | $ 1,000,000 |
Employee Common Share Purchase Plan [Member] | Scenario 1 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employer Matching Percentage | 20.00% | |
Employee Common Share Purchase Plan [Member] | Scenario 2 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employer Matching Percentage | 10.00% | |
Employee Common Share Purchase Plan [Member] | Minimum [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employee Contribution | $ 25 | |
Employee Common Share Purchase Plan [Member] | Minimum [Member] | Scenario 2 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employee Contribution | 3,000 | |
Employee Common Share Purchase Plan [Member] | Maximum [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employee Contribution | 8,000 | |
Employee Common Share Purchase Plan [Member] | Maximum [Member] | Scenario 1 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employee Contribution | 3,000 | |
Employee Common Share Purchase Plan [Member] | Maximum [Member] | Scenario 2 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Stock Purchase Plan (ESSP), Employee Contribution | $ 8,000 | |
Common Shareholders Dividend Reinvestment and Share Purchase Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Dividend Reinvestment Plan Percentage Discount From Average Market Price Of Common Shares | 5.00% | |
Stock Option Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 11,700,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 10 years | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Contractual Term, Employee Retirement Or Termination For Other Than Just Cause | 24 months | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Contractual Term, Employee Termination For Just Cause Or Resignation Or Death | 6 months | |
Fair Value Assumptions, Historical Volatility Period | 5 years | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount | $ 2,000,000 | 2,000,000 |
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Cash Received | 3,000,000 | 16,000,000 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value | $ 2,000,000 | $ 13,000,000 |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit | $ 21.58 | $ 20.42 |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Upper Range Limit | $ 46.19 | $ 46.19 |
Stock Option Plan [Member] | First Anniversary [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 25.00% | |
Stock Option Plan [Member] | Second Anniversary [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 25.00% | |
Stock Option Plan [Member] | Third Anniversary [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 25.00% | |
Stock Option Plan [Member] | Fourth Anniversary [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 25.00% | |
Deferred Share Unit Plans [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount | $ 7,000,000 | $ 8,000,000 |
Stock Issued During Period, Shares, Conversion of Units | 1 | |
Number Of Trading Days | 10 days | |
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 2,000,000 | 3,000,000 |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | $ 0 | |
Deferred Share Unit Plans [Member] | Scenario 1 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Deferred Share Unit Plan Percentage Of Value Of Actual Annual Incentive Award | 25.00% | |
Deferred Share Unit Plans [Member] | Scenario 2 [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Deferred Share Unit Plan Percentage Of Value Of Actual Annual Incentive Award | 50.00% | |
Performance Share Unit Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount | $ 14,000,000 | 11,000,000 |
Number Of Trading Days | 50 days | |
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 4,000,000 | $ 4,000,000 |
Performance-based Share Unit Plan Performance Cycle Term | 3 years |
Stock-based Compensation (Weigh
Stock-based Compensation (Weighted Average Fair Values, Assumptions in Valuation Models for Options Granted) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Stock-Based Compensation [Abstract] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | $ 2.37 | $ 2.8 |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 5 years | 5 years |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate | 1.22% | 0.66% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 4.60% | 4.08% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 14.41% | 15.45% |
Stock-based Compensatin (Stock
Stock-based Compensatin (Stock Options) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | 100,000 | 620,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | 100,000 | 620,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | $ 2.37 | $ 2.8 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options | $ 3 | $ 3 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years 6 months | 2 years 4 months 24 days | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 5 years 4 months 25 days | 5 years 8 months 21 days | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | $ 22 | $ 17 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value | $ 2 | $ 2 | |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Beginning Balance | 2,920,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | 827,400 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | (103,825) | ||
Ending Balance | 3,643,575 | 2,920,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number | [1],[2] | 1,903,925 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract] | |||
Beginning Balance | $ 37.42 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price | 45.16 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | 28.91 | ||
Ending Balance | 39.42 | $ 37.42 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price | [1],[2] | $ 35.37 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | 827,400 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | (103,825) | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | $ 28.91 | ||
Employee Non-vested Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | [3] | 827,400 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares | [3] | 0 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract] | |||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | $ 2.37 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | |||
Beginning Balance | [3] | 1,520,125 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | [3] | 827,400 | |
Sharebased Compensation Arrangement By Sharebased Payment Award Options Nonvested Options Forfeited Number Of Shares | [3] | (607,875) | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares | [3] | 0 | |
Ending Balance | [3] | 1,739,650 | 1,520,125 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Beginning Balance | $ 2.69 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | 2.37 | ||
Sharebased Compensation Arrangement By Sharebased Payment Award Options Nonvested Options Forfeited Weighted Average Grant Date Fair Value | 2.73 | ||
Ending Balance | $ 2.52 | $ 2.69 | |
[1] | As at December 31, 2017 the fair value of options that vested in the year was $2 million (2016 - $2 million). | ||
[2] | As at December 31, 2017, the weighted average remaining term of vested options was 5.4 years with an aggregate intrinsic value of $22 million (2016 - 5.7 years, $17 million). | ||
[3] | As at December 31, 2017 there was $3 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.5 years (2016 - $3 million, 2.4 years). |
Stock-based Compensation (Emplo
Stock-based Compensation (Employee and Director DSUs ) (Details) - Deferred Share Unit Plans [Member] | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Employee [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 680,931 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 73,185 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 2,482 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares | 34 |
Ending Balance | shares | 751,600 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | $ / shares | $ 27.5 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 37.74 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares | 46.58 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares | 46.58 |
Ending Balance | $ / shares | $ 28.44 |
Director [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 395,798 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 86,281 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 9,486 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares | 108 |
Ending Balance | shares | 472,485 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | $ / shares | $ 33.88 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 42.96 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares | 44 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares | 45.39 |
Ending Balance | $ / shares | $ 35.33 |
Stock-based Compensation (Em171
Stock-based Compensation (Employee PSUs) (Details) - Performance Share Unit Plan [Member] - Employee [Member] $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2017CAD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 560,880 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 519,789 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 220,075 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | shares | 30,596 |
Ending Balance | shares | 829,998 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | $ / shares | $ 37.55 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 44.35 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | $ / shares | 30.67 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares | 43.66 |
Ending Balance | $ / shares | $ 43.41 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract] | |
Beginning Balance | $ | $ 25.5 |
Ending Balance | $ | $ 41.1 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - Emera Inc - NSP Maritime Link Inc. [Member] - Available-for-sale Investment and Restricted Cash [Member] - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Variable Interest Entity [Line Items] | ||
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets | $ 510 | $ 315 |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | $ 67 | $ 577 |
SUPPLEMENTAL FINANCIAL INFOR173
SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statements of Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues [Abstract] | ||
Regulated electric | $ 4,721 | $ 3,437 |
Regulated | 1,002 | 499 |
Non-regulated | 503 | 341 |
Total operating revenues | 6,226 | 4,277 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 1,638 | 1,283 |
Regulated cost of natural gas | 379 | 177 |
Regulated fuel adjustment | 59 | 61 |
Non-regulated fuel for generation and purchased power | 209 | 313 |
Non-regulated direct costs | 28 | 29 |
Operating, maintenance and general | 1,399 | 1,137 |
Provincial, state, and municipal taxes | 326 | 195 |
Depreciation and amortization | 856 | 588 |
Total operating expenses | 4,835 | 3,722 |
Operating Income (Loss) | 1,391 | 555 |
Income from equity investments | 124 | 100 |
Other income (expenses), net | 2 | 174 |
Interest expense, net | (698) | (585) |
Income before provision for income taxes | 819 | 244 |
Income tax expense (recovery) | 520 | (22) |
Net income | 299 | 266 |
Non-controlling interest in subsidiaries | 5 | 11 |
Preferred stock dividends | 28 | 28 |
Net income attributable to common shareholders | 266.1 | 227.2 |
Comprehensive income attributable to common shareholders | 0 | 228 |
Consolidation, Eliminations [Member] | ||
Revenues [Abstract] | ||
Total operating revenues | (57) | (35) |
Operating expenses | ||
Total operating expenses | (57) | (35) |
Operating Income (Loss) | 0 | 0 |
Income (Loss) from Subsidiaries, before Tax | (336) | (150) |
Income from equity investments | 0 | 0 |
Intercompany income (expenses), net | (38) | (46) |
Other income (expenses), net | 5 | 0 |
Interest expense, net | 0 | 0 |
Income before provision for income taxes | (369) | (196) |
Income tax expense (recovery) | 0 | 0 |
Net income | (369) | (196) |
Non-controlling interest in subsidiaries | 4 | 4 |
Preferred stock dividends | (42) | (50) |
Net income attributable to common shareholders | (331) | (150) |
Comprehensive income attributable to common shareholders | 17 | (283) |
Parent Company [Member] | ||
Revenues [Abstract] | ||
Total operating revenues | 0 | 0 |
Operating expenses | ||
Total operating expenses | 41 | 39 |
Operating Income (Loss) | (41) | (39) |
Income (Loss) from Subsidiaries, before Tax | 336 | 150 |
Income from equity investments | 1 | 18 |
Intercompany income (expenses), net | 92 | 203 |
Other income (expenses), net | 0 | 135 |
Interest expense, net | 138 | 226 |
Income before provision for income taxes | 250 | 241 |
Income tax expense (recovery) | (44) | (14) |
Net income | 294 | 255 |
Non-controlling interest in subsidiaries | 0 | 0 |
Preferred stock dividends | 28 | 28 |
Net income attributable to common shareholders | 266 | 227 |
Comprehensive income attributable to common shareholders | 0 | 228 |
Subsidiary Issuer [Member] | ||
Revenues [Abstract] | ||
Total operating revenues | 0 | 0 |
Operating expenses | ||
Total operating expenses | 0 | 0 |
Operating Income (Loss) | 0 | 0 |
Income (Loss) from Subsidiaries, before Tax | 0 | 0 |
Income from equity investments | 0 | 0 |
Intercompany income (expenses), net | 195 | 101 |
Other income (expenses), net | 0 | 0 |
Interest expense, net | 155 | 85 |
Income before provision for income taxes | 40 | 16 |
Income tax expense (recovery) | 17 | 7 |
Net income | 23 | 9 |
Non-controlling interest in subsidiaries | 0 | 0 |
Preferred stock dividends | 0 | 0 |
Net income attributable to common shareholders | 23 | 9 |
Comprehensive income attributable to common shareholders | 3 | 19 |
Guarantor Subsidiaries [Member] | ||
Revenues [Abstract] | ||
Total operating revenues | 4,165 | 2,494 |
Operating expenses | ||
Total operating expenses | 3,241 | 2,127 |
Operating Income (Loss) | 924 | 367 |
Income (Loss) from Subsidiaries, before Tax | 0 | 0 |
Income from equity investments | 1 | 0 |
Intercompany income (expenses), net | (204) | (107) |
Other income (expenses), net | 16 | 24 |
Interest expense, net | 242 | 127 |
Income before provision for income taxes | 495 | 157 |
Income tax expense (recovery) | 511 | 48 |
Net income | (16) | 109 |
Non-controlling interest in subsidiaries | 0 | 0 |
Preferred stock dividends | 29 | 31 |
Net income attributable to common shareholders | (45) | 78 |
Comprehensive income attributable to common shareholders | (392) | 205 |
Non-Guarantor Subsidiaries [Member] | ||
Revenues [Abstract] | ||
Total operating revenues | 2,118 | 1,818 |
Operating expenses | ||
Total operating expenses | 1,610 | 1,591 |
Operating Income (Loss) | 508 | 227 |
Income (Loss) from Subsidiaries, before Tax | 0 | 0 |
Income from equity investments | 122 | 82 |
Intercompany income (expenses), net | (45) | (151) |
Other income (expenses), net | (19) | 15 |
Interest expense, net | 163 | 147 |
Income before provision for income taxes | 403 | 26 |
Income tax expense (recovery) | 36 | (63) |
Net income | 367 | 89 |
Non-controlling interest in subsidiaries | 1 | 7 |
Preferred stock dividends | 13 | 19 |
Net income attributable to common shareholders | 353 | 63 |
Comprehensive income attributable to common shareholders | $ 372 | $ 59 |
SUPPLEMENTAL FINANCIAL INFOR174
SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statement of Financial Position) (Details) - CAD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | $ 438 | $ 404 | $ 1,092 |
Restricted Cash and Cash Equivalents, Current | 65 | 87 | |
Inventory, Net | 418 | 472 | |
Derivative Instruments and Hedges, Assets | 141 | 145 | |
Regulatory Assets, Current | 138 | 80 | |
Other Assets, Current | 1,326 | 1,323 | |
Total current assets | 2,526 | 2,511 | |
Property, Plant and Equipment, Net | 16,995 | 17,290 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | 138 | 125 | |
Derivative instruments | 112 | 131 | |
Regulatory assets | 1,238 | 1,242 | |
Net investment in direct financing lease | 481 | 488 | |
Investments subject to significant influence | 1,215 | 947 | |
Goodwill | 5,805 | 6,213 | 264 |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 261 | 274 | |
Total other assets | 9,250 | 9,420 | |
Assets, Total | 28,771 | 29,221 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 1,241 | 961 | |
Current portion of long-term debt | 741 | 476 | |
Accounts payable | 1,161 | 1,242 | |
Derivative instruments | 227 | 325 | |
Regulatory liabilities | 226 | 362 | |
Other current liabilities | 350 | 358 | |
Total current liabilities | 3,946 | 3,724 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 13,140 | 14,268 | |
Intercompany long term debt | 0 | 0 | |
Deferred income taxes | 1,011 | 1,672 | |
Derivative instruments | 83 | 150 | |
Regulatory liabilities | 2,242 | 1,277 | |
Other long-term liabilities | 609 | 645 | |
Total long-term liabilities | 17,644 | 18,681 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 5,601 | 4,738 | 2,157 |
Preferred Stock, Value, Issued | 709 | 709 | |
Contributed surplus | 76 | 75 | |
Accumulated other comprehensive Income | (188) | 106 | |
Retained earnings | 891 | 1,076 | |
Total Emera Incorporated equity | 7,089 | 6,704 | |
Non-controlling interest in subsidiaries | 92 | 112 | |
Total equity | 7,181 | 6,816 | $ 4,334 |
Liabilities and Equity, Total | 28,771 | 29,221 | |
Consolidation, Eliminations [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 0 | 0 | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
AccountsReceivableRelatedPartiesCurrent | (195) | (646) | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | (6) | (13) | |
Regulatory Assets, Current | 0 | 0 | |
Other Assets, Current | 0 | 0 | |
Total current assets | (201) | (659) | |
Property, Plant and Equipment, Net | 0 | 0 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | 7 | (38) | |
Derivative instruments | (4) | (12) | |
Regulatory assets | 0 | 0 | |
Net investment in direct financing lease | 0 | 0 | |
Investments In Subsidiaries | (8,490) | (8,349) | |
Investments subject to significant influence | 0 | 0 | |
Goodwill | 0 | 0 | |
Intercompany notes receivable | (6,381) | (6,504) | |
Other investments - intercompany | (70) | (2,270) | |
Other long term assets | (20) | (19) | |
Total other assets | (14,958) | (17,192) | |
Assets, Total | (15,159) | (17,851) | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 0 | |
Current portion of long-term debt | 0 | 0 | |
Accounts payable | 0 | 0 | |
Intercompany payable | (225) | (646) | |
Derivative instruments | (5) | (13) | |
Regulatory liabilities | (1) | 0 | |
Other current liabilities | 0 | 0 | |
Total current liabilities | (231) | (659) | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 0 | 0 | |
Intercompany long term debt | (6,377) | (6,501) | |
Deferred income taxes | 7 | (38) | |
Derivative instruments | (4) | (12) | |
Regulatory liabilities | 0 | 0 | |
Other long-term liabilities | (19) | (19) | |
Total long-term liabilities | (6,393) | (6,570) | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | (6,689) | (8,416) | |
Preferred Stock, Value, Issued | (696) | (891) | |
Contributed surplus | (258) | (151) | |
Accumulated other comprehensive Income | 230 | (159) | |
Retained earnings | (1,142) | (1,039) | |
Total Emera Incorporated equity | (8,555) | (10,656) | |
Non-controlling interest in subsidiaries | 20 | 34 | |
Total equity | (8,535) | (10,622) | |
Liabilities and Equity, Total | (15,159) | (17,851) | |
Parent Company [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 276 | 200 | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
AccountsReceivableRelatedPartiesCurrent | 74 | 57 | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | 5 | 13 | |
Regulatory Assets, Current | 0 | 0 | |
Other Assets, Current | 3 | 3 | |
Total current assets | 358 | 273 | |
Property, Plant and Equipment, Net | 17 | 14 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | 70 | 31 | |
Derivative instruments | 4 | 12 | |
Regulatory assets | 0 | 0 | |
Net investment in direct financing lease | 0 | 0 | |
Investments In Subsidiaries | 8,490 | 8,349 | |
Investments subject to significant influence | 5 | 5 | |
Goodwill | 0 | 0 | |
Intercompany notes receivable | 1,140 | 1,341 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 29 | 33 | |
Total other assets | 9,738 | 9,771 | |
Assets, Total | 10,113 | 10,058 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 0 | |
Current portion of long-term debt | 0 | 0 | |
Accounts payable | 9 | 6 | |
Intercompany payable | 55 | 534 | |
Derivative instruments | 5 | 14 | |
Regulatory liabilities | 0 | 0 | |
Other current liabilities | 60 | 54 | |
Total current liabilities | 129 | 608 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 2,205 | 2,338 | |
Intercompany long term debt | 656 | 366 | |
Deferred income taxes | 0 | 0 | |
Derivative instruments | 4 | 12 | |
Regulatory liabilities | 0 | 0 | |
Other long-term liabilities | 9 | 13 | |
Total long-term liabilities | 2,895 | 2,746 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 5,601 | 4,738 | |
Preferred Stock, Value, Issued | 709 | 709 | |
Contributed surplus | 76 | 75 | |
Accumulated other comprehensive Income | (188) | 106 | |
Retained earnings | 891 | 1,076 | |
Total Emera Incorporated equity | 7,089 | 6,704 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 7,089 | 6,704 | |
Liabilities and Equity, Total | 10,113 | 10,058 | |
Subsidiary Issuer [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 21 | 28 | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
AccountsReceivableRelatedPartiesCurrent | 9 | 9 | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | 0 | 0 | |
Regulatory Assets, Current | 0 | 0 | |
Other Assets, Current | 0 | 0 | |
Total current assets | 30 | 37 | |
Property, Plant and Equipment, Net | 0 | 0 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | 0 | 0 | |
Derivative instruments | 0 | 0 | |
Regulatory assets | 0 | 0 | |
Net investment in direct financing lease | 0 | 0 | |
Investments In Subsidiaries | 0 | 0 | |
Investments subject to significant influence | 0 | 0 | |
Goodwill | 0 | 0 | |
Intercompany notes receivable | 4,285 | 4,558 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 0 | 0 | |
Total other assets | 4,285 | 4,558 | |
Assets, Total | 4,315 | 4,595 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 0 | |
Current portion of long-term debt | 0 | 0 | |
Accounts payable | 0 | 0 | |
Intercompany payable | 6 | 6 | |
Derivative instruments | 0 | 0 | |
Regulatory liabilities | 0 | 0 | |
Other current liabilities | 6 | 13 | |
Total current liabilities | 12 | 19 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 4,034 | 4,314 | |
Intercompany long term debt | 0 | 0 | |
Deferred income taxes | 4 | 1 | |
Derivative instruments | 0 | 0 | |
Regulatory liabilities | 0 | 0 | |
Other long-term liabilities | 0 | 0 | |
Total long-term liabilities | 4,038 | 4,315 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 242 | 242 | |
Preferred Stock, Value, Issued | 0 | 0 | |
Contributed surplus | 0 | 0 | |
Accumulated other comprehensive Income | (9) | 10 | |
Retained earnings | 32 | 9 | |
Total Emera Incorporated equity | 265 | 261 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 265 | 261 | |
Liabilities and Equity, Total | 4,315 | 4,595 | |
Guarantor Subsidiaries [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 47 | 48 | |
Restricted Cash and Cash Equivalents, Current | 1 | 1 | |
AccountsReceivableRelatedPartiesCurrent | 4 | 11 | |
Inventory, Net | 243 | 273 | |
Derivative Instruments and Hedges, Assets | 11 | 33 | |
Regulatory Assets, Current | 114 | 54 | |
Other Assets, Current | 546 | 478 | |
Total current assets | 966 | 898 | |
Property, Plant and Equipment, Net | 12,258 | 12,724 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | (10) | 18 | |
Derivative instruments | 2 | 2 | |
Regulatory assets | 552 | 647 | |
Net investment in direct financing lease | 12 | 13 | |
Investments In Subsidiaries | 0 | 0 | |
Investments subject to significant influence | 13 | 13 | |
Goodwill | 5,709 | 6,110 | |
Intercompany notes receivable | 1 | 16 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 68 | 85 | |
Total other assets | 6,347 | 6,904 | |
Assets, Total | 19,571 | 20,526 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 1,241 | 948 | |
Current portion of long-term debt | 701 | 436 | |
Accounts payable | 620 | 756 | |
Intercompany payable | 90 | 81 | |
Derivative instruments | 52 | 10 | |
Regulatory liabilities | 91 | 225 | |
Other current liabilities | 137 | 130 | |
Total current liabilities | 2,932 | 2,586 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 3,741 | 4,687 | |
Intercompany long term debt | 4,582 | 4,778 | |
Deferred income taxes | 435 | 1,193 | |
Derivative instruments | 4 | 0 | |
Regulatory liabilities | 1,889 | 973 | |
Other long-term liabilities | 267 | 274 | |
Total long-term liabilities | 11,259 | 12,338 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 4,311 | 4,177 | |
Preferred Stock, Value, Issued | 620 | 620 | |
Contributed surplus | 110 | 45 | |
Accumulated other comprehensive Income | (36) | 340 | |
Retained earnings | 375 | 420 | |
Total Emera Incorporated equity | 5,380 | 5,602 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 5,380 | 5,602 | |
Liabilities and Equity, Total | 19,571 | 20,526 | |
Non-Guarantor Subsidiaries [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 94 | 128 | |
Restricted Cash and Cash Equivalents, Current | 64 | 86 | |
AccountsReceivableRelatedPartiesCurrent | 108 | 569 | |
Inventory, Net | 175 | 199 | |
Derivative Instruments and Hedges, Assets | 131 | 112 | |
Regulatory Assets, Current | 24 | 26 | |
Other Assets, Current | 777 | 842 | |
Total current assets | 1,373 | 1,962 | |
Property, Plant and Equipment, Net | 4,720 | 4,552 | |
Other Assets, Noncurrent [Abstract] | |||
Deferred income taxes | 71 | 114 | |
Derivative instruments | 110 | 129 | |
Regulatory assets | 686 | 595 | |
Net investment in direct financing lease | 469 | 475 | |
Investments In Subsidiaries | 0 | 0 | |
Investments subject to significant influence | 1,197 | 929 | |
Goodwill | 96 | 103 | |
Intercompany notes receivable | 955 | 589 | |
Other investments - intercompany | 70 | 2,270 | |
Other long term assets | 184 | 175 | |
Total other assets | 3,838 | 5,379 | |
Assets, Total | 9,931 | 11,893 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 13 | |
Current portion of long-term debt | 40 | 40 | |
Accounts payable | 532 | 480 | |
Intercompany payable | 74 | 25 | |
Derivative instruments | 175 | 314 | |
Regulatory liabilities | 136 | 137 | |
Other current liabilities | 147 | 161 | |
Total current liabilities | 1,104 | 1,170 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 3,160 | 2,929 | |
Intercompany long term debt | 1,139 | 1,357 | |
Deferred income taxes | 565 | 516 | |
Derivative instruments | 79 | 150 | |
Regulatory liabilities | 353 | 304 | |
Other long-term liabilities | 352 | 377 | |
Total long-term liabilities | 5,845 | 5,852 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 2,136 | 3,997 | |
Preferred Stock, Value, Issued | 76 | 271 | |
Contributed surplus | 148 | 106 | |
Accumulated other comprehensive Income | (185) | (191) | |
Retained earnings | 735 | 610 | |
Total Emera Incorporated equity | 2,910 | 4,793 | |
Non-controlling interest in subsidiaries | 72 | 78 | |
Total equity | 2,982 | 4,871 | |
Liabilities and Equity, Total | $ 9,931 | $ 11,893 |
SUPPLEMENTAL FINANCIAL INFOR175
SUPPLEMENTAL FINANCIAL INFORMATION Company (Condensed Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | $ 1,193 | $ 1,053 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | (8,409) |
Additions to property, plant and equipment | (1,529) | (1,080) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (213) | (276) |
Proceeds from Sale of Equity Method Investments | 0 | 665 |
Other investing activities | (19) | 63 |
Net cash used in investing activities | (1,761) | (9,037) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | (31) | 118 |
Proceeds from (Repayments of) Short-term Debt | 383 | 0 |
Proceeds from Issuance of Long-term Debt | 129 | 6,423 |
Proceeds from Convertible Debt | 0 | 1,413 |
Retirement of long-term debt | (453) | (273) |
Net repayments under committed credit facilities | 230 | (315) |
Proceeds from Issuance of Common Stock | 682 | 354 |
Dividends on common stock | (287) | (221) |
Dividends on preferred stock | (28) | (28) |
Dividends paid by subsidiaries to non-controlling interest | (6) | (5) |
Proceeds from (Payments for) Other Financing Activities | (26) | (18) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 593 | 7,448 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (13) | (65) |
Cash and Cash Equivalents, Period Increase (Decrease) | 12 | (601) |
Beginning Balance | 491 | |
Ending Balance | 503 | 491 |
Consolidation, Eliminations [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | (861) | 171 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | (13) | 0 |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | 0 |
Proceeds from Sale of Equity Method Investments | 0 | 0 |
Repayment of Notes Receivable from Related Parties | (1,099) | 9,179 |
Other investing activities | 3 | 0 |
Net cash used in investing activities | (1,109) | 9,179 |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | 0 | 14 |
Proceeds from Issuance of Long-term Debt | 113 | (5,081) |
Proceeds from Convertible Debt | 0 | 0 |
Retirement of long-term debt | 15 | 19 |
Proceeds from Long-term Lines of Credit | 6 | (6) |
Proceeds from Issuance of Common Stock | 1,703 | (4,202) |
Issuance of preferred stock, net of issuance costs | 195 | (195) |
Dividends on common stock | 272 | 254 |
Dividends on preferred stock | 42 | 49 |
Dividends paid by subsidiaries to non-controlling interest | (4) | (3) |
Proceeds from (Payments for) Other Financing Activities | (372) | (185) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 1,970 | (9,336) |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | 0 | 0 |
Cash and Cash Equivalents, Period Increase (Decrease) | 0 | 14 |
Beginning Balance | 0 | (14) |
Ending Balance | 0 | 0 |
Parent Company [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 195 | 265 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | (5) | (2) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | 0 |
Proceeds from Sale of Equity Method Investments | 0 | 665 |
Repayment of Notes Receivable from Related Parties | (708) | (2,348) |
Other investing activities | (34) | 0 |
Net cash used in investing activities | (747) | (1,685) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | 0 | (14) |
Proceeds from Issuance of Long-term Debt | 0 | 2,037 |
Proceeds from Convertible Debt | 0 | (44) |
Retirement of long-term debt | 0 | (250) |
Proceeds from Long-term Lines of Credit | (30) | (210) |
Proceeds from Issuance of Common Stock | 682 | 354 |
Issuance of preferred stock, net of issuance costs | 0 | 0 |
Dividends on common stock | (287) | (221) |
Dividends on preferred stock | (28) | (28) |
Dividends paid by subsidiaries to non-controlling interest | 0 | 0 |
Proceeds from (Payments for) Other Financing Activities | 290 | 0 |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 627 | 1,624 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | 1 | (4) |
Cash and Cash Equivalents, Period Increase (Decrease) | 76 | 200 |
Beginning Balance | 200 | 0 |
Ending Balance | 276 | 200 |
Subsidiary Issuer [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 22 | 29 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | 0 | 0 |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | 0 |
Proceeds from Sale of Equity Method Investments | 0 | 0 |
Repayment of Notes Receivable from Related Parties | (26) | (4,416) |
Other investing activities | 0 | 0 |
Net cash used in investing activities | (26) | (4,416) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | 0 | 0 |
Proceeds from Issuance of Long-term Debt | 0 | 4,187 |
Proceeds from Convertible Debt | 0 | 0 |
Retirement of long-term debt | 0 | 0 |
Proceeds from Long-term Lines of Credit | 0 | 0 |
Proceeds from Issuance of Common Stock | 0 | 242 |
Issuance of preferred stock, net of issuance costs | 0 | 0 |
Dividends on common stock | 0 | 0 |
Dividends on preferred stock | 0 | 0 |
Dividends paid by subsidiaries to non-controlling interest | 0 | 0 |
Proceeds from (Payments for) Other Financing Activities | 0 | 0 |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 0 | 4,429 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (3) | (14) |
Cash and Cash Equivalents, Period Increase (Decrease) | (7) | 28 |
Beginning Balance | 28 | 0 |
Ending Balance | 21 | 28 |
Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 712 | 481 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | 8,409 |
Additions to property, plant and equipment | (1,031) | (673) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | 0 |
Proceeds from Sale of Equity Method Investments | 0 | 0 |
Repayment of Notes Receivable from Related Parties | 15 | (18) |
Other investing activities | (20) | (3) |
Net cash used in investing activities | (1,036) | (9,103) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | (18) | 122 |
Proceeds from (Repayments of) Short-term Debt | 383 | |
Proceeds from Issuance of Long-term Debt | 147 | 4,516 |
Proceeds from Convertible Debt | 0 | 0 |
Retirement of long-term debt | (413) | (6) |
Proceeds from Long-term Lines of Credit | 21 | 0 |
Proceeds from Issuance of Common Stock | 134 | 3,865 |
Issuance of preferred stock, net of issuance costs | 0 | 195 |
Dividends on common stock | 0 | 0 |
Dividends on preferred stock | (29) | (31) |
Dividends paid by subsidiaries to non-controlling interest | 0 | 0 |
Proceeds from (Payments for) Other Financing Activities | 96 | (18) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 321 | 8,643 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | 2 | 7 |
Cash and Cash Equivalents, Period Increase (Decrease) | (1) | 28 |
Beginning Balance | 49 | 21 |
Ending Balance | 48 | 49 |
Non-Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 1,125 | 107 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | (480) | (405) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (213) | (276) |
Proceeds from Sale of Equity Method Investments | 0 | 0 |
Repayment of Notes Receivable from Related Parties | 1,818 | (2,397) |
Other investing activities | 32 | 66 |
Net cash used in investing activities | 1,157 | (3,012) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Change in short-term debt, net | (13) | (4) |
Proceeds from Issuance of Long-term Debt | (131) | 764 |
Proceeds from Convertible Debt | 0 | 1,457 |
Retirement of long-term debt | (55) | (36) |
Proceeds from Long-term Lines of Credit | 233 | (99) |
Proceeds from Issuance of Common Stock | (1,837) | 95 |
Issuance of preferred stock, net of issuance costs | (195) | 0 |
Dividends on common stock | (272) | (254) |
Dividends on preferred stock | (13) | (18) |
Dividends paid by subsidiaries to non-controlling interest | (2) | (2) |
Proceeds from (Payments for) Other Financing Activities | (40) | 185 |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | (2,325) | 2,088 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (13) | (54) |
Cash and Cash Equivalents, Period Increase (Decrease) | (56) | (871) |
Beginning Balance | 214 | 1,085 |
Ending Balance | $ 158 | $ 214 |