Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2016shares | |
Document and Entity Information [Abstract] | |
Document Type | 40-F |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2016 |
Document Fiscal Year Focus | 2,016 |
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 | |
Entity Common Stock, Shares Outstanding | 210,024,389 |
Series A Preferred Stock [Member] | |
Entity Common Stock, Shares Outstanding | 3,864,636 |
Series B Preferred Stock [Member] | |
Entity Common Stock, Shares Outstanding | 2,135,364 |
Series C Preferred Stock [Member] | |
Entity Common Stock, Shares Outstanding | 10,000,000 |
Series E Preferred Stock [Member] | |
Entity Common Stock, Shares Outstanding | 5,000,000 |
Series F Preferred Stock [Member] | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Consolidated Statements of Inco
Consolidated Statements of Income - CAD shares in Millions, CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Operating revenues | ||
Regulated electric | CAD 3,437 | CAD 2,141 |
Regulated Gas | 499 | 52 |
Non-regulated | 341 | 596 |
Total operating revenues | 4,277 | 2,789 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 1,222 | 815 |
Regulated cost of natural gas | 177 | 0 |
Regulated fuel adjustment | 61 | 42 |
Non-regulated fuel for generation and purchased power | 313 | 336 |
Non-regulated direct costs | 29 | 19 |
Operating, maintenance and general | 1,137 | 666 |
Provincial, state, and municipal taxes | 195 | 63 |
Depreciation and amortization | 588 | 340 |
Total operating expenses | 3,722 | 2,281 |
Income from operations | 555 | 508 |
Income from equity investments | 100 | 108 |
Other income (expenses), net | 174 | 141 |
Interest expense, net | (585) | (212) |
Income before provision for income taxes | 244 | 545 |
Income tax expense (recovery) | (22) | 93 |
Net income | 266 | 452 |
Non-controlling interest in subsidiaries | 11 | 25 |
Net income of Emera Incorporated | 255 | 427 |
Preferred stock dividends | 28 | 30 |
Net income attributable to common shareholders | CAD 227.2 | CAD 397.2 |
Weighted average shares of common stock outstanding (in millions) | ||
Basic | 171.4 | 145.8 |
Diluted | 172.2 | 146.4 |
Earnings per common share (note 9) | ||
Basic | CAD 1.33 | CAD 2.72 |
Diluted | 1.32 | 2.71 |
Dividends per common share declared | CAD 1.995 | CAD 1.6625 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Consolidated Statements of Comprehensive Income [Abstract] | ||
Net income | CAD 266 | CAD 452 |
Foreign currency translation adjustment | 32 | 435 |
Unrealized gains (losses) on net investment hedges | (49) | 0 |
Cash flow hedges | ||
Net derivative gains (losses) | 11 | (34) |
Less: reclassification adjustment for losses (gains) included in income | 11 | 7 |
Net effects of cash flow hedges | 22 | (27) |
Unrealized gains on available-for-sale investment | ||
Unrealized gain (loss) arising during the period | 3 | (3) |
Less: reclassification adjustment for (gains) recognized in income | (4) | 0 |
Net unrealized holding gains (losses) | (1) | (3) |
Net change in unrecognized pension and post-retirement benefit obligation | 12 | 107 |
Other equity method reclassification adjustment | (46) | 0 |
Other comprehensive income (loss) | (30) | 512 |
Comprehensive income (loss) | 236 | 964 |
Comprehensive income (loss) attributable to non-controlling interest | 8 | 53 |
Comprehensive Income of Emera Incorporated | CAD 228 | CAD 911 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income (Parenthetical) CAD in Millions, $ in Billions | 12 Months Ended | ||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | |
Consolidated Statements of Comprehensive Income [Abstract] | |||
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax | CAD 3 | CAD (7) | |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $ | $ 1.2 | ||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax | (1) | ||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 2 | ||
Other Comprehensive Income (Loss), Available-for-sale Securities, before Reclassification Adjustments, Tax | (3) | (8) | |
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax | 9 | ||
Other Comprehensive Income Los sAvailable For Sale Securities Before Reclassification Adjustments Tax Other Equity Method | CAD 9 | CAD (14) |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD CAD in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | CAD 404,000 | CAD 1,073,000 |
Restricted cash | 87,000 | 19,000 |
Receivables, net | 1,014,000 | 578,000 |
Income taxes receivable | 33,000 | 12,000 |
Inventory | 472,000 | 314,000 |
Derivative instruments | 145,000 | 250,000 |
Regulatory assets | 80,000 | 94,000 |
Other current assets | 276,000 | 256,000 |
Total current assets | 2,511,000 | 2,596,000 |
Property, plant and equipment, net of accumulated depreciation and amortization of $7,787and $3,737, respectively | 17,290,000 | 6,469,000 |
Other assets | ||
Income taxes receivable | 48,000 | 49,000 |
Deferred income taxes | 125,000 | 32,000 |
Derivative instruments | 131,000 | 168,000 |
Pension and post-retirement assets | 9,000 | 9,000 |
Regulatory assets | 1,242,000 | 605,000 |
Net investment in direct financing lease | 488,000 | 480,000 |
Investments subject to significant influence | 947,000 | 1,145,000 |
Available-for-sale investment | 48,000 | 116,000 |
Goodwill | 6,213,000 | 264,000 |
Other long term assets | 169,000 | 106,000 |
Total other assets | 9,420,000 | 2,974,000 |
Total assets | 29,221,000 | 12,039,000 |
Current liabilities | ||
Short-term debt | 961,000 | 16,000 |
Current portion of long-term debt | 476,000 | 274,000 |
Accounts payable | 1,242,000 | 394,000 |
Income taxes payable | 19,000 | 8,000 |
Derivative instruments | 325,000 | 349,000 |
Regulatory liabilities | 362,000 | 112,000 |
Pension and post-retirement liabilities | 58,000 | 7,000 |
Other current liabilities | 281,000 | 207,000 |
Total current liabilities | 3,724,000 | 1,367,000 |
Long-term liabilities | ||
Long-term debt | 14,268,000 | 3,735,000 |
Deferred income taxes | 1,672,000 | 762,000 |
Convertible debentures (2015 represented by instalment receipts) | 8,000 | 681,000 |
Derivative instruments | 150,000 | 96,000 |
Regulatory liabilities | 1,277,000 | 353,000 |
Asset retirement obligations | 170,000 | 109,000 |
Pension and post-retirement liabilities | 669,000 | 303,000 |
Other long-term liabilities | 467,000 | 299,000 |
Total long-term liabilities | 18,681,000 | 6,338,000 |
Commitments and contingencies | ||
Equity | ||
Common stock | 4,738,000 | 2,157,000 |
Cumulative preferred stock | 709,000 | 709,000 |
Contributed surplus | 75,000 | 29,000 |
Accumulated other comprehensive Income | 106,000 | 137,000 |
Retained earnings | 1,076,000 | 1,168,000 |
Total Emera Incorporated equity | 6,704,000 | 4,200,000 |
Non-controlling interest in subsidiaries | 112,000 | 134,000 |
Total equity | 6,816,000 | 4,334,000 |
Total liabilities and equity | CAD 29,221,000 | CAD 12,039,000 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Consolidated Balance Sheets [Abstract] | ||
Accumulated depreciation on property, plant and equipment | CAD 7,787 | CAD 3,737 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities | ||
Net income | CAD 266 | CAD 452 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 593 | 352 |
Income from equity investments, net of dividends | (59) | (34) |
Allowance for equity funds used during construction | (22) | (2) |
Deferred income taxes, net | (67) | 20 |
Net change in pension and post-retirement obligations | 13 | 37 |
Regulated Fuel Adjustments Mechanism | 63 | 39 |
Net changes in fair value of derivative instruments | 258 | 96 |
Net change in regulatory assets and liabilities | (25) | (6) |
Net change in capitalized transportation capacity | 33 | (133) |
Foreign exchange loss (gain) | 43 | (27) |
Gain on APUC sale of common shares and conversion of subscription receipts | (223) | 0 |
Proceeds from Other Operating Activities | 46 | |
Payments for Other Operating Activities | (18) | |
Changes in non-cash working capital | 134 | (102) |
Net cash provided by operating activities | 1,053 | 674 |
Investing activities | ||
Acquisition, net of cash acquired | (8,409) | 0 |
Additions to property, plant and equipment | (1,031) | (427) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (276) | (136) |
Net proceeds on sale of investment subject to significant influence | 665 | 282 |
Proceeds on distribution from investment subject to significant influence | 0 | 179 |
Other investing activities | (54) | (22) |
Net cash used in investing activities | (9,105) | (124) |
Financing activities | ||
Change in short-term debt, net | 118 | (262) |
Proceeds from long-term debt | 6,423 | 446 |
Proceeds from convertible debentures, net of issuance costs (2015 represented by instalment receipts) | 1,413 | 681 |
Retirement of long-term debt | (273) | (90) |
Net repayments under committed credit facilities | (315) | (201) |
Issuance of common stock, net of issuance costs | 354 | 9 |
Dividends on common stock | (221) | (162) |
Dividends on preferred stock | (28) | (30) |
Dividends paid by subsidiaries to non-controlling interest | (5) | (14) |
Redemption of preferred shares by subsidiary | 0 | (135) |
Other financing activities | (18) | (21) |
Net cash provided by financing activities | 7,448 | 221 |
Effect of exchange rate changes on cash and cash equivalents | (65) | 81 |
Net increase (decrease) in cash and cash equivalents | (669) | 852 |
Cash and cash equivalents, beginning of period | 1,073 | 221 |
Cash and cash equivalents, end of period | 404 | 1,073 |
Cash and cash equivalents consists of: | ||
Cash and cash equivalents | CAD 404 | CAD 221 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD CAD in Millions | Total | Emera Inc | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Loss ("AOCL") | Retained Earnings | Non- Controlling Interest |
Balance at Dec. 31, 2014 | CAD 3,705 | CAD 3,399 | CAD 2,016 | CAD 709 | CAD 9 | CAD (347) | CAD 1,012 | CAD 306 |
Net income | 452 | 427 | 0 | 0 | 0 | 0 | 427 | 25 |
Other Comprehensive Income (Loss), Net of Tax | 512 | 484 | 0 | 0 | 0 | 484 | 0 | 28 |
Issuance of stock, net of issuance costs | 84 | 84 | 84 | 0 | 0 | 0 | 0 | 0 |
Cash dividends declared on preferred stock | (30) | (30) | 0 | 0 | 0 | 0 | (30) | 0 |
Cash dividends declared on common stock | (240) | (240) | 0 | 0 | 0 | 0 | (240) | 0 |
Stock Issued During Period, Value, Employee Contributions and Dividend Reinvestment Plan | (3) | 84 | 84 | 0 | 0 | 0 | 0 | (3) |
Senior management stock options exercised | 2 | 2 | 2 | 0 | 0 | 0 | 0 | 0 |
Stock option expense | 1 | 1 | 0 | 0 | 1 | 0 | 0 | 0 |
Common stock issued under purchase plan | 1 | 1 | 1 | 0 | 0 | 0 | 0 | 0 |
Beneficial conversion feature, net of tax (note 9) | 0 | |||||||
Preferred dividends paid by subsidiaries to non-controlling interest | (12) | 0 | 0 | 0 | 0 | 0 | 0 | (12) |
Common Dividends paid by subsidiaries to non-controlling interest | (3) | 0 | 0 | 0 | 0 | 0 | 0 | (3) |
Redemption of preferred shares by subsidiary | (132) | 0 | 0 | 0 | 0 | 0 | 0 | (132) |
Acquisition Non Controlling Interest | (5) | 73 | 54 | 0 | 19 | 0 | 0 | (78) |
Equity Method Investment | (1) | (1) | 0 | 0 | 0 | 0 | (1) | 0 |
Other | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Balance at Dec. 31, 2015 | 4,334 | 4,200 | 2,157 | 709 | 29 | 137 | 1,168 | 134 |
Net income | 266 | 255 | 0 | 0 | 0 | 0 | 255 | 11 |
Other Comprehensive Income (Loss), Net of Tax | (30) | (27) | 0 | 0 | 0 | (27) | 0 | (3) |
Issuance of stock, net of issuance costs | 2,450 | 2,450 | 2,450 | 0 | 0 | 0 | 0 | 0 |
Cash dividends declared on preferred stock | (28) | (28) | 0 | 0 | 0 | 0 | (28) | 0 |
Cash dividends declared on common stock | (324) | (324) | 0 | 0 | 0 | 0 | (324) | 0 |
Stock Issued During Period, Value, Employee Contributions and Dividend Reinvestment Plan | 110 | 110 | 110 | 0 | 0 | 0 | 0 | 0 |
Senior management stock options exercised | 16 | 16 | 17 | 0 | (1) | 0 | 0 | 0 |
Stock option expense | 2 | 2 | 0 | 0 | 2 | 0 | 0 | 0 |
Common stock issued under purchase plan | 1 | 1 | 1 | 0 | 0 | 0 | 0 | 0 |
Beneficial conversion feature, net of tax (note 9) | 43 | 43 | 0 | 0 | 43 | 0 | 0 | 0 |
Preferred dividends paid by subsidiaries to non-controlling interest | (3) | 0 | 0 | 0 | 0 | 0 | 0 | (3) |
Common Dividends paid by subsidiaries to non-controlling interest | (2) | 0 | 0 | 0 | 0 | 0 | 0 | (2) |
Acquisition Non Controlling Interest | (15) | 10 | 3 | 0 | 7 | 0 | 0 | (25) |
Other | (4) | (4) | 0 | 0 | (5) | (4) | 5 | 0 |
Balance at Dec. 31, 2016 | CAD 6,816 | CAD 6,704 | CAD 4,738 | CAD 709 | CAD 75 | CAD 106 | CAD 1,076 | CAD 112 |
Consolidated Statements of Cha9
Consolidated Statements of Changes in Equity (Parenthetical) - CAD / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash dividends declared on common stock | CAD 1.995 | CAD 1.6625 |
Series A Preferred Stock [Member] | ||
Cash dividends declared on preferred stock | 0.6388 | |
Series B Preferred Stock [Member] | ||
Cash dividends declared on preferred stock | 0.5724 | |
Series E Preferred Stock [Member] | ||
Cash dividends declared on preferred stock | CAD 1.125 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Summary of Significant Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows: Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera’s primary rate-regulated subsidiaries and investments at December 31, 2016 included the following: Emera Florida and New Mexico represents TECO 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 includes: Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), an integrated regulated electric utility, serving approximately 736,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 374,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 522,000 customers across New Mexico; TECO Finance, Inc. (“TECO Finance”), a wholly owned financing subsidiary of TECO Energy. Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the prima ry electricity supplier in Nova Scotia, serving approximately 511,000 customers; Emera Maine provides electric transmission and distribution services to approximately 157,000 customers in the State of Maine in the United States ; Emera (Caribbean) Incorporated (“ECI”) 100.0 per cent interest (December 31, 2015 – 95.5 per cent) includes: The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the islan d of Barbados, serving approximately 126,000 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 (“ICDU”)) in Grand Ba hama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers; a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers; a 19.1 per cent indirect interest (December 31, 2015 – 18.2 per cent indirect interest) in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility in St. Lucia; Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline deliv ering 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 (“REC”), which expires in 2034; Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focuse d on two transmission investments related to the development of an 824 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 is developing 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 is scheduled to be completed in Q4 2017 and then be in service by January 1, 2018; a 62.7 per cent investment (December 31, 2015 – 55.1 per cent) in the partnership capital of Labrador-Island Link Limited Partners hip (“LIL”), a $3.4 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. 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 on completion of the LIL and final costing of all transmission projects relat ed 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. The investment in LIL is accounted for on the equity basis. Nalcor Energy has indicated that the project 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 t ransports 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, includes: Emera Energy Services (“EES” ), 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” (“NEGG”)), a 1,115 MW of combined-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 (“Broo klyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northern 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 l evels across Emera; Emera US Finance LP, a wholly owned financing subsidiary of Emera that issued multiple series of United States dollar denominated senior, unsecured notes for the purpose funding the acquisition of TECO Energy; Emera US Holdings Inc. (“E USHI”), 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; On December 8, 2016, Emera sold the Company’s remaining 4. 7 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), a public company traded on the Toronto Stock Exchange under the symbol “AQN”; 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, 2016 . 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 regulat ed 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 the 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 reasonable 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. They are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers (see n ote 17 for additi onal 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 self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the aver age rates 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 dominated debt held in Canadian functional currency companies a s 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 sheet date, and the effective portion of the hedge , is reco rded 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 the respective regulator and recorded based on meter readi ngs and estimates, which occur on a systematic basis throughout a month. 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 unbil led 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 performed, 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 ne t 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 investm ent 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 r ate 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 additions, 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 disposal costs, less salvage procee ds, 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 occur. The cost of property, pl ant 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 attributable to the capital project. Ov erhead 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. Expenditures for project developmen t 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 mai ntenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of d epreciable 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. Amortization is determined by the strai ght-line method, based on the estimated remaining service lives of the asset in each category. The service lives of regulated intangible assets require the appropriate regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase pr ice 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 guidance, goodwill is sub ject to an annual assessment for impairment at the reporting unit level. See note 23 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 Balance 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 realized. 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 balance at the amount expec ted 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 credits 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 or 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. Emera classifies interest and penalties associated with unrecogn ized tax benefits as interest and operating expense, respectively. Derivatives and Hedging Activities Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management pol icies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Man agement Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks. 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 physic al and financial contracts 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 purchases 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 allow 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 discont inue 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 a t 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 realiz ed. Any ineffective 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, 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, NSPI and GBPC that are documented as economic hedges, and for whi ch 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 r egulatory 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 these derivatives related to fuel for generation and purchased powe r 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 o f 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 classifies gains and losses on derivativ es 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 not offset by the fair value amount s of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”. Cash and Cash Equivalents Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $183 million have an effective interest rate of 0.6 per cent at December 31, 2016 ( 2015 – $78 million with an effective i nterest rate of 0.6 per cent). 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 pa yment fee may be assessed on account balances 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 provisions 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 accounts. Provisions for lo sses 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 customer rates. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purc hased, or allocated by the respective government agency. Asset Impairment Goodwill Goodwill is not amortized, but is subject to an annual impairment test. Emera’s reporting units containing goodwill assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount during the fourth quarter of each year, and interim impairment tests are performed when impairment indicat ors are present. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recover able if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. See note 23 for further detail . C ost 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 comp leted, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value. Fina ncial 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 securities 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 evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the ac quisition 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 sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statut e, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows 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, prior 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 depreciated in the same manner as the related long-lived asset. Over time, the liability is accrete d to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is deferred to a regulatory asset 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 ARO refers to a legal obligation to perform an asset retirement activity i n 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 liability is recognized at fair value when an amount can be determined. Variable Interest Entities The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facili ties. 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 obligatio n to absorb losses or the right to receive benefits of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary bene ficiary, the VIE is not consolidated in the Company’s consolidated financial statements. 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 includ ed 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 Tampa Electric and PGS are included as an expense on the Consolidated St atements 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 employe e 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 method of accounting for stock-based compensation. Stock-based compens ation 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 recognize d 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 employ ees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change oc curs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets . |
Change in Accounting Policy
Change in Accounting Policy | 12 Months Ended |
Dec. 31, 2016 | |
Change in Accounting Policy [Abstract] | |
Accounting Changes and Error Corrections [Text Block] | 2. C HANGE IN ACCOUNTING POLICY The new US GAAP accounting policies that are applicable to, and were adopted by the Company in 2016 , with no material impact on its con solidated financial statements, are described as follows: Consolidation In February 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amen dments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities were subject to re-evaluation under the revised consolidation model. Interest – Imputation of Interest In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest , which simplifies the presentation of debt issuance co sts. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company adopted this standard in Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in $62 million of debt issuance costs, as at December 31, 2015, previously presented as “Other lo ng-term assets”, being reclassified as a deduction from the carrying amount of the related long-term debt and “Convertible debentures” on its Consolidated Balance Sheets. In accordance with ASU 2015-15 Interest: Imputation of Interest , the Company conti nues to present debt issuance costs related to its revolving credit facilities and related instruments in “Other long-term assets” on its Consolidated Balance Sheets. Compensation – Retirement Benefits In April 2015, the FASB issued ASU 2015-04, Compensa tion – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. Intangibles – Goodwill and Other – Internal-Use Software In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a softw are license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does no t include a software license, the customer would account for the arrangement as a service contract. The guidance does not change USGAAP for a customer’s accounting for service contracts. Inventory – Simplifying the Measurement of Inventory In July 2015 , the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory . The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or mar ket. The Company early adopted in 2016 , as permitted. Derivatives and Hedging – Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships . The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge ac counting criteria continue to be met. The Company early adopted in 2016 , as permitted. Investments – Equity Method and Joint Ventures In March 2016, the FASB issued ASU 2016-07, Investments – Equity Method and Joint Ventures , which is part of FASB’s i nitiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. The Company ear ly adopted in 2016 , as permitted. Compensation – Stock Compensation In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liabilities and presentation on the statement of cash flows . The Company early adopted in 2016 , as permitted. |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncements [Abstract] | |
FUTURE ACCOUNTING PRONOUNCEMENTS | 3. FU TURE ACCOUNTING PR ONOUNCEMENTS The Company 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 minimal 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 recognition framework , which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The core principle is that a compa ny should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance will require additional disclosures regarding the nature, amoun t, 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 within those periods, beginning after December 15, 2017 and will a llow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018. The Company has implemented a project plan and is in the process of evaluating the impact of adoption of this standard on its consolidated financial statements and disclosures. This includes evaluating the available adoption methods, accounting for contributions in aid of construction and contract acquisition costs, the impact of collectability risk, unique contr act characteristics in the Company’s non-regulated businesses and disclosure requirements. The Company is also monitoring the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force. The ultimate impact of the adoption of ASC Topic 606, and the method of adoption, has not yet been finalized. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Finan cial 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, including interim repor ting within those periods, beginning after December 15, 2017. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements. 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 lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosure s 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 appli ed using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements. 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 investment 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 experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit qua lity indicators. This guidance will be effective for annual 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 retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements. Classification of Certain Cash Receipts and Cash Payment s 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 an d cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Decemb er 15, 2017 , with early adoption permitted, and is required to be applied on a retrospective approach. The C ompany is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows. Restricted Cash on the Stateme nt of Cash Flows In November 2016, the FASB issued ASU 2016-18, Restricted Cash on the Statement of Cash Flows . The standard will require t he 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 will no longer be presented in the statement of cash flows. 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 on a retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows. Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Defin ition 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 p eriods, beginning after December 15, 2017 , with early adoption permitted and is required to be applied prospectively. 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 measurement 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 will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testin g dates after January 1, 2017. The guidance is required to be applied prospectivel y. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2016 | |
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 USD per common share. The net cash purchase price totaled $ 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 net cash purchase price was financed through: (i) $ 728 million ($ 560 million USD) related to the first instalment of converti ble debentures represented by instalment receipts issued in 2015, $ 1.56 billion ($ 1.2 billion USD) fixed -to-floating subordinated notes, $ 500 million ($ 384 million USD) in Canadian long-term debt and $ 4.2 billion ($ 3.25 billion USD) in US long-term senior unsecured notes; (ii) available cash on hand; and (iii) drawings of $ 1.4 billion ($ 1.1 billion USD) on the Company’s acquisition credit facility. Total proceeds of the debt, that were not otherwise required to complete the acquisition, have been used for general corporate purposes. On August 2, 2016, the convertible debenture Final Instalment Date, Emera received the remaining two thirds of the convertible debenture instalments (note 10 ), for net proceeds of $ 1.4 billion. These funds were used to repa y the Company’s acquisition credit facility. TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include Tampa Electric, an integrated regulated electric utility in W est Central Florida, PGS, a regulated gas distribution utility serving customers across Florida, and NMGC, a regulated gas distribution utility in New Mexico. The majority of TECO Energy’s operations are subject to the rate-setting authority of the Feder al Energy Regulatory Commission (“FERC”), Florida Public Service Commission (“FPSC”), and New Mexico Public Regulation Commission (“NMPRC”), and are accounted for pursuant to USGAAP, including the accounting guidance for regulated operations. Except for un regulated long-term debt acquired and deferred taxes, preliminary 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 e xpect 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 accord ance with the acquisition method of accounting. 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 income 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 profil e. The goodwill recognized as part of this 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 preliminary allocation of the purchase conside ration 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. The allocation of the preliminary purchase consideration is considered preliminary due to the continued evaluation and analysis of deferred income taxes and the allocation of goodwill between reporting units. 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 preliminarily allocated to the TECO Energy reporting units and is subject to change as additional information is obtained through the purchase price allocation process. 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 E mera’s goodwill (note 23 ) . Acquisition Related Expenses Acquisition related expenses totaled $ 250 million ($166 million after-tax) and $ 76 million ($53 million after-tax) for the twelve months ended December 31, 2016 and 2015, respectively. These costs have been recognized in the Consolidated Statements of Income as follows: For the Year ended millions of Canadian dollars December 31 2016 2015 Operating revenues – regulated gas $ (10) $ - Operating, maintenance, and general 89 52 Interest expense, net 148 24 Other income (expenses), net (3) - Income tax expense (recovery) (84) (23) Acquisition related costs $ 166 $ 53 As part of the acquisition the Company has agreed to fund certain commitments in New Mexico. These commitments include contributions relating to economic development, donations, construction of an enlarged pipeline to the New Mexico/Mexico border, establishment of a matching fund to extend gas infrastructure in New Mexico and an annual customer bill reduction credit through June 30, 2018. For the year ended December 31, 2016 , Emera recognized $ 10 million in “Operating revenues - Regulated gas” and $ 30 million in “Operating, maintenance, and general” associated with these commitments for a total of $ 40 million ($ 23 million after-tax). In addition to the New Mexico commitments, operating, maintenance, and general expenses includes acquisition related leg al, accounting, banking and advisory fees and the accelerated vesting of outstanding stock-based compensation awards. Other income (expenses), net includes foreign exchange gains on acquisition related transactions. Interest expense, net includes interes t incurred on the convertible debentures represented by instalment receipts and the acquisition credit facility issued for the purpose of financing the TECO Energy acquisition. In addition, it includes interest for the period between the issuance date and the acquisition date on acquisition-related debt and the Beneficial Conversion Feature discount expensed on conversion of the convertible debentures. Supplemental Pro Forma Data The unaudited pro forma financial information below gives effect to the ac quisition of TECO Energy as if the transaction had occu rred at the beginning of 2015. 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 p lace at the beginning of 2015 , 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 a nd includes adjustments for pro forma financing costs associated with the acquisition. In addition, net income from TECO Coal, a discontinued operation sold by TECO Energy in 2015 is excluded. After-tax adjustments increased pro forma net income attribut able to common shareholders by $ 53 million for the twelve months ended December 31, 2016 . The twelve months ended December 31, 2015 after-tax adjustments were a decrease of $ 35 million. Adjustments to pro forma operating revenues resulted in an increase of $ 10 million for the year ended December 31, 2016 , with no adjustment for 2015. For the Year ended millions of Canadian dollars December 31 2016 2015 Pro forma operating revenues $ 6,034 $ 6,297 Pro forma net income attributable to common shareholders $ 386 $ 584 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2016 | |
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. As at December 31, 2016 , Emera has six reportable segments, specifically: Emera Florida and New Mexico (includes TEC, consisting of two divisi ons: Tampa Electric and PGS, NMGC, their parent company TECO Energy, and TECO Finance, a wholly owned financing subsidiary of TECO Energy); NSPI; Emera Maine; Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, and an equity investme nt in Lucelec); Emera Energy (Emera Energy Services, NEGG Facilities, Bayside Power, Brooklyn Energy and an equity investment in Bear Swamp); and Corporate and Other (Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic invest ments and holding companies). 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 $ 1,356 $ 297 $ 419 $ 298 $ 69 $ (2) $ 4,276 Inter-segment revenues (1) - - - - 11 24 (34) 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 2 312 - 600 Interest revenue - - - - 1 1 - 2 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 inter-company balances and inter-company 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. Inter-company 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) Corporate and Other Interest expense has 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. 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, 2015 Operating revenues from external customers (1) $ - $ 1,417 $ 284 $ 442 $ 578 $ 68 $ (2) $ 2,787 Inter-segment revenues (1) - - - 8 12 24 (42) 2 Total operating revenues - 1,417 284 450 590 92 (44) 2,789 Allowance for funds used during construction - debt and equity - 4 2 - - - - 6 Regulated fuel and fixed cost deferral adjustments - 42 - - - - - 42 Depreciation and amortization - 206 47 44 41 2 - 340 Interest expense - 129 19 14 1 59 - 222 Interest revenue - 5 - - 1 - - 6 Internally allocated interest (3) - - - - (18) 18 - - Income from equity investments - - - 3 21 84 - 108 Income tax expense (recovery) - 23 27 3 50 (10) - 93 Net income attributable to common shareholders - 130 45 41 99 82 - 397 Capital expenditures - 271 65 44 98 9 - 487 As at December 31, 2015 Total assets - 4,721 1,558 1,403 1,919 2,663 (225) 12,039 Investments subject to significant influence - - 12 39 - 1,094 - 1,145 Goodwill - - 158 106 - - - 264 (1) All significant inter-company balances and inter-company 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. Inter-company 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) 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 2016 2015 Canada $ 1,510 $ 1,546 United States 2,348 786 Barbados 254 259 The Bahamas 121 154 Dominica 44 44 $ 4,277 $ 2,789 (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 2016 2015 Canada $ 3,791 $ 3,672 United States 12,724 2,034 Barbados 416 402 The Bahamas 295 299 Dominica 64 62 $ 17,290 $ 6,469 |
Investments Subject to Signific
Investments Subject to Significant Influence and Equity Income | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2016 2015 2016 LIL (1) $ 400 $ 208 $ 24 $ 9 62.7 NSPML 315 188 21 15 100.0 M&NP (2) 175 189 23 23 12.9 Lucelec (2) 39 39 3 3 19.1 APUC (3) - 504 18 37 - Bear Swamp (4) - - 11 17 50.0 Other Investments 18 17 - 4 $ 947 $ 1,145 $ 100 $ 108 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. (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. This is consistent with industry practice for similar investments with significant influence. (3) On May 24, 2016, Emera completed the sale of 50.1 million common shares or 19.3 per cent of APUC's issued and outstanding common shares. This resulted in a pre-tax gain of $172 million (after-tax gain of $146 million), which was recorded in "Other income (expenses), net" in Q2 2016. On June 30, 2016, Emera exchanged 12.9 million of APUC subscription receipts and dividend equivalents into common shares. This resulted in a pre-tax gain of $63 million (after-tax gain of $53 million), which was recorded in "Other income (expenses), net" in Q2 2016. As a result of these transactions, Emera reclassified its investment in APUC from "Investments Subject to Significant Influence" to "Investment Securities" on the Consolidated Balance Sheets in Q2 2016, recorded at fair value. On December 8, 2016, Emera completed the sale of 12.9 million common shares or 4.7 per cent of APUC's issued and outstanding common shares. This sale resulted in a pre-tax loss of $12 million (after-tax loss of $10 million), which was recorded in "Other income (expenses), net" in Q4 2016. Emera no longer holds any interest in APUC. (4) 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 $217 million (2015 - $225 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Equity investments include a $14 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 33). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2016 2015 Balance Sheets Current assets $ 439 $ 439 Property, plant and equipment 1,132 648 Non-current assets 276 554 Total assets $ 1,847 $ 1,641 Current liabilities $ 219 $ 130 Long-term debt 1,288 1,288 Non-current liabilities 25 35 Equity 315 188 Total liabilities and equity $ 1,847 $ 1,641 |
Other Income (Expenses), Net
Other Income (Expenses), Net | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 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 - Allowance for equity funds used during construction 22 2 Foreign exchange (losses) gains and mark-to-market adjustments related to the TECO Energy acquisition (2) (135) 119 Gain on sale of NWP investment (3) - 19 Other 11 1 $ 174 $ 141 (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. (3) On January 25, 2015, Emera completed the sale of its 49 per cent interest in NWP. This resulted in a pre-tax gain of $19 million (after-tax gain of $12 million). |
Interest Expense, Net
Interest Expense, Net | 12 Months Ended |
Dec. 31, 2016 | |
Interest Income (Expense), Net [Abstract] | |
INTEREST EXPENSE, NET | 8. INTEREST EX PENSE, NET Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2016 2015 Interest on debt $ 443 $ 193 Beneficial conversion feature (note 10) 62 - Interest on Convertible Debentures (note 10) 65 23 Interest on acquisition credit facility related to the TECO Energy acquisition (note 4) 11 - Allowance for borrowed funds used during construction (13) (4) Interest revenue (2) (6) Other 19 6 $ 585 $ 212 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
INCOME TAXES | 9. INCOME TAXE S 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 2016 2015 Income before provision for income taxes $ 244 $ 545 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rates 76 169 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (47) (31) Non-taxable portion of gains on APUC transactions (34) - Non-deductible (non-taxable) portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition 21 (18) Financing deductions (17) (10) Tax effect of equity earnings (10) (11) Manufacturing and investment allowances (7) (5) Foreign tax rate variance (5) 2 Other 1 (3) Income tax expense (recovery) $ (22) $ 93 Effective income tax rate (9%) 17% 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. 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 2016 2015 Current income taxes Canada $ 13 $ 42 United States 18 26 Other 15 5 Deferred income taxes Canada $ (113) $ 11 United States 151 14 Other - (1) Operating loss carry forwards Canada (2) (4) United States (104) - Income tax expense (recovery) $ (22) $ 93 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 2016 2015 Canada $ 71 $ 349 United States 44 137 Other 129 59 Income before provision for income taxes $ 244 $ 545 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 2016 2015 Deferred income tax assets: Tax loss carry forwards $ 1,036 $ 72 Regulatory liabilities - cost of removal 388 42 Tax credit carry forwards 318 7 Derivative instruments 173 204 Pension and post-retirement liabilities 147 129 Regulatory liabilities – deferrals related to derivative instruments 101 94 Asset retirement obligations 47 47 Other 355 136 Total deferred income tax assets before valuation allowance 2,565 731 Valuation allowance (58) (18) Total deferred income tax assets after valuation allowance $ 2,507 $ 713 Deferred income tax (liabilities): Property, plant and equipment $ (3,625) $ (960) Derivative instruments (202) (264) Net investment in direct financing lease (103) (89) Other (124) (130) Total deferred income tax liabilities $ (4,054) $ (1,443) Consolidated Balance Sheets presentation: Long-term deferred income tax assets 125 32 Long-term deferred income tax liabilities (1,672) (762) Net deferred income tax liabilities $ (1,547) $ (730) 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 2016 2015 Canada NOL $ 199 $ 103 Capital loss 77 84 United States Federal NOL $ 2,595 $ 48 State NOL 1,183 225 Capital loss 14 4 Tax credit 318 30 Other NOL $ 22 $ 14 The following table summarizes as at December 31, 2016 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 $ 61 $ (27) $ 34 2026-2036 Capital loss 16 (16) - Indefinite United States Federal NOL $ 908 $ - $ 908 2024-2036 State NOL 45 (1) 44 2017-2036 Capital loss 3 (3) - 2018-2019 Tax credit 318 - 318 2019-2036 Other NOL $ 3 $ (3) $ - 2017-2023 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 $ 58 million has been recorded as at December 31, 2016 (2015 - $ 18 million) related to the loss carry forwards and investments. The following table provides details of the change i n unrecognized tax benefits for the years ended December 31 as follows: millions of Canadian dollars 2016 2015 Balance, January 1 $ 6 $ 5 Increases due to tax positions related to current year 12 - Increases due to tax positions related to a prior year - 1 Balance, December 31 $ 18 $ 6 The total amount of unrecognized tax benefits as at December 31, 2016 was $ 18 million ( 2015 - $ 6 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 ( 2015 - $ 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 $ 667 million as at December 31, 2016 ( 2015 - $ 669 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, 2016 , 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 cumulative 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 applicabl e interest will be refunded. 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 wil l be available in subsequent years. Should NSPI receive similar notices of reassessment for the 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 believe that 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 pr ocess is not determinable at this time. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2016 | |
Common Stock [Abstract] | |
COMMON STOCK | 10. COMMON STOCK Authorized : Unlimited number of non-par value common shares. 2016 2015 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, January 1 147.21 $ 2,157 143.78 $ 2,016 Conversion of Convertible Debentures 51.99 2,115 - - Issuance of common stock (1) 7.69 338 1.25 54 Issued for cash under Purchase Plans at market rate 2.51 115 2.10 88 Discount on shares purchased under Dividend Reinvestment Plan - (5) - (4) Options exercised under senior management share option plan 0.62 17 0.08 2 Stock-based compensation - 1 - 1 Balance, December 31 210.02 $ 4,738 147.21 $ 2,157 (1) In Q1 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. In addition, Emera completed an offering of 7.63 million common shares in December 2016, at $45.25 per common share, for net proceeds of approximately $345 million. The net proceeds were $335 million after $10 million of issuance costs, net of taxes. As at December 31, 2016 , there were the following common shares reserved for issuance: 6.6 million ( 2015 – 7.3 million) under the senior management stock option plan, 1.5 million ( 2015 – 1.6 million) under the employee common share purchase plan and 7.9 million ( 2015 – 3.3 million) under the dividend reinvestment plan. The issuance of common shares under the current or proposed common share compensation arrangements will not exceed 10 per cent of Emera's outstanding common shares . As at Dece mber 31, 2016 , Emera is in compliance with this requirement. Convertible Debentures On September 28, 2015, to finance a portion of the acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”) completed the sale of $1.9 billion aggregate principal amount of 4.0 per cent convertible unsecured subordinated debentures, represented by instalment receipts. On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggre gate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion. The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 (the “First Instalment”) was paid on closing of the Debenture Offerings on September 28, 2015 and October 2, 2015, and the remaining $667 (the “Final Instalment”) was payable on August 2, 2016 (the “Final Instalment Date”). Prior to the Final Instalment Date, the Debentures were represented by instalment receipts. The instalment receipts traded on the Toronto Stock Exchange (“TSX”) from September 28, 2015 to August 2, 2016 under the symbol “EMA.IR”. The Debentures will mature on Se ptember 29, 2025 and, as of the Final Instalment Date, bear interest at 0 per cent. The proceeds of the first instalment and the over-allotment of the Debentures were $727.6 million ($681.4 million net of issue costs). The proceeds of the final instalmen t payment were $1.457 billion ($1.413 billion net of issue costs). Final Instalment Notice was issued by Emera on June 29, 2016 with a payable date of August 2, 2016. At the option of the holde rs, each fully paid Debenture was convertible into common sha res of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This was a conversion rate of 23.8949 common shares per $1,000 principal amount o f Debentures. As the Final Instalment Date occurred prior to the first anniversary of the closing of the Debenture Offering, holders of the convertible debentures who paid the final instalment by August 2, 2016 received, in addition to the payment of acc rued and unpaid interest, a make-whole payment . This represented the interest that would have accrued from the day following the Final Instalment Date up to and including September 28, 2016. Recorded in the year ended December 31, 2016 is $65 million ($4 5 million after-tax) of interest expense related to the Convertible Debentures including the $21 million ($14 million after-tax) make-whole paymen t in Q2 2016 (note 8 ). As at December 31, 2016 , a total of 51.99 million common shares of the C ompany were is sued, representing conversion in to common shares of more than 99.6 per cent of the Convertible Debentures. After the Final Instalment Date of August 2, 2016, debentures not converted may be redeemed by Emera at a price equal to their principal amount. At maturity, Emera has the right to pay the principal 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 date. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | 11. EARNINGS PER SH ARE 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 potentially dilutive securities. Such dilutive items include Company contributions to the se nior 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) 2016 2015 Numerator Net income attributable to common shareholders $ 227.2 $ 397.2 Convertible Debentures 0.2 - Diluted numerator 227.4 397.2 Denominator Weighted average shares of common stock outstanding 170.4 144.9 Weighted average deferred share units outstanding 1.0 0.9 Weighted average shares of common stock outstanding – basic 171.4 145.8 Stock-based compensation 0.6 0.6 Convertible Debentures 0.2 - Weighted average shares of common stock outstanding – diluted 172.2 146.4 Earnings per common share Basic $ 1.33 $ 2.72 Diluted $ 1.32 $ 2.71 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 12. ACCUMULATED OTHER COMPREHEN SIVE INCOME (LOSS) The components of accumulated other comprehensive income are as follows: millions of Canadian dollars (Losses) gains on derivatives recognized as cash flow hedges Net change in unrecognized pension and post-retirement benefit costs Net change in net investment hedges Net change on available-for-sale investments Unrealized (loss) gain on translation of self-sustaining foreign operations Total AOCI For the year ended December 31, 2016 Balance, January 1, 2016 $ (35) $ (318) $ - $ - $ 490 $ 137 Other comprehensive income (loss) before reclassifications 11 - (49) 3 35 - Amounts reclassified from accumulated other comprehensive income loss 11 12 - (4) - 19 Equity method reclassification adjustments (8) (3) - - (35) (46) Net current period other comprehensive income (loss) 14 9 (49) (1) - (27) Other - - - - (4) (4) Balance, December 31, 2016 $ (21) $ (309) $ (49) $ (1) $ 486 $ 106 millions of Canadian dollars (Losses) gains on derivatives recognized as cash flow hedges Net change in unrecognized pension and post-retirement benefit costs Net change in net investment hedges Net change on available-for-sale investments Unrealized (loss) gain on translation of self-sustaining foreign operations Total AOCI For the year ended December 31, 2015 Balance, January 1, 2015 $ (8) $ (425) $ - $ 3 $ 82 $ (348) Other comprehensive income (loss) before reclassifications (34) - - (3) 408 371 Amounts reclassified from accumulated other comprehensive income loss (gain) 7 107 - - - 114 Net current period other comprehensive income (loss) (27) 107 - (3) 408 485 Balance, December 31, 2015 $ (35) $ (318) $ - $ - $ 490 $ 137 The reclassifications out of accumulated other comprehensive income (loss) are as follows: For the Year ended December 31 millions of Canadian dollars 2016 2015 Affected line item in the Consolidated Statements of Income Amounts reclassified from AOCI Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (2) $ (5) Interest rate swaps Income from equity investments 1 1 Foreign exchange forwards Operating revenue - regulated 12 9 Total before tax 11 5 Income tax expense - 2 Total net of tax $ 11 $ 7 Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) OM&G $ 41 $ 50 Past service costs (gains) OM&G (9) (7) Amounts reclassified into obligations Pension and post-retirement benefits (17) 72 Total before tax 15 115 Income tax expense (recovery) (3) (8) Total net of tax $ 12 $ 107 Net change in available-for-sale investments Other income (expenses), net $ (4) $ - Total before tax (4) - Income tax expense (recovery) - - Total net of tax $ (4) $ - Equity method reclassification adjustments Investments subject to significant influence $ 54 $ - Total before tax 54 - Income tax expense (recovery) (8) - Total net of tax $ 46 $ - Total reclassifications out of AOCI, net of tax, for the period $ 65 $ 114 |
Receivables, Net
Receivables, Net | 12 Months Ended |
Dec. 31, 2016 | |
Receivables [Abstract] | |
RECEIVABLES, NET | 13. RECEIVABLES, NET Receivables, net consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Customer accounts receivable – billed $ 715 $ 406 Customer accounts receivable – unbilled 270 144 Total customer accounts receivable 985 550 Allowance for doubtful accounts (13) (12) Customer accounts receivable, net 972 538 Other 42 40 $ 1,014 $ 578 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2016 | |
Inventory [Abstract] | |
INVENTORY | 14. INVENTORY Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Fuel $ 235 $ 185 Materials 215 100 Emission credits (1) 22 29 $ 472 $ 314 (1)The NEGG Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative ("RGGI") 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, 2016 | |
Derivative Instruments [Abstract] | |
DERIVATIVE INSTRUMENTS | 15. 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 2016 2015 2016 2015 Current Cash flow hedges Power swaps $ 5 $ 8 $ 2 $ 1 Foreign exchange forwards - - 12 14 5 8 14 15 Regulatory deferral Commodity swaps and forwards Coal purchases 26 - 9 12 Power purchases 3 - 1 - Natural gas purchases and sales 28 2 - 1 Heavy fuel oil purchases 6 - 4 20 Foreign exchange forwards 56 85 - 10 Physical natural gas purchases and sales - 2 - - 119 89 14 43 HFT derivatives Power swaps and physical contracts 33 151 44 119 Natural gas swaps, futures, forwards, physical contracts 93 99 357 359 Foreign exchange options - - - 2 126 250 401 480 Other derivatives Foreign exchange forwards - 92 1 - - 92 1 - Total gross current derivatives 250 439 430 538 Impact of master netting agreements with intent to settle net or simultaneously (105) (189) (105) (189) Total current derivatives 145 250 325 349 Long-term Cash flow hedges Power swaps 5 12 3 4 Foreign exchange forwards - - 10 27 5 12 13 31 Regulatory deferral Commodity swaps and forwards Coal purchases 57 - - 4 Power purchases 4 - 3 - Natural gas purchases and sales 5 - 2 - Heavy fuel oil purchases 4 - 3 17 Foreign exchange forwards 50 121 - - 120 121 8 21 HFT derivatives Power swaps and physical contracts 14 13 27 28 Natural gas swaps, futures, forwards and physical contracts 18 72 127 63 Foreign exchange options - 1 - 1 32 86 154 92 Other derivatives Interest rate swap - - 1 3 - - 1 3 Total gross long-term derivatives 157 219 176 147 Impact of master netting agreements with intent to settle net or simultaneously (26) (51) (26) (51) Total long-term derivatives 131 168 150 96 Total derivatives $ 276 $ 418 $ 475 $ 445 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 2016 2015 2016 2015 Regulatory deferral $ 10 $ - $ 10 $ - HFT derivatives 121 240 121 240 Total impact of master netting agreements with intent to settle net or simultaneously $ 131 $ 240 $ 131 $ 240 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. Emera also enters into interest rate swaps to fix Bear Swamp’s cost of debt. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. 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 2016 2015 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 2 - - 5 - - Realized gain (loss) in operating revenue – Regulated - - (12) - - (9) Realized gain (loss) in income from equity investments - (1) - - (1) - Total gains (losses) in Net income $ 2 $ (1) $ (12) $ 5 $ (1) $ (9) As at December 31 millions of Canadian dollars 2016 2015 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 $ 2 $ - $ (22) $ 4 $ (1) $ (42) The Company expects $14 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, 2016, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2017 2018 2019 2020 Foreign exchange forwards (USD) sales $ 53 $ 45 $ 30 $ 30 Foreign exchange forwards (EURO) purchases 3 - - - Regulatory Deferral As previously noted, Tampa Electric, PGS , NMGC , NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption. 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 2016 2015 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 $ 40 $ - $ (2) $ (24) $ - $ (7) Unrealized gain (loss) in regulatory liabilities 101 (1) (30) 1 9 173 Realized (gain) loss in regulatory assets - - 12 (3) - - Realized (gain) loss in regulatory liabilities - - (8) - - - Realized (gain) loss in property, plant and equipment - - - - - (1) Realized (gain) loss in inventory (1) 5 - (44) 12 - (44) Realized (gain) loss in regulated fuel for generation and purchased power (2) 17 (1) (18) (16) (7) (18) Total change derivative instruments $ 163 $ (2) $ (90) $ (30) $ 2 $ 103 (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, 2016 , 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: 2017 2018-2020 millions Purchases Purchases Coal (metric tonnes) - 2 Natural Gas (Mmbtu) 42 24 Heavy fuel oil (bbls) - 1 Foreign Exchange Swaps and Forwards As at December 31, 2016 , the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contr acts that are expected to settle as outlined below: 2017 2018-2020 Fuel purchases exposure (millions of US dollars) $ 224 $ 240 Weighted average rate 1.0722 1.1138 % of USD requirements 120% 44% The Company reassesses foreign exchange forecasts 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 , a s 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 2016 2015 Power swaps and physical contracts in non-regulated operating revenues $ (1) $ 10 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 69 5 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (7) (3) Foreign exchange options in other income (expenses), net (2) (1) $ 59 $ 11 As at December 31, 2016 , the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: millions 2017 2018 2019 2020 2021 Natural gas purchases (Mmbtu) 270 69 54 45 45 Natural gas sales (Mmbtu) 202 20 16 12 1 Power purchases (MWh) 3 - - - - Power sales (MWh) 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 2016 2015 Interest Foreign Interest Foreign rate exchange rate exchange swaps forwards swaps forwards Realized gain (loss) in other income (expense) $ - $ (87) $ - $ - Unrealized gain (loss) in other income (expense) - - - 92 Unrealized gain (loss) in interest expense, net 2 - (3) - Total gains (losses) in net income $ 2 $ (87) $ (3) $ 92 As at December 31, 2016, 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. During the year ended December 31, 2016, $1,519 million in foreign exchange forwards and swaps that were used to partially hedge proceeds for the TECO Energy acquisition settled. 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, 2016 , the maximum exposure the Company has to credit risk is $ 1,019 million ( 2015 - $ 901 million) , which includ es 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 counterparti es 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 in terest 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 a t December 31, 2016 was $ 271 million ( 2015 - $ 94 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 Derivative s 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 relating t o creditworthiness, collateral, non-performance and default. As at December 31, 2016 , the Company had $ 104 million ( 2015 - $ 83 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 $ 91 million ( 2015 - $ 72 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, 2016 December 31, 2015 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 315 24% $ 189 20% Commercial 170 13% 103 10% Industrial 38 3% 29 3% Other 69 5% 53 5% 592 45% 374 38% Trading group Credit rating of A- or above 52 4% 31 3% Credit rating of BBB- to BBB+ 60 5% 22 2% Not rated 57 4% 31 3% 169 13% 84 8% Other accounts receivable 253 20% 120 12% 1,014 78% 578 58% Derivative Instruments (current and long-term) Credit rating of A- or above 252 20% 340 34% Credit rating of BBB- to BBB+ 1 0% 70 7% Not rated 23 2% 8 1% 276 22% 418 42% $ 1,290 100% $ 996 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Cash collateral provided to others $ 91 $ 107 Cash collateral received from others 52 29 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 the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full col lateralization. As at December 31, 2016 , the total fair value of these derivatives, in a l iability position, wa s $ 475 million ( December 31, 2015 – $ 445 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, 2016 | |
Fair Value Measurements [Abstract] | |
FAIR VALUE MEASUREMENTS | 16 . FAIR VALUE MEASUREMENTS The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 15 ), 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, 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 Commodity swaps and forwards 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 swap - 1 - 1 - 2 - 2 Total liabilities 25 61 389 475 Net assets (liabilities) $ (4) $ 154 $ (349) $ (199) As at December 31, 2015 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 20 $ - $ - $ 20 20 - - 20 Regulatory deferral Commodity swaps and forwards Coal purchases - 1 - 1 Foreign exchange forwards - 207 - 207 Physical natural gas purchases and sales - - 2 2 - 208 2 210 HFT derivatives Power swaps and physical contracts 38 1 (8) 31 Natural gas swaps, futures, forwards and physical contracts - 8 57 65 38 9 49 96 Other derivatives Foreign exchange forwards - 92 - 92 - 92 - 92 Total assets 58 309 51 418 Liabilities Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 41 - 41 5 41 - 46 Regulatory deferral Commodity swaps and forwards Coal purchases - 16 - 16 Natural gas purchases and sales 1 - - 1 Heavy fuel oil purchases - 37 - 37 Foreign exchange forwards - 10 - 10 1 63 - 64 HFT derivatives Power swaps and physical contracts 15 - (2) 13 Foreign exchange options - 4 - 4 Natural gas swaps, futures, forwards and physical contracts 14 22 279 315 29 26 277 332 Other derivatives Interest rate swaps - 3 - 3 - 3 - 3 Total liabilities 35 133 277 445 Net assets (liabilities) $ 23 $ 176 $ (226) $ (27) The change in the fair value of the Level 3 financial assets for the year ended December 31, 2016 was as follows: Regulatory Deferral Cash Flow Hedges and HFT Derivatives millions of Canadian dollars Oil Financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2016 $ - $ 2 $ (8) $ 57 $ 51 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Unrealized gains (losses) included in regulatory assets or liabilities 3 (1) - - 2 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 8 (18) (10) Net transfers out of Level 3 (2) - - - (2) Balance, December 31, 2016 $ 1 $ - $ - $ 39 $ 40 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2016 was as follows: Regulatory Deferral Cash Flow Hedges and HFT Derivatives millions of Canadian dollars Oil Financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2016 $ - $ - $ (2) $ 279 $ 277 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 2 110 112 Balance, December 31, 2016 $ - $ - $ - $ 389 $ 389 The Company evaluate s the observable input of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2016 , transfer s from Level 3 to Level 1 were a result of an increase in observable inputs. Emera’s Enterprise Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hie rarchy that prioritizes the inputs used to measure fair value. When possible, determining fair value is based primarily on observable market inputs in active markets. Contracts with quoted prices available in active markets and exchanges for identical as sets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are classified as leve l 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations within Emera and its aff iliates. Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis dif ferentials; 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 include 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 discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly l ower (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, 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) As at December 31, 2015 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets Regulatory deferral – Physical $ 2 Modelled pricing Third-party pricing $5.15 - $6.21 $5.72 natural gas purchases and sales Probability of default 0.01% 0.01% HFT derivatives – (8) Modelled pricing Third-party pricing $26.27 - $129.20 $70.45 Power swaps and Correlation factor 0.98% - 1.00% 0.99% physical contracts Probability of default 0.00% - 0.02% 0.00% Discount rate 0.00% - 0.15% 0.01% 54 Modelled pricing Third-party pricing $1.13 - $9.12 $3.26 Probability of default 0.00% - 0.10% 0.01% Discount rate 0.00% - 0.33% 0.04% 3 Modelled pricing Third-party pricing $1.25 - $15.74 $6.19 Basis adjustment (0.06)% - 0.95% 0.68% Probability of default 0.00% - 0.09% 0.00% Discount rate 0.00% - 0.08% 0.00% Total assets $ 51 Liabilities HFT derivatives – $ (2) Modelled pricing Third-party pricing $26.27 - $129.20 $70.82 Power swaps and Correlation factor 0.98% - 1.00% 0.99% physical contracts Own credit risk 0.00% - 0.02% 0.00% Discount rate 0.00% - 0.15% 0.01% HFT derivatives – 279 Modelled pricing Third-party pricing $0.74 - $10.59 $5.58 Natural gas swaps, Probability of default 0.00% - 0.03% 0.00% physical contracts Discount rate 0.00% - 0.12% 0.01% Total liabilities 277 Net assets (liabilities) $ (226) The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: As at December 31, 2016 millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total Long-term debt (including current portion) $ 14,744 $ 15,723 $ 78 $ 14,843 $ 802 $ 15,723 As at December 31, 2015 millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total Long-term debt (including current portion) $ 4,009 $ 4,487 $ - $ 3,841 $ 646 $ 4,487 The fair values 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 level 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 level 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 dominated Hybrid Notes as a hedge of the foreign currency exposure of i ts ne t investment in United States dollar denominated operations. A foreign currency loss of $49 million was recorded in Other Comprehensive Income for the twelve months ended December 31, 2016 ( 2015 – nil). There was no ineffectiveness for the twelve months ended December 31, 2016 ( 2015 – 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 value 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, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | 17. REGULATORY Assets and Liabilities 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. Emera Florida and New Mexico Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is a lso 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 collect total revenues equal to their cost of providing service, plus an appropriate return on invested capital. Base Rates - Tampa Elect ric 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 w ould receive a revenue increase of $ 110 million USD effective January 1, 2017 or the date Tampa Electric’s Polk Power Station goes into service, whichever is later. The expansion of Polk Power Station went into service on January 17, 2017. The agreement also provides that Tampa Electric’s allowed regulatory ROE would remain in pla ce with a potential increase of the midpoint to 10.50 per cent from 10.25 per cent if U.S. Treasury bond yields exceed a specified threshold. This agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE were to fall below 9.25 per cent (or 9.5 per cent if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25 per cent (or 11.5 per cent if the allo wed ROE is increased as described above) any party to the agreement other than Tampa Electric 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. Base Rates - PGS 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 related 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 established in PGS’s next general rate proceeding or December 31, 2 020. 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 cus tomer 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 site s 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 2016, PGS recorded $ 16 million USD of this amortization. Base Rates - NMGC NMGC’s base rates were es tablished 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 continu e to provide an annual bill reduction credit of $ 4 million USD through June 30, 2018. NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Act”) and is subject to regulation under the Act by the UARB. The 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 r egulated ROE range for 2016 and 2015 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 Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and 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 yea r. On December 18, 2015, the Province enacted the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”) , which required NSPI to file a three-year stability plan for Fuel Costs and a General Rate Application (“GRA”) for non-fuel costs if req uired by April 30, 2016. On March 7, 2016, NSPI announced that it would not file a GRA related to non-fuel electricity rates for the 2017 to 2019 period and NSPI filed the stability plan for Fuel Costs with the UARB for 2017 through 2019. On July 19, 2 016, the UARB approved a Consensus Agreement between NSPI and customer representatives related to the Rate Stability Plan fuel costs for 2017 through 2019 which resulted in an average annual increase of 1.1 per cent for each of these three years. Subseque ntly, certain customer representatives requested changes resulting in amended rates that were approved by the UARB on November 15, 2016 and result in an average annual rate increase of 1.0 per cent for each of these three years. In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered Fuel Costs. The approved customer rates reset the base cost of fuel rates for 2016. In addition, $ 12 million was recovered of prior years’ unrecovered Fuel Costs in 2016 . This resulted in a combined average rate decrease for customers of approximately 1 per cent in 2016. The rates and recovery of these costs began on January 1, 2016. On December 21, 2016, the UARB approved a settlement agreement between NSPI and custom er representatives which resolved all issues related to the 2014 and 2015 FAM Audit and an issue that would impact future periods. As a result of this settlement agreement, NSPI agreed to forego $ 3 million of any incentive payment as a result of 2016 fuel costs savings achieved by the Company. NSPI achieved a $ 2.8 million incentive payment for 2016 and contributed that plus an additional $ 0.2 million to the benefit of customers. On December 12, 2016, the UARB approved NSPI’s application to refund over-re covered fuel costs in 2016 to customers. The over-recovered fuel costs balance at the end of 2016 will be refunded to customers through a one-time credit on their bills prior to April 30, 2017 and will be based on individual electricity usage in 2016. Th e balance to be refunded to customers is approximately $ 36 million. FAM and fixed cost deferrals recognized in the 2016 and 2015 Consolidated Statement of Income consisted of the following: For the Year ended December 31 millions of Canadian dollars 2016 2015 (Over) under recovery of current period Fuel costs $ 29 $ (24) Recovery from customers of prior years’ Fuel costs 12 56 Application of non-fuel revenues 20 45 Regulated fixed cost deferral related to 2015 demand side management - (35) Regulated fuel adjustment mechanism $ 61 $ 42 Emera Maine Emera Maine’s core businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries 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 22, 2016 the allowed ROE became 9.00 per cent on a common equity component of 49 per cent. Transmission Operations There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities. Bangor Hydro District Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmiss ion investments, adjusted for current year forecasted transmission investments. Effective June 1, 201 6 , transmission rates for the Bangor Hydro district increased by approximately 2 per cent in connection with its annual transmission formula rate filing ( 201 5 – increased by 21 per cent). The increase is associated primarily with the recovery of increase d transmission plant in service and as a result of the prior year tariff rate including a rate refund related to the aforementioned FERC ROE decision. Ban gor Hydro District’s bulk transmi ssion assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District , along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for curren t year forecasted investments. The participating transmission providers are also required to contri bute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. On June 1, 201 6 , Bangor District’s regionally recoverable transmission investments and ex penses in creased by 9 per cent (201 5 – de creased by 6 per cent). MPS District MPS District (the franchise electric service territory associated with the former Maine Public Service Company in northern Maine) 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 transmission investments and expenses, adjusted for current year forecasted investments . The current allo wed ROE for transmission operations is 10.2 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2016 the transmission rates for the Maine Public Service district increased by approximately 43 per cent for wholesale customers (2015 - decreased by 1 per cent) and on July 1, 2016 increased by 36 per cent for retail customers (2015 - decreased by 22 per cent) in connection with its annual transmission formula rate filing. These increases were primarily due to an increase in the recovery of increased transmission plant in service. The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC. 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 accounting orders issued by the MPUC. Unlike transmission and distribution operati onal assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover strand ed costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. Each year , stranded cost rates in each District are evaluated for a potential rate change on July 1 to recover cost deferrals for the pr ior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information. Bangor Hydro District Bangor District’s net regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $ 11.4 million as at December 31, 2016 (2015 – $ 19.7 million) or 1.0 per cent of Emera Maine’s net asset base (20 15 – 1.8 per cent). The Bangor Hydro District is currently undergoing a stranded cost rate proceeding with the MPUC to set rates for the period March 1, 2017 to February 28, 2020. While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To stabilize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and ad dressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly. MPS District Effective January 1, 2015, the stranded cost rates for the Maine Public Service district decreased by approximately 150 per cent. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75 per cent, with a common equity component of 48 per cent. On July 1, 2016, stranded cost rates further decreased by 7.6 % to flow back over-collections associated with stranded cost reconciliation deferrals. The allowed ROE remaine d consistent with the January 1, 2015 rate change. The reduced stranded cost revenues are offset by reductions in expense and do not affect earnings. The Maine Public district is currently undergoing a stranded cost rate proceeding with the MPUC to set ra tes for the period March 1, 2017 to February 28, 2020. 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 , which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ens ure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to generate , transmit and distribute electricity on the island until 2028. BLPC is regulated under a cost-of-service mod el, 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 rate base for 2016 and 2015 was 10 per cent. All BLPC fuel cos ts 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 approved the calculation of the fuel charge, which is adjusted on a m onthly basis. 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 rate base for 2016 and 2015 was 15 per cent. 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 . Grand Bahama Power Company Limited GBPC is a vertically integrated utility and sole provid er of electricity on Grand Bahama Island. The Grand Bahama Port Authority (“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 and a reasonable return earned. GBPC’s approved regulated return on rate base was 8.8 per cent for 2016 and 10 per cent for 2015 . In October 2016, the island of Grand Bahama took a direct hit from Hurricane Matthew. GBPC’s generation and substation infrastructure weathered the storm well, however over 2,100 transmission and distribution poles and related conduit were damaged or dest royed, as were many connections to customer homes. Restoration efforts have been completed. GBPC has recorded $ 28 million USD of restoration costs associated with Hurricane Matthew with no impact to net income. $ 21 million USD has been recorded as a reg ulated asset amortized over five years and $ 7 million USD recorded as property plant and equipment depreciating at an average 27 years. Both assets are included in Rate Base. The GBPA has approved full recovery of the storm restoration costs in this mann er. In December 2016, the GBPA approved that 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 Mat thew 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 de ferral at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied 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 considered a Gro up 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 Br unswick Pipeline. Regulatory Assets and Liabilities Regulatory assets and liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Regulatory assets Deferred income tax regulatory assets $ 632 $ 431 Pension and post-retirement medical plan 373 12 Environmental remediations 49 - Unamortized defeasance costs 39 46 2015 demand side management deferral 32 36 GBPC Hurricane Matthew restoration 28 - Stranded cost recovery 27 28 Debt basis adjustment 19 - Deferrals related to derivative instruments 15 68 Cost-recovery clauses 12 - Deferred bond refinancing costs 9 - Regulated fuel adjustment mechanism - 14 Other 87 64 $ 1,322 $ 699 Current $ 80 $ 94 Long-term 1,242 605 Total regulatory assets $ 1,322 $ 699 Regulatory liabilities Accumulated reserve - cost of remova l 990 94 Deferrals related to derivative instruments 230 $ 210 Cost-recovery clauses 153 - Regulated fuel adjustment mechanism 94 42 Transmission and delivery storm reserve 75 - Self-insurance fund (notes 7 and 33) 30 87 Deferred income tax regulatory liabilities 26 18 Bill reduction credit (note 4) 10 - Other 31 14 $ 1,639 $ 465 Current $ 362 $ 112 Long-term 1,277 353 Total regulatory liabilities $ 1,639 $ 465 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. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and postretirement benefits at Emera Florida and New Mexico. It is included in rate base and earns a rate of return as permitted by th e FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Environmental Remediation This asset is primarily related to Peoples Gas 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, 2016 , totaled $ 0.8 billion ( 2015 – $ 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. The 2015 Program Costs were deferred to a regul atory 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 from a commercial lender in order to re pay NSPI the amount it expended on behalf of its customers in 2015. On December 2, 2016, EffficiencyOne secured the financing and advanced funds to NSPI to finance the 2015 DSM deferral. This was set up as a payable on the consolidated balance sheet, inc luded in current and long-term other liabilities. As NSPI collects the associated amounts from customers over the next seven years, it will repay the balance to EfficiencyOne thereby reducing the liability. The 2016 annual DSM costs have not been deferre d and have been charged to earnings. Hurricane Matthew Restoration This asset represents restoration costs incurred by GBPC associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The GBPA has approved full recovery of storm restoration costs. Stranded Cost Recovery Due to the decommissioning of a steam turbine in GBPC 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. 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 or inventory, depending on the nature of the it em 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 position. Cost Recovery Claus es These assets and liabilities are related to FPSC and NMPRC 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. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. Deferred Bond Refinancing Costs This asset represents Tampa Electric and NMGC past 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 average cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instrumen ts. Fuel Adjustment Mechanism Differences between actual Fuel Costs and amounts recovered from NSPI 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 subsequ ent year. The 2016 FAM liability is recorded as a current FAM liability of $ 32 million, to be applied in 2017 and a long-term FAM liability of $ 62 million to be returned to customers during the 2018 through 2019 period as legislated. Accumulated Reserve – Cost of Removal This regulatory liability represents the non-ARO C ost of R emoval (“COR”) in the accumulated reserve for depreciation of 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 ra temaking purposes . This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. Prior to July 1, 2016, NSPI presented COR as a deduction in the carrying value of proper ty, plant and equipment as part of accumulated depreciation. The total amount reclassified as at December 31, 2015 was $ 94 million. Transmission and Delivery 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 its reserve to the current level. As a result of several nam ed storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $ 11 million of storm costs in 2016 and 2015. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surch arge to customers during the five month period ended December 31, 2017. Bill Reduction Credit This regulatory liability represents NMGC’s stipulation agreement included a commitment to provide an annual bill reduction credit to customers of $ 4 million USD per year through June 30, 2018 , as part of Emera’s acquisition of TECO Energy. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | 18 . RELATED PA RTY 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. Inter-company 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 in note 1 . All material amounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies include natural gas transportation capacity revenues from M&NP reported in the Consolidated Statements of Inc ome. Revenues from M&NP, reported in Operating rev enues, Non-regulated, totaled $ 29 million for the year ended December 31, 2016 ( 2015 - $ 23 million). There are no significant amounts between Emera and its associated companies reported on Emera’s Consoli dated Balance S heets as at December 31, 2016 and 2015 . |
Prepayments and Other Current A
Prepayments and Other Current Assets | 12 Months Ended |
Dec. 31, 2016 | |
Prepaid Expense and Other Assets, Current [Abstract] | |
Prepayment and other current assets [Text Block] | 19. PREPAYMENTS AND OTHER CURRENT ASSETS Prepayments and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Capitalized transportation capacity (1) $ 190 $ 223 Prepaid expenses 57 18 Due from related parties 16 2 Net investment in direct financing lease 8 6 Other 5 7 $ 276 $ 256 (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, 2016 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | 20. PROPERTY, P LANT 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 2016 2015 Generation 3 to 131 $ 10,553 $ 4,957 Transmission 28 to 77 2,799 1,603 Distribution 11 to 80 5,715 2,503 Gas transmission and distribution 10 to 85 2,895 - General plant and other 3 to 50 1,711 932 Total cost 23,673 9,995 Less: Accumulated depreciation (7,787) (3,737) 15,886 6,258 Construction work in progress 1,404 211 Net book value $ 17,290 $ 6,469 |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Employee Benefit Plans [Abstract] | |
EMPLOYEE BENEFIT PLANS | 21. EMPLOYEE BENEFIT PLANS Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover sub stantially 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. The acquisition of TECO Energy has added three defined benefit pension plans: TECO Energy Group Retirement Plan. An ongoing qualified pension plan covering all employees of TECO Energy, Inc. and its affiliates. This plan is a pension equity plan funded solely by employer contributions. There are no employee contributions to this plan. TECO Energy Group Supplemental Executive Retirement Plan. An unqualified supplemental executive retirement plan covering certain officers elected by the previous TECO Energy Board of Directors. This plan was historically unfu nded, but was funded as a result of Emera’s acquisition of TECO Energy. TECO Energy Group Benefit Restoration Plan . An unfunded supplemental executive retirement plan effective January 1, 2016. The plan provides the benefits under the TECO Energy Group R etirement Plan formula that would otherwise be restricted as a result of the Internal Revenue Code. In addition, there are two non-pension benefit plans: TECO Energy Post-retirement Health and Welfare Plan. This plan offers retirees under age 65 and thei r dependents a self-funded health reimbursement account (“HRA”) medical plan identical to that offered to active TECO Energy employees. Retirees over the age of 65 are enrolled in a Medicare Advantage plan. New Mexico Gas Company Retiree Medical Plan . Th is plan offers retirees under age 65 and their dependents a self-funded HRA medical plan identical to that offered to active TECO Energy employees. Retirees over age 65 and their dependents receive a fixed subsidy with which they can purchase additional c overage through a medical supplement program. Dental benefits are provided to retirees and spouses. Plan assets are held in a trust. The net periodic costs below that relate to TECO Energy reflect purchase accounting at the acquisition date. In accord ance with the Company’s accounting policies, unamortized gains and losses and past service costs are recognized in AOCI for TECO Energy’s unregulated companies and as regulatory assets for their regulated companies. 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 2016 2015 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 $ 1,520 $ 88 $ 1,470 $ 102 Addition of TECO Energy, July 1, 2016 1,035 277 - - Service cost 35 4 22 3 Plan participant contributions 8 - 8 - Interest cost 79 9 59 4 Plan amendments - 2 - (27) Benefits paid (94) (16) (61) (6) Actuarial losses (2) (12) (15) 1 Foreign currency translation adjustment 26 6 37 11 Balance, December 31 2,607 358 1,520 88 Change in plan assets Balance, January 1 1,300 6 1,205 5 Addition of TECO Energy, July 1, 2016 830 29 - - Employer contributions 49 17 23 6 Plan participant contributions 8 - 8 - Benefits paid (94) (16) (61) (6) Actual return on assets, net of expenses 93 2 96 - Foreign currency translation adjustment 22 1 29 1 Balance, December 31 2,208 39 1,300 6 Funded status, end of year $ (399) $ (319) $ (220) $ (82) 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 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,579 $ 358 $ 1,489 $ 87 Fair value of plan assets 2,171 39 1,261 5 Funded status $ (408) $ (319) $ (228) $ (82) Plans with Accumulated Benefit Obligation (“ABO”) in excess of plan assets The ABO for the defined benefit pension plans was $ 2,489 million as at December 31, 2016 ( 2015 – $ 1,427 million). T he aggregate financial position for those plan s with an ABO in excess of the p lan assets for the yea rs ended December 31 is as follows : millions of Canadian dollars 2016 2015 Defined benefit pension plans Defined benefit pension plans ABO $ 2,462 $ 1,424 Fair value of plan assets 2,171 1,261 Funded status $ (291) $ (163) Balance Sheet The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 millions of Canadian dollars 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Current liabilities $ (41) $ (17) $ (4) $ (3) Long-term liabilities (367) (302) (224) (79) Other asset (non-current) 9 - 9 - Amount included in deferred tax asset 16 (1) 19 (3) AOCL (AOCI) and regulatory assets after-tax adjustment 620 45 330 (9) Net amount recognized at end of year $ 237 $ (275) $ 130 $ (94) 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, 2016 $ - $ 353 $ (4) Amortized in current period (9) (42) 1 Current year addition to AOCL or regulatory assets 318 19 - Balance, December 31, 2016 $ 309 $ 330 $ (3) Non-pension benefits plans Balance, January 1, 2016 $ - $ 15 $ (27) Amortized in current period - (2) 8 Current year addition to AOCL (AOCI) or regulatory assets 48 2 - Balance, December 31, 2016 $ 48 $ 15 $ (19) 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 330 $ 15 $ 353 $ 15 Past service (gains) (3) (19) (4) (27) Regulatory assets 309 48 - - Total AOCL (AOCI) and regulatory assets on a pre-tax basis 636 44 349 (12) Amount included in deferred tax asset (16) 1 (19) 3 Net amount in AOCL (AOCI) and regulatory assets after-tax adjustment $ 620 $ 45 $ 330 $ (9) Benefit cost components Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of Canadian dollars 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 35 $ 4 $ 22 $ 3 Interest cost 79 9 59 3 Expected return on plan assets (97) (1) (65) - Current year amortization of: Actuarial losses 42 2 48 1 Past service costs (gains) (1) (8) (1) (6) Regulatory assets (liability) 9 - - - Total $ 67 $ 6 $ 63 $ 1 The expected return on plan assets is determined based on the market-related value of plan assets of $ 1,180 million as at January 1, 2016 and $ 859 million as at the acquisition date for TECO Energy ( 2015 – $ 1,089 million) , adjusted for interest on certain cash flows during the year. T he market-related value of assets for TECO Energy was reset to equal the market value of assets as at July 1, 2016. The market-related value of assets is based on a five-year smoothed asset va lue. 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 assets 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 36% to 50% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Short-term securities 0% to 2% Fixed income 40% to 48% Equities 50% to 61% 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, 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. As at December 31, 2015 millions of Canadian dollars NAV Level 1 Total Percentage Cash and cash equivalents - $ 12 $ 12 1 % Equity securities: Canadian equity - 190 190 - % US equity - 240 240 18 % Other equity - 240 240 18 % Other investments measured at NAV $ 619 - 619 48 % Total $ 619 $ 682 $ 1,301 100 % Refer to note 16 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 substantially unrelated to salary. The company 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. The target asset allocation for the Emera Maine Post-Retirement Benefits Plan is as follows: Asset Class Target Range at Market Short-term securities 10% to 50% Fixed income 0% to 40% Equities: US 30% to 60% Non-US 0% to 60% The assets for the NMGC Post-Retirement Benefits Plan are invested in life insurance policies. The life insurance does not mirror any specific employee benefit. The p lan can tap into the cash surrender value of the life insurance policies to generate cash to pay retire e medical costs. In addition, as the individuals covered by the life insurance die, the p lan receives the life insurance proceeds (less any cash surrender value previously drawn upon) to cover retiree medical costs. The fair values of investments as at December 31, 2016 , for all Post - Retirement Benefit Plans by asset category, are as follows: 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 December 31, 2015 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 20 % Other investments measured at NAV $ 4 - - 4 80 % Total $ 4 $ 1 $ - $ 5 100 % Refer to Note 16 for more information on the fair value hierarchy and inputs used to measure fair value. Investments in Emera As at December 31, 2016 and 2015 , 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 2017 $ 117 $ 25 Expected benefit payments 2017 172 22 2018 140 23 2019 150 23 2020 156 24 2021 165 25 2022 – 2026 912 130 Assumptions The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 2016 2015 (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 3.96 % 4.18 % 4.02 % 4.04 % Rate of compensation increase 2.82 % 2.54 % 3.07 % 3.50 % Health care trend - initial (next year) - 6.78 % - 5.50 % - ultimate - 4.45 % - 4.20 % - year ultimate reached - 2020 - 2020 Benefit cost for year ended December 31: Discount rate 3.79 % 3.88 % 3.99 % 3.98 % Expected long-term return on plan assets 6.33 % 4.43 5.91 % - Rate of compensation increase 2.88 % 2.56 % 3.07 % 3.50 % Health care trend - initial (current year) - 6.76 % - 5.90 % - ultimate - 4.45 % - 4.30 % - year ultimate reached - 2020 - 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 2016 : millions of Canadian dollars Increase Decrease Service cost and interest cost $ 1 $ (1) Accumulated post-retirement benefit obligation, December 31 20 (17) Sensitivity Analysis for Defined Benefit Pension Plans The impact on the 2016 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 $ (7) $ 7 Asset rate assumption (4) 4 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 2017: 2017 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (53) $ (1) Past service gains 1 8 Regulatory assets (16) 3 Total $ (68) $ 10 Defined Contribution Plan Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2016 was $ 17 million ( 2015 – $ 9 million) , with the increase due to the acquisition of TECO E nergy . |
Net Investment in Direct Financ
Net Investment in Direct Financing Lease | 12 Months Ended |
Dec. 31, 2016 | |
Net Investment in Direct Financing Lease [Abstract] | |
NET INVESTMENT IN DIRECT FINANCING LEASE | 22 . NET INVESTMENT IN DIRECT FINANCING LEASE Emera’s net investment in direct financing lease primarily relates to Brunswick Pipeline. B runswick Pipeline commenced service on July 16, 2009, transporting re-gasified LNG for Repsol Energy Canada under a 25 - year firm service agreement. 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 consist s of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Total minimum lease payments to be received $ 1,194 $ 1,202 Less: amounts representing estimated executory costs (223) (213) Minimum lease payments receivable $ 971 $ 989 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (658) (686) Net investment in direct financing lease $ 496 $ 486 Principal due within one year (included in “Prepayments and other current assets”) 8 6 Net investment in direct financing lease – long-term $ 488 $ 480 Future minimum lease payments to be received for the next five years: For the Year ended December 31 millions of Canadian dollars 2017 2018 2019 2020 2021 Minimum lease payments to be received $ 65 $ 65 $ 65 $ 65 $ 65 Less: amounts representing estimated executory costs (11) (11) (12) (12) (12) Minimum lease payments receivable $ 54 $ 54 $ 53 $ 53 $ 53 |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill [Abstract] | |
GOODWILL | 23. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2016 2015 Balance, January 1 $ 264 $ 222 Acquisition of TECO Energy as at July 1, 2016 (note 4) 5,771 - Impairment - - Change in foreign exchange rate 178 42 Balance, December 31 $ 6,213 $ 264 G oodwill on Emera’s balance sheet relates to the ac quisitions of TECO Energy (see n ote 4), Emera Maine and GBPC. Goodwill 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. Emera’s reporting units with goodwill are Tampa Electric, PGS , New Mexico Gas, Emera Maine and GBPC. 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 bypass es the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fa ir value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the impli ed fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction 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. A qualitative assessment was performed for Emera Maine , concluding that the fair value of the reporting unit exceeded its carrying value, and as such, no quantitative assessmen t was performed. The fair value for GBPC was determined using a discounted cash flow analysis. The fair values for the reporting units acquired in the TECO Energy acquisition (Tampa Electric, PGS , New Mexico Gas) have been preliminarily determined using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of the reporting units’ projected cash flows. It includes a n estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is a market participant rate based on a peer grou p of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings before interest, taxes, depreciation and amorti zation (“EBITDA”) of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then app lied to the last-twelve-months EBITDA of the subject company. Significant assumptions used in estimating the fair value include discount and growth rates, valuation of NOLs, utility sector market performance and transactions, projected operating and capit al cash flows and the calculation of the terminal value. In addition to this quantitative analysis, management performed a qualitative assessment in Q4 2016 to ensure that there were no changes in facts or circumstances from the July 1, 2016 acquisition da te that would require additional fair value testing for the Tampa Electric, PGS , and New Mexico Gas reporting units. The company determined the fair value of reporting units exceed their book value and related goodwill carrying amounts at December 31, 2016 an d December 31, 2015 , resulting in no impairment charge. 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 and GBPC. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT | 24. 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 2016 Weighted-average interest rate 2015 Weighted-average interest rate TECO Energy/TECO Finance $ Advances on revolving credit and term facilities 685 1.74 % - - % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 228 1.49 % - - % NMGC Advances on revolving credit facilities 35 1.71 % - - % NSPI Bank indebtedness 1 2.70 % 16 2.70 % GBPC Advances on revolving credit facilities 12 5.75 % - - % Short-term debt $ 961 $ 16 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 2016 2015 TECO Energy/TECO Finance - term credit facility 2017 537 $ - TECO Energy/TECO Finance - revolving credit facility 2018 403 - Tampa Electric Company - revolving credit facility 2018 436 - Tampa Electric Company - accounts receivable revolving credit facility 2018 201 - NMGC - revolving credit facility 2018 168 - GBPC - revolving credit facility 2017 17 18 Total 1,762 18 Less: Advances under revolving credit and term facilities 960 - Letters of credit issued inside credit facilities 3 - Total advances under available facilities 963 - Available capacity under existing agreements $ 799 $ 18 The weighted average interest rate on outstanding short-term debt at December 31, 2016 was 1.73 per cent ( 2015 – 2.70 per cent ). Credit Facilities TECO Energy/TECO Finance Term Credit Facility TECO Energy has a $537 million ( $ 4 00 million USD ) bank credit facility maturing March 14, 2017. Interest rates on the borrowings are based on LIBOR plus a margin. TECO Finance expects to refinance the credit facility before maturity. TECO Energy/TECO Finance Revolving Credit Facility TECO Energy has a $403 million ( $300 million USD ) bank credit facility maturing December 17, 2018 . Interest rates on the borrowings are based on LIBOR plus a margin. TEC Credit Facility TEC has a $436 million ($325 million USD) bank credit facility with a maturity date of D ecember 17, 2018. Interest rates on the borrowings are based on LIBOR plus a margin. TEC Accounts Receivable Facility TEC has a $201 million ($150 million USD) accounts receivable collate ralized borrowing facility with a maturity date of March 23, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates. TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. NMGC Credit Agreement NMGC has a $168 million ($125 million USD) bank credit facility with a maturity dat e of December 17, 2018. Interest rates on the borrowings are based on one-month LIBOR plus a margin. |
Other Current Liabilities
Other Current Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Other Current Liabilities [Abstract] | |
OTHER CURRENT LIABILITIES | 25. OTHER CURR ENT LIABILITIES Other current liabilities consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Accrued charges $ 137 $ 130 Accrued interest on long-term debt 96 44 Sales and other taxes payable 16 4 Accrued interest on convertible debentures represented by instalment receipts (note 8) - 11 Emission credits obligations (1) 10 6 Other 22 12 $ 281 $ 207 (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 14) 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, 2016 | |
Long-term Debt [Abstract] | |
LONG-TERM DEBT | 26. L ONG-TERM DEBT Emera’s long-term debt includes the issuances detailed below. 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 , including the debt assumed on the acquisition of TECO Energy, consisted of the following: millions of Canadian dollars Weighted Average Interest Rate 2016 (1) Weighted Average Interest Rate 2015 (1) Maturity 2016 2015 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 30 $ 240 Unsecured fixed rate notes 3.50% 3.85% 2019-2023 725 475 Fixed to floating subordinated notes (USD) (2) 6.75% - 2076 1,611 - $ 2,366 $ 715 Emera US Finance LP Unsecured senior notes (USD) (2) 3.60% - 2019 - 2046 $ 4,364 $ - 4,364 - TECO Finance (3) Variable rate notes (USD) Variable - 2018 $ 336 $ - Fixed rate notes and bonds (USD) 5.86% 2017 - 2020 805 - $ 1,141 $ - Tampa Electric (4) Fixed rate notes and bonds (USD) 4.90% - 2018 - 2045 $ 2,579 $ - $ 2,579 $ - PGS Fixed rate notes and bonds (USD) 5.06% - 2018 - 2045 $ 351 $ - $ 351 $ - NMGC Fixed rate notes and bonds (USD) 4.53% - 2021 - 2026 $ 363 $ - $ 363 $ - NMGI Fixed rate notes and bonds (USD) 3.41% - 2019 - 2024 $ 269 $ - $ 269 $ - NSPI Commercial paper Variable Variable 2020 $ 264 $ 369 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 Capital lease obligations 4.80% 4.58% 2019 - 1 $ 2,324 $ 2,430 Emera Maine LIBOR loans and demand loans Variable Variable 2019 $ 32 $ 32 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 67 69 Unsecured senior fixed rate notes (USD) 4.28% 4.31% 2017-2044 281 296 $ 380 $ 397 EBP Senior secured credit facility 3.08% 3.08% 2019 $ 248 $ 249 $ 248 $ 249 GBPC Unsecured amortizing fixed rate notes (USD) 3.62% 3.62% 2021-2022 $ 63 $ 77 Unsecured senior notes (USD) 7.07% 7.07% 2020-2023 67 68 $ 130 $ 145 BLPC & ECI Secured fixed rate senior notes (5) 5.65% 5.64% 2020 - 2028 $ 81 $ 89 Secured senior notes (USD) (6) Variable - 2021 201 - $ 282 $ 89 Adjustments Fair market value adjustment - TECO Energy acquisition (7) $ 58 $ - Debt issuance costs (111) (16) Amount due within one year (476) (274) $ (529) $ (290) Long-Term Debt $ 14,268 $ 3,735 (1) Weighted average interest rate of fixed rate long-term debt. (2) See below for details on the long-term debt related to the acquisition of TECO Energy. (3) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (4) 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. (5) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (6) See below for details on the long-term debt issued by ECI in November, 2016. (7) 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 2016 2015 Emera – revolving credit facility (1) June 2020 $ 700 $ 700 NSPI - revolving credit facility (1) October 2020 600 500 Emera Maine – revolving credit facility September 2019 107 111 BLPC – revolving credit facility 2017-2021 26 26 Total 1,433 1,337 Less: Borrowings under credit facilities 326 641 Letters of credit issued inside credit facilities 37 33 Use of available facilities 363 674 Available capacity under existing agreements $ 1,070 $ 663 (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, 2016 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.62:1 Recent Financing Activity Emera On December 13, 2016, Emera's Series H $250 million 2.96% med ium-term notes matured and were repaid. Emera – TECO Energy Acquisition Related Capital Market Transactions 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 . TECO Finance On April 10, 2015, TECO Finance completed an offering of $250 million USD aggregate principal amount of floating rate notes due 2018 (“the 2018 Notes”), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on April 10, 2018. The 2018 Notes bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness . Tampa Electric On May 20, 2015, TEC completed an offering of $250 million USD aggregate principal amount of 4.20 per cent n otes due May 15, 2045 . 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 follows: millions of Canadian dollars 2017 2018 2019 2020 2021 Thereafter Total Emera $ - $ - $ 225 $ 30 $ - $ 2,111 $ 2,366 Emera US Finance LP - - 671 - 1,007 2,686 4,364 TECO Energy - 409 67 - 643 2,443 3,562 TECO Finance 403 335 - 403 - - 1,141 NSPI - - 95 264 - 1,965 2,324 Emera Maine 33 6 32 40 - 269 380 EBP - - 248 - - - 248 GBPC 11 12 12 40 11 44 130 BLPC and ECI 29 29 30 58 26 110 282 Total $ 476 $ 791 $ 1,380 $ 835 $ 1,687 $ 9,628 $ 14,797 |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATION | 27. 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 ARO 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 2016 2015 Balance, January 1 $ 109 $ 106 Additions (1) 48 - Additions due to acquisition 9 - Liabilities settled (2) (2) Accretion included in depreciation expense 7 8 Accretion deferred to regulatory asset (included in property, plant and equipment) (2) (8) Other 1 5 Balance, December 31 $ 170 $ 109 (1) Tampa Electric produces ash and other by-products known as coal combustion residuals ("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 Environmental Cost Recovery Clause. However, additional petitions will be submitted for recovery of future project expenses based on engineering studies currently being performed. As at December 31, 2016 and 2015 , some of the Company’s transmission and distribution assets may have additional conditional ARO which are not recognized in the 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, 2016 | |
Commitments and Contingencies [Abstract] | |
COMMITMENTS AND CONTINGENCIES | 28. COMMITMENTS AND CONTINGENCIES A. Commitments As at December 31, 2016 , 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 2017 2018 2019 2020 2021 Thereafter Total Purchased power (1) $ 253 $ 224 $ 206 $ 202 198 $ 2,272 $ 3,355 Fuel and gas supply 475 161 109 28 22 - 795 Demand Side Management 42 48 13 - - - 103 Transportation (2) 496 392 310 280 196 1,622 3,296 Long-term service agreements (3) 92 55 67 44 42 227 527 Capital projects 133 - - - - - 133 Equity investment commitments (4) 236 - - 200 - - 436 Leases and other (5) 66 17 14 12 8 70 187 $ 1,793 $ 897 $ 719 $ 766 $ 466 $ 4,191 $ 8,832 (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 ("FLG") 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. In connection with the acquisition of TECO Energy, Emera made certain commitments approved by the NMPRC. See note 4 for additional information. Beginning in 2018, NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over 35 years. The timing and amount of future payments could change based on UARB approval and final costing of the Maritime Link after construction is complete. B. Legal Proceedings Emera Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed 12 separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acqui sition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints sought to enjoin the merger pursuant to the acquisition agreement. On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Direct ors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of unders tanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger, which have now been made. On December 16, 2016, the judge entered a n order and final judgement approving a stipulation of settlement negotiated by the parties, thereby concluding this matter. 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. 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 Secur ities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambrian related to the purchase of TECO Coal by Cambrian. While the outcome of such matter is uncertain, management does not believe that its ultimate resolution will h ave a material adverse effect on the Company’s results of operations, financial condition or cash flows. TECO Guatemala Holdings (“TGH”) On December 19, 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 (Guatemala) under the Dominican Republic Central America – United States Fee Trade Agreement, issued an award in the case (“the Award”). The ICSID Tr ibunal unanimously found in favor of TGH and awarded damages to TGH of approximately $ 21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2 per cent. On April 18, 2014, Guatemala filed an application for annulm ent of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. On April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain defici encies in the ICSID Tribunal’s determination of the amount of TGH’s damages. On April 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala ’s application for annulment of the award and upheld the original $21 million USD award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to t he 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 interest 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. TGH and Guatemala have each selected an arbitrator and ICSID has recently selected a President for the new tribunal. Results to date do not reflect any benefit. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and Peopl es Gas divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its Peoples Gas 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, 2016, TEC has estimated its ultimate financial liability to be $ 43 million ($ 32 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 sites 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 disco unted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely 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 include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigat ion which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes 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 settlement as discussed in note 17, an agreement to accelerate the amortization of the regulated asset associated w ith this reserve. Emera Maine On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the FERC alleging that the 11.14 per cent base RO E under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint that changed the methodology used to set the ROE and resulted in a lower base transmission ROE of 10.57 per cent and a lower total ROE (inclusive of incentive adders) of 11.74 per cent for the period of October 1, 2011 to December 31, 2012. The ROE was confirmed by FERC in two subsequent orders and has now been appealed to the U.S. Court of Appeals for the DC Circuit. The Court has decided to hold the appeal of this case in abeyance pending the outcome of the ENE Case and MA AG II Case discussed below. On June 30, 2016, Emera Maine completed the processing of refunds to customers to reflect the 10.57 per cent ROE. On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was un just and unreasonable (“the ENE Case”). This complaint applies to the period from January 1, 2013 to March 31, 2014. On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC on similar gro unds (“the MA AG II Case”) in relation to the period from July 31, 2014 to October 31, 2015. The ENE Case and MA AG II Case were subsequently consolidated by FERC into a single case. On March 22, 2016, a FERC Administrative Law Judge (“ALJ”) issued a reco mmended decision to FERC with respect to the consolidated cases. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for the MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. The ALJ’s recommended decision is not definitive and FERC has the ability to adjust the ALJ’s recommended decision. A decision by FERC is not expected until early 2017. On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base ROE to 8.61 per cent and the maximum ROE to 11.24 per cent for the period April 29, 2016 to July 29, 2017. Emera Maine has recorded a reserve of $ 5 million pre-tax ($ 4 million USD) (December 31, 2015 - $ 7 million or $ 5 million USD) for the ENE Case and MA AG II Case. The reserves r ecorded for these complaints have been recorded as “Regulatory Liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve h as been made as a result of the EMCOS complaint, as the outcome is considered uncertain. 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. C. Environment Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon presen t environmental laws and regulations. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28A. The estimated expenditures do not include costs related to possible changes in the environmental laws o r regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions. Emera Florida and New Mexico Tampa Electric operates fossil fuel burning power plants with air emissions regulated by the Clean Air Act and material Clean Water Act implications and impacts by federal and state legislative initiatives. Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of Clean Air Interstate Rule (“CAIR”) and th ese expenses were rate recoverable under the Florida environmental cost recovery clause (“ECRC”) as approved by the FPSC. Similarly, future expenses should be eligible for recovery upon petition by Tampa Electric and approval by the FPSC. On July 7, 2011 , EPA released its final CAIR-replacement rule, called Cross-State Air Pollution Rule (“CSAPR”). An update to CSAPR was finalized on October 26, 2016 and will be implemented in 2017. Based on updated EPA modeling and favorable consideration of atmospheri c dynamics, Florida is no longer subject to CSAPR requirements. However, Florida (including Tampa Electric power plants) could be subject to a future version of CSAPR as a result of an expected update triggered by compliance with the more stringent 2015 o zone standard or ongoing litigation related to current rule applicability. NSPI NSPI’s activities are subject to a broad range of federal, provincial, regional and local laws and environmental regulations, designed to protect, restore and enhance the qua lity of the environment including air, water and solid waste. In November 2014, the Government of Canada and the Province of Nova Scotia entered into a Greenhouse gas (“GHG”) emission regulatio ns equivalency agreement, which allows NSPI to achieve compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory requirements as they are deemed to be equivalent. In March 2016, Canada’s First Ministers issued the “Vancouver Declaration” on clean growth and climate change. First Ministers agreed to develop a Pan-Canadian Framework and implement it by early 2017. Four working groups, comprised of federal, provincial and territorial officials were established to prov ide recommendations and research to the Federal government. NSPI provided input into this process through the Nova Scotia government, the Government of Canada and directly to the working groups through the submission of a discussion paper. In October 2 016, the Government of Canada announced that the pan-Canadian framework would include a national price on carbon component, implemented by 2018 through either a carbon tax or a cap and trade system, applicable in each province except those which enact thei r own comparable carbon pricing mechanism by that time. On November 21, 2016, the Government of Canada announced a second component of the plan would include an accelerated plan to phase out coal in Canada, to transition Canada's electricity system towar ds 90 per cent non-emitting generation sources by 2030. On the same day, the Province of Nova Scotia and the Government of Canada made two announcements regarding Nova Scotia’s participation in the Pan-Canadian plan: Carbon pricing component An agreemen t in principle covering the carbon component had been reached and will be governed on the following principles: Nova Scotia will adopt a province-wide 2030 emissions reduction target equal or greater than Canada’s target of a 30 per cent reduction from 20 05 levels by 2030; Nova Scotia will implement an agreed upon cap and trade system; and The Province of Nova Scotia and the Government of Canada will agree upon a methodology and scenarios for the modeling of projected GHG emissions to support the developme nt of Nova Scotia’s cap and trade system. Accelerated phase out of coal component Nova Scotia and the Government of Canada will establish a new equivalency agreement that will enable the province to move directly from fossil fue ls to clean energy sources and enable NSPI’s coal-fired plants to operate at some capacity beyond 2030. On December 9, 2016, the Government of Canada and eight provinces (including Nova Scotia) signed the Pan Canadian Framework on Clean Growth and Climate Change. The Government of Canada has committed to ensuring that the provinces and territories have the flexibility to design their own policies and programs to meet emission-reduction targets, supported by federal investments in infrastructure, spe cific emission-reduction opportunities and clean technologies. Details under the agreements are expected to be finalized by the end of 2017. NSPI anticipates that any costs prudently incurred to achieve the legislated reductions would be recoverable from customers under NSPI’s regulatory framework. NSPI will continue to work with both the Province of Nova Scotia and the Government of Canada as the details of the agreements are finalized and to advance solutions that are in the best interest of customers. The Government of Canada has indicated their intention to resume discussions regarding Base Level Industrial Emission Requirements (”BLIER”s) for sulphur dioxide and nitrogen dioxide and have outlined their intention to develop a Clean Energy Standard for natural gas and possibly diesel. The details of both processes are not yet known. NSPI will participate in these processes in 2017. NSPI estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulatio ns will be approximately $ 41 million during fiscal 2017 and are estimated to be $ 41 million from 2018 through 2021 . Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28A. Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2016 . Polychlorin ated Biphenyl Equipment In response to the Canadian Environmental Protection Act 1999, 2008 Polychlorinated Biphenyl (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that fall under the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $ 43 million and, as at December 31, 2016 , approximately $ 28 million ( December 31, 2015 – $ 20 million) has been spent to date. NSPI h as recognized an ARO on the balance sheet of $ 11 million as at December 31, 2016 ( December 31, 2015 – $ 15 million) associated with the PCB phase-out program. Emera Energy Emissions The NEGG Facilities are subject to the RGGI for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The NEGG Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impa ct financial and operational performance. D. Principal Risks and Uncertainties In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net assets or liquidity or capital resources in the near term. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future. Sound risk management is an essenti al discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. As cost-of-service utilities with an obligation to serve customers, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon approval by the respect ive regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate c an be impacted by significant shifts in government policy (including shifts in policy which could occur as a result of climate change concerns) and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, LIL, M&NP and Lucelec. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate regulated companies and their respective regulators determin e whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory ap proach through technical conferences and, where appropriate, negotiated settlements. Weather and Climate Risk Shifts in weather patterns affect energy sales and associated revenues and costs. Extreme weather events generally result in increased operatin g costs associated with restoring service to customers as a result of unplanned outages. Emera responds to outages which occur as a result of significant weather events according to each subsidiary’s respective emergency services restoration plan. Changes in Environmental Legislation Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting GHG emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials. In addition to imposing continuing compliance obligations, there are permit re quirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera . Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera. In addition, Emera’s business could be materially affected by changes in government poli cy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns. New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to ad ditional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments. Emera manages its environmental risk by operating in a manner that is respectful and protective of the environm ent and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating su bsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates globally, with an in creasing 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. Co nsistent 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 en ters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits 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 subsidiaries 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. Consequently, Emera is an active participant in the debt and equity markets. After giving effect to the TECO Energy acquisition, Emera now has total debt of $ 15 billion. Any disruption in capital markets could have a material impact on Emer a’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout 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 its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business a nd 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 the 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 financing 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 maturi ties. The Company 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 rat es 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 raise in times of increasi ng 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. Commercial Relationships Risk The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages its commercial relationships risk by monitoring credit risk and monitoring of significant devel opments with its customers, partners and suppliers. 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 exposed 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 contractual 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-regulated 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 changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax benefits are determined by existing tax laws and could be negatively impacted by changes in laws. “Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in the corporate income t ax rate. Although a reduction 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 . 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. E. Guarantees and Letters of Credit Emera had significant guarantees and letters of credit on behalf of third parties outstanding as discussed below. These are not included within the Consolidated Balance Sheets as at December 31, 2016. Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be $ 1.577 billion, which reduces in the ord inary course as project costs are paid. The current exposure as at December 31, 2016 is $ 577 million. TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entit |
Cumulative Preferred Stock
Cumulative Preferred Stock | 12 Months Ended |
Dec. 31, 2016 | |
Cumulative Preferred Stock [Abstract] | |
CUMULATIVE PREFERRED STOCK | 29. CUMULATIVE PREFERRED STOCK Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2016 December 31, 2015 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 On Augu st 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issues and outstanding Series A Shares were tendered for conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B Shares”). As a result of the conversion, Emera has 3,864,636 Series A Shares and 2,135,364 Series B Shares issued an d outstanding. The 2016 dividends for the Series A and Series B shares were $ 0.6388 per share and $ 0.5724 respectively. The First Preferred Shares, Se ries 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 Augu st 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 cas h 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 Bo nd - 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 Director s 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 First Preferred Shares, Series E, are entitled to receive fixed rate cumulative cash dividends, as and w hen 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 August 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, 2020 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 plu s 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, Augu st 15, 2023 and February 15, 2025 respectively and on August 15, August 15 and February 15 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 and $ 25.50 per share plus all accrued and unpaid dividends up to but excluding the 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 h as the right to redeem the outstanding First Preferred Shares, Series E on or after August 15, 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 rede emed on or after August 15, 2021, but prior to August 15, 2022; and at $ 25.00 per Series E Preferred 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 redemptio n. As the First Preferred Shares, Series A, B, C, E and F are neither redeemable at the option of the shareholder nor have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the consolidated stateme nts of earnings immediately before arriving at “Net earnings attributable to common shareholders” and will be shown on the consolidated statement of equity 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 the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferre d 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 liquidation, 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 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, 2016 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Noncontrolling Interest Disclosure [Text Block] | 30. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 ICDU $ 53 $ 52 Preferred shares of GBPC 34 34 Domlec 25 23 ECI (1) - 25 $ 112 $ 134 (1) On December 17, 2015, an indirect wholly owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent. On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares (which owns 51.9 per cent share of Domlec), increasing Emera's ownership interest in ECI from 95.5 to 100 per cent. Preferred shares of GBPC: Authorized: 35,000 non-voting cumulative redeemable variable perpetual preferred shares 2016 2015 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 35,000 $ 34 35,000 $ 34 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: 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 cumu lative 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 st ock 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, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS | 31 . SUPPLEMENTARY INFORMATIO N TO CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year ended December 31 millions of Canadian dollars 2016 2015 Changes in non-cash working capital: Receivables, net $ (104) $ (19) Income taxes receivable (23) (22) Inventory 88 (2) Prepayments and other current assets (18) 9 Accounts payable and customer deposits 162 (45) Income taxes payable 14 (32) Other current liabilities 15 9 Total non-cash working capital 134 (102) Supplemental disclosure of cash paid (received): Interest $ 480 $ 196 Income taxes $ 57 $ 124 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 103 $ 78 Beneficial Conversion Feature of the convertible debentures $ 43 $ - |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Stock-Based Compensation [Abstract] | |
STOCK-BASED COMPENSATION | 32 . 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, 2016 under the Employee Common Share Purchase Plan was $ 1 million ( 2015 – $ 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, 2016 2015 Weighted average fair value per option $ 2.80 $ 2.66 Expected term 5 years 5 years Risk-free interest rate 0.66 % 0.73 % Expected dividend yield 4.08 % 3.65 % Expected volatility 15.45 % 14.58 % The following table summarizes information related to the stock options for 2016 : 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, 2015 2,927,068 $ 33.07 1,453,486 $ 2.64 Granted 615,100 46.19 615,100 2.80 Exercised (622,168) 25.65 N/A N/A Forfeited - - (548,461) 2.68 Options outstanding December 31, 2016 2,920,000 $ 37.42 1,520,125 $ 2.69 Options exercisable December 31, 2016 (2)(3) 1,399,875 $ 33.35 (1) As at December 31, 2016 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 2.4 years (2015 - $3 million, 2.3 years). (2) As at December 31, 2016, the weighted average remaining term of vested options was 5.7 years with an aggregate intrinsic value of $17 million (2015 - 5.3 years, $21 million). (3) As at December 31, 2016 the fair value of options that vested in the year was $2 million (2015 - $1 million). Compensation cost recognized for stock options for the year ended December 31, 2016 was $ 2 million ( 2015 – $ 1 million) , which is included in “Operating, maintenance and general” on the Consolidated Statements of Income. As at December 31, 2016 , cash received from option exercises was $ 16 million ( 2015 – $ 2 million). The total intrinsic value of options exercised for the year ended December 31, 2016 was $ 13 million ( 2015 – $ 1 million). The range of exercise prices for the options outst anding as at December 31, 2016 was $ 20.42 to $ 46.19 ( 2015 – $ 19.88 to $ 42.71 ). 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, 2016 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, 2015 606,646 $ 26.27 362,750 $ 31.36 Granted including DRIP 74,855 37.60 69,429 43.67 Exercised (570) 46.58 (36,381) 27.42 Outstanding and exercisable as at December 31, 2016 680,931 $ 27.50 395,798 $ 33.88 Compensation cost recognized for employee and director DSU for the year ended December 31, 2016 was $ 8 million ( 2015 – $ 8 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2016 were $ 3 million ( 2015 – $ 3 million); $nil was offset with regulatory assets and regulatory liabilities ( 2015 – $ 1 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, 2016 is presented in the following table: Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2015 497,496 $ 34.50 $ 21.5 Granted including DRIP 280,950 40.60 Exercised (208,999) 34.39 Forfeited (8,567) 37.54 Outstanding as at December 31, 2016 560,880 $ 37.55 $ 25.5 Compensation cost recognized for the PSU plan for the year ended December 31, 2016 was $ 11 million ( 2015 – $ 10 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2016 were $ 4 million ( 2015 – $ 3 million). |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entities [Abstract] | |
VARIABLE INTEREST ENTITIES | 33. VARIABLE INTEREST ENTITIES 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 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 obl igation 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, 2016 an d 2015 , the Company has identified the following material VIEs: Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. I n Q2 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 t he economic performance of the Maritime Link Project. Thus, Emera began recording the Maritime Link Project as an equity investment. BLPC has established a Self-Insurance Fund primarily for the purpose of building a fund to cover risk against damage an d consequential loss to certain generating, transmission 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. In its det ermination 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, because ECI, th rough 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”. The Company has identified certain 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 beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and m ake management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2016 December 31, 2015 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) $ 315 $ 577 $ 188 $ 1,007 |
Comparative Information
Comparative Information | 12 Months Ended |
Dec. 31, 2016 | |
Comparative Information [Abstract] | |
COMPARATIVE INFORMATION | 34 . 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, 2016 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | 35. SUBSEQUENT EVENTS These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 10, 2017, the date the financial statements were issued. |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Financial Information of Parent Company Only Disclosure [Text Block] | 36. 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 solidated 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 interna tional 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 requirements for guarantor reporting . Emera Incorporated Co 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 Regulated electric $ - $ - $ 1,665 $ 1,774 $ (2) $ 3,437 Regulated gas - - 451 48 - 499 Non-regulated - - 378 (4) (33) 341 Total operating revenues - - 2,494 1,818 (35) 4,277 Operating expenses Regulated fuel for generation and purchased power - - 560 662 - 1,222 Regulated cost of natural gas - - 177 - - 177 Regulated fuel adjustment mechanism and fixed cost deferrals - - - 61 - 61 Non-regulated fuel for generation and purchased power - - 261 56 (4) 313 Non-regulated direct costs - - - 52 (23) 29 Operating, maintenance and general 37 - 647 461 (8) 1,137 Provincial, state and municipal taxes - - 152 43 - 195 Depreciation and amortization 2 - 330 256 - 588 Total 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 Net income (loss) of Emera Incorporated 255 9 109 82 (200) 255 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 Co nsolidated Statements of Income For the year ended December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues Regulated electric $ - $ - $ 283 $ 1,860 $ (2) $ 2,141 Regulated gas - - - 52 - 52 Non-regulated - - 419 219 (42) 596 Total operating revenues - - 702 2,131 (44) 2,789 Operating expenses Regulated fuel for generation and purchased power - - 70 745 - 815 Regulated fuel adjustment mechanism and fixed cost deferrals - - - 42 - 42 Non-regulated fuel for generation and purchased power - - 277 64 (5) 336 Non-regulated direct costs - - - 49 (30) 19 Operating, maintenance and general 54 - 148 472 (8) 666 Provincial, state and municipal taxes - - 21 42 - 63 Depreciation and amortization 1 - 79 260 - 340 Total operating expenses 55 - 595 1,674 (43) 2,281 Income (loss) from operations (55) - 107 457 (1) 508 Income (loss) from equity investments in subsidiaries 270 - - - (270) - Income from equity investments 37 - 5 66 - 108 Intercompany income (expenses), net 156 - - 8 (164) - Other income (expenses), net 91 - 21 29 - 141 Interest expense, net 46 - 28 272 (134) 212 Income (loss) before provision for income taxes 453 - 105 288 (301) 545 Income tax expense (recovery) 25 - 35 33 - 93 Net income (loss) 428 - 70 255 (301) 452 Non-controlling interest in subsidiaries - - - 13 12 25 Net income (loss) of Emera Incorporated 428 - 70 242 (313) 427 Preferred stock dividends 30 - 15 26 (41) 30 Net income (loss) attributable to common shareholders $ 398 $ - $ 55 $ 216 $ (272) $ 397 Comprehensive income (loss) of Emera Incorporated $ 911 $ - $ 303 $ 452 $ (755) $ 911 Emera Incorporated 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 Receivables, net 1 - 429 584 - 1,014 Intercompany receivables 57 9 11 569 (646) - Income taxes receivable - - 5 28 - 33 Inventory - - 273 199 - 472 Derivative instruments 13 - 33 112 (13) 145 Regulatory assets - - 54 26 - 80 Prepayments and other current assets 2 - 44 230 - 276 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 Income taxes receivable - - - 48 - 48 Deferred income taxes 31 - 18 114 (38) 125 Derivative instruments 12 - 2 129 (12) 131 Pension and post-retirement asset - - - 9 - 9 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 Investment securities - - - 48 - 48 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 70 (19) 169 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 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) - Income taxes payable - 6 - 13 - 19 Derivative instruments 14 - 10 314 (13) 325 Regulatory liabilities - - 225 137 - 362 Pension and post-retirement liabilities - - 51 7 - 58 Other current liabilities 54 7 79 141 - 281 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 Convertible debentures 8 - - - - 8 Derivative instruments 12 - - 150 (12) 150 Regulatory liabilities - - 973 304 - 1,277 Asset retirement obligations - - 61 109 - 170 Pension and post-retirement liabilities 17 - 433 219 - 669 Other long-term liabilities 5 - 213 268 (19) 467 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 Consolidated Balance Sheets As at December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Assets Current assets Cash and cash equivalents $ - $ - $ 19 $ 1,068 $ (14) $ 1,073 Restricted cash - - 1 18 - 19 Receivables, net 2 - 70 506 - 578 Intercompany receivable 102 - 51 95 (248) - Income taxes receivable - - 9 3 - 12 Inventory - - 48 266 - 314 Derivative instruments 109 - 46 112 (17) 250 Regulatory assets - - 17 77 - 94 Prepayments and other current assets 9 - 4 243 - 256 Total current assets 222 - 265 2,388 (279) 2,596 Property, plant and equipment, net of accumulated depreciation 15 - 2,035 4,419 - 6,469 Other assets Income taxes receivable - - - 49 - 49 Deferred income taxes - - 47 19 (34) 32 Derivative instruments 35 - - 167 (34) 168 Pension and post-retirement assets - - - 9 - 9 Regulatory assets - - 100 505 - 605 Net investment in direct financing lease - - - 480 - 480 Investments in subsidiaries accounted for using the equity method 6,042 - - - (6,042) - Investments subject to significant influence 509 - 12 624 - 1,145 Investment securities - - - 116 - 116 Goodwill - - 158 106 - 264 Intercompany notes receivable 3,051 - - 2,754 (5,805) - Other investments - intercompany - - - 98 (98) - Other long-term assets 16 - 13 77 - 106 Total other assets 9,653 - 330 5,004 (12,013) 2,974 Total assets $ 9,890 $ - $ 2,630 $ 11,811 $ (12,292) $ 12,039 Emera Incorporated Consolidated Balance Sheets – Continued As at December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ 14 $ - $ - $ 16 $ (14) $ 16 Current portion of long-term debt 250 - 6 18 - 274 Accounts payable 17 - 76 301 - 394 Income taxes payable - - - 8 - 8 Intercompany payable 52 - 92 77 (221) - Derivative instruments 17 - 36 313 (17) 349 Regulatory liabilities - - 10 102 - 112 Pension and post-retirement liabilities - - - 7 - 7 Other current liabilities 51 - 24 132 - 207 Total current liabilities 401 - 244 974 (252) 1,367 Long-term liabilities Long-term debt 464 - 389 2,882 - 3,735 Intercompany long-term debt 2,631 - 120 3,072 (5,823) - Deferred income taxes 3 - 343 450 (34) 762 Convertible debentures (represented by installment receipts) 2,139 - - (1,458) - 681 Derivative instruments 34 - - 96 (34) 96 Regulatory liabilities - - 12 341 - 353 Asset retirement obligations - - - 109 - 109 Pension and post-retirement liabilities 13 - 93 197 - 303 Other long-term liabilities 5 - 61 233 - 299 Total long-term liabilities 5,289 - 1,018 5,922 (5,891) 6,338 Equity Common stock 2,157 - 312 3,829 (4,141) 2,157 Cumulative preferred stock 709 - 425 271 (696) 709 Contributed surplus 29 - 45 133 (178) 29 Accumulated other comprehensive income (loss) 137 - 245 (169) (76) 137 Retained earnings 1,168 - 341 751 (1,092) 1,168 Total Emera Incorporated equity 4,200 - 1,368 4,815 (6,183) 4,200 Non-controlling interest in subsidiaries - - - 100 34 134 Total equity 4,200 - 1,368 4,915 (6,149) 4,334 Total liabilities and equity $ 9,890 $ - $ 2,630 $ 11,811 $ (12,292) $ 12,039 Emera Incorporated 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) by 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) - (633) (396) - (1,031) 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 - - (42) (12) - (54) Net cash provided by (used in) investing activities (1,685) (4,416) (9,102) (3,081) 9,179 (9,105) 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 29 (940) 14 (669) Cash and cash equivalents, beginning of period - - 19 1,068 (14) 1,073 Cash and cash equivalents, end of period $ 200 $ 28 $ 48 $ 128 $ - $ 404 Emera Incorporated Consolidated Statements of Cash Flows For the year ended December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) operating activities $ 291 $ - $ 190 $ 364 $ (171) $ 674 Investing activities Additions to property, plant and equipment (7) - (66) (354) - (427) Net purchase of investments subject to significant influence, inclusive of acquisition costs (1) - (3) (132) - (136) Proceeds on sale of investment subject to significant influence - - 282 - - 282 Other intercompany investing activities (2,453) - - (29) 2,482 - Other investing activities (751) - (10) (413) 1,331 157 Net cash provided by (used in) investing activities (3,212) - 203 (928) 3,813 (124) Financing activities Change in short-term debt, net 4 - - (262) (4) (262) Proceeds from long-term debt, net of issuance costs - - 29 1,465 (1,048) 446 Proceeds from convertible debentures represented by instalment receipts, net of issuance costs 2,138 - - (1,457) - 681 Retirement of long-term debt - - (420) (372) 702 (90) Net borrowings (repayments) under committed credit facilities (39) - (9) (153) - (201) Issuance of common stock, net of issuance costs 9 - - 2,390 (2,390) 9 Issuance of preferred stock, net of issuance costs - - - 6 (6) - Dividends on common stock (162) - - (162) 162 (162) Dividends on preferred stock (30) - (15) (25) 40 (30) Dividends paid by subsidiaries to non-controlling interest - - - (3) (11) (14) Other financing activities 1,001 - (11) (55) (1,091) (156) Net cash provided by (used in) financing activities 2,921 - (426) 1,372 (3,646) 221 Effect of exchange rate changes on cash and cash equivalents - - 14 67 - 81 Net increase (decrease) in cash and cash equivalents - - (19) 875 (4) 852 Cash and cash equivalents, beginning of period - - 38 193 (10) 221 Cash and cash equivalents, end of period $ - $ - $ 19 $ 1,068 $ (14) $ 1,073 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
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, gas transmission and utility energy services. Emera’s primary rate-regulated subsidiaries and investments at December 31, 2016 included the following: Emera Florida and New Mexico represents TECO 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 includes: Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), an integrated regulated electric utility, serving approximately 736,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 374,000 customers across Florida; New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 522,000 customers across New Mexico; TECO Finance, Inc. (“TECO Finance”), a wholly owned financing subsidiary of TECO Energy. Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the prima ry electricity supplier in Nova Scotia, serving approximately 511,000 customers; Emera Maine provides electric transmission and distribution services to approximately 157,000 customers in the State of Maine in the United States ; Emera (Caribbean) Incorporated (“ECI”) 100.0 per cent interest (December 31, 2015 – 95.5 per cent) includes: The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the islan d of Barbados, serving approximately 126,000 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 (“ICDU”)) in Grand Ba hama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers; a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers; a 19.1 per cent indirect interest (December 31, 2015 – 18.2 per cent indirect interest) in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility in St. Lucia; Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline deliv ering 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 (“REC”), which expires in 2034; Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focuse d on two transmission investments related to the development of an 824 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 is developing 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 is scheduled to be completed in Q4 2017 and then be in service by January 1, 2018; a 62.7 per cent investment (December 31, 2015 – 55.1 per cent) in the partnership capital of Labrador-Island Link Limited Partners hip (“LIL”), a $3.4 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. 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 on completion of the LIL and final costing of all transmission projects relat ed 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. The investment in LIL is accounted for on the equity basis. Nalcor Energy has indicated that the project 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 t ransports 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, includes: Emera Energy Services (“EES” ), 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” (“NEGG”)), a 1,115 MW of combined-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 (“Broo klyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northern 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 l evels across Emera; Emera US Finance LP, a wholly owned financing subsidiary of Emera that issued multiple series of United States dollar denominated senior, unsecured notes for the purpose funding the acquisition of TECO Energy; Emera US Holdings Inc. (“E USHI”), 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; On December 8, 2016, Emera sold the Company’s remaining 4. 7 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), a public company traded on the Toronto Stock Exchange under the symbol “AQN”; and other investments. |
Basis of Accounting, Policy [Policy Text Block] | 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] | 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, 2016 . 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 regulat ed 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] | 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 the 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 reasonable 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 accounting applies where rates are established by, or subject to approval by, an independent third party regulator. They are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers (see n ote 17 for additi onal details). |
Foreign Currency Transactions and Translations Policy [Policy Text Block] | 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 self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the aver age rates 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 dominated debt held in Canadian functional currency companies a s 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 sheet date, and the effective portion of the hedge , is reco rded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings. |
Revenue Recognition, Policy [Policy Text Block] | 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 the respective regulator and recorded based on meter readi ngs and estimates, which occur on a systematic basis throughout a month. 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 unbil led 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 performed, 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 ne t 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 investm ent 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 r ate 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. |
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 employe e 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 method of accounting for stock-based compensation. Stock-based compens ation 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 recognize d 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 employ ees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change oc curs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $183 million have an effective interest rate of 0.6 per cent at December 31, 2016 ( 2015 – $78 million with an effective i nterest rate of 0.6 per cent). |
Receivables, Policy [Policy Text Block] | 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 pa yment fee may be assessed on account balances 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 provisions 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 accounts. Provisions for lo sses 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] | 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 customer rates. Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purc hased, or allocated by the respective government agency. |
Property, Plant and Equipment, Policy [Policy Text Block] | 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 additions, 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 disposal costs, less salvage procee ds, 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 occur. |
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block] | Goodwill Goodwill is not amortized, but is subject to an annual impairment test. Emera’s reporting units containing goodwill assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount during the fourth quarter of each year, and interim impairment tests are performed when impairment indicat ors are present. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recover able if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. See note 23 for further detail . C ost 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 comp leted, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value. Fina ncial 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 securities 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 evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the ac quisition 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. |
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 Balance 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 realized. 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 balance at the amount expec ted 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 credits 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 or 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. Emera classifies interest and penalties associated with unrecogn ized tax benefits as interest and operating expense, respectively. |
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 sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statut e, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the fair value of the estimated cash flows 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, prior 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 depreciated in the same manner as the related long-lived asset. Over time, the liability is accrete d to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is deferred to a regulatory asset 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 ARO refers to a legal obligation to perform an asset retirement activity i n 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 liability is recognized at fair value when an amount can be determined. |
Derivatives, Hedge Discontinuances [Policy Text Block] | Derivatives and Hedging Activities Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management pol icies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Man agement Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks. 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 physic al and financial contracts 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 purchases 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 allow 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 discont inue 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 a t 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 realiz ed. Any ineffective 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, 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, NSPI and GBPC that are documented as economic hedges, and for whi ch 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 r egulatory 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 these derivatives related to fuel for generation and purchased powe r 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 o f 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 classifies gains and losses on derivativ es 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 not offset by the fair value amount s of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”. |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Variable Interest Entities The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facili ties. 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 obligatio n to absorb losses or the right to receive benefits of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary bene ficiary, the VIE is not consolidated in the Company’s consolidated financial statements. |
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 includ ed 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 Tampa Electric and PGS are included as an expense on the Consolidated St atements 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. |
Acquisition (Tables)
Acquisition (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 preliminarily allocated to the TECO Energy reporting units and is subject to change as additional information is obtained through the purchase price allocation process. 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 2016 2015 Operating revenues – regulated gas $ (10) $ - Operating, maintenance, and general 89 52 Interest expense, net 148 24 Other income (expenses), net (3) - Income tax expense (recovery) (84) (23) Acquisition related costs $ 166 $ 53 |
Business Acquisition, Pro Forma Information [Table Text Block] | For the Year ended millions of Canadian dollars December 31 2016 2015 Pro forma operating revenues $ 6,034 $ 6,297 Pro forma net income attributable to common shareholders $ 386 $ 584 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 (2) NSPI Maine Caribbean Energy Other Eliminations Total For the year ended December 31, 2016 Operating revenues from external customers (1) $ 1,839 $ 1,356 $ 297 $ 419 $ 298 $ 69 $ (2) $ 4,276 Inter-segment revenues (1) - - - - 11 24 (34) 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 2 312 - 600 Interest revenue - - - - 1 1 - 2 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 inter-company balances and inter-company 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. Inter-company 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) Corporate and Other Interest expense has 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. 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, 2015 Operating revenues from external customers (1) $ - $ 1,417 $ 284 $ 442 $ 578 $ 68 $ (2) $ 2,787 Inter-segment revenues (1) - - - 8 12 24 (42) 2 Total operating revenues - 1,417 284 450 590 92 (44) 2,789 Allowance for funds used during construction - debt and equity - 4 2 - - - - 6 Regulated fuel and fixed cost deferral adjustments - 42 - - - - - 42 Depreciation and amortization - 206 47 44 41 2 - 340 Interest expense - 129 19 14 1 59 - 222 Interest revenue - 5 - - 1 - - 6 Internally allocated interest (3) - - - - (18) 18 - - Income from equity investments - - - 3 21 84 - 108 Income tax expense (recovery) - 23 27 3 50 (10) - 93 Net income attributable to common shareholders - 130 45 41 99 82 - 397 Capital expenditures - 271 65 44 98 9 - 487 As at December 31, 2015 Total assets - 4,721 1,558 1,403 1,919 2,663 (225) 12,039 Investments subject to significant influence - - 12 39 - 1,094 - 1,145 Goodwill - - 158 106 - - - 264 (1) All significant inter-company balances and inter-company 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. Inter-company 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) 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 2016 2015 Canada $ 1,510 $ 1,546 United States 2,348 786 Barbados 254 259 The Bahamas 121 154 Dominica 44 44 $ 4,277 $ 2,789 (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 2016 2015 Canada $ 3,791 $ 3,672 United States 12,724 2,034 Barbados 416 402 The Bahamas 295 299 Dominica 64 62 $ 17,290 $ 6,469 |
INVESTMENTS SUBJECT TO SIGNIF49
INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2016 2015 2016 LIL (1) $ 400 $ 208 $ 24 $ 9 62.7 NSPML 315 188 21 15 100.0 M&NP (2) 175 189 23 23 12.9 Lucelec (2) 39 39 3 3 19.1 APUC (3) - 504 18 37 - Bear Swamp (4) - - 11 17 50.0 Other Investments 18 17 - 4 $ 947 $ 1,145 $ 100 $ 108 (1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. (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. This is consistent with industry practice for similar investments with significant influence. (3) On May 24, 2016, Emera completed the sale of 50.1 million common shares or 19.3 per cent of APUC's issued and outstanding common shares. This resulted in a pre-tax gain of $172 million (after-tax gain of $146 million), which was recorded in "Other income (expenses), net" in Q2 2016. On June 30, 2016, Emera exchanged 12.9 million of APUC subscription receipts and dividend equivalents into common shares. This resulted in a pre-tax gain of $63 million (after-tax gain of $53 million), which was recorded in "Other income (expenses), net" in Q2 2016. As a result of these transactions, Emera reclassified its investment in APUC from "Investments Subject to Significant Influence" to "Investment Securities" on the Consolidated Balance Sheets in Q2 2016, recorded at fair value. On December 8, 2016, Emera completed the sale of 12.9 million common shares or 4.7 per cent of APUC's issued and outstanding common shares. This sale resulted in a pre-tax loss of $12 million (after-tax loss of $10 million), which was recorded in "Other income (expenses), net" in Q4 2016. Emera no longer holds any interest in APUC. (4) 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 $217 million (2015 - $225 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets. Equity investments include a $14 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 33). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of Canadian dollars 2016 2015 Balance Sheets Current assets $ 439 $ 439 Property, plant and equipment 1,132 648 Non-current assets 276 554 Total assets $ 1,847 $ 1,641 Current liabilities $ 219 $ 130 Long-term debt 1,288 1,288 Non-current liabilities 25 35 Equity 315 188 Total liabilities and equity $ 1,847 $ 1,641 |
Other Income (Expenses), Net (T
Other Income (Expenses), Net (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 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 - Allowance for equity funds used during construction 22 2 Foreign exchange (losses) gains and mark-to-market adjustments related to the TECO Energy acquisition (2) (135) 119 Gain on sale of NWP investment (3) - 19 Other 11 1 $ 174 $ 141 (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. (3) On January 25, 2015, Emera completed the sale of its 49 per cent interest in NWP. This resulted in a pre-tax gain of $19 million (after-tax gain of $12 million). |
Interest Expense, Net (Tables)
Interest Expense, Net (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Interest on debt $ 443 $ 193 Beneficial conversion feature (note 10) 62 - Interest on Convertible Debentures (note 10) 65 23 Interest on acquisition credit facility related to the TECO Energy acquisition (note 4) 11 - Allowance for borrowed funds used during construction (13) (4) Interest revenue (2) (6) Other 19 6 $ 585 $ 212 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Income before provision for income taxes $ 244 $ 545 Statutory income tax rate 31% 31% Income taxes, at statutory income tax rates 76 169 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (47) (31) Non-taxable portion of gains on APUC transactions (34) - Non-deductible (non-taxable) portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition 21 (18) Financing deductions (17) (10) Tax effect of equity earnings (10) (11) Manufacturing and investment allowances (7) (5) Foreign tax rate variance (5) 2 Other 1 (3) Income tax expense (recovery) $ (22) $ 93 Effective income tax rate (9%) 17% |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | millions of Canadian dollars 2016 2015 Current income taxes Canada $ 13 $ 42 United States 18 26 Other 15 5 Deferred income taxes Canada $ (113) $ 11 United States 151 14 Other - (1) Operating loss carry forwards Canada (2) (4) United States (104) - Income tax expense (recovery) $ (22) $ 93 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 2016 2015 Canada $ 71 $ 349 United States 44 137 Other 129 59 Income before provision for income taxes $ 244 $ 545 |
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 2016 2015 Deferred income tax assets: Tax loss carry forwards $ 1,036 $ 72 Regulatory liabilities - cost of removal 388 42 Tax credit carry forwards 318 7 Derivative instruments 173 204 Pension and post-retirement liabilities 147 129 Regulatory liabilities – deferrals related to derivative instruments 101 94 Asset retirement obligations 47 47 Other 355 136 Total deferred income tax assets before valuation allowance 2,565 731 Valuation allowance (58) (18) Total deferred income tax assets after valuation allowance $ 2,507 $ 713 Deferred income tax (liabilities): Property, plant and equipment $ (3,625) $ (960) Derivative instruments (202) (264) Net investment in direct financing lease (103) (89) Other (124) (130) Total deferred income tax liabilities $ (4,054) $ (1,443) Consolidated Balance Sheets presentation: Long-term deferred income tax assets 125 32 Long-term deferred income tax liabilities (1,672) (762) Net deferred income tax liabilities $ (1,547) $ (730) |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | millions of Canadian dollars 2016 2015 Canada NOL $ 199 $ 103 Capital loss 77 84 United States Federal NOL $ 2,595 $ 48 State NOL 1,183 225 Capital loss 14 4 Tax credit 318 30 Other NOL $ 22 $ 14 |
Summary of Tax Credit Carryforwards [Table Text Block] | The following table summarizes as at December 31, 2016 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 $ 61 $ (27) $ 34 2026-2036 Capital loss 16 (16) - Indefinite United States Federal NOL $ 908 $ - $ 908 2024-2036 State NOL 45 (1) 44 2017-2036 Capital loss 3 (3) - 2018-2019 Tax credit 318 - 318 2019-2036 Other NOL $ 3 $ (3) $ - 2017-2023 |
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | millions of Canadian dollars 2016 2015 Balance, January 1 $ 6 $ 5 Increases due to tax positions related to current year 12 - Increases due to tax positions related to a prior year - 1 Balance, December 31 $ 18 $ 6 |
Common Stock (Tables)
Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Common Stock [Abstract] | |
Schedule of Common Stock Outstanding Roll Forward [Table Text Block] | Authorized : Unlimited number of non-par value common shares. 2016 2015 Issued and outstanding: millions of shares millions of Canadian dollars millions of shares millions of Canadian dollars Balance, January 1 147.21 $ 2,157 143.78 $ 2,016 Conversion of Convertible Debentures 51.99 2,115 - - Issuance of common stock (1) 7.69 338 1.25 54 Issued for cash under Purchase Plans at market rate 2.51 115 2.10 88 Discount on shares purchased under Dividend Reinvestment Plan - (5) - (4) Options exercised under senior management share option plan 0.62 17 0.08 2 Stock-based compensation - 1 - 1 Balance, December 31 210.02 $ 4,738 147.21 $ 2,157 (1) In Q1 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. In addition, Emera completed an offering of 7.63 million common shares in December 2016, at $45.25 per common share, for net proceeds of approximately $345 million. The net proceeds were $335 million after $10 million of issuance costs, net of taxes. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 Numerator Net income attributable to common shareholders $ 227.2 $ 397.2 Convertible Debentures 0.2 - Diluted numerator 227.4 397.2 Denominator Weighted average shares of common stock outstanding 170.4 144.9 Weighted average deferred share units outstanding 1.0 0.9 Weighted average shares of common stock outstanding – basic 171.4 145.8 Stock-based compensation 0.6 0.6 Convertible Debentures 0.2 - Weighted average shares of common stock outstanding – diluted 172.2 146.4 Earnings per common share Basic $ 1.33 $ 2.72 Diluted $ 1.32 $ 2.71 |
Accumulated Other Comprehensi55
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 (Losses) gains on derivatives recognized as cash flow hedges Net change in unrecognized pension and post-retirement benefit costs Net change in net investment hedges Net change on available-for-sale investments Unrealized (loss) gain on translation of self-sustaining foreign operations Total AOCI For the year ended December 31, 2016 Balance, January 1, 2016 $ (35) $ (318) $ - $ - $ 490 $ 137 Other comprehensive income (loss) before reclassifications 11 - (49) 3 35 - Amounts reclassified from accumulated other comprehensive income loss 11 12 - (4) - 19 Equity method reclassification adjustments (8) (3) - - (35) (46) Net current period other comprehensive income (loss) 14 9 (49) (1) - (27) Other - - - - (4) (4) Balance, December 31, 2016 $ (21) $ (309) $ (49) $ (1) $ 486 $ 106 millions of Canadian dollars (Losses) gains on derivatives recognized as cash flow hedges Net change in unrecognized pension and post-retirement benefit costs Net change in net investment hedges Net change on available-for-sale investments Unrealized (loss) gain on translation of self-sustaining foreign operations Total AOCI For the year ended December 31, 2015 Balance, January 1, 2015 $ (8) $ (425) $ - $ 3 $ 82 $ (348) Other comprehensive income (loss) before reclassifications (34) - - (3) 408 371 Amounts reclassified from accumulated other comprehensive income loss (gain) 7 107 - - - 114 Net current period other comprehensive income (loss) (27) 107 - (3) 408 485 Balance, December 31, 2015 $ (35) $ (318) $ - $ - $ 490 $ 137 |
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 2016 2015 Affected line item in the Consolidated Statements of Income Amounts reclassified from AOCI Losses (gain) on derivatives recognized as cash flow hedges Power and gas swaps Non-regulated fuel for generation and purchased power $ (2) $ (5) Interest rate swaps Income from equity investments 1 1 Foreign exchange forwards Operating revenue - regulated 12 9 Total before tax 11 5 Income tax expense - 2 Total net of tax $ 11 $ 7 Net change in unrecognized pension and post-retirement benefit costs Actuarial losses (gains) OM&G $ 41 $ 50 Past service costs (gains) OM&G (9) (7) Amounts reclassified into obligations Pension and post-retirement benefits (17) 72 Total before tax 15 115 Income tax expense (recovery) (3) (8) Total net of tax $ 12 $ 107 Net change in available-for-sale investments Other income (expenses), net $ (4) $ - Total before tax (4) - Income tax expense (recovery) - - Total net of tax $ (4) $ - Equity method reclassification adjustments Investments subject to significant influence $ 54 $ - Total before tax 54 - Income tax expense (recovery) (8) - Total net of tax $ 46 $ - Total reclassifications out of AOCI, net of tax, for the period $ 65 $ 114 |
Receivables, Net (Tables)
Receivables, Net (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Receivables [Abstract] | |
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block] | 13. RECEIVABLES, NET Receivables, net consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Customer accounts receivable – billed $ 715 $ 406 Customer accounts receivable – unbilled 270 144 Total customer accounts receivable 985 550 Allowance for doubtful accounts (13) (12) Customer accounts receivable, net 972 538 Other 42 40 $ 1,014 $ 578 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Inventory [Abstract] | |
Schedule of Inventory, Current [Table Text Block] | 14. INVENTORY Inventory consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Fuel $ 235 $ 185 Materials 215 100 Emission credits (1) 22 29 $ 472 $ 314 (1)The NEGG Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative ("RGGI") 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, 2016 | |
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 2016 2015 2016 2015 Current Cash flow hedges Power swaps $ 5 $ 8 $ 2 $ 1 Foreign exchange forwards - - 12 14 5 8 14 15 Regulatory deferral Commodity swaps and forwards Coal purchases 26 - 9 12 Power purchases 3 - 1 - Natural gas purchases and sales 28 2 - 1 Heavy fuel oil purchases 6 - 4 20 Foreign exchange forwards 56 85 - 10 Physical natural gas purchases and sales - 2 - - 119 89 14 43 HFT derivatives Power swaps and physical contracts 33 151 44 119 Natural gas swaps, futures, forwards, physical contracts 93 99 357 359 Foreign exchange options - - - 2 126 250 401 480 Other derivatives Foreign exchange forwards - 92 1 - - 92 1 - Total gross current derivatives 250 439 430 538 Impact of master netting agreements with intent to settle net or simultaneously (105) (189) (105) (189) Total current derivatives 145 250 325 349 Long-term Cash flow hedges Power swaps 5 12 3 4 Foreign exchange forwards - - 10 27 5 12 13 31 Regulatory deferral Commodity swaps and forwards Coal purchases 57 - - 4 Power purchases 4 - 3 - Natural gas purchases and sales 5 - 2 - Heavy fuel oil purchases 4 - 3 17 Foreign exchange forwards 50 121 - - 120 121 8 21 HFT derivatives Power swaps and physical contracts 14 13 27 28 Natural gas swaps, futures, forwards and physical contracts 18 72 127 63 Foreign exchange options - 1 - 1 32 86 154 92 Other derivatives Interest rate swap - - 1 3 - - 1 3 Total gross long-term derivatives 157 219 176 147 Impact of master netting agreements with intent to settle net or simultaneously (26) (51) (26) (51) Total long-term derivatives 131 168 150 96 Total derivatives $ 276 $ 418 $ 475 $ 445 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 2016 2015 2016 2015 Regulatory deferral $ 10 $ - $ 10 $ - HFT derivatives 121 240 121 240 Total impact of master netting agreements with intent to settle net or simultaneously $ 131 $ 240 $ 131 $ 240 |
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 2016 2015 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 2 - - 5 - - Realized gain (loss) in operating revenue – Regulated - - (12) - - (9) Realized gain (loss) in income from equity investments - (1) - - (1) - Total gains (losses) in Net income $ 2 $ (1) $ (12) $ 5 $ (1) $ (9) As at December 31 millions of Canadian dollars 2016 2015 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 $ 2 $ - $ (22) $ 4 $ (1) $ (42) The Company expects $14 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, 2016, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below: millions 2017 2018 2019 2020 Foreign exchange forwards (USD) sales $ 53 $ 45 $ 30 $ 30 Foreign exchange forwards (EURO) purchases 3 - - - |
Schedule Of Regulatory Deferred Gain Losses Derivatives [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2016 2015 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 $ 40 $ - $ (2) $ (24) $ - $ (7) Unrealized gain (loss) in regulatory liabilities 101 (1) (30) 1 9 173 Realized (gain) loss in regulatory assets - - 12 (3) - - Realized (gain) loss in regulatory liabilities - - (8) - - - Realized (gain) loss in property, plant and equipment - - - - - (1) Realized (gain) loss in inventory (1) 5 - (44) 12 - (44) Realized (gain) loss in regulated fuel for generation and purchased power (2) 17 (1) (18) (16) (7) (18) Total change derivative instruments $ 163 $ (2) $ (90) $ (30) $ 2 $ 103 (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] | 2017 2018-2020 millions Purchases Purchases Coal (metric tonnes) - 2 Natural Gas (Mmbtu) 42 24 Heavy fuel oil (bbls) - 1 2017 2018-2020 Fuel purchases exposure (millions of US dollars) $ 224 $ 240 Weighted average rate 1.0722 1.1138 % of USD requirements 120% 44% The Company reassesses foreign exchange forecasts 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 2016 2015 Power swaps and physical contracts in non-regulated operating revenues $ (1) $ 10 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 69 5 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power (7) (3) Foreign exchange options in other income (expenses), net (2) (1) $ 59 $ 11 |
Offsetting Liabilities Expected To Settle [Table Text Block] | millions 2017 2018 2019 2020 2021 Natural gas purchases (Mmbtu) 270 69 54 45 45 Natural gas sales (Mmbtu) 202 20 16 12 1 Power purchases (MWh) 3 - - - - Power sales (MWh) 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 2016 2015 Interest Foreign Interest Foreign rate exchange rate exchange swaps forwards swaps forwards Realized gain (loss) in other income (expense) $ - $ (87) $ - $ - Unrealized gain (loss) in other income (expense) - - - 92 Unrealized gain (loss) in interest expense, net 2 - (3) - Total gains (losses) in net income $ 2 $ (87) $ (3) $ 92 As at December 31, 2016, 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. During the year ended December 31, 2016, $1,519 million in foreign exchange forwards and swaps that were used to partially hedge proceeds for the TECO Energy acquisition settled. |
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, 2016 December 31, 2015 millions of Canadian dollars % of total exposure millions of Canadian dollars % of total exposure Receivables, net Regulated utilities Residential $ 315 24% $ 189 20% Commercial 170 13% 103 10% Industrial 38 3% 29 3% Other 69 5% 53 5% 592 45% 374 38% Trading group Credit rating of A- or above 52 4% 31 3% Credit rating of BBB- to BBB+ 60 5% 22 2% Not rated 57 4% 31 3% 169 13% 84 8% Other accounts receivable 253 20% 120 12% 1,014 78% 578 58% Derivative Instruments (current and long-term) Credit rating of A- or above 252 20% 340 34% Credit rating of BBB- to BBB+ 1 0% 70 7% Not rated 23 2% 8 1% 276 22% 418 42% $ 1,290 100% $ 996 100% |
Schedule of Financial Instruments Owned and Pledged as Collateral [Table Text Block] | As at December 31 December 31 millions of Canadian dollars 2016 2015 Cash collateral provided to others $ 91 $ 107 Cash collateral received from others 52 29 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | 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 Commodity swaps and forwards 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 swap - 1 - 1 - 2 - 2 Total liabilities 25 61 389 475 Net assets (liabilities) $ (4) $ 154 $ (349) $ (199) As at December 31, 2015 millions of Canadian dollars Level 1 Level 2 Level 3 Total Assets Cash flow hedges Power swaps $ 20 $ - $ - $ 20 20 - - 20 Regulatory deferral Commodity swaps and forwards Coal purchases - 1 - 1 Foreign exchange forwards - 207 - 207 Physical natural gas purchases and sales - - 2 2 - 208 2 210 HFT derivatives Power swaps and physical contracts 38 1 (8) 31 Natural gas swaps, futures, forwards and physical contracts - 8 57 65 38 9 49 96 Other derivatives Foreign exchange forwards - 92 - 92 - 92 - 92 Total assets 58 309 51 418 Liabilities Cash flow hedges Power swaps $ 5 $ - $ - $ 5 Foreign exchange forwards - 41 - 41 5 41 - 46 Regulatory deferral Commodity swaps and forwards Coal purchases - 16 - 16 Natural gas purchases and sales 1 - - 1 Heavy fuel oil purchases - 37 - 37 Foreign exchange forwards - 10 - 10 1 63 - 64 HFT derivatives Power swaps and physical contracts 15 - (2) 13 Foreign exchange options - 4 - 4 Natural gas swaps, futures, forwards and physical contracts 14 22 279 315 29 26 277 332 Other derivatives Interest rate swaps - 3 - 3 - 3 - 3 Total liabilities 35 133 277 445 Net assets (liabilities) $ 23 $ 176 $ (226) $ (27) |
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, 2016 was as follows: Regulatory Deferral Cash Flow Hedges and HFT Derivatives millions of Canadian dollars Oil Financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2016 $ - $ 2 $ (8) $ 57 $ 51 Increase (reduction) in benefit included in regulated fuel for generation and purchased power - (1) - - (1) Unrealized gains (losses) included in regulatory assets or liabilities 3 (1) - - 2 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 8 (18) (10) Net transfers out of Level 3 (2) - - - (2) Balance, December 31, 2016 $ 1 $ - $ - $ 39 $ 40 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2016 was as follows: Regulatory Deferral Cash Flow Hedges and HFT Derivatives millions of Canadian dollars Oil Financial derivatives Physical natural gas purchases and sales Power Natural gas Total Balance, January 1, 2016 $ - $ - $ (2) $ 279 $ 277 Total realized and unrealized gains (losses) included in non-regulated operating revenues - - 2 110 112 Balance, December 31, 2016 $ - $ - $ - $ 389 $ 389 |
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | 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) As at December 31, 2015 millions of Canadian dollars Fair Value Valuation Technique Unobservable Input Range Weighted average Assets Regulatory deferral – Physical $ 2 Modelled pricing Third-party pricing $5.15 - $6.21 $5.72 natural gas purchases and sales Probability of default 0.01% 0.01% HFT derivatives – (8) Modelled pricing Third-party pricing $26.27 - $129.20 $70.45 Power swaps and Correlation factor 0.98% - 1.00% 0.99% physical contracts Probability of default 0.00% - 0.02% 0.00% Discount rate 0.00% - 0.15% 0.01% 54 Modelled pricing Third-party pricing $1.13 - $9.12 $3.26 Probability of default 0.00% - 0.10% 0.01% Discount rate 0.00% - 0.33% 0.04% 3 Modelled pricing Third-party pricing $1.25 - $15.74 $6.19 Basis adjustment (0.06)% - 0.95% 0.68% Probability of default 0.00% - 0.09% 0.00% Discount rate 0.00% - 0.08% 0.00% Total assets $ 51 Liabilities HFT derivatives – $ (2) Modelled pricing Third-party pricing $26.27 - $129.20 $70.82 Power swaps and Correlation factor 0.98% - 1.00% 0.99% physical contracts Own credit risk 0.00% - 0.02% 0.00% Discount rate 0.00% - 0.15% 0.01% HFT derivatives – 279 Modelled pricing Third-party pricing $0.74 - $10.59 $5.58 Natural gas swaps, Probability of default 0.00% - 0.03% 0.00% physical contracts Discount rate 0.00% - 0.12% 0.01% Total liabilities 277 Net assets (liabilities) $ (226) |
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 December 31, 2016 millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total Long-term debt (including current portion) $ 14,744 $ 15,723 $ 78 $ 14,843 $ 802 $ 15,723 As at December 31, 2015 millions of Canadian dollars Carrying Amount Fair Value Level 1 Level 2 Level 3 Total Long-term debt (including current portion) $ 4,009 $ 4,487 $ - $ 3,841 $ 646 $ 4,487 |
Regulatory Assets and Liabili60
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Regulatory assets Deferred income tax regulatory assets $ 632 $ 431 Pension and post-retirement medical plan 373 12 Environmental remediations 49 - Unamortized defeasance costs 39 46 2015 demand side management deferral 32 36 GBPC Hurricane Matthew restoration 28 - Stranded cost recovery 27 28 Debt basis adjustment 19 - Deferrals related to derivative instruments 15 68 Cost-recovery clauses 12 - Deferred bond refinancing costs 9 - Regulated fuel adjustment mechanism - 14 Other 87 64 $ 1,322 $ 699 Current $ 80 $ 94 Long-term 1,242 605 Total regulatory assets $ 1,322 $ 699 Regulatory liabilities Accumulated reserve - cost of remova l 990 94 Deferrals related to derivative instruments 230 $ 210 Cost-recovery clauses 153 - Regulated fuel adjustment mechanism 94 42 Transmission and delivery storm reserve 75 - Self-insurance fund (notes 7 and 33) 30 87 Deferred income tax regulatory liabilities 26 18 Bill reduction credit (note 4) 10 - Other 31 14 $ 1,639 $ 465 Current $ 362 $ 112 Long-term 1,277 353 Total regulatory liabilities $ 1,639 $ 465 |
Fuel Adjustment Mechanism [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2016 2015 (Over) under recovery of current period Fuel costs $ 29 $ (24) Recovery from customers of prior years’ Fuel costs 12 56 Application of non-fuel revenues 20 45 Regulated fixed cost deferral related to 2015 demand side management - (35) Regulated fuel adjustment mechanism $ 61 $ 42 |
Prepayments and Other Current61
Prepayments and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Prepaid Expense and Other Assets, Current [Abstract] | |
Prepayment and other current assets [ Table Text Block] | 19. PREPAYMENTS AND OTHER CURRENT ASSETS Prepayments and other current assets consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 Capitalized transportation capacity (1) $ 190 $ 223 Prepaid expenses 57 18 Due from related parties 16 2 Net investment in direct financing lease 8 6 Other 5 7 $ 276 $ 256 (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, 2016 | |
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 2016 2015 Generation 3 to 131 $ 10,553 $ 4,957 Transmission 28 to 77 2,799 1,603 Distribution 11 to 80 5,715 2,503 Gas transmission and distribution 10 to 85 2,895 - General plant and other 3 to 50 1,711 932 Total cost 23,673 9,995 Less: Accumulated depreciation (7,787) (3,737) 15,886 6,258 Construction work in progress 1,404 211 Net book value $ 17,290 $ 6,469 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 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 $ 1,520 $ 88 $ 1,470 $ 102 Addition of TECO Energy, July 1, 2016 1,035 277 - - Service cost 35 4 22 3 Plan participant contributions 8 - 8 - Interest cost 79 9 59 4 Plan amendments - 2 - (27) Benefits paid (94) (16) (61) (6) Actuarial losses (2) (12) (15) 1 Foreign currency translation adjustment 26 6 37 11 Balance, December 31 2,607 358 1,520 88 Change in plan assets Balance, January 1 1,300 6 1,205 5 Addition of TECO Energy, July 1, 2016 830 29 - - Employer contributions 49 17 23 6 Plan participant contributions 8 - 8 - Benefits paid (94) (16) (61) (6) Actual return on assets, net of expenses 93 2 96 - Foreign currency translation adjustment 22 1 29 1 Balance, December 31 2,208 39 1,300 6 Funded status, end of year $ (399) $ (319) $ (220) $ (82) |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block] | millions of Canadian dollars 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 2,579 $ 358 $ 1,489 $ 87 Fair value of plan assets 2,171 39 1,261 5 Funded status $ (408) $ (319) $ (228) $ (82) millions of Canadian dollars 2016 2015 Defined benefit pension plans Defined benefit pension plans ABO $ 2,462 $ 1,424 Fair value of plan assets 2,171 1,261 Funded status $ (291) $ (163) |
Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | As at December 31 millions of Canadian dollars 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Current liabilities $ (41) $ (17) $ (4) $ (3) Long-term liabilities (367) (302) (224) (79) Other asset (non-current) 9 - 9 - Amount included in deferred tax asset 16 (1) 19 (3) AOCL (AOCI) and regulatory assets after-tax adjustment 620 45 330 (9) Net amount recognized at end of year $ 237 $ (275) $ 130 $ (94) |
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, 2016 $ - $ 353 $ (4) Amortized in current period (9) (42) 1 Current year addition to AOCL or regulatory assets 318 19 - Balance, December 31, 2016 $ 309 $ 330 $ (3) Non-pension benefits plans Balance, January 1, 2016 $ - $ 15 $ (27) Amortized in current period - (2) 8 Current year addition to AOCL (AOCI) or regulatory assets 48 2 - Balance, December 31, 2016 $ 48 $ 15 $ (19) 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses $ 330 $ 15 $ 353 $ 15 Past service (gains) (3) (19) (4) (27) Regulatory assets 309 48 - - Total AOCL (AOCI) and regulatory assets on a pre-tax basis 636 44 349 (12) Amount included in deferred tax asset (16) 1 (19) 3 Net amount in AOCL (AOCI) and regulatory assets after-tax adjustment $ 620 $ 45 $ 330 $ (9) |
Schedule of Net Benefit Costs [Table Text Block] | As at Year ended December 31 millions of Canadian dollars 2016 2015 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 35 $ 4 $ 22 $ 3 Interest cost 79 9 59 3 Expected return on plan assets (97) (1) (65) - Current year amortization of: Actuarial losses 42 2 48 1 Past service costs (gains) (1) (8) (1) (6) Regulatory assets (liability) 9 - - - Total $ 67 $ 6 $ 63 $ 1 |
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 36% to 50% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Short-term securities 0% to 2% Fixed income 40% to 48% Equities 50% to 61% As at December 31, 2015 millions of Canadian dollars NAV Level 1 Total Percentage Cash and cash equivalents - $ 12 $ 12 1 % Equity securities: Canadian equity - 190 190 - % US equity - 240 240 18 % Other equity - 240 240 18 % Other investments measured at NAV $ 619 - 619 48 % Total $ 619 $ 682 $ 1,301 100 % Asset Class Target Range at Market Short-term securities 10% to 50% Fixed income 0% to 40% Equities: US 30% to 60% Non-US 0% to 60% 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 December 31, 2015 millions of Canadian dollars NAV Level 1 Level 2 Total Percentage Cash and cash equivalents - $ 1 $ - $ 1 20 % Other investments measured at NAV $ 4 - - 4 80 % Total $ 4 $ 1 $ - $ 5 100 % |
Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | 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. |
Schedule of Expected Benefit Payments [Table Text Block] | millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2017 $ 117 $ 25 Expected benefit payments 2017 172 22 2018 140 23 2019 150 23 2020 156 24 2021 165 25 2022 – 2026 912 130 |
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: 2016 2015 (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 3.96 % 4.18 % 4.02 % 4.04 % Rate of compensation increase 2.82 % 2.54 % 3.07 % 3.50 % Health care trend - initial (next year) - 6.78 % - 5.50 % - ultimate - 4.45 % - 4.20 % - year ultimate reached - 2020 - 2020 Benefit cost for year ended December 31: Discount rate 3.79 % 3.88 % 3.99 % 3.98 % Expected long-term return on plan assets 6.33 % 4.43 5.91 % - Rate of compensation increase 2.88 % 2.56 % 3.07 % 3.50 % Health care trend - initial (current year) - 6.76 % - 5.90 % - ultimate - 4.45 % - 4.30 % - year ultimate reached - 2020 - 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 20 (17) millions of Canadian dollars Increase Decrease Discount rate assumption $ (7) $ 7 Asset rate assumption (4) 4 |
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 2017: 2017 millions of Canadian dollars Defined benefit pension plans Non-pension benefit plans Actuarial gains (losses) $ (53) $ (1) Past service gains 1 8 Regulatory assets (16) 3 Total $ (68) $ 10 |
Net Investment in Direct Fina64
Net Investment in Direct Financing Lease (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Total minimum lease payments to be received $ 1,194 $ 1,202 Less: amounts representing estimated executory costs (223) (213) Minimum lease payments receivable $ 971 $ 989 Estimated residual value of leased property (unguaranteed) 183 183 Less: unearned finance lease income (658) (686) Net investment in direct financing lease $ 496 $ 486 Principal due within one year (included in “Prepayments and other current assets”) 8 6 Net investment in direct financing lease – long-term $ 488 $ 480 |
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 2017 2018 2019 2020 2021 Minimum lease payments to be received $ 65 $ 65 $ 65 $ 65 $ 65 Less: amounts representing estimated executory costs (11) (11) (12) (12) (12) Minimum lease payments receivable $ 54 $ 54 $ 53 $ 53 $ 53 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill [Abstract] | |
Schedule of Goodwill [Table Text Block] | 23. GOODWILL The change in goodwill for the year ended December 31 is due to the following: millions of Canadian dollars 2016 2015 Balance, January 1 $ 264 $ 222 Acquisition of TECO Energy as at July 1, 2016 (note 4) 5,771 - Impairment - - Change in foreign exchange rate 178 42 Balance, December 31 $ 6,213 $ 264 |
Short-Term Debt (Tables)
Short-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Short-term Debt [Abstract] | |
Schedule of Short-term Debt [Table Text Block] | millions of Canadian dollars 2016 Weighted-average interest rate 2015 Weighted-average interest rate TECO Energy/TECO Finance $ Advances on revolving credit and term facilities 685 1.74 % - - % Tampa Electric Company Advances on accounts receivable and revolving credit facilities 228 1.49 % - - % NMGC Advances on revolving credit facilities 35 1.71 % - - % NSPI Bank indebtedness 1 2.70 % 16 2.70 % GBPC Advances on revolving credit facilities 12 5.75 % - - % Short-term debt $ 961 $ 16 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 2016 2015 TECO Energy/TECO Finance - term credit facility 2017 537 $ - TECO Energy/TECO Finance - revolving credit facility 2018 403 - Tampa Electric Company - revolving credit facility 2018 436 - Tampa Electric Company - accounts receivable revolving credit facility 2018 201 - NMGC - revolving credit facility 2018 168 - GBPC - revolving credit facility 2017 17 18 Total 1,762 18 Less: Advances under revolving credit and term facilities 960 - Letters of credit issued inside credit facilities 3 - Total advances under available facilities 963 - Available capacity under existing agreements $ 799 $ 18 |
Other Current Liabilities (Tabl
Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Accrued charges $ 137 $ 130 Accrued interest on long-term debt 96 44 Sales and other taxes payable 16 4 Accrued interest on convertible debentures represented by instalment receipts (note 8) - 11 Emission credits obligations (1) 10 6 Other 22 12 $ 281 $ 207 (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 14) 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, 2016 | |
Long-term Debt [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | millions of Canadian dollars Weighted Average Interest Rate 2016 (1) Weighted Average Interest Rate 2015 (1) Maturity 2016 2015 Emera Bankers acceptances, LIBOR loans Variable Variable 2020 $ 30 $ 240 Unsecured fixed rate notes 3.50% 3.85% 2019-2023 725 475 Fixed to floating subordinated notes (USD) (2) 6.75% - 2076 1,611 - $ 2,366 $ 715 Emera US Finance LP Unsecured senior notes (USD) (2) 3.60% - 2019 - 2046 $ 4,364 $ - 4,364 - TECO Finance (3) Variable rate notes (USD) Variable - 2018 $ 336 $ - Fixed rate notes and bonds (USD) 5.86% 2017 - 2020 805 - $ 1,141 $ - Tampa Electric (4) Fixed rate notes and bonds (USD) 4.90% - 2018 - 2045 $ 2,579 $ - $ 2,579 $ - PGS Fixed rate notes and bonds (USD) 5.06% - 2018 - 2045 $ 351 $ - $ 351 $ - NMGC Fixed rate notes and bonds (USD) 4.53% - 2021 - 2026 $ 363 $ - $ 363 $ - NMGI Fixed rate notes and bonds (USD) 3.41% - 2019 - 2024 $ 269 $ - $ 269 $ - NSPI Commercial paper Variable Variable 2020 $ 264 $ 369 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 Capital lease obligations 4.80% 4.58% 2019 - 1 $ 2,324 $ 2,430 Emera Maine LIBOR loans and demand loans Variable Variable 2019 $ 32 $ 32 Secured fixed rate mortgage bonds (USD) 9.74% 9.74% 2020-2022 67 69 Unsecured senior fixed rate notes (USD) 4.28% 4.31% 2017-2044 281 296 $ 380 $ 397 EBP Senior secured credit facility 3.08% 3.08% 2019 $ 248 $ 249 $ 248 $ 249 GBPC Unsecured amortizing fixed rate notes (USD) 3.62% 3.62% 2021-2022 $ 63 $ 77 Unsecured senior notes (USD) 7.07% 7.07% 2020-2023 67 68 $ 130 $ 145 BLPC & ECI Secured fixed rate senior notes (5) 5.65% 5.64% 2020 - 2028 $ 81 $ 89 Secured senior notes (USD) (6) Variable - 2021 201 - $ 282 $ 89 Adjustments Fair market value adjustment - TECO Energy acquisition (7) $ 58 $ - Debt issuance costs (111) (16) Amount due within one year (476) (274) $ (529) $ (290) Long-Term Debt $ 14,268 $ 3,735 (1) Weighted average interest rate of fixed rate long-term debt. (2) See below for details on the long-term debt related to the acquisition of TECO Energy. (3) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. (4) 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. (5) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). (6) See below for details on the long-term debt issued by ECI in November, 2016. (7) 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 2016 2015 Emera – revolving credit facility (1) June 2020 $ 700 $ 700 NSPI - revolving credit facility (1) October 2020 600 500 Emera Maine – revolving credit facility September 2019 107 111 BLPC – revolving credit facility 2017-2021 26 26 Total 1,433 1,337 Less: Borrowings under credit facilities 326 641 Letters of credit issued inside credit facilities 37 33 Use of available facilities 363 674 Available capacity under existing agreements $ 1,070 $ 663 (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, 2016 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 to 1 0.62:1 |
Schedule of Maturities of Long-term Debt [Table Text Block] | millions of Canadian dollars 2017 2018 2019 2020 2021 Thereafter Total Emera $ - $ - $ 225 $ 30 $ - $ 2,111 $ 2,366 Emera US Finance LP - - 671 - 1,007 2,686 4,364 TECO Energy - 409 67 - 643 2,443 3,562 TECO Finance 403 335 - 403 - - 1,141 NSPI - - 95 264 - 1,965 2,324 Emera Maine 33 6 32 40 - 269 380 EBP - - 248 - - - 248 GBPC 11 12 12 40 11 44 130 BLPC and ECI 29 29 30 58 26 110 282 Total $ 476 $ 791 $ 1,380 $ 835 $ 1,687 $ 9,628 $ 14,797 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Balance, January 1 $ 109 $ 106 Additions (1) 48 - Additions due to acquisition 9 - Liabilities settled (2) (2) Accretion included in depreciation expense 7 8 Accretion deferred to regulatory asset (included in property, plant and equipment) (2) (8) Other 1 5 Balance, December 31 $ 170 $ 109 (1) Tampa Electric produces ash and other by-products known as coal combustion residuals ("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 Environmental Cost Recovery Clause. However, additional petitions will be submitted for recovery of future project expenses based on engineering studies currently being performed. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies [Abstract] | |
Other Commitments [Table Text Block] | millions of Canadian dollars 2017 2018 2019 2020 2021 Thereafter Total Purchased power (1) $ 253 $ 224 $ 206 $ 202 198 $ 2,272 $ 3,355 Fuel and gas supply 475 161 109 28 22 - 795 Demand Side Management 42 48 13 - - - 103 Transportation (2) 496 392 310 280 196 1,622 3,296 Long-term service agreements (3) 92 55 67 44 42 227 527 Capital projects 133 - - - - - 133 Equity investment commitments (4) 236 - - 200 - - 436 Leases and other (5) 66 17 14 12 8 70 187 $ 1,793 $ 897 $ 719 $ 766 $ 466 $ 4,191 $ 8,832 (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 ("FLG") 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, 2016 | |
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, 2016 December 31, 2015 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 S72
Non-Controlling Interest in Subsidiaries (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Noncontrolling Interest [Table Text Block] | 30. NON-CONTROLLING INTEREST IN SUBSIDIARIES Non-controlling interest in subsidiaries consisted of the following: As at December 31 December 31 millions of Canadian dollars 2016 2015 ICDU $ 53 $ 52 Preferred shares of GBPC 34 34 Domlec 25 23 ECI (1) - 25 $ 112 $ 134 (1) On December 17, 2015, an indirect wholly owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent. On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares (which owns 51.9 per cent share of Domlec), increasing Emera's ownership interest in ECI from 95.5 to 100 per cent. |
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 2016 2015 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 35,000 $ 34 35,000 $ 34 |
Supplemental Information to C73
Supplemental Information to Consolidated Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | For the Year ended December 31 millions of Canadian dollars 2016 2015 Changes in non-cash working capital: Receivables, net $ (104) $ (19) Income taxes receivable (23) (22) Inventory 88 (2) Prepayments and other current assets (18) 9 Accounts payable and customer deposits 162 (45) Income taxes payable 14 (32) Other current liabilities 15 9 Total non-cash working capital 134 (102) Supplemental disclosure of cash paid (received): Interest $ 480 $ 196 Income taxes $ 57 $ 124 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 103 $ 78 Beneficial Conversion Feature of the convertible debentures $ 43 $ - |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
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 [Table Text Block] | For the year ended December 31, 2016 2015 Weighted average fair value per option $ 2.80 $ 2.66 Expected term 5 years 5 years Risk-free interest rate 0.66 % 0.73 % Expected dividend yield 4.08 % 3.65 % Expected volatility 15.45 % 14.58 % |
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, 2015 2,927,068 $ 33.07 1,453,486 $ 2.64 Granted 615,100 46.19 615,100 2.80 Exercised (622,168) 25.65 N/A N/A Forfeited - - (548,461) 2.68 Options outstanding December 31, 2016 2,920,000 $ 37.42 1,520,125 $ 2.69 Options exercisable December 31, 2016 (2)(3) 1,399,875 $ 33.35 (1) As at December 31, 2016 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 2.4 years (2015 - $3 million, 2.3 years). (2) As at December 31, 2016, the weighted average remaining term of vested options was 5.7 years with an aggregate intrinsic value of $17 million (2015 - 5.3 years, $21 million). (3) As at December 31, 2016 the fair value of options that vested in the year was $2 million (2015 - $1 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, 2015 606,646 $ 26.27 362,750 $ 31.36 Granted including DRIP 74,855 37.60 69,429 43.67 Exercised (570) 46.58 (36,381) 27.42 Outstanding and exercisable as at December 31, 2016 680,931 $ 27.50 395,798 $ 33.88 Employee PSU Weighted Average Grant Date Fair Value Aggregate intrinsic value Outstanding as at December 31, 2015 497,496 $ 34.50 $ 21.5 Granted including DRIP 280,950 40.60 Exercised (208,999) 34.39 Forfeited (8,567) 37.54 Outstanding as at December 31, 2016 560,880 $ 37.55 $ 25.5 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entities [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | As at December 31, 2016 December 31, 2015 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) $ 315 $ 577 $ 188 $ 1,007 |
Supplemental Financial Inform76
Supplemental Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Income Statement [Table Text Block] | Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues Regulated electric $ - $ - $ 1,665 $ 1,774 $ (2) $ 3,437 Regulated gas - - 451 48 - 499 Non-regulated - - 378 (4) (33) 341 Total operating revenues - - 2,494 1,818 (35) 4,277 Operating expenses Regulated fuel for generation and purchased power - - 560 662 - 1,222 Regulated cost of natural gas - - 177 - - 177 Regulated fuel adjustment mechanism and fixed cost deferrals - - - 61 - 61 Non-regulated fuel for generation and purchased power - - 261 56 (4) 313 Non-regulated direct costs - - - 52 (23) 29 Operating, maintenance and general 37 - 647 461 (8) 1,137 Provincial, state and municipal taxes - - 152 43 - 195 Depreciation and amortization 2 - 330 256 - 588 Total 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 Net income (loss) of Emera Incorporated 255 9 109 82 (200) 255 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 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Operating revenues Regulated electric $ - $ - $ 283 $ 1,860 $ (2) $ 2,141 Regulated gas - - - 52 - 52 Non-regulated - - 419 219 (42) 596 Total operating revenues - - 702 2,131 (44) 2,789 Operating expenses Regulated fuel for generation and purchased power - - 70 745 - 815 Regulated fuel adjustment mechanism and fixed cost deferrals - - - 42 - 42 Non-regulated fuel for generation and purchased power - - 277 64 (5) 336 Non-regulated direct costs - - - 49 (30) 19 Operating, maintenance and general 54 - 148 472 (8) 666 Provincial, state and municipal taxes - - 21 42 - 63 Depreciation and amortization 1 - 79 260 - 340 Total operating expenses 55 - 595 1,674 (43) 2,281 Income (loss) from operations (55) - 107 457 (1) 508 Income (loss) from equity investments in subsidiaries 270 - - - (270) - Income from equity investments 37 - 5 66 - 108 Intercompany income (expenses), net 156 - - 8 (164) - Other income (expenses), net 91 - 21 29 - 141 Interest expense, net 46 - 28 272 (134) 212 Income (loss) before provision for income taxes 453 - 105 288 (301) 545 Income tax expense (recovery) 25 - 35 33 - 93 Net income (loss) 428 - 70 255 (301) 452 Non-controlling interest in subsidiaries - - - 13 12 25 Net income (loss) of Emera Incorporated 428 - 70 242 (313) 427 Preferred stock dividends 30 - 15 26 (41) 30 Net income (loss) attributable to common shareholders $ 398 $ - $ 55 $ 216 $ (272) $ 397 Comprehensive income (loss) of Emera Incorporated $ 911 $ - $ 303 $ 452 $ (755) $ 911 |
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 $ 200 $ 28 $ 48 $ 128 $ - $ 404 Restricted cash - - 1 86 - 87 Receivables, net 1 - 429 584 - 1,014 Intercompany receivables 57 9 11 569 (646) - Income taxes receivable - - 5 28 - 33 Inventory - - 273 199 - 472 Derivative instruments 13 - 33 112 (13) 145 Regulatory assets - - 54 26 - 80 Prepayments and other current assets 2 - 44 230 - 276 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 Income taxes receivable - - - 48 - 48 Deferred income taxes 31 - 18 114 (38) 125 Derivative instruments 12 - 2 129 (12) 131 Pension and post-retirement asset - - - 9 - 9 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 Investment securities - - - 48 - 48 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 70 (19) 169 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 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) - Income taxes payable - 6 - 13 - 19 Derivative instruments 14 - 10 314 (13) 325 Regulatory liabilities - - 225 137 - 362 Pension and post-retirement liabilities - - 51 7 - 58 Other current liabilities 54 7 79 141 - 281 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 Convertible debentures 8 - - - - 8 Derivative instruments 12 - - 150 (12) 150 Regulatory liabilities - - 973 304 - 1,277 Asset retirement obligations - - 61 109 - 170 Pension and post-retirement liabilities 17 - 433 219 - 669 Other long-term liabilities 5 - 213 268 (19) 467 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 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Assets Current assets Cash and cash equivalents $ - $ - $ 19 $ 1,068 $ (14) $ 1,073 Restricted cash - - 1 18 - 19 Receivables, net 2 - 70 506 - 578 Intercompany receivable 102 - 51 95 (248) - Income taxes receivable - - 9 3 - 12 Inventory - - 48 266 - 314 Derivative instruments 109 - 46 112 (17) 250 Regulatory assets - - 17 77 - 94 Prepayments and other current assets 9 - 4 243 - 256 Total current assets 222 - 265 2,388 (279) 2,596 Property, plant and equipment, net of accumulated depreciation 15 - 2,035 4,419 - 6,469 Other assets Income taxes receivable - - - 49 - 49 Deferred income taxes - - 47 19 (34) 32 Derivative instruments 35 - - 167 (34) 168 Pension and post-retirement assets - - - 9 - 9 Regulatory assets - - 100 505 - 605 Net investment in direct financing lease - - - 480 - 480 Investments in subsidiaries accounted for using the equity method 6,042 - - - (6,042) - Investments subject to significant influence 509 - 12 624 - 1,145 Investment securities - - - 116 - 116 Goodwill - - 158 106 - 264 Intercompany notes receivable 3,051 - - 2,754 (5,805) - Other investments - intercompany - - - 98 (98) - Other long-term assets 16 - 13 77 - 106 Total other assets 9,653 - 330 5,004 (12,013) 2,974 Total assets $ 9,890 $ - $ 2,630 $ 11,811 $ (12,292) $ 12,039 Emera Incorporated Consolidated Balance Sheets – Continued As at December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Liabilities and Equity Current liabilities Short-term debt $ 14 $ - $ - $ 16 $ (14) $ 16 Current portion of long-term debt 250 - 6 18 - 274 Accounts payable 17 - 76 301 - 394 Income taxes payable - - - 8 - 8 Intercompany payable 52 - 92 77 (221) - Derivative instruments 17 - 36 313 (17) 349 Regulatory liabilities - - 10 102 - 112 Pension and post-retirement liabilities - - - 7 - 7 Other current liabilities 51 - 24 132 - 207 Total current liabilities 401 - 244 974 (252) 1,367 Long-term liabilities Long-term debt 464 - 389 2,882 - 3,735 Intercompany long-term debt 2,631 - 120 3,072 (5,823) - Deferred income taxes 3 - 343 450 (34) 762 Convertible debentures (represented by installment receipts) 2,139 - - (1,458) - 681 Derivative instruments 34 - - 96 (34) 96 Regulatory liabilities - - 12 341 - 353 Asset retirement obligations - - - 109 - 109 Pension and post-retirement liabilities 13 - 93 197 - 303 Other long-term liabilities 5 - 61 233 - 299 Total long-term liabilities 5,289 - 1,018 5,922 (5,891) 6,338 Equity Common stock 2,157 - 312 3,829 (4,141) 2,157 Cumulative preferred stock 709 - 425 271 (696) 709 Contributed surplus 29 - 45 133 (178) 29 Accumulated other comprehensive income (loss) 137 - 245 (169) (76) 137 Retained earnings 1,168 - 341 751 (1,092) 1,168 Total Emera Incorporated equity 4,200 - 1,368 4,815 (6,183) 4,200 Non-controlling interest in subsidiaries - - - 100 34 134 Total equity 4,200 - 1,368 4,915 (6,149) 4,334 Total liabilities and equity $ 9,890 $ - $ 2,630 $ 11,811 $ (12,292) $ 12,039 |
Condensed Cash Flow Statement [Table Text Block] | Emera Incorporated 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) by 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) - (633) (396) - (1,031) 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 - - (42) (12) - (54) Net cash provided by (used in) investing activities (1,685) (4,416) (9,102) (3,081) 9,179 (9,105) 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 29 (940) 14 (669) Cash and cash equivalents, beginning of period - - 19 1,068 (14) 1,073 Cash and cash equivalents, end of period $ 200 $ 28 $ 48 $ 128 $ - $ 404 Emera Incorporated Consolidated Statements of Cash Flows For the year ended December 31, 2015 Parent Subsidiary Issuer Guarantor Subsidiaries Non-guarantor Subsidiaries Eliminations Consolidated millions of Canadian dollars Net cash provided by (used in) operating activities $ 291 $ - $ 190 $ 364 $ (171) $ 674 Investing activities Additions to property, plant and equipment (7) - (66) (354) - (427) Net purchase of investments subject to significant influence, inclusive of acquisition costs (1) - (3) (132) - (136) Proceeds on sale of investment subject to significant influence - - 282 - - 282 Other intercompany investing activities (2,453) - - (29) 2,482 - Other investing activities (751) - (10) (413) 1,331 157 Net cash provided by (used in) investing activities (3,212) - 203 (928) 3,813 (124) Financing activities Change in short-term debt, net 4 - - (262) (4) (262) Proceeds from long-term debt, net of issuance costs - - 29 1,465 (1,048) 446 Proceeds from convertible debentures represented by instalment receipts, net of issuance costs 2,138 - - (1,457) - 681 Retirement of long-term debt - - (420) (372) 702 (90) Net borrowings (repayments) under committed credit facilities (39) - (9) (153) - (201) Issuance of common stock, net of issuance costs 9 - - 2,390 (2,390) 9 Issuance of preferred stock, net of issuance costs - - - 6 (6) - Dividends on common stock (162) - - (162) 162 (162) Dividends on preferred stock (30) - (15) (25) 40 (30) Dividends paid by subsidiaries to non-controlling interest - - - (3) (11) (14) Other financing activities 1,001 - (11) (55) (1,091) (156) Net cash provided by (used in) financing activities 2,921 - (426) 1,372 (3,646) 221 Effect of exchange rate changes on cash and cash equivalents - - 14 67 - 81 Net increase (decrease) in cash and cash equivalents - - (19) 875 (4) 852 Cash and cash equivalents, beginning of period - - 38 193 (10) 221 Cash and cash equivalents, end of period $ - $ - $ 19 $ 1,068 $ (14) $ 1,073 |
Summary of Significant Accoun77
Summary of Significant Accounting Policies (Nature of Operations Narrative) (Details) CAD in Millions | Dec. 31, 2016CADMWCustomerskm | Mar. 22, 2016 | Dec. 31, 2015 |
Public Utilities, General Disclosures [Line Items] | |||
Indirect Ownership Percentage By Parent | 100.00% | ||
Emera Maine [Member] | Maine | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 157,000 | ||
Nova Scotia Power Inc. [Member] | Nova Scotia [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 511,000 | ||
Emera (Caribbean) Incorporated Parent [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Controlling Interest Ownership Percentage By Parent | 100.00% | 95.50% | 95.50% |
Equity Method Investment, Ownership Percentage | 95.50% | 80.70% | |
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% | ||
Indirect Ownership Percentage By Parent | 49.60% | ||
Number Of Cutomers | 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 Cutomers | 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% | 18.20% | |
Emera (Caribbean) Incorporated Parent [Member] | The Barbados Light and Power Company Limited [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 126,000 | ||
Emera Inc | Algonquin Power and Utilities Corporation [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Equity Method Investment, Ownership Percentage | 4.70% | 19.60% | |
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 | NSP Maritime Link Inc. [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Equity Method Investment, Ownership Percentage | 49.00% | ||
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% | ||
Equity Method Investment, Ownership Percentage | 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 | CAD | CAD 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 | 62.70% | 55.10% | |
Public Utilities, Property, Plant and Equipment, Transmission and Distribution | CAD | CAD 3,400 | ||
TECO Energy Inc Parent [Member] | New Mexico Gas Company [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 522,000 | ||
TECO Energy Inc Parent [Member] | Peoples Gas System Division [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 374,000 | ||
TECO Energy Inc Parent [Member] | Tampa Electric Division [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Number Of Cutomers | 736,000 | ||
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 Accoun78
Summary of Significant Accounting Policies (Cash, Short-term Investments and Receivables) (Narrative) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash and Cash Equivalents [Abstract] | ||
Short-term Investments | CAD 183 | CAD 78 |
Investment Interest Rate | 0.60% | 0.60% |
Acquisition (Purchase Considera
Acquisition (Purchase Consideration) (Details) - TECO Energy Inc [Member] $ / shares in Units, CAD in Millions, $ in Millions | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Aug. 02, 2016CAD | Jul. 01, 2016USD ($)$ / shares |
Business Combination, Consideration Transferred [Abstract] | ||||
Business Acquisition, Share Price | $ 27.55 | |||
Payments to Acquire Businesses, Gross | CAD 8,400 | $ 6,500 | ||
Business Combination, Consideration Transferred, Liabilities Incurred | 5,500 | 4,200 | ||
Business Combination, Consideration Transferred | 13,900 | $ 10,700 | ||
Short-Term Debt/Long-Term Debt [Abstract] | ||||
Convertible Debt | 728 | CAD 1,400 | $ 560 | |
Junior Subordinated Notes, Noncurrent | 1,560 | 1,200 | ||
Other Long-term Debt, Noncurrent | 500 | 384 | ||
Senior Notes, Noncurrent | 4,200 | 3,250 | ||
Line of Credit Facility, Fair Value of Amount Outstanding | CAD 1,400 | $ 1,100 |
Acquision (Purchase Considerati
Acquision (Purchase Consideration) (Details) CAD in Millions | Dec. 31, 2016CAD | Jul. 01, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2014CAD |
Fair value assigned to net assets: | ||||
Goodwill | CAD 6,213 | CAD 264 | CAD 222 | |
TECO Energy Inc [Member] | ||||
Multiple Foreign Currency Exchange Rates [Abstract] | ||||
Foreign Currency Exchange Rate, Translation | 1.3009 | |||
Purchase Consideration | CAD 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 | CAD 475 |
Acquision (Related Expenses and
Acquision (Related Expenses and Pro Forma Data) (Details) - TECO Energy Inc [Member] - CAD CAD in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | CAD 166 | CAD 53 | ||
Business Acquisition, Pro Forma Information [Abstract] | ||||
Pro forma operating revenues | 6,034 | 6,297 | ||
Prop forma net income attributable to common shareholders | 386 | 584 | ||
Adjusted pro forma operating revenues increased | CAD 10 | CAD 10 | 10 | 10 |
Business Acquisitions Pro Forma Increase To Net Income Loss | 53 | (35) | ||
New Mexico | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 23 | |||
Sales [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | (10) | 0 | ||
Sales [Member] | New Mexico | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | (10) | |||
Operating Expense [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 89 | 52 | ||
Operating Expense [Member] | New Mexico | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 30 | |||
Interest Expense [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 148 | 24 | ||
Other Operating Income (Expense) [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | (3) | 0 | ||
Before Tax [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 250 | 76 | ||
Before Tax [Member] | New Mexico | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | 40 | |||
Income Tax Expense [Member] | ||||
Business Combination, Separately Recognized Transactions [Line Items] | ||||
Business Combination, Acquisition Related Costs | CAD (84) | CAD (23) |
Segment Information (Reportable
Segment Information (Reportable Segments) (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | CAD 4,277 | CAD 2,789 | |
Allowance for Funds Used During Construction, Investing Activities | 35 | 6 | |
Regulated Fuel Adjustment | 61 | 42 | |
Depreciation, Depletion and Amortization | 588 | 340 | |
Interest Expense | 600 | 222 | |
Investment Income, Interest | 2 | 6 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 100 | 108 | |
Income tax expense (recovery) | (22) | 93 | |
Net Income (Loss) Attributable to Parent | 255 | 427 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 487 | 487 | |
Assets, Total | 29,221 | 12,039 | |
Goodwill | 6,213 | 264 | CAD 222 |
Investments subject to significant influence | 947 | 1,145 | |
All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 4,276 | 2,787 | |
Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 1 | 2 | |
Intersegment Eliminations [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | (36) | (44) | |
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 | |
Investment Income, Interest | 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 | (113) | (225) | |
Goodwill | 0 | 0 | |
Investments subject to significant influence | 0 | 0 | |
Intersegment Eliminations [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | (2) | (2) | |
Intersegment Eliminations [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | (34) | (42) | |
Emera Florida And New Mexico Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 1,839 | 0 | |
Allowance for Funds Used During Construction, Investing Activities | 28 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 243 | 0 | |
Interest Expense | 125 | 0 | |
Investment Income, Interest | 0 | 0 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 100 | 0 | |
Net Income (Loss) Attributable to Parent | 172 | 0 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 0 | 0 | |
Assets, Total | 18,016 | 0 | |
Goodwill | 5,957 | 0 | |
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 | 1,839 | 0 | |
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 | 1,356 | 1,417 | |
Allowance for Funds Used During Construction, Investing Activities | 6 | 4 | |
Regulated Fuel Adjustment | 61 | 42 | |
Depreciation, Depletion and Amortization | 197 | 206 | |
Interest Expense | 127 | 129 | |
Investment Income, Interest | 0 | 5 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 12 | 23 | |
Net Income (Loss) Attributable to Parent | 130 | 130 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 271 | 271 | |
Assets, Total | 4,776 | 4,721 | |
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 | 1,356 | 1,417 | |
Nova Scotia Power Inc Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 0 | |
Emera Maine Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 297 | 284 | |
Allowance for Funds Used During Construction, Investing Activities | 1 | 2 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 51 | 47 | |
Interest Expense | 19 | 19 | |
Investment Income, Interest | 0 | 0 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 0 | 0 | |
Income tax expense (recovery) | 23 | 27 | |
Net Income (Loss) Attributable to Parent | 47 | 45 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 65 | 65 | |
Assets, Total | 1,543 | 1,558 | |
Goodwill | 154 | 158 | |
Investments subject to significant influence | 13 | 12 | |
Emera Maine Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 297 | 284 | |
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 | 419 | 450 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 48 | 44 | |
Interest Expense | 15 | 14 | |
Investment Income, Interest | 0 | 0 | |
Internally Allocated Interest | 0 | 0 | |
Income (Loss) from Equity Method Investments | 3 | 3 | |
Income tax expense (recovery) | 14 | 3 | |
Net Income (Loss) Attributable to Parent | 100 | 41 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 44 | 44 | |
Assets, Total | 1,331 | 1,403 | |
Goodwill | 102 | 106 | |
Investments subject to significant influence | 39 | 39 | |
Emera Caribbean Segment [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 419 | 442 | |
Emera Caribbean Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 0 | 8 | |
Emera Energy Segment [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 309 | 590 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 45 | 41 | |
Interest Expense | 2 | 1 | |
Investment Income, Interest | 1 | 1 | |
Internally Allocated Interest | (24) | (18) | |
Income (Loss) from Equity Method Investments | 11 | 21 | |
Income tax expense (recovery) | (53) | 50 | |
Net Income (Loss) Attributable to Parent | (110) | 99 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 98 | 98 | |
Assets, Total | 1,702 | 1,919 | |
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 | 298 | 578 | |
Emera Energy Segment [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 11 | 12 | |
Corporate and Other [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 93 | 92 | |
Allowance for Funds Used During Construction, Investing Activities | 0 | 0 | |
Regulated Fuel Adjustment | 0 | 0 | |
Depreciation, Depletion and Amortization | 4 | 2 | |
Interest Expense | 312 | 59 | |
Investment Income, Interest | 1 | 0 | |
Internally Allocated Interest | 24 | 18 | |
Income (Loss) from Equity Method Investments | 86 | 84 | |
Income tax expense (recovery) | (118) | (10) | |
Net Income (Loss) Attributable to Parent | (112) | 82 | |
Segment Reporting Information, Additional Information [Abstract] | |||
Capital expenditures | 9 | 9 | |
Assets, Total | 1,966 | 2,663 | |
Goodwill | 0 | 0 | |
Investments subject to significant influence | 895 | 1,094 | |
Amortization Related to Unregulated Long Term Debt | 13 | ||
Corporate and Other [Member] | All External Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | 69 | 68 | |
Corporate and Other [Member] | Internal Customers [Member] | |||
Segment Reporting Information, Profit (Loss) [Abstract] | |||
Revenues, Total | CAD 24 | CAD 24 |
Segment Information (Geographic
Segment Information (Geographical) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | CAD 4,277 | CAD 2,789 |
NoncurrentAssets | 17,290 | 6,469 |
CA | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 1,510 | 1,546 |
NoncurrentAssets | 3,791 | 3,672 |
UNITED STATES | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 2,348 | 786 |
NoncurrentAssets | 12,724 | 2,034 |
BARBADOS | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 254 | 259 |
NoncurrentAssets | 416 | 402 |
BAHAMAS | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 121 | 154 |
NoncurrentAssets | 295 | 299 |
DOMINICA | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues, Total | 44 | 44 |
NoncurrentAssets | CAD 64 | CAD 62 |
Investments Subject to Signif84
Investments Subject to Significant Influence and Equity Income (Equity Method) (Details) - CAD shares in Millions, CAD in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | May 24, 2016 | |
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 947 | CAD 1,145 | CAD 947 | CAD 1,145 | ||
Income (Loss) from Equity Method Investments | CAD 100 | 108 | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Indirect Ownership Percentage By Parent | 100.00% | 100.00% | ||||
Equity Method Investments | CAD 947 | 1,145 | CAD 947 | 1,145 | ||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 14 | 14 | ||||
Other Liabilities, Noncurrent | 467 | 299 | 467 | 299 | ||
Labrador-Island Link Limited Partnership [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 400 | 208 | 400 | 208 | ||
Income (Loss) from Equity Method Investments | CAD 24 | 9 | ||||
Equity Method Investment, Ownership Percentage | 62.70% | 62.70% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Indirect Ownership Percentage By Parent | 24.90% | 24.90% | ||||
Equity Method Investments | CAD 400 | 208 | CAD 400 | 208 | ||
NSP Maritime Link Inc. [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 315 | 188 | 315 | 188 | ||
Income (Loss) from Equity Method Investments | CAD 21 | 15 | ||||
Equity Method Investment, Ownership Percentage | 100.00% | 100.00% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Equity Method Investments | CAD 315 | 188 | CAD 315 | 188 | ||
Maritimes and Northeast Pipline [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 175 | 189 | 175 | 189 | ||
Income (Loss) from Equity Method Investments | CAD 23 | 23 | ||||
Equity Method Investment, Ownership Percentage | 12.90% | 12.90% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Equity Method Investments | CAD 175 | 189 | CAD 175 | 189 | ||
Saint Lucia Electricity Services Limited [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 39 | 39 | 39 | 39 | ||
Income (Loss) from Equity Method Investments | CAD 3 | 3 | ||||
Equity Method Investment, Ownership Percentage | 19.10% | 19.10% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Equity Method Investments | CAD 39 | 39 | CAD 39 | 39 | ||
Algonquin Power and Utilities Corporation [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 0 | 504 | 0 | 504 | ||
Income (Loss) from Equity Method Investments | CAD 18 | 37 | ||||
Equity Method Investment, Ownership Percentage | 0.00% | 0.00% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Indirect Ownership Percentage By Parent | 19.30% | |||||
Common Stock Sold Equity Method Investments | 50.1 | |||||
Gain (Loss) on Sale of Equity Investments | CAD (12) | CAD 172 | ||||
After Tax Gain Loss On Sale Of Equity Investments | (10) | CAD 146 | ||||
Subscription Receipts And Dividend Equivalents Exchanged For Common Shares | 12.9 | |||||
Equity Method Investments | 0 | 504 | CAD 0 | 504 | ||
Bear Swamp Power Company Limited Liability Company [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | CAD 0 | 0 | 0 | 0 | ||
Income (Loss) from Equity Method Investments | CAD 11 | 17 | ||||
Equity Method Investment, Ownership Percentage | 50.00% | 50.00% | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital | 179 | |||||
Equity Method Investments | CAD 0 | 0 | CAD 0 | 0 | ||
Other Liabilities, Noncurrent | 217 | 225 | 217 | 225 | ||
APUC Subscription Receipts Dividend Equivalents Common Shares [Member] | ||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Gain (Loss) on Sale of Equity Investments | CAD 63 | |||||
After Tax Gain Loss On Sale Of Equity Investments | CAD 53 | |||||
Other Investments | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Equity Method Investments | 18 | 17 | 18 | 17 | ||
Income (Loss) from Equity Method Investments | 0 | 4 | ||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||
Equity Method Investments | CAD 18 | CAD 17 | CAD 18 | CAD 17 |
Investments Subject to Signif85
Investments Subject to Significant Influence and Equity Income (Variable Interest Entity) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Consolidated Balance Sheets [Abstract] | |||
Assets, Current, Total | CAD 2,511 | CAD 2,596 | |
Property, Plant and Equipment, Net | 17,290 | 6,469 | |
Other Assets, Noncurrent, Total | 9,420 | 2,974 | |
Assets, Total | 29,221 | 12,039 | |
Liabilities, Current, Total | 3,724 | 1,367 | |
Liabilities, Noncurrent, Total | 18,681 | 6,338 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total | 6,816 | 4,334 | CAD 3,705 |
Liabilities and Equity, Total | 29,221 | 12,039 | |
NSPML [Member] | |||
Consolidated Balance Sheets [Abstract] | |||
Assets, Current, Total | 439 | 439 | |
Property, Plant and Equipment, Net | 1,132 | 648 | |
Other Assets, Noncurrent, Total | 276 | 554 | |
Assets, Total | 1,847 | 1,641 | |
Liabilities, Current, Total | 219 | 130 | |
Long-term Debt | 1,288 | 1,288 | |
Liabilities, Noncurrent, Total | 25 | 35 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Total | 315 | 188 | |
Liabilities and Equity, Total | CAD 1,847 | CAD 1,641 |
Other Income (Expenses), Net (D
Other Income (Expenses), Net (Details) CAD in Millions, $ in Millions | Jan. 25, 2015CAD | Jun. 30, 2016CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Jun. 30, 2016USD ($) |
Increase (Decrease) in Allowance for Equity Funds Used During Construction | CAD 22 | CAD 2 | |||
Foreign Currency Transaction Gain (Loss), before Tax | (43) | 27 | |||
Other | 11 | 1 | |||
Other Nonoperating Income (Expense) | 174 | 141 | |||
Algonquin Power and Utilities Corporation [Member] | |||||
Gain (Loss) on Investments | 160 | 0 | |||
Gain Loss On Conversion Of Subscription Receipts | 63 | 0 | |||
The Barbados Light and Power Company Limited [Member] | |||||
Gain (Loss) on Investments | CAD 53 | ||||
Increase (Decrease) in Self Insurance Reserve | 53 | 0 | |||
Self Insurance Reserve | 30 | $ 22 | |||
Gain (Loss) On Investments After Tax | CAD 43 | ||||
TECO Energy Inc [Member] | |||||
Foreign Currency Transaction Gain (Loss), before Tax | (135) | 119 | |||
Convertible Subordinated Debt | CAD 2,185 | ||||
Convertible debenture interest rate | 4.00% | ||||
Northeast Wind Partnership [Member] | |||||
Gain (Loss) on Investments | CAD 19 | CAD 0 | CAD 19 | ||
Equity Method Investment, Ownership Percentage | 49.00% | ||||
Gain (Loss) On Investments After Tax | CAD 12 |
Interest Expense, Net (Details)
Interest Expense, Net (Details) CAD in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2016CAD | Dec. 31, 2016CAD | Jun. 30, 2016CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | |
Debt Instrument [Line Items] | |||||
Interest on debt | CAD 443 | CAD 193 | |||
Beneficial Conversion Feature | (43) | 0 | |||
Allowance for Funds Used During Construction | (13) | (4) | |||
Interest Revenue | (2) | (6) | |||
Other | 19 | 6 | |||
Interest Expense (Income), Net | 585 | 212 | |||
Interest Expense, Long-term Debt, Additional Information [Abstract] | |||||
Amortization of Debt Discount (Premium) | CAD 62 | ||||
Amortization Of Debt Discount (Premium) After Tax | CAD 43 | ||||
Debt Instrument Convertible Converted Percent | 0.995 | ||||
Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest on debt | 11 | 0 | |||
Convertible Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest on debt | 65 | 23 | |||
Interest Expense, Long-term Debt, Additional Information [Abstract] | |||||
Beneficial conversion feature, Interest Expense | CAD 62 | CAD 62 | |||
Convertible Subordinated Debt | CAD 2,185 | ||||
Interest Expense, Junior Subordinated Debentures | CAD 21 |
Income Taxes (Effective Tax Rat
Income Taxes (Effective Tax Rate) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income before provision for income taxes | CAD 244 | CAD 545 |
Statutory income tax rate | 31.00% | 31.00% |
Income taxes, at statutory income tax rates | CAD 76 | CAD 169 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (47) | (31) |
Financing deductions | 17 | 10 |
Manufacturing And Investment Allowances | (7) | (5) |
Foreign tax rate variance | (5) | 2 |
Tax effect of equity earnings | (10) | (11) |
Other | 1 | (3) |
Income Tax Expense (Benefit), Total | CAD (22) | CAD 93 |
Effective Income Tax Rate Reconciliation, Percent | (9.00%) | 17.00% |
TECO Energy Inc [Member] | ||
Non-taxable portion of mark-to-market gains related to pending TECO Energy acquisition | CAD 21 | CAD (18) |
Algonquin Power and Utilities Corporation [Member] | ||
Non-taxable portion of gains on transactions | CAD (34) | CAD 0 |
Income Taxes (Components) (Deta
Income Taxes (Components) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | CAD (67) | CAD 20 |
Income tax expense (recovery) | (22) | 93 |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 244 | 545 |
Income taxes, at statutory income tax rates | 76 | 169 |
Canada [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 13 | 42 |
Deferred income taxes | (113) | 11 |
Operating loss carry forwards | (2) | (4) |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 71 | 349 |
United States [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 18 | 26 |
Deferred income taxes | 151 | 14 |
Operating loss carry forwards | (104) | 0 |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | 44 | 137 |
Other [Member] | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 15 | 5 |
Deferred income taxes | 0 | (1) |
Supplemental Tax Information [Abstract] | ||
Income before provision for income taxes | CAD 129 | CAD 59 |
Income Taxes (Deferred) (Detail
Income Taxes (Deferred) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Components of Deferred Tax Assets [Abstract] | ||
Deferred Tax Assets, Tax Loss Carry Forwards | CAD 1,036 | CAD 72 |
Tax credit carry forwards | 318 | 7 |
Regulatory liabilities - cost of removal | 388 | 42 |
Deferred Tax Assets, Derivative Instruments | 173 | 204 |
Pension and post-retirement liabilities | 147 | 129 |
Regulatory liabilities | 101 | 94 |
Asset retirement obligations | 47 | 47 |
Deferred Tax Assets, Goodwill and Intangible Assets | 0 | 0 |
Deferred Tax Assets, Other | 355 | 136 |
Deferred Tax Assets, Gross, Total | 2,565 | 731 |
Deferred Tax Assets, Valuation Allowance | (58) | (18) |
Deferred Tax Assets, Net of Valuation Allowance, Total | 2,507 | 713 |
Components of Deferred Tax Liabilities [Abstract] | ||
Deferred Tax Liabilities, Property, Plant and Equipment | (3,625) | (960) |
Deferred Tax Liabilities, Derivatives | (202) | (264) |
Deferred Tax Liabilities, Leasing Arrangements | (103) | (89) |
Deferred Tax Liabilities, Other | (124) | (130) |
Deferred Tax Liabilities, Gross, Total | (4,054) | (1,443) |
Noncurrent Deferred Tax Liabilities And Assets [Abstract] | ||
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent | 125 | 32 |
Deferred Tax Liabilities, Net, Noncurrent | (1,672) | (762) |
Deferred Tax Assets (Liabilities), Net, Noncurrent, Total | CAD (1,547) | CAD (730) |
Income Taxes (Carry Overs) (Det
Income Taxes (Carry Overs) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Tax Credit Carryforwards | CAD 318 | CAD 7 |
Tax Loss Carry Forwards Valuation Allowance [Abstract] | ||
Deferred Tax Assets, Valuation Allowance | 58 | 18 |
Loss carry forwards and investments [Member] | ||
Tax Loss Carry Forwards Valuation Allowance [Abstract] | ||
Deferred Tax Assets, Valuation Allowance | 58 | 18 |
Domestic Tax Authority [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | 199 | 103 |
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 | 84 |
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 | 61 | |
Valuation Allowance | (27) | |
Net Deferred Tax Assets | CAD 34 | |
Domestic Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,036 | |
Domestic Tax Authority [Member] | Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,026 | |
Foreign Tax Authority [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | CAD 2,595 | 48 |
Deferred Tax Assets, Tax Credit Carryforwards | 318 | 30 |
Foreign Tax Authority [Member] | Capital Loss Carryforward [Member] | ||
Tax Loss Carry Forwards [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards | 14 | 4 |
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 3 | |
Valuation Allowance | (3) | |
Net Deferred Tax Assets | CAD 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 | CAD 908 | |
Valuation Allowance | 0 | |
Net Deferred Tax Assets | CAD 908 | |
Foreign Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,036 | |
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 | CAD 1,183 | 225 |
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 45 | |
Valuation Allowance | (1) | |
Net Deferred Tax Assets | CAD 44 | |
Foreign Tax Authority [Member] | State Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,036 | |
Foreign Tax Authority [Member] | State Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,017 | |
Foreign Tax Authority [Member] | Tax credit carry forwards [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | CAD 318 | |
Valuation Allowance | 0 | |
Net Deferred Tax Assets | CAD 318 | |
Foreign Tax Authority [Member] | Tax credit carry forwards [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,036 | |
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 | CAD 22 | CAD 14 |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Assets Uncertain Realization | 3 | |
Valuation Allowance | (3) | |
Net Deferred Tax Assets | CAD 0 | |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | Maximum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,023 | |
Other Tax Authority [Member] | Operating Loss Carryforward [Member] | Minimum [Member] | ||
Deferred Tax Assets Uncertain Realization [Abstract] | ||
Deferred Tax Asset Expiration Period | 2,017 |
Income Taxes (Unrecognized Bene
Income Taxes (Unrecognized Benefits) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning, January 1 | CAD 6 | CAD 5 |
Increases due to tax positions related to current year | 12 | 0 |
Increases due to tax positions related to a prior year | 0 | 1 |
Decreases due to tax positions related to a prior year | 0 | 0 |
Decreases due to expiration of statute of limitations | 0 | 0 |
Balance, December 31 | CAD 18 | CAD 6 |
Income Taxes (Reasonable Probab
Income Taxes (Reasonable Probablity of Tax Benefit) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract] | ||
Accrued interest | CAD 1 | CAD 1 |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Temporary Differences/Potential change | 667 | CAD 669 |
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 | CAD 23 |
Common Stock (Common Stock Roll
Common Stock (Common Stock Rollfoward) (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) In Common Stock Shares [Roll Forward] | ||
Balance, January 1 | 147,210,000 | 143,780,000 |
Conversion of Convertible Debentures | 51,990,000 | 0 |
Issued for cash under Purchase Plans at market rate | 2,510,000 | 2,100,000 |
Discount on shares purchased under Dividend Reinvestment Plan | 0 | 0 |
Options exercised under senior management share option plan | 620,000 | 80,000 |
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period | 0 | 0 |
Balance, December 31 | 210,020,000 | 147,210,000 |
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Common Stock, Value, Issued, Beginning Balance | CAD 2,157,000 | CAD 2,016,000 |
Conversion of Convertible Debentures | 2,115,000 | 0 |
Issued for cash under Purchase Plans at market rate | 115,000 | 88,000 |
Discount on shares purchased under Dividend Reinvestment Plan Value | (5,000) | (4,000) |
Options exercised under senior management share option plan | 17,000 | 2,000 |
Stock-based compensation | 1,000 | 1,000 |
Common Stock, Value, Issued, Ending Balance | CAD 4,738,000 | CAD 2,157,000 |
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 | (622,168) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 1,500,000 | 1,600,000 |
Stock Compensation Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 6,600,000 | 7,300,000 |
Dividend Reinvestment [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 7,900,000 | 3,300,000 |
Common Stock (Narrative) (Detai
Common Stock (Narrative) (Details) CAD / shares in Units, shares in Thousands, CAD in Millions | Aug. 02, 2016CADCAD / shares | Sep. 28, 2015CADCAD / shares | Dec. 31, 2016CADNumberOfDaysshares | Dec. 31, 2015CAD | Jun. 30, 2016CAD | Oct. 02, 2015CAD |
Debt Instrument [Line Items] | ||||||
Interest Expense, Debt | CAD 443 | CAD 193 | ||||
Emera Inc | Convertible Subordinated Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Convertible, Conversion Per Share | CAD / shares | CAD 1,000 | |||||
Debt Instrument, Maturity Date | Sep. 29, 2025 | |||||
Convertible debenture interest rate | 0.00% | |||||
Debt Instrument, Convertible, Conversion Ratio | 23.8949 | 0.996 | ||||
Interest Expense, Debt | CAD 65 | |||||
Interest Expense Debt After Tax | CAD 45 | |||||
Debt Instrument, Periodic Payment Terms, Balloon Payment to be Paid | CAD 21 | |||||
Debt Instrument Periodic Payment Terms Balloon Payment To Be Paid After Tax | CAD 14 | |||||
Common Stock, Shares, Issued | shares | 51,990 | |||||
Common Stock, Conversion Rate | 95.00% | |||||
Debt Instrument, Convertible, Threshold Trading Days | NumberOfDays | 20 | |||||
TECO Energy Inc [Member] | Emera Inc | Convertible Subordinated Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | CAD 1,900 | |||||
Debt Instrument, Convertible, Conversion Percent | 4.00% | |||||
Debt Instrument, Face Amount, Additional Amount | CAD 285 | |||||
Aggregate proceeds of the Debenture Offering | CAD 2,185 | |||||
Debt Instrument, Convertible, Conversion Per Share | CAD / shares | CAD 1,000 | |||||
Debt Instrument, Convertible, Conversion Per Share, First Installment | CAD / shares | CAD 333 | |||||
Debt Instrument, Convertible, Conversion Per Share, Final Installment | CAD / shares | CAD 667 | |||||
Proceeds from Convertible Debt First Installment | CAD 727.6 | |||||
Proceeds from Convertible Debt Net of Issuance Costs, First Installment | CAD 1,413 | CAD 681.4 | ||||
Proceeds from Convertible Debt , Final Installment | CAD 1,457 | |||||
Debt Instrument, Convertible, Conversion Price | CAD / shares | CAD 41.85 |
Earnings Per Share (Reconciliat
Earnings Per Share (Reconciliation of Basic and Diluted Earnings Per Share) (Details) - CAD CAD / shares in Units, shares in Thousands, CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Earnings Per Share Reconciliation [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | CAD 227.2 | CAD 397.2 |
Interest on Convertible Debt, Net of Tax | 0.2 | 0 |
Net Income (Loss) Available to Common Stockholders, Diluted, Total | CAD 227.4 | CAD 397.2 |
Weighted Average Number of Shares Outstanding Reconciliation [Abstract] | ||
Weighted Average Number of Shares Issued, Basic | 170,400 | 144,900 |
Weighted Average Number of Shares deferred share units outstanding | 1,000 | 900 |
Weighted Average Number of Shares Outstanding, Basic, Total | 171,400 | 145,800 |
Incremental Weighted Average Shares Attributable to Dilutive Effect [Abstract] | ||
IncrementalCommonSharesAttributableToShareBasedPaymentArrangements | 600 | 600 |
Incremental Common Shares Attributable to Dilutive Effect of Dividend Reinvesatment Program | 0 | 0 |
IncrementalCommonSharesAttributableToConversionOfDebtSecurities | 200 | 0 |
Weighted Average Number of Shares Outstanding, Diluted, Total | 172,200 | 146,400 |
Basic | CAD 1.33 | CAD 2.72 |
Diluted | CAD 1.32 | CAD 2.71 |
Earnings Per Share, Additional Infomration [Abstract] | ||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 0 | 0 |
Accumulated Other Comprehensi97
Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | CAD 137 | CAD (348) |
Other comprehensive income (loss) before reclassifications | 0 | 371 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 19 | (114) |
Other equity method reclassification adjustment | (46) | 0 |
Net current period other comprehensive income (loss) | (27) | 485 |
Other | (4) | 0 |
Ending Balance | 106 | 137 |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (35) | (8) |
Other comprehensive income (loss) before reclassifications | 11 | (34) |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 11 | (7) |
Other equity method reclassification adjustment | (8) | |
Net current period other comprehensive income (loss) | 14 | (27) |
Other | 0 | 0 |
Ending Balance | (21) | (35) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (318) | (425) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 12 | (107) |
Other equity method reclassification adjustment | (3) | |
Net current period other comprehensive income (loss) | 9 | 107 |
Other | 0 | 0 |
Ending Balance | (309) | (318) |
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 0 | 0 |
Other comprehensive income (loss) before reclassifications | (49) | 0 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 0 | 0 |
Other equity method reclassification adjustment | 0 | |
Net current period other comprehensive income (loss) | (49) | 0 |
Other | 0 | 0 |
Ending Balance | (49) | 0 |
Accumulated Net Available For Sale Securities Gain (Loss) [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 0 | 3 |
Other comprehensive income (loss) before reclassifications | 3 | (3) |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | (4) | 0 |
Other equity method reclassification adjustment | 0 | |
Net current period other comprehensive income (loss) | (1) | (3) |
Other | 0 | 0 |
Ending Balance | (1) | 0 |
Accumulated Foreign Currency Adjustment Attributable to Parent [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 490 | 82 |
Other comprehensive income (loss) before reclassifications | 35 | 408 |
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | 0 | 0 |
Other equity method reclassification adjustment | (35) | |
Net current period other comprehensive income (loss) | 0 | 408 |
Other | (4) | 0 |
Ending Balance | CAD 486 | CAD 490 |
Accumulated Other Comprehensi98
Accumulated Other Comprehensive Income (Reclassifications Out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Non-regulated fuel for generation and purchased power | CAD 313 | CAD 336 |
Income (Loss) from Equity Method Investments | 100 | 108 |
Operating, maintenance and general | 1,137 | 666 |
Other Income (Expense) | 174 | 141 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 244 | 545 |
Income tax expense (recovery) | (22) | 93 |
Net income | 266 | 452 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Net income | 65 | 114 |
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 | 11 | 5 |
Income tax expense (recovery) | 0 | 2 |
Net income | 11 | 7 |
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 | (2) | (5) |
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 | 1 | 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 | 12 | 9 |
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 | 15 | 115 |
Income tax expense (recovery) | (3) | (8) |
Net income | 12 | 107 |
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 | 41 | 50 |
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 | (9) | (7) |
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 | (17) | 72 |
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) | (4) | 0 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | (4) | 0 |
Income tax expense (recovery) | 0 | 0 |
Net income | (4) | 0 |
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 | 54 | 0 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 54 | 0 |
Income tax expense (recovery) | (8) | 0 |
Net income | CAD 46 | CAD 0 |
Receivables, Net (Details)
Receivables, Net (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customer accounts receivable | CAD 985 | CAD 550 |
Allowance for Doubtful Accounts | (13) | (12) |
Customer accounts receivable, net | 972 | 538 |
Other | 42 | 40 |
Receivables, Net | 1,014 | 578 |
Billed [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customer accounts receivable | 715 | 406 |
Unbilled [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customer accounts receivable | CAD 270 | CAD 144 |
Inventory (Details)
Inventory (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Inventory [Abstract] | ||
Fuel | CAD 235 | CAD 185 |
Raw Materials | 215 | 100 |
Emission Credits | 22 | 29 |
Inventory, Net, Total | CAD 472 | CAD 314 |
Derivatives (Derivative Assets
Derivatives (Derivative Assets and Liabilities) (Details) - Designated as Hedging Instrument [Member] - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | CAD (131) | CAD (240) |
Derivative Asset, Total | 276 | 418 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (131) | (240) |
Derivative Liability, Total | 475 | 445 |
Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 250 | 439 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (105) | (189) |
Derivative Asset, Total | 145 | 250 |
Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 157 | 219 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (26) | (51) |
Derivative Asset, Total | 131 | 168 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 176 | 147.3 |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (26) | (51.3) |
Derivative Liability, Total | 150 | 96 |
Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 430 | 538 |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (105) | (189) |
Derivative Liability, Total | 325 | 349 |
Cash Flow Hedging [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 8 |
Cash Flow Hedging [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 12 |
Cash Flow Hedging [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 14 | 15 |
Cash Flow Hedging [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 13 | 31.3 |
Cash Flow Hedging [Member] | Power swaps [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 8 |
Cash Flow Hedging [Member] | Power swaps [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 2 | 1 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 12 | 14 |
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 10 | 27.2 |
Cash Flow Hedging [Member] | Power swaps and physical contracts [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 12 |
Cash Flow Hedging [Member] | Power swaps and physical contracts [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 4.1 |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Regulatory Deferral Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (10) | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (10) | 0 |
Regulatory Deferral Hedge [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 119 | 89 |
Regulatory Deferral Hedge [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 120 | 121 |
Regulatory Deferral Hedge [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 14 | 43 |
Regulatory Deferral Hedge [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 8 | 21 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 56 | 85 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 50 | 121 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 10 |
Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 26 | 0 |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 57 | 0 |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 9 | 12 |
Regulatory Deferral Hedge [Member] | Derivative instrument whose primary underlying risk is tied to commodity prices for coal purchases. | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 4.4 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 28 | 2 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 0 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 1 |
Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 2 | 0 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 6 | 0 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 4 | 0 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 4 | 20 |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 16.6 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 2 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Held for Trading Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (121) | (240) |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | (121) | (240) |
Held for Trading Hedge [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 126 | 250 |
Held for Trading Hedge [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 32 | 86 |
Held for Trading Hedge [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 401 | 480 |
Held for Trading Hedge [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 154 | 92 |
Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 1 |
Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 2 |
Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 1 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 33 | 151 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 14 | 13 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 44 | 119 |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 27 | 28 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 93 | 99 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 18 | 72 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 357 | 359 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 127 | 63 |
Other Derivatives Hedge [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 92 |
Other Derivatives Hedge [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Other Derivatives Hedge [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1 | 0 |
Other Derivatives Hedge [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1 | 3 |
Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | Current Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 92 |
Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | Current Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1 | 0 |
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | Noncurrent Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | Noncurrent Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | CAD 1 | CAD 3 |
Derivatives (Master Netting Agr
Derivatives (Master Netting Agreements) (Details) - Designated as Hedging Instrument [Member] - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | CAD 131 | CAD 240 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 131 | 240 |
Regulatory Deferral Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 10 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 10 | 0 |
Held for Trading Hedge [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 121 | 240 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract] | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | CAD 121 | CAD 240 |
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, CAD in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2016EUR (€) | Dec. 31, 2016USD ($) | |
Cash Flow Hedging [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | CAD 14 | |||||
Cash Flow Hedging [Member] | Power swaps [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | 2 | CAD 5 | ||||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | 2 | 4 | ||||
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 | 2 | 5 | ||||
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 | (1) | (1) | ||||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | 0 | (1) | ||||
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 | (1) | (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 | (12) | (9) | ||||
Unrealized Gain (Loss) on Cash Flow Hedging Instruments, Effective Portion | (22) | (42) | ||||
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 | (12) | (9) | ||||
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 | CAD 0 | CAD 0 | ||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2017 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | $ | $ 53 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2018 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | $ | 45 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2019 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | $ | 30 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Sales [Member] | 2020 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | $ | $ 30 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Cost of Sales [Member] | 2017 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | € | € 3 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Cost of Sales [Member] | 2018 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | € | 0 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Cost of Sales [Member] | 2019 | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Notional Amount | € | 0 | |||||
Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | Cost of Sales [Member] | 2020 | ||||||
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 | $ (3) | ||||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Operating Income (Expense) [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | $ | $ 0 | $ 0 |
Derivatives (Changes in Realize
Derivatives (Changes in Realized and Unrealized Gains (Losses) with Respect to Derivatives Receiving Regulatory Deferral) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized Gain (Loss) on Derivatives | CAD (258) | CAD (96) |
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 | 163 | (30) |
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 | 40 | (24) |
Derivative, Gain (Loss) on Derivative, Net | 0 | (3) |
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 | 101 | 1 |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Commodity swaps and forwards [Member] | Property, Plant and Equipment [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | 0 | 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 | 5 | 12 |
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 | 17 | (16) |
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 | (2) | 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 | 0 | 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) | 9 |
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Property, Plant and Equipment [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] | 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 | (1) | (7) |
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 | (90) | 103 |
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 | (2) | (7) |
Derivative, Gain (Loss) on Derivative, Net | 12 | 0 |
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) | 173 |
Derivative, Gain (Loss) on Derivative, Net | (8) | 0 |
Designated as Hedging Instrument [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | Property, Plant and Equipment [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] | Inventory [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Gain (Loss) on Derivative, Net | (44) | (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 | CAD (18) | CAD (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, 2016MMBTUTbbl | |
Coal [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Mass | T | 0 |
Coal [Member] | 2017 to 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Mass | T | 2 |
Fuel [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 42 |
Fuel [Member] | 2017 to 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 24 |
CrudeOilMember | 2017 | |
Derivative [Line Items] | |
DerivativeNonmonetaryNotionalAmountVolume | bbl | 0 |
CrudeOilMember | 2017 to 2020 | |
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, 2016USD ($) |
2,017 | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 224 |
Derivative, Average Forward Exchange Rate | 1.0722 |
Derivative, Percent of USD Required to Purchase | 120.00% |
2017 to 2020 | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 240 |
Derivative, Average Forward Exchange Rate | 1.1138 |
Derivative, Percent of USD Required to Purchase | 44.00% |
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 CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Gain (Loss) on Derivative Instruments Held for Trading Purposes, Net | CAD 59 | CAD 11 |
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 | 0 | 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 | (1) | 10 |
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 | (7) | (3) |
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 | 69 | 5 |
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 | CAD (1) | CAD (2) |
Derivatives (Notional Volume108
Derivatives (Notional Volumes of Outstanding HFT Derivatives) (Details) - Designated as Hedging Instrument [Member] - Held for Trading Hedge [Member] MWh in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2016MMBTUMWh | |
Natural Gas [Member] | Sales [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 202 |
Natural Gas [Member] | Sales [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 20 |
Natural Gas [Member] | Sales [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 16 |
Natural Gas [Member] | Sales [Member] | 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 12 |
Natural Gas [Member] | Sales [Member] | 2021 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 1 |
Natural Gas [Member] | Cost of Sales [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 270 |
Natural Gas [Member] | Cost of Sales [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 69 |
Natural Gas [Member] | Cost of Sales [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 54 |
Natural Gas [Member] | Cost of Sales [Member] | 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 45 |
Natural Gas [Member] | Cost of Sales [Member] | 2021 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 45 |
Power [Member] | Sales [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 4 |
Power [Member] | Sales [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Sales [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Sales [Member] | 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Sales [Member] | 2021 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Cost of Sales [Member] | 2017 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 3 |
Power [Member] | Cost of Sales [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Cost of Sales [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Cost of Sales [Member] | 2020 | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | 0 |
Power [Member] | Cost of Sales [Member] | 2021 | |
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) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Gain (Loss) on Derivatives | CAD | CAD (258) | CAD (96) | ||
Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | Line of Credit [Member] | Brunswick Pipeline [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Convertible Subordinated Debt | CAD | CAD 250 | |||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 2 | $ (3) | ||
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 | ||
Derivative, Gain (Loss) on Derivative, Net | 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 | (3) | ||
Designated as Hedging Instrument [Member] | Foreign Exchange Option [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ (87) | 92 | ||
Designated as Hedging Instrument [Member] | Foreign Exchange Option [Member] | TECO Energy Inc [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Line of Credit Facility, Expiration Date | Dec. 31, 2019 | Dec. 31, 2019 | ||
Derivative, Notional Amount | CAD | CAD 1,519 | |||
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 | $ (87) | 0 | ||
Derivative, Gain (Loss) on Derivative, Net | 0 | 92 | ||
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 CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Credit Derivatives [Line Items] | ||
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure | CAD 1,290 | CAD 996 |
Total cash deposits/collateral on hand | 107 | 91 |
Accounts Receivable [Member] | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure | 1,019 | 901 |
Total cash deposits/collateral on hand | 271 | 94 |
Financial assets, considered to be past due | CAD 104 | 83 |
Derivative, Credit Risk, Past Due Days Outstanding | 69 days | |
Fair Value of assets | CAD 91 | CAD 72 |
Derivatives (Concentration Risk
Derivatives (Concentration Risk) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 100.00% | 100.00% |
Concentration Risk | CAD 1,290 | CAD 996 |
Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 78.00% | 58.00% |
Concentration Risk | CAD 592 | CAD 374 |
Accounts Receivable [Member] | A- Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 4.00% | 3.00% |
Concentration Risk | CAD 52 | CAD 31 |
Accounts Receivable [Member] | BBB- to BBB+ Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 5.00% | 2.00% |
Concentration Risk | CAD 60 | CAD 22 |
Accounts Receivable [Member] | Not Rated [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 4.00% | 3.00% |
Concentration Risk | CAD 57 | CAD 31 |
Accounts Receivable, Residential [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 24.00% | 20.00% |
Concentration Risk | CAD 315 | CAD 189 |
Accounts Receivable, Commercial [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 13.00% | 10.00% |
Concentration Risk | CAD 170 | CAD 103 |
Accounts Receivable, Industrial [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 3.00% | 3.00% |
Concentration Risk | CAD 38 | CAD 29 |
Accounts Receivable, Other [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 5.00% | 5.00% |
Concentration Risk | CAD 69 | CAD 53 |
Regulated utilities [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 45.00% | 38.00% |
Concentration Risk | CAD 592 | CAD 374 |
Trading group [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 13.00% | 8.00% |
Concentration Risk | CAD 169 | CAD 84 |
Other Accounts Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 20.00% | 12.00% |
Concentration Risk | CAD 253 | CAD 120 |
Derivative [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 22.00% | 42.00% |
Concentration Risk | CAD 276 | CAD 418 |
Derivative [Member] | A- Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 20.00% | 34.00% |
Concentration Risk | CAD 252 | CAD 340 |
Derivative [Member] | BBB- to BBB+ Rating [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 0.00% | 7.00% |
Concentration Risk | CAD 1 | CAD 70 |
Derivative [Member] | Not Rated [Member] | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 2.00% | 1.00% |
Concentration Risk | CAD 23 | CAD 8 |
Derivatives (Cash Collateral) (
Derivatives (Cash Collateral) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Instruments [Abstract] | ||
Derivative, Collateral, Obligation to Return Cash | CAD 107 | CAD 91 |
Derivative, Collateral, Right to Reclaim Cash | 29 | 52 |
Collateral Already Posted, Aggregate Fair Value | CAD 475 | CAD 445 |
Fair Values (Fair Value - Deriv
Fair Values (Fair Value - Derivatives) (Details) - Designated as Hedging Instrument [Member] - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | CAD 276 | CAD 418 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 475 | 445 |
Fair Value, Measurements, Recurring [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 276 | 418 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 475 | 445 |
Fair Value, Net Asset (Liability), Total | (199) | (27) |
Fair Value, Measurements, Recurring [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 10 | 20 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 27 | 46 |
Fair Value, Measurements, Recurring [Member] | Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 10 | 20 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 4 | 5 |
Fair Value, Measurements, Recurring [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 23 | 41 |
Fair Value, Measurements, Recurring [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 229 | 210 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 12 | 64 |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 106 | 207 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 10 |
Fair Value, Measurements, Recurring [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 | 74 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 16 |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 33 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | 1 |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 9 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 37 |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 2 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Regulatory Deferral Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 37 | 96 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 434 | 332 |
Fair Value, Measurements, Recurring [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | (6) | 31 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 13 | |
Fair Value, Measurements, Recurring [Member] | Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 4 |
Fair Value, Measurements, Recurring [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 17 | |
Fair Value, Measurements, Recurring [Member] | Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 43 | 65 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 417 | 315 |
Fair Value, Measurements, Recurring [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 92 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 3 |
Fair Value, Measurements, Recurring [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Measurements, Recurring [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 92 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | 3 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 21 | 58 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 25 | 35 |
Fair Value, Net Asset (Liability), Total | (4) | 23 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 10 | 20 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 4 | 5 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 10 | 20 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 4 | 5 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 18 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 5 | 1 |
Fair Value, Measurements, Recurring [Member] | 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 | 0 |
Fair Value, Measurements, Recurring [Member] | 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 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 8 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 1 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 3 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Regulatory Deferral Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | (7) | 38 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 16 | 29 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | (7) | 38 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 15 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 12 | |
Fair Value, Measurements, Recurring [Member] | 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 | 4 | 14 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 215 | 309 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 61 | 133 |
Fair Value, Net Asset (Liability), Total | 154 | 176 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 23 | 41 |
Fair Value, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 23 | 41 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 210 | 208 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 7 | 63 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 106 | 207 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 10 |
Fair Value, Measurements, Recurring [Member] | 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 | 74 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 16 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 25 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 6 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | 37 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Regulatory Deferral Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 5 | 9 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 29 | 26 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 1 | 1 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 4 |
Fair Value, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | 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 | 4 | 8 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 24 | 22 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 92 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 2 | 3 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 92 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 1 | 3 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 40 | 51 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 389 | 277 |
Fair Value, Net Asset (Liability), Total | (349) | (226) |
Fair Value, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Cash Flow Hedging [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 1 | 2 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | 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 | 0 |
Fair Value, Measurements, Recurring [Member] | 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 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | 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 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 1 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 2 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Regulatory Deferral Hedge [Member] | Interest Rate Swap [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 39 | 49 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 389 | 277 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Power swaps [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | (8) |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | (2) | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | 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 | 39 | 57 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 389 | 279 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | Foreign Exchange Forward [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Derivatives Hedge [Member] | Interest Rate Swap [Member] | ||
Assets, Fair Value Disclosure [Abstract] | ||
Derivative Asset | 0 | |
Liabilities, Fair Value Disclosure [Abstract] | ||
Derivative Liability | CAD 0 | CAD 0 |
Fair Values (fair value of the
Fair Values (fair value of the Level 3 financial assets) (Details) - Designated as Hedging Instrument [Member] CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | CAD 51 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (10) |
Net transfers out of Level 3 | 2 |
Ending Balance | 40 |
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) |
Non-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 | 0 |
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 | 2 |
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 | 2 |
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] | Non-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 | 0 |
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 | 0 |
Net transfers out of Level 3 | 2 |
Ending Balance | 1 |
Regulatory Deferral Hedge [Member] | Oil Financial Derivatives [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 | 3 |
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 | 57 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (18) |
Net transfers out of Level 3 | 0 |
Ending Balance | 39 |
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] | Non-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 | (8) |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 8 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
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] | Non-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 | CAD 0 |
Fair Values (fair value of t115
Fair Values (fair value of the Level 3 financial Liabilities) (Details) - Designated as Hedging Instrument [Member] CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | CAD 277 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 112 |
Net transfers out of Level 3 | 0 |
Ending Balance | 389 |
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 |
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 |
Regulatory Liabilities [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities 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, 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 | 0 |
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 | 0 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Regulatory Liabilities [Member] | |
Fair Value, Liabilities 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] | Natural Gas [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 279 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 110 |
Net transfers out of Level 3 | 0 |
Ending Balance | 389 |
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] | Natural Gas [Member] | Regulatory Liabilities [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities 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, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | (2) |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 2 |
Net transfers out of Level 3 | 0 |
Ending Balance | 0 |
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 |
Cash Flow Hedging And Held for Trading Hedge [Member] | Power [Member] | Regulatory Liabilities [Member] | Derivative Financial Instruments, Liabilities [Member] | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Unrealized gains (losses) included in regulatory assets or liabilities | CAD 0 |
Fair Values (Quantitative Infor
Fair Values (Quantitative Information Significant Unobservable Inputs - Assets & Liabilities) (Details) - Designated as Hedging Instrument [Member] - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 40 | CAD 51 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | 389 | 277 |
Derivative Assets (Liabilities), at Fair Value, Net, Total | (349) | (226) |
Held for Trading Hedge [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | 54 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | 0 | |
Held for Trading Hedge [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | CAD 3 | |
Held for Trading Hedge [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 3 | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.25 | |
Fair Value Inputs, Comparability Adjustments | (0.06%) | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 15.74 | |
Fair Value Inputs, Comparability Adjustments | 0.95% | |
Fair Value Inputs, Probability of Default | 0.09% | |
Fair Value Inputs, Discount Rate | 0.08% | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 6.19 | |
Fair Value Inputs, Comparability Adjustments | 0.68% | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.83 | CAD 46.45 |
Fair Value Inputs, Comparability Adjustments | (0.11%) | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Entity Credit Risk | 0.06% | |
Fair Value Inputs, Discount Rate | 0.00% | 0.00% |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 11.87 | CAD 103.27 |
Fair Value Inputs, Comparability Adjustments | 0.64% | |
Fair Value Inputs, Probability of Default | 0.05% | |
Fair Value Inputs, Entity Credit Risk | 0.06% | |
Fair Value Inputs, Discount Rate | 0.10% | 4.15% |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 5.93 | CAD 70.69 |
Fair Value Inputs, Comparability Adjustments | 0.27% | |
Fair Value Inputs, Probability of Default | 0.01% | |
Fair Value Inputs, Entity Credit Risk | 0.06% | |
Fair Value Inputs, Discount Rate | 0.01% | 0.47% |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.13 | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 9.12 | |
Fair Value Inputs, Probability of Default | 0.10% | |
Fair Value Inputs, Discount Rate | 0.33% | |
Held for Trading Hedge [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 3.26 | |
Fair Value Inputs, Probability of Default | 0.01% | |
Fair Value Inputs, Discount Rate | 0.04% | |
Held for Trading Hedge [Member] | Physical natural gas purchases and sales [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 12 | |
Held for Trading Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Probability of Default | 0.01% | |
Held for Trading Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.83 | CAD 5.15 |
Fair Value Inputs, Comparability Adjustments | (0.11%) | |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 11.87 | 6.21 |
Fair Value Inputs, Comparability Adjustments | 0.64% | |
Fair Value Inputs, Probability of Default | 0.05% | |
Fair Value Inputs, Discount Rate | 0.10% | |
Held for Trading Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 6.16 | CAD 5.72 |
Fair Value Inputs, Comparability Adjustments | 0.39% | |
Fair Value Inputs, Probability of Default | 0.00% | 0.01% |
Fair Value Inputs, Discount Rate | 0.00% | |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 0 | CAD (8) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | CAD 0 | CAD (2) |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 19.7 | CAD 26.27 |
Fair Value Inputs, Correlation factor | 0.98% | |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.09% | 0.00% |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 76.94 | CAD 129.2 |
Fair Value Inputs, Correlation factor | 1.00% | |
Fair Value Inputs, Entity Credit Risk | 0.02% | 0.02% |
Fair Value Inputs, Discount Rate | 0.02% | 0.15% |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 33.48 | CAD 70.82 |
Fair Value Inputs, Correlation factor | 0.99% | |
Fair Value Inputs, Entity Credit Risk | 0.01% | 0.00% |
Fair Value Inputs, Discount Rate | 0.03% | 0.01% |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 19.7 | CAD 26.27 |
Fair Value Inputs, Correlation factor | 0.98% | |
Fair Value Inputs, Probability of Default | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.02% | 0.00% |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 76.94 | CAD 129.2 |
Fair Value Inputs, Correlation factor | 1.00% | |
Fair Value Inputs, Probability of Default | 0.01% | 0.02% |
Fair Value Inputs, Discount Rate | 0.09% | 0.15% |
Held for Trading Hedge [Member] | Power swaps and physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 33.37 | CAD 70.45 |
Fair Value Inputs, Correlation factor | 0.99% | |
Fair Value Inputs, Probability of Default | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.03% | 0.01% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 27 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | CAD 386 | CAD 279 |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Entity Credit Risk | 0.00% | |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.55 | CAD 0.74 |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Entity Credit Risk | 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] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 11.87 | CAD 10.59 |
Fair Value Inputs, Probability of Default | 0.03% | |
Fair Value Inputs, Entity Credit Risk | 0.70% | |
Fair Value Inputs, Discount Rate | 0.14% | 0.07% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 6.26 | CAD 5.58 |
Fair Value Inputs, Probability of Default | 0.00% | |
Fair Value Inputs, Entity Credit Risk | 0.00% | 0.00% |
Fair Value Inputs, Discount Rate | 0.02% | 0.01% |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 1.41 | |
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] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 11.87 | |
Fair Value Inputs, Probability of Default | 7.00% | |
Fair Value Inputs, Discount Rate | 0.32% | |
Held for Trading Hedge [Member] | Natural gas swaps, futures, forwards, physical contracts [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 3.87 | CAD 5.56 |
Fair Value Inputs, Probability of Default | 0.01% | 0.46% |
Fair Value Inputs, Discount Rate | 0.05% | 5.28% |
Regulatory Deferral Hedge [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | CAD 0 | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | 1 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | CAD 0 | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Probability of Default | 0.80% | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 0 | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | 69.64 | |
Regulatory Deferral Hedge [Member] | Heavy fuel oil purchases [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 69.64 | |
Fair Value Inputs, Probability of Default | 0.80% | |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 0 | CAD 2 |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Probability of Default | 0.01% | |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 4.75 | |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | 4.94 | |
Regulatory Deferral Hedge [Member] | Physical natural gas purchases and sales [Member] | Market Approach Valuation Technique [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member] | Weighted Average [Member] | ||
Fair Value Inputs [Abstract] | ||
Fair Value Inputs, Offered Quotes | CAD 4.87 | |
Fair Value Inputs, Probability of Default | 0.01% | |
Cash Flow Hedging [Member] | Power swaps and physical contracts [Member] | ||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | CAD 0 |
Fair Values (Assets and Liabili
Fair Values (Assets and Liabilities Not Measured at Fair Value ) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value Measurement [Domain] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | CAD 15,723 | CAD 4,487.3 |
Reported Value Measurement [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 14,744 | 4,009 |
Long-term Debt, Fair Value | 15,723 | 4,486.7 |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 78 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 14,843 | 3,841.3 |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | CAD 802 | CAD 646 |
Fair Values (Hybrid Notes) (Det
Fair Values (Hybrid Notes) (Details) - Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - Foreign Currency Gain (Loss) [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Hybrid Instruments [Line Items] | ||
Hybrid Instruments at Fair Value, Net | $ 1,200 | |
Other Comprehensive Income (Loss) [Member] | ||
Hybrid Instruments [Line Items] | ||
Unrealized Gain (Loss) on Foreign Currency Derivatives, Net, before Tax | 49 | |
Gain (Loss) on Foreign Currency Cash Flow Hedge Ineffectiveness | $ 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, 2016USD ($) | |
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 Minimum Bond Rate Threshold | 9.50% |
Public Utilities Approved Return On Equity Percentage Trigger Rate Maximum | 11.25% |
Public Utilities Approved Return On Equity Percentage Trigger Rate Maximum Bond Rate Threshold | 11.50% |
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% |
Public Utilities Approved Rate Increase (Decrease) Percentage Bond Rate Threshold | 10.25% |
Maximum [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Return on Equity, Percentage | 11.25% |
Public Utilities Approved Rate Increase (Decrease) Percentage Bond Rate Threshold | 10.50% |
Regulatory Assets and Liabil120
Regulatory Assets and Liabilities (ROE of People Gas System Division) (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | |
Public Utilities, General Disclosures [Line Items] | ||||
Regulatory Assets | CAD | CAD 1,322 | CAD 699 | ||
Regulatory Assets, Current | CAD | 80 | 94 | ||
Environmental remediations [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Regulatory Assets | CAD | CAD 49 | CAD 0 | ||
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 | $ 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) CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
New Mexico Gas Company [Member] | New Mexico Public Regulatory [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities Bill Reduction | CAD 4 |
Regulatory Assets and Liabil122
Regulatory Assets and Liabilities (ROE of NSPI) (Details) - CAD CAD in Millions | Jul. 19, 2016 | Dec. 31, 2016 | Dec. 31, 2015 |
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Liabilities | CAD 1,639 | CAD 465 | |
Regulatory Assets | 1,322 | 699 | |
Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets | CAD 0 | CAD 14 | |
Nova Scotia Power Inc. [Member] | Fuel Adjustment Mechanism Asset [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulated common equity component | 40.00% | ||
Approved average annual increase | (1.00%) | ||
Public Utilities Prior Recovery of Prior Period Fuel Costs | CAD 12 | ||
Public Utilties Additional Contribution To Customers | 0.2 | ||
Nova Scotia Power Inc. [Member] | Fuel Adjustment Mechanism [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities Prior Recovery of Prior Period Fuel Costs | 3 | ||
Public Utilties Fuel Costs Savings Achieved During the Period | 2.8 | ||
Public Utilities refunds payable to customers | CAD 36 | ||
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) CAD in Millions, $ in Millions | Dec. 21, 2016CAD | Jun. 01, 2016 | Jan. 02, 2015 | Jun. 19, 2014 | Sep. 30, 2011 | Oct. 31, 2016USD ($)Transmissions_Distribution_Poles | Jun. 30, 2016 | Dec. 31, 2016CADkm | Dec. 31, 2015CAD | Mar. 31, 2014 | Dec. 31, 2012 |
Public Utilities, General Disclosures [Line Items] | |||||||||||
Regulatory Assets | CAD 1,322 | CAD 699 | |||||||||
Emera Maine [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.57% | 11.14% | 10.57% | 10.57% | 11.74% | ||||||
Emera Maine [Member] | Restructuring Of Above-market Power Purchase Contract And Deferrals [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Net Regulatory Assets | CAD 11.4 | ||||||||||
Net Regulatory Assets, Percentage | 1.00% | ||||||||||
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% | ||||||||||
Emera Maine [Member] | Maine Public Utilities Commission (MPUC) [Member] | Storm Costs [Member] | Electric Distribution [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | CAD 4 | ||||||||||
Bangor Hydro District [Member] | Electric Transmission [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 2.00% | 21.00% | |||||||||
Public Utilities, Recoverable Transmission Investment and Expenses, Percentage | 9.00% | (6.00%) | |||||||||
Bangor Hydro District [Member] | Restructuring Of Above-market Power Purchase Contract And Deferrals [Member] | Electric Transmission [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Net Regulatory Assets | CAD 19.7 | ||||||||||
Net Regulatory Assets, Percentage | 1.80% | ||||||||||
Maine Public Service District [Member] | Electric Transmission [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Return on Equity, Percentage | 6.75% | ||||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 48.00% | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 10.20% | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Retail Customers, Percentage | 36.00% | (22.00%) | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Wholesale Customers, Percentage | 43.00% | (1.00%) | |||||||||
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 | 8.80% | 10.00% | |||||||||
Regulatory Assets | $ | $ 21 | ||||||||||
Property plant and equipment | $ | $ 7 | ||||||||||
Regulatory Asset Amortization Period | 5 years | ||||||||||
Property plant and equipment useful life | 27 years | ||||||||||
Grand Bahama Power Company Limited [Member] | Storm Costs [Member] | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Number of Transmission and Distribution Poles | Transmissions_Distribution_Poles | 2,100 | ||||||||||
Public Utilities Restoration Cost | $ | $ 28 | ||||||||||
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) - CAD CAD in Billions | Dec. 31, 2016 | Dec. 31, 2015 |
Nova Scotia Power Inc. [Member] | Defeased Debt [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Long-term Debt | CAD 0.8 | CAD 0.8 |
Regulatory Assets and Liabil125
Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | CAD 80 | CAD 94 |
Regulatory Assets, Noncurrent | 1,242 | 605 |
Regulatory Assets, Total | 1,322 | 699 |
Deferred income tax regulatory assets [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 632 | 431 |
Pension and post-retirement medical plan [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 373 | 12 |
Environmental remediations [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 49 | 0 |
Unamortized Defeasance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 39 | 46 |
GBPC Hurricane Matthew restoration [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 28 | 0 |
Demand Side Management [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 32 | 36 |
Stranded cost recovery [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 27 | 28 |
Deferrals related to derivative instruments [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 15 | 68 |
Debt Basis Adjustment [Member] [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 19 | 0 |
Deferred Bond Refinancing Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 9 | 0 |
Cost Recovery Clauses [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 12 | 0 |
Fuel Adjustment Mechanism Asset [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | 0 | 14 |
Fuel Adjustment Mechanism Asset [Member] | Regulated Operation [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0 | 14 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Total | CAD 87 | CAD 64 |
Regulatory Assets and Liabil126
Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Regulatory Liabilities [Line Items] | ||
Regulatory Liability, Current | CAD 362 | CAD 112 |
Regulatory Liability, Noncurrent | 1,277 | 353 |
Regulatory Liabilities, Total | 1,639 | 465 |
Accumulated reserve - cost of removal [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 94 | 990 |
Deferrals related to derivative instruments [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 210 | 230 |
Cost Recovery Clauses Liability [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 0 | 153 |
Fuel Adjustment Mechanism Liability [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 42 | 94 |
Transmission And Delivery Storm Reserve [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 0 | 75 |
Self Insruance Fund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 87 | 30 |
Deferred income tax regulatory assets [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 18 | 26 |
Bill Reduction Credit [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | 0 | 10 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities, Total | CAD 31 | CAD 14 |
Regulatory Assets and Liabil127
Regulatory Assets and Liabilities (FAM Roll Forward) (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD | |
Fuel Adjustment Mechanism [Roll Forward] | |||||
Beginning balance | CAD 94 | ||||
Over Under Recovery Of Current Period Fuel Costs | 29 | CAD (24) | |||
Recovery From Rebate | 12 | 56 | |||
Non Fuel Revenues To Offset Potential Fuel Related Rate Increase | 20 | 45 | |||
Regulated fixed cost deferral related to 2015 demand side management | 0 | (35) | |||
Interest On Fuel Adjustment Mechanism Balance | 61 | 42 | |||
Ending balance | 80 | 94 | |||
Regulatory Assets, Current | CAD 94 | CAD 94 | CAD 80 | CAD 94 | |
Regulatory Liability, Current | 362 | 112 | |||
Regulatory Liability, Noncurrent | 1,277 | CAD 353 | |||
Recovery Stranded Costs | $ | $ 21 | ||||
FAM [Member] | |||||
Fuel Adjustment Mechanism [Roll Forward] | |||||
Regulatory Liability, Current | 32 | ||||
Regulatory Liability, Noncurrent | CAD 62 |
Regulatory Assets and Liabil128
Regulatory Assets and Liabilities (Other) (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2016CAD | Dec. 31, 2015CAD | |
Regulatory Assets [Line Items] | |||
Regulatory Assets | CAD 1,322 | CAD 699 | |
TECO Energy Inc [Member] | |||
Regulatory Assets [Line Items] | |||
Public Utilities Annual Bill Reduction To Customers | $ | $ 4 | ||
TECO Energy Inc [Member] | Storm Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | CAD 11 | ||
Tampa Electric Division [Member] | Storm Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | CAD 11 |
Related Paty Transactions (Tran
Related Paty Transactions (Transactions Between Emera and Associated Parties) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Maritimes and Northeast Pipline [Member] | Natural gas transportation capacity [Member] | ||
Related Party Transaction [Line Items] | ||
Revenue from Related Parties | CAD 29 | CAD 23 |
Prepayments And Other Curren130
Prepayments And Other Current Assets (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Prepaid Expense and Other Assets, Current [Abstract] | ||
Capitalized transportation capacity | CAD 190 | CAD 223 |
Prepaid expenses | 57 | 18 |
Due From Related Parties | 16 | 2 |
Net investment in direct financing lease | 8 | 6 |
Other Prepaid Expenses | 5 | 7 |
Prepayments and other current assets | CAD 276 | CAD 256 |
Property, plant and equipment
Property, plant and equipment (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | CAD 23,673 | CAD 9,995 |
Less: Accumulated depreciation | (7,787) | (3,737) |
Property, Plant and Equipment, Net | 17,290 | 6,469 |
Net Book Value | 15,886 | 6,258 |
Electric Generation Equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | CAD 10,553 | 4,957 |
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 | CAD 2,799 | 1,603 |
Electric Transmission [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 28 years | |
Electric Transmission [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 75 years | |
Electric Distribution [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | CAD 5,715 | 2,503 |
Electric Distribution [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 11 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 | CAD 2,895 | 0 |
Gas, Transmission and Distribution Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Useful Life | 10 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 | CAD 1,711 | 932 |
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 | 50 years | |
Construction in Progress [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Total cost | CAD 1,404 | CAD 211 |
Employee Benefit Plans (Changes
Employee Benefit Plans (Changes in Benefit Obligation and Plan Aassets and the Funded Status) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | CAD 1,301 | |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 2,208 | CAD 1,301 |
Pension Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 1,520 | 1,470 |
Addition of Teco | 1,035 | 0 |
Defined Benefit Plan, Service Cost | 35 | 22 |
Defined Benefit Plan, Contributions by Plan Participants | 8 | 8 |
Defined Benefit Plan, Interest Cost | 79 | 59 |
Defined Benefit Plan, Plan Amendments | 0 | 0 |
Benefits Paid | (94) | (61) |
Defined Benefit Plan, Actuarial Gain (Loss) | (2) | (15) |
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss) | 26 | 37 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 2,607 | 1,520 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | 1,300 | 1,205 |
Addition of Teco | 830 | 0 |
Defined Benefit Plan, Contributions by Employer | 49 | 23 |
Defined Benefit Plan, Contributions by Plan Participants | 8 | 8 |
Benefits Paid | (94) | (61) |
Defined Benefit Plan, Actual Return on Plan Assets | 93 | 96 |
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets | 22 | 29 |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 2,208 | 1,300 |
Defined Benefit Plan, Funded Status of Plan [Abstract] | ||
Defined Benefit Plan, Funded Status of Plan | (399) | (220) |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 88 | 102 |
Addition of Teco | 277 | 0 |
Defined Benefit Plan, Service Cost | 4 | 3 |
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 |
Defined Benefit Plan, Interest Cost | 9 | 4 |
Defined Benefit Plan, Plan Amendments | 2 | (27) |
Benefits Paid | (16) | (6) |
Defined Benefit Plan, Actuarial Gain (Loss) | (12) | 1 |
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss) | 6 | 11 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 358 | 88 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Defined Benefit Plan, Fair Value of Plan Assets, Beginning Balance | 6 | 5 |
Addition of Teco | 29 | 0 |
Defined Benefit Plan, Contributions by Employer | 17 | 6 |
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 |
Benefits Paid | (16) | (6) |
Defined Benefit Plan, Actual Return on Plan Assets | 2 | 0 |
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets | 1 | 1 |
Defined Benefit Plan, Fair Value of Plan Assets, Ending Balance | 39 | 6 |
Defined Benefit Plan, Funded Status of Plan [Abstract] | ||
Defined Benefit Plan, Funded Status of Plan | CAD (319) | CAD (82) |
Employee Benefit Plans (Plans w
Employee Benefit Plans (Plans with PBO/APBO in excess of Plan assets) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Aggregate Projected Benefit Obligation | CAD 2,579 | CAD 1,489 |
Aggregate Fair Value of Plan Assets | 2,171 | 1,261 |
Funded Status | (408) | (228) |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Aggregate Projected Benefit Obligation | 358 | 87 |
Aggregate Fair Value of Plan Assets | 39 | 5 |
Funded Status | CAD (319) | CAD (82) |
Employee Benefit Plans (Accumul
Employee Benefit Plans (Accumulated Benefit Obligation (ABO)) (Details) - Pension Plan [Member] - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | ||
ABO | CAD 2,462 | CAD 1,424 |
Fair Value of Plan Assets | 2,171 | 1,261 |
Funded Status | CAD (291) | CAD (163) |
Employee Benefit Plans (Amounts
Employee Benefit Plans (Amounts Recognized in the Consolidated Balance Sheets ) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | CAD (58) | CAD (7) |
Liabilities, Noncurrent | (669) | (303) |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 9 | 9 |
Pension Plan [Member] | ||
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | (41) | (4) |
Liabilities, Noncurrent | (367) | (224) |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 9 | 9 |
Deferred Tax Assets, Defined Benefit Plan | (16) | (19) |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 620 | 330 |
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total | 237 | 130 |
Non-pension Benefit Plans [Member | ||
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract] | ||
Current Liabilities | (17) | (3) |
Liabilities, Noncurrent | (302) | (79) |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 0 | 0 |
Deferred Tax Assets, Defined Benefit Plan | 1 | 3 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 45 | (9) |
Defined Benefit Plan, Amounts Recognized in Balance Sheet, Total | CAD (275) | CAD (94) |
Employee Benefit Plans (Change
Employee Benefit Plans (Change in AOCI ) (Details) CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | CAD 349 |
Balance, December 31 | 636 |
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 | 353 |
Amortized in current period, Net Actuarial Gain (Loss) | (42) |
Current year addition to AOCI | 19 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | 330 |
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 | (4) |
Amortized in current period, Net Prior Service Cost (Credit) | 1 |
Current year addition to AOCI | 0 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | (3) |
Pension Plan [Member] | Regulatory Assets [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 0 |
Amortized in current period, Net Actuarial Gain (Loss) | (9) |
Current year addition to AOCI | 318 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | 309 |
Non-pension Benefit Plans [Member | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | (12) |
Balance, December 31 | 44 |
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 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | 15 |
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 | (27) |
Amortized in current period, Net Prior Service Cost (Credit) | 8 |
Current year addition to AOCI | 0 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | (19) |
Non-pension Benefit Plans [Member | Regulatory Assets [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Balance, January 1 | 0 |
Amortized in current period, Net Actuarial Gain (Loss) | 0 |
Current year addition to AOCI | 48 |
Adjustments for MPS | 0 |
Foreign currency translation adjustment | 0 |
Balance, December 31 | CAD 48 |
Employee Benefit Plans (AOCI )
Employee Benefit Plans (AOCI ) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses | CAD (330) | CAD (353) |
Past service (gains) | (3) | (4) |
Regulatory Assets | 309 | 0 |
Accumulated Other Comprehensive Income (Loss), before Tax, Total | 636 | 349 |
Deferred Tax Assets, Defined Benefit Plan | (16) | (19) |
Net amount in AOCI after tax adjustment | 620 | 330 |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actuarial losses | (15) | (15) |
Past service (gains) | (19) | (27) |
Regulatory Assets | 48 | 0 |
Accumulated Other Comprehensive Income (Loss), before Tax, Total | 44 | (12) |
Deferred Tax Assets, Defined Benefit Plan | 1 | 3 |
Net amount in AOCI after tax adjustment | CAD 45 | CAD (9) |
Employee Benefit Plans (Benefit
Employee Benefit Plans (Benefit Cost Components) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Service Cost | CAD 35 | CAD 22 |
Defined Benefit Plan, Interest Cost | 79 | 59 |
Defined Benefit Plan, Expected Return on Plan Assets | (97) | (65) |
Defined Benefit Plan, Amortization of Gains (Losses) | 42 | 48 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | (1) | (1) |
Current year amortization of regulatory assets liabilties | 9 | 0 |
Net Periodic Benefit Cost, Total | 67 | 63 |
Non-pension Benefit Plans [Member | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Service Cost | 4 | 3 |
Defined Benefit Plan, Interest Cost | 9 | 4 |
Defined Benefit Plan, Expected Return on Plan Assets | (1) | 0 |
Defined Benefit Plan, Amortization of Gains (Losses) | 2 | 1 |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | (8) | (6) |
Current year amortization of regulatory assets liabilties | 0 | 0 |
Net Periodic Benefit Cost, Total | CAD 6 | CAD 1 |
Employee Benefit Plans (Asset C
Employee Benefit Plans (Asset Class) (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Pension Plan [Member] | Short-term securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 5.00% |
Pension Plan [Member] | Fixed Income Funds [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 35.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 50.00% |
Pension Plan [Member] | Equity Securities, Canadian [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 12.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 22.00% |
Pension Plan [Member] | Equity Securities, Non Canadian [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 36.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 50.00% |
Non-pension Benefit Plans [Member | Short-term securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 2.00% |
Non-pension Benefit Plans [Member | Fixed Income Funds [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 40.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 48.00% |
Non-pension Benefit Plans [Member | Equity Securities [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 50.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 61.00% |
United States Postretirement Benefit Plan of US Entity [Member] | Short-term securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 10.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 50.00% |
United States Postretirement Benefit Plan of US Entity [Member] | Fixed Income Funds [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 40.00% |
United States Postretirement Benefit Plan of US Entity [Member] | Equity Securities, United States [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 30.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 60.00% |
United States Postretirement Benefit Plan of US Entity [Member] | Equity Securities, Non United States [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 60.00% |
Employee Benefit Plans (Fair Va
Employee Benefit Plans (Fair Value of Investments) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
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 | CAD 2,208 | CAD 1,301 | |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 732 | CAD 682 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 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 | CAD 31 | CAD 12 | |
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 | 31 | CAD 12 | |
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 | CAD 0 | ||
Net In Transit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | (2.00%) | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD (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 | (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 | ||
Net Asset Value Member [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 1,362 | ||
Open Ended Invesments Measured at NAV [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 51.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 1,132 | ||
Collective Trust Measured at NAV [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 11.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 230 | ||
Other investments measured at Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 48.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 619 | ||
Other investments measured at Net Asset Value [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 0 | ||
Equity Securities, Canadian [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 9.00% | 0.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | CAD 192 | CAD 190 | |
Equity Securities, Canadian [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 192 | CAD 190 | |
Equity Securities, United States [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 14.00% | 18.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | CAD 303 | CAD 240 | |
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 | CAD 303 | CAD 240 | |
Equity Securities, Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 11.00% | 18.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | CAD 243 | CAD 240 | |
Equity Securities, Other [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 243 | 240 | |
Government Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 2.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 47 | ||
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 | CAD 47 | ||
Corporate Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 2.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 53 | ||
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 | CAD 53 | ||
Other Fixed Income Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 9.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 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 | ||
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 | 14 | ||
Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 2,208 | 1,300 | CAD 1,205 |
Postretirement Benefit Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 39 | CAD 6 | CAD 5 |
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 | ||
Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 33 | ||
Postretirement Benefit Plan [Member] | Cash and cash equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 3.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 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 | ||
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 | CAD 0 | ||
Postretirement Benefit Plan [Member] | Life insurance policies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 85.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 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 | ||
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 | 33 | ||
Postretirement Benefit Plan [Member] | Net Asset Value Member [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 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 | 12.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 5 | ||
Post Retirement Benefit Plans | |||
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 | CAD 39 | CAD 5 | |
Post Retirement Benefit Plans | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | 1 | |
Post Retirement Benefit Plans | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 33 | CAD 0 | |
Post Retirement Benefit Plans | Cash and cash equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 3.00% | 20.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | CAD 1 | CAD 1 | |
Post Retirement Benefit Plans | 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 | |
Post Retirement Benefit Plans | 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 | CAD 0 | 0 | |
Post Retirement Benefit Plans | Life insurance policies [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 85.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 33 | ||
Post Retirement Benefit Plans | 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 | ||
Post Retirement Benefit Plans | Life insurance policies [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 33 | ||
Post Retirement Benefit Plans | Net Asset Value Member [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 5 | CAD 4 | |
Post Retirement Benefit Plans | Other investments measured at Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Plan Asset Allocations | 12.00% | 80.00% | |
Defined Benefit Plan, Fair Value of Plan Assets | CAD 5 | CAD 4 |
Employee Benefit Plans (Expecte
Employee Benefit Plans (Expected Cash Flows, Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plans, Estimated Future Employer Contributions in 2017 | CAD 117 |
Defined Benefit Plan, Expected Future Benefit Payments, 2017 | 172 |
Defined Benefit Plan, Expected Future Benefit Payments, 2018 | 140 |
Defined Benefit Plan, Expected Future Benefit Payments, 2019 | 150 |
Defined Benefit Plan, Expected Future Benefit Payments, 2020 | 156 |
Defined Benefit Plan, Expected Future Benefit Payments, 2021 | 165 |
Defined Benefit Plan, Expected Future Benefit Payments, 2022-20206 | 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, 2017 | 22 |
Defined Benefit Plan, Expected Future Benefit Payments, 2018 | 23 |
Defined Benefit Plan, Expected Future Benefit Payments, 2019 | 23 |
Defined Benefit Plan, Expected Future Benefit Payments, 2020 | 24 |
Defined Benefit Plan, Expected Future Benefit Payments, 2021 | 25 |
Defined Benefit Plan, Expected Future Benefit Payments, 2022-20206 | CAD 130 |
Employee Benefit Plans (Assumpt
Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-retirement Benefit Plans) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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 | CAD 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 | 20 | |
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation | 17 | |
Defined Benefit Plan, Assumptions Used in Calculations [Abstract] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Increase | (7) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate Decrease | 7 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Increase | (4) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Asset Rate Decrease | CAD 4 | |
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 | 3.96% | 4.02% |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 2.82% | 3.07% |
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 | 3.79% | 3.99% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.33% | 5.91% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 2.88% | 3.07% |
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 | 4.18% | 4.04% |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 2.54% | 3.50% |
Defined Benefit Plan, Benefit Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 6.78% | 5.50% |
Defined Benefit Plan, Benefit Obligation, Ultimate Health Care Cost Trend Rate | 4.45% | 4.20% |
Defined Benefit Plan, Benefit Obligation, Year that Rate Reaches Ultimate Trend Rate | 2,020 | 2,020 |
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 | 3.88% | 3.98% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 4.43% | 0.00% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 2.56% | 3.50% |
Defined Benefit Plan, Net Periodic Benefit Cost, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 6.76% | 5.90% |
Defined Benefit Plan, Net Periodic Benefit Cost, Ultimate Health Care Cost Trend Rate | 4.45% | 4.30% |
Defined Benefit Plan, Net Periodic Benefit Cost, Year that Rate Reaches Ultimate Trend Rate | 2,020 | 2,020 |
Employee Benefit Plans (Amou143
Employee Benefit Plans (Amounts to be Amortized in the Next Fiscal Year) (Details) CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Pension Plan [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Future Amortization of Gain (Loss) | CAD (53) |
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | 1 |
Regulated assets | (16) |
Total | (68) |
Non-pension Benefit Plans [Member | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Future Amortization of Gain (Loss) | (1) |
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | 8 |
Regulated assets | 3 |
Total | CAD 10 |
Employee Benefit Plans narrativ
Employee Benefit Plans narrative (Details) - CAD CAD in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Jul. 01, 2016 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 2,208 | CAD 1,301 | ||
TECO Energy Inc [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,180 | 1,089 | CAD 859 | |
Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
ABO for defined pension plans | 2,489 | 1,427 | ||
Defined Benefit Plan, Fair Value of Plan Assets | 2,208 | 1,300 | CAD 1,205 | |
Pension Plan [Member] | TECO Energy Inc [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution Amount | 17 | 9 | ||
Other Postretirement Benefit Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | CAD 39 | CAD 6 | CAD 5 |
Net Investment In Direct Fin145
Net Investment In Direct Financing Lease (Direct Fianncing Leases and Future Minimum Payments Received) (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ||
Capital Leases, Net Investment in Direct Financing Leases, Minimum Payments to be Received | CAD 1,194 | CAD 1,202 |
Capital Leases, Net Investment in Direct Financing Leases, Executory Costs | (223) | (213) |
Minimum lease payments receivable | 971 | 989 |
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 | (658) | (686) |
Capital Leases, Net Investment in Direct Financing Leases, Total | 496 | 486 |
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Current | 8 | 6 |
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent | 488 | CAD 480 |
Capital Leases, Future Minimum Payments Receivable, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments, Receivable in 2017 | 65 | |
Capital Leases, Future Minimum Payments, Receivable in 2018 | 65 | |
Capital Leases, Future Minimum Payments, Receivable in 2019 | 65 | |
Capital Leases, Future Minimum Payments, Receivable in 2020 | 65 | |
Capital Leases, Future Minimum Payments, Receivable in 2021 | 65 | |
Capital Leases, Future Minimum Payments, estimated executory costs, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments, estimated executory costs, 2017 | (11) | |
Capital Leases, Future MinimumPayments, estimated executory costs in 2018 | (11) | |
Capital Leases, Future Minimum Payments, estimated executory costs in 2019 | (12) | |
Capital Leases, Future Minimum Payments, estimated executory costs in 2020 | (12) | |
Capital Leases, Future Minimum Payments, estimated executory costs in 2021 | (12) | |
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs, Fiscal Year Maturity [Abstract] | ||
Capital Leases, Future Minimum Payments Receivable Net of Executory Costs, 2017 | 54 | |
Capital Leases, Future Minimum Payments, Receivable Net of Executory Costs in 2018 | 54 | |
Capital Leases, Future Minimum Payments, Receivable Net of Executory Costs in 2019 | 53 | |
Capital Leases, Future Minimum Payments, Receivable Net of Executory Costs in 2020 | 53 | |
Capital Leases, Future Minimum Payments, Receivable Net of Executory Costs in 2021 | CAD 53 |
Goodwill (Details)
Goodwill (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | CAD 264 | CAD 222 |
Goodwill, Acquired During Period | 5,771 | 0 |
Goodwill, Impairment Loss | 0 | 0 |
Goodwill, Foreign Currency Translation Gain (Loss) | 178 | 42 |
Goodwill, Ending Balance | CAD 6,213 | CAD 264 |
Short Term Debt (Short-term deb
Short Term Debt (Short-term debt and the related weighted-average interest rates) (Details) - CAD | Dec. 31, 2016 | Dec. 31, 2015 |
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 961,000,000 | CAD 16,000,000 |
Short-term Debt, Weighted Average Interest Rate | 1.73% | 2.70% |
TECO Energy Inc. and TECO Finance Inc. [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 685,000,000 | CAD 0 |
Short-term Debt, Weighted Average Interest Rate | 1.74% | 0.00% |
Tampa Electric Division [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 228,000,000 | CAD 0 |
Short-term Debt, Weighted Average Interest Rate | 1.49% | 0.00% |
New Mexico Gas Company [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 35,000,000 | CAD 0 |
Short-term Debt, Weighted Average Interest Rate | 1.71% | 0.00% |
Nova Scotia Power Inc. [Member] | Notes Payable to Banks [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 1,000,000 | CAD 16,000,000 |
Short-term Debt, Weighted Average Interest Rate | 2.70% | 2.70% |
Grand Bahama Power Company Limited [Member] | Notes Payable to Banks [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 12,000,000 | CAD 0 |
Short-term Debt, Weighted Average Interest Rate | 5.75% | 0.00% |
Emera Energy Services [Member] | Line of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Short-term Debt | CAD 0 | CAD 0 |
Short-term Debt, Weighted Average Interest Rate | 0.00% | 0.00% |
Short Term Debt (short-term rev
Short Term Debt (short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity) (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 13, 2016 | Dec. 31, 2015 | |
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 1,762 | CAD 18 | |
Letters of Credit Outstanding, Amount | CAD 37 | 33 | |
Total advances under available facilities | 363 | 674 | |
Available capacity under existing agreements | 1,070 | 663 | |
Long-term Line of Credit | CAD 326 | CAD 641 | |
Short-term Debt, Weighted Average Interest Rate | 1.73% | 2.70% | |
Short term debt revolving and non revolving credit facility [Member] | |||
Short-term Debt [Line Items] | |||
Credit Facility Advances | CAD 960 | CAD 0 | |
Letters of Credit Outstanding, Amount | 3 | 0 | |
Total advances under available facilities | 963 | 0 | |
Available capacity under existing agreements | 799 | 18 | |
TECO Energy Inc. and TECO Finance Inc. [Member] | Revolving Credit Facility [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 403 | CAD 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
TECO Energy Inc. and TECO Finance Inc. [Member] | Line of Credit [Member] | |||
Short-term Debt [Line Items] | |||
Short-term Debt, Weighted Average Interest Rate | 1.74% | 0.00% | |
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 | CAD 537 | CAD 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2017 | ||
Tampa Electric Division [Member] | Revolving Credit Facility [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 436 | 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
Tampa Electric Division [Member] | Accounts Receivable Revolving Credit Facility | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 201 | CAD 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
Tampa Electric Division [Member] | Line of Credit [Member] | |||
Short-term Debt [Line Items] | |||
Short-term Debt, Weighted Average Interest Rate | 1.49% | 0.00% | |
New Mexico Gas Company [Member] | Revolving Credit Facility [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 168 | CAD 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
New Mexico Gas Company [Member] | Line of Credit [Member] | |||
Short-term Debt [Line Items] | |||
Short-term Debt, Weighted Average Interest Rate | 1.71% | 0.00% | |
Grand Bahama Power Company Limited [Member] | Revolving Credit Facility [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 17 | CAD 18 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2017 | ||
Emera Energy Services [Member] | Line of Credit [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 0 | CAD 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2014 | ||
Short-term Debt, Weighted Average Interest Rate | 0.00% | 0.00% |
Short Term Debt (Narrative) (De
Short Term Debt (Narrative) (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 31, 2015CAD | |
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 1,762 | CAD 18 | |
Revolving Credit Facility [Member] | Tampa Electric Division [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 436 | $ 325 | |
Line of Credit Facility, Expiration Date | 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 | CAD 403 | 300 | |
Line of Credit Facility, Expiration Date | Dec. 17, 2018 | ||
Accounts Receivable Revolving Credit Facility | Tampa Electric Division [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 201 | 150 | |
Line of Credit Facility, Expiration Date | Mar. 23, 2018 | ||
Accounts Receivable Revolving Credit Facility | New Mexico Gas Company [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 168 | 125 | |
Line of Credit Facility, Expiration Date | Dec. 17, 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 | CAD 537 | $ 400 | |
Line of Credit Facility, Expiration Date | Mar. 14, 2017 |
Other Current Liabilities (Deta
Other Current Liabilities (Details) - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Other Current Liabilities [Abstract] | ||
Accrued Liabilities, Current | CAD 137 | CAD 130 |
Accrued interest on long-term debt | 96 | 44 |
Sales and Excise Tax Payable, Current | 16 | 4 |
Accrued interest on convertible debentures represented by instalment receipts | 0 | 11 |
Deferred Emission Credits, Current | 10 | 6 |
Dividends Payable, Current | 0 | 0 |
Other Sundry Liabilities, Current | 22 | 12 |
Other Liabilities, Current, Total | CAD 281 | CAD 207 |
Long Term Debt (Long-term Debt)
Long Term Debt (Long-term Debt) (Details) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2016USD ($) | Dec. 13, 2016CAD | Jun. 16, 2016CAD | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | ||||||
Fair Market Value Adjustments to Debt | CAD 0 | CAD 58,000,000 | ||||
Debt issuance costs | (16,000,000) | (111,000,000) | ||||
Amount due within one year | (274,000,000) | (476,000,000) | ||||
Long Term Debt, Adjustments | (290,000,000) | (529,000,000) | ||||
Long-term Debt and Capital Lease Obligations | 3,735,000,000 | CAD 14,268,000,000 | ||||
Emera Inc | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 2,366,000,000 | CAD 715,000,000 | ||||
Emera Inc | Bankers Acceptances, LIBOR Loans [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Variable rate | Variable | Variable | ||||
Long-term Debt, Gross | CAD 30,000,000 | CAD 240,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2020 | |||||
Emera Inc | Unsecured fixed rate notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 725,000,000 | CAD 475,000,000 | ||||
Emera Inc | Unsecured fixed rate notes [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.50% | 3.50% | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Emera Inc | Unsecured fixed rate notes [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.85% | 3.85% | ||||
Debt Instrument, Maturity Date | Dec. 31, 2024 | |||||
Emera Inc | Medium-term Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.96% | |||||
Debt Instrument, Face Amount | CAD 250,000,000 | |||||
Emera Inc | Fixed to floating subordinated notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 6.75% | 6.75% | ||||
Long-term Debt, Gross | CAD 1,611,000,000 | CAD 0 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2076 | |||||
Emera US Finance LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 4,364,000,000 | CAD 0 | ||||
Emera US Finance LP [Member] | Unsecured senior notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.60% | 3.60% | ||||
Long-term Debt, Gross | CAD 4,364,000,000 | CAD 0 | ||||
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] | ||||||
Variable rate | Variable | |||||
Long-term Debt, Gross | CAD 1,141,000,000 | 0 | ||||
TECO Finance, Inc. [Member] | Unsecured Debt [Member] | Unsecured Notes, 4.00% [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 336,000,000 | 0 | ||||
TECO Finance, Inc. [Member] | Unsecured Debt [Member] | Unsecured Notes, 6.57% [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.86% | 5.86% | ||||
Long-term Debt, Gross | CAD 805,000,000 | 0 | ||||
TECO Finance, Inc. [Member] | Variable rate notes [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 | 5.86% | 5.86% | ||||
Long-term Debt, Gross | CAD 805,000,000 | 0 | ||||
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2017 | |||||
TECO Finance, Inc. [Member] | Fixed rate notes and bonds [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2020 | |||||
Tampa Electric Division [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 2,579,000,000 | 0 | ||||
Tampa Electric Division [Member] | Unsecured Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | 0 | |||||
Tampa Electric Division [Member] | Senior Notes [Member] | Unsecured Notes, Floating Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ | $ 86 | |||||
Tampa Electric Division [Member] | Senior Notes [Member] | Senior Unsecured Note I [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ | 51.6 | |||||
Tampa Electric Division [Member] | Senior Notes [Member] | Senior Secured Notes I [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Face Amount | $ | $ 75 | |||||
Tampa Electric Division [Member] | Fixed rate notes and bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 4.90% | 4.90% | ||||
Long-term Debt, Gross | CAD 2,579,000,000 | 0 | ||||
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 | CAD 351,000,000 | CAD 0 | ||||
Peoples Gas System Division [Member] | Fixed rate notes and bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 5.06% | 5.06% | ||||
Long-term Debt, Gross | CAD 351,000,000 | CAD 0 | ||||
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 | CAD 363,000,000 | 0 | ||||
New Mexico Gas Company [Member] | Unsecured Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 0 | |||||
New Mexico Gas Company [Member] | Fixed rate notes and bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 4.53% | 4.53% | ||||
Long-term Debt, Gross | CAD 363,000,000 | CAD 0 | ||||
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 | CAD 269,000,000 | 0 | ||||
New Mexico Gas Incorporate [Member] | Unsecured Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 0 | |||||
New Mexico Gas Incorporate [Member] | Fixed rate notes and bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.41% | 3.41% | ||||
Long-term Debt, Gross | CAD 269,000,000 | CAD 0 | ||||
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 | CAD 2,324,000,000 | CAD 2,430,000,000 | ||||
Nova Scotia Power Inc. [Member] | Commercial Paper [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Variable rate | Variable | Variable | ||||
Long-term Debt, Gross | CAD 264,000,000 | CAD 369,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2020 | |||||
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 5.73% | 5.73% | 5.73% | 5.73% | ||
Long-term Debt, Gross | CAD 1,965,000,000 | CAD 1,965,000,000 | ||||
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] | Medium-term Notes [Member] | Series F [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.75% | 9.75% | ||||
Long-term Debt, Gross | CAD 95,000,000 | CAD 95,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Nova Scotia Power Inc. [Member] | Fixed rate debenture [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 9.75% | 9.75% | 9.75% | 9.75% | ||
Long-term Debt, Gross | CAD 95,000,000 | CAD 95,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Nova Scotia Power Inc. [Member] | Capital Lease Obligations [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 0 | 1,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Emera Maine [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | $ | $ 380 | $ 397 | ||||
Emera Maine [Member] | LIBOR loans and demand loans [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 32,000,000 | 32,000,000 | ||||
Emera Maine [Member] | General & Refunding Mortgage Bonds I [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.28% | 4.28% | ||||
Long-term Debt, Gross | CAD 281,000,000 | CAD 296,000,000 | ||||
Debt Instrument, Face Amount | $ | $ 20 | |||||
Emera Maine [Member] | Loans Payable [Member] | LIBOR loans and demand loans [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Emera Maine [Member] | LIBOR loans and demand loans [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Variable rate | Variable | Variable | ||||
Long-term Debt, Gross | $ | $ 32 | $ 32 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Emera Maine [Member] | Secured fixed rate mortgage bonds [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 9.74% | 9.74% | 9.74% | 9.74% | ||
Long-term Debt, Gross | $ | $ 67 | $ 69 | ||||
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 | 4.28% | 4.31% | 4.28% | 4.31% | ||
Long-term Debt, Gross | $ | $ 281 | $ 296 | ||||
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2017 | |||||
Emera Maine [Member] | Unsecured senior fixed rate notes [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2044 | |||||
Emera Brunswick Pipeline Company Limited [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.08% | 3.08% | ||||
Long-term Debt, Gross | CAD 248,000,000 | CAD 249,000,000 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Emera Brunswick Pipeline Company Limited [Member] | Secured senior notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.08% | 3.08% | 3.08% | 3.08% | ||
Long-term Debt, Gross | CAD 248,000,000 | CAD 249,000,000 | ||||
Emera Brunswick Pipeline Company Limited [Member] | Senior secured credit facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||
Grand Bahama Power Company Limited [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | $ | $ 130 | $ 145 | ||||
Grand Bahama Power Company Limited [Member] | Unsecured Debt [Member] | Unsecured Notes I [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.62% | 3.62% | ||||
Long-term Debt, Gross | CAD 63,000,000 | 77,000,000 | ||||
Grand Bahama Power Company Limited [Member] | Unsecured Debt [Member] | Unsecured Notes II [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.07% | 7.07% | ||||
Long-term Debt, Gross | CAD 67,000,000 | CAD 68,000,000 | ||||
Grand Bahama Power Company Limited [Member] | Unsecured amortizing fixed rate notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 3.62% | 3.62% | 3.62% | 3.62% | ||
Long-term Debt, Gross | $ | $ 63 | $ 77 | ||||
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 | |||||
Grand Bahama Power Company Limited [Member] | Unsecured senior notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Weighted average interest rate | 7.07% | 7.07% | 7.07% | 7.07% | ||
Long-term Debt, Gross | $ | $ 67 | $ 68 | ||||
Grand Bahama Power Company Limited [Member] | Unsecured senior notes [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2020 | |||||
Grand Bahama Power Company Limited [Member] | Unsecured senior notes [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Maturity Date | Dec. 31, 2023 | |||||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | $ | 282 | 89 | ||||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Senior Notes [Member] | Senior Secured Notes I [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Gross | CAD 201,000,000 | CAD 0 | ||||
Debt Instrument, Maturity Date | Dec. 31, 2021 | |||||
The Barbados Light & Power Company Limited And Emera Caribbean Incorporated [Member] | Secured senior notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Variable rate | Variable | |||||
Long-term Debt, Gross | $ | $ 201 | $ 0 | ||||
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 | 5.65% | 5.64% | 5.65% | 5.64% | ||
Long-term Debt, Gross | $ | $ 81 | $ 89 | ||||
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 CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 13, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 1,762 | CAD 18 | |
Long-term Line of Credit | CAD 326 | 641 | |
Letters of Credit Outstanding, Amount | 37 | 33 | |
Use Of Available Facilities | 363 | 674 | |
Line of Credit Facility, Remaining Borrowing Capacity | CAD 1,070 | 663 | |
Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 1,433 | 1,337 | |
Emera Inc | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 700 | 700 | |
Line of Credit Facility, Expiration Date | Jun. 30, 2020 | ||
Overdraft limit on lines of credit accounts | CAD 50 | ||
TECO Energy Inc. and TECO Finance Inc. [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 0 | 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
Tampa Electric Division [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 0 | 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
New Mexico Gas Company [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 0 | 0 | |
Line of Credit Facility, Expiration Date | Dec. 31, 2018 | ||
Nova Scotia Power Inc. [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 600 | 500 | |
Line of Credit Facility, Expiration Date | Oct. 31, 2020 | ||
Emera Maine [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 107 | 111 | |
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 | CAD 26 | CAD 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, 2017 | ||
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, 2021 |
Long Term Debt (Debt Covenants)
Long Term Debt (Debt Covenants) (Details) - Syndicated Credit Facilities [Member] | Dec. 31, 2016 |
Debt Instrument [Line Items] | |
Debt Instrument Covenant Requirement | 0.7 |
Ratio of Indebtedness to Net Capital | 0.62 |
Long Term Debt (Long Term Matur
Long Term Debt (Long Term Maturities) (Details) CAD in Millions | Dec. 31, 2016CAD |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | CAD 476 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 791 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 1,380 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 835 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 1,687 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal after 2022 | 9,628 |
Total debt maturities including current portion | 14,797 |
Emera Inc | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 0 |
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 | 30 |
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 after 2022 | 2,111 |
Emera US Finance LP [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 0 |
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 | 671 |
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 | 1,007 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal after 2022 | 2,686 |
Total debt maturities including current portion | 4,364 |
TECO Energy Inc [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 0 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 409 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 67 |
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 | 643 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal after 2022 | 2,443 |
Total debt maturities including current portion | 3,562 |
TECO Finance, Inc. [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 403 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 335 |
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 | 403 |
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 after 2022 | 0 |
Total debt maturities including current portion | 1,141 |
Emera Maine [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 33 |
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 | 32 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 40 |
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 after 2022 | 269 |
Total debt maturities including current portion | 380 |
Nova Scotia Power Inc. [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 0 |
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 | 264 |
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 after 2022 | 1,965 |
Total debt maturities including current portion | 2,324 |
EBP [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 0 |
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 | 248 |
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 after 2022 | 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, Repayments of Principal in 2017 | 11 |
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 | 12 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 40 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 11 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal after 2022 | 44 |
Total debt maturities including current portion | 130 |
The Barbados Light and Power Company Limited [Member] | |
Debt Instrument [Line Items] | |
Long-term Debt and Capital Lease Obligations, Repayments of Principal in 2017 | 29 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2018 | 29 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2019 | 30 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2020 | 58 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal in 2021 | 26 |
Long-term Debt and Capital Lease Obligations, Maturities, Repayments of Principal after 2022 | 110 |
Total debt maturities including current portion | CAD 282 |
Long Term Debt (Narrative) (Det
Long Term Debt (Narrative) (Details) $ in Millions | Nov. 29, 2016USD ($) | Apr. 10, 2015 | Jun. 30, 2016 | Dec. 31, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2016USD ($) | Jun. 16, 2016CAD | Jun. 16, 2016USD ($) | May 27, 2016CAD | Apr. 29, 2016CAD | May 20, 2015USD ($) | Apr. 11, 2015USD ($) |
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 1,762,000,000 | CAD 18,000,000 | ||||||||||
Proceeds from Issuance of Common Stock | 354,000,000 | 9,000,000 | ||||||||||
Emera Inc | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,366,000,000 | 715,000,000 | ||||||||||
Emera Inc | Medium-term Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.96% | 2.96% | ||||||||||
Debt Instrument, Face Amount | CAD 250,000,000 | |||||||||||
Emera Inc | Hybrid Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.75% | 6.75% | ||||||||||
Debt Instrument, Face Amount | $ | $ 1,200 | |||||||||||
Emera Inc | Hybrid Notes [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 100.00% | |||||||||||
Emera Inc | Hybrid Notes, 2026 through 2046 [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 5.44% | |||||||||||
Emera Inc | Hybrid Notes, 2046 through 2076 [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 6.19% | |||||||||||
Emera Inc | Canadian Notes [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.90% | 2.90% | ||||||||||
Debt Instrument, Face Amount | CAD 500,000,000 | |||||||||||
Nova Scotia Power Inc. [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,324,000,000 | 2,430,000,000 | ||||||||||
Nova Scotia Power Inc. [Member] | Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 600,000,000 | |||||||||||
Line of credit current borrowing capacity | CAD 500,000,000 | |||||||||||
Nova Scotia Power Inc. [Member] | Commercial Paper [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 500,000,000 | |||||||||||
Line of credit current borrowing capacity | CAD 400,000,000 | |||||||||||
Nova Scotia Power Inc. [Member] | Medium-term Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | CAD 1,965,000,000 | 1,965,000,000 | ||||||||||
Emera Brunswick Pipeline Company Limited [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.08% | 3.08% | ||||||||||
Debt Instrument, Maturity Date | Dec. 31, 2019 | |||||||||||
Long-term Debt, Gross | CAD 248,000,000 | 249,000,000 | ||||||||||
Emera US Finance LP [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 4,364,000,000 | 0 | ||||||||||
Emera US Finance LP [Member] | U.S. Notes [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Face Amount | $ | $ 3,250 | |||||||||||
Emera US Finance LP [Member] | U.S. Notes, Due 2019 [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.15% | 2.15% | ||||||||||
Debt Instrument, Face Amount | $ | $ 500 | |||||||||||
Emera US Finance LP [Member] | U.S. Notes, Due 2021 [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.70% | 2.70% | ||||||||||
Debt Instrument, Face Amount | $ | $ 750 | |||||||||||
Emera US Finance LP [Member] | U.S. Notes, Due 2026 [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.55% | 3.55% | ||||||||||
Debt Instrument, Face Amount | $ | $ 750 | |||||||||||
Emera US Finance LP [Member] | U.S. Notes, Due 2046 [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | ||||||||||
Debt Instrument, Face Amount | $ | $ 1,250 | |||||||||||
Tampa Electric Division [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 2,579,000,000 | 0 | ||||||||||
Tampa Electric Division [Member] | Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | CAD 436,000,000 | $ 325 | ||||||||||
Line of Credit Facility, Expiration Date | Dec. 17, 2018 | |||||||||||
Tampa Electric Division [Member] | Unsecured Debt [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | 0 | |||||||||||
TECO Finance, Inc. [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term Debt, Gross | CAD 1,141,000,000 | CAD 0 | ||||||||||
TECO Finance, Inc. [Member] | Floating rate notes due 2018 [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of credit current borrowing capacity | $ | $ 250 | |||||||||||
TECO Finance, Inc. [Member] | Notes due 2045 [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.60% | |||||||||||
ECI [Member] | Line of Credit [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Line of credit current borrowing capacity | $ | $ 150 | |||||||||||
Line of Credit Facility, Expiration Date | Nov. 29, 2021 | |||||||||||
ECI [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 4.08% | |||||||||||
ECI [Member] | Notes due 2045 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.20% | |||||||||||
Debt Instrument, Face Amount | $ | $ 250 |
Asset Retirement Obligation (AR
Asset Retirement Obligation (ARO Roll Forward) (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance, January 1 | CAD 109 | CAD 106 | |
Additions | [1] | 48 | 0 |
Additions due to acquisition | 9 | 0 | |
Liabilities settled | (2) | (2) | |
Asset Retirement Obligation, Accretion Expense | 7 | 8 | |
Asset Retirement Obligation, Accretion Expense Deferred To Regulatory Asset | (2) | (8) | |
Asset Retirement Obligation, Revision of Estimate | 1 | 5 | |
Balance, December 31 | CAD 170 | CAD 109 | |
[1] | Tampa Electric produces ash and other by-products known as coal combustion residuals ("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 Environmental Cost Recovery Clause. However, additional petitions will be submitted for recovery of future project expenses based on engineering studies currently being performed. |
Commitments and Contingencie157
Commitments and Contingencies (Contractual Obligations) (Details) CAD in Millions | Dec. 31, 2016CAD | |
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | CAD 1,793 | |
Contractual Obligation, Due in Second Year | 897 | |
Contractual Obligation, Due in Third Year | 719 | |
Contractual Obligation, Due in Fourth Year | 766 | |
Contractual Obligation, Due in Fifth Year | 466 | |
Contractual Obligation, Due after Fifth Year | 4,191 | |
Contractual Obligation | 8,832 | |
Purchased Power [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 253 | [1] |
Contractual Obligation, Due in Second Year | 224 | [1] |
Contractual Obligation, Due in Third Year | 206 | [1] |
Contractual Obligation, Due in Fourth Year | 202 | [1] |
Contractual Obligation, Due in Fifth Year | 198 | [1] |
Contractual Obligation, Due after Fifth Year | 2,272 | [1] |
Contractual Obligation | 3,355 | [1] |
Fuel And Gas Supply [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 475 | |
Contractual Obligation, Due in Second Year | 161 | |
Contractual Obligation, Due in Third Year | 109 | |
Contractual Obligation, Due in Fourth Year | 28 | |
Contractual Obligation, Due in Fifth Year | 22 | |
Contractual Obligation, Due after Fifth Year | 0 | |
Contractual Obligation | 795 | |
Demand Side Management [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 42 | |
Contractual Obligation, Due in Second Year | 48 | |
Contractual Obligation, Due in Third Year | 13 | |
Contractual Obligation, Due in Fourth Year | 0 | |
Contractual Obligation, Due in Fifth Year | 0 | |
Contractual Obligation, Due after Fifth Year | 0 | |
Contractual Obligation | 103 | |
Transportation [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 496 | [2] |
Contractual Obligation, Due in Second Year | 392 | [2] |
Contractual Obligation, Due in Third Year | 310 | [2] |
Contractual Obligation, Due in Fourth Year | 280 | [2] |
Contractual Obligation, Due in Fifth Year | 196 | [2] |
Contractual Obligation, Due after Fifth Year | 1,622 | [2] |
Contractual Obligation | 3,296 | [2] |
Long-term service agreements [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 92 | [3] |
Contractual Obligation, Due in Second Year | 55 | [3] |
Contractual Obligation, Due in Third Year | 67 | [3] |
Contractual Obligation, Due in Fourth Year | 44 | [3] |
Contractual Obligation, Due in Fifth Year | 42 | [3] |
Contractual Obligation, Due after Fifth Year | 227 | [3] |
Contractual Obligation | 527 | [3] |
Capital projects [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 133 | |
Contractual Obligation, Due in Second Year | 0 | |
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 | 133 | |
Equity investment commitments [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 236 | [4] |
Contractual Obligation, Due in Second Year | 0 | [4] |
Contractual Obligation, Due in Third Year | 0 | [4] |
Contractual Obligation, Due in Fourth Year | 200 | [4] |
Contractual Obligation, Due in Fifth Year | 0 | [4] |
Contractual Obligation, Due after Fifth Year | 0 | [4] |
Contractual Obligation | 436 | [4] |
Leases and other [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Obligation, Due in Next Fiscal Year | 66 | [5] |
Contractual Obligation, Due in Second Year | 17 | [5] |
Contractual Obligation, Due in Third Year | 14 | [5] |
Contractual Obligation, Due in Fourth Year | 12 | [5] |
Contractual Obligation, Due in Fifth Year | 8 | [5] |
Contractual Obligation, Due after Fifth Year | 70 | [5] |
Contractual Obligation | CAD 187 | [5] |
[1] | Annual requirement to purchase electricity production from independent power producers 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 ("FLG") 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 Contingencie158
Commitments and Contingencies (Legal Proceedings) (Details) CAD in Millions, $ in Millions | Apr. 29, 2016 | Mar. 22, 2016 | Jun. 19, 2014 | Dec. 19, 2013USD ($) | Sep. 30, 2011 | Jun. 30, 2016 | Mar. 31, 2014 | Dec. 31, 2012 | Sep. 30, 2016CAD | Sep. 30, 2016USD ($) | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) |
Tampa Electric And Peoples Gas Division [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Loss Contingency, Estimate of Possible Loss | CAD 43 | $ 32 | ||||||||||
Emera Maine [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.57% | 11.14% | 10.57% | 10.57% | 11.74% | |||||||
Emera Maine [Member] | ENE Case [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Loss Contingency, Estimate of Possible Loss | CAD 5 | $ 4 | ||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.59% | |||||||||||
Emera Maine [Member] | ENE Case [Member] | Maximum [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.42% | |||||||||||
Emera Maine [Member] | MA AG II Case [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Loss Contingency, Estimate of Possible Loss | CAD 7 | $ 5 | ||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.90% | |||||||||||
Emera Maine [Member] | MA AG II Case [Member] | Maximum [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 12.19% | |||||||||||
Emera Maine [Member] | Eastern Massachusetts Consumer Owned Systems [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 8.61% | |||||||||||
Emera Maine [Member] | Eastern Massachusetts Consumer Owned Systems [Member] | Maximum [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 11.24% | |||||||||||
TECO Guatemala Holdings [Member] | Prime Rate [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Litigation Settlement, Amount | $ 21 | |||||||||||
Public Utilities, Approved Return on Equity, Percentage | 2.00% |
Commitments and Contingencie159
Commitments and Contingencies (Environmental Accruals) (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accrual for Environmental Loss Contingencies Disclosure [Abstract] | |||
Asset Retirement Obligation | CAD 170 | CAD 109 | CAD 106 |
Nova Scotia Power Inc. [Member] | |||
Accrual for Environmental Loss Contingencies Disclosure [Abstract] | |||
Accrual for Environmental Loss Contingencies, Undiscounted, Next Twelve Months | 41 | ||
Accrual for Environmental Loss Contingencies, Undiscounted, Second Year Through Fifth Year | CAD 41 | ||
Carbon Emission Reduction Targets [Abstract] | |||
Per cent non-emitting generation sources | 90.00% | ||
Canada's target per cent reduction under the Paris Agreement | 30.00% | ||
Polychlorinated Biphenyl (PCB) Regulations [Member] | Nova Scotia Power Inc. [Member] | |||
Accrual for Environmental Loss Contingencies Disclosure [Abstract] | |||
Accrual for Environmental Loss Contingencies | CAD 43 | ||
Accrual for Environmental Loss Contingencies, Payments | 28 | 20 | |
Asset Retirement Obligation | CAD 11 | CAD 15 |
Commitments and Contingencie160
Commitments and Contingencies (Principal Risks and Uncertainties) (Details) CAD in Millions, $ in Billions | Jul. 01, 2016CAD | Jul. 01, 2016USD ($) | Dec. 31, 2016CAD | Dec. 31, 2015CAD |
Loss Contingencies [Line Items] | ||||
Public Utilities, Property, Plant and Equipment, Net | CAD 15,886 | CAD 6,258 | ||
Total Debt | CAD 15,000 | |||
TECO Energy Inc [Member] | ||||
Loss Contingencies [Line Items] | ||||
Business Combination, Consideration Transferred | CAD 13,900 | $ 10.7 |
Commitments and Contingencie161
Commitments and Contingencies (Guarantees and Letters of Credit) (Details) CAD in Millions, $ in Millions | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | Dec. 13, 2016CAD | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) |
Guarantor Obligations [Line Items] | |||||
Guaranty Liabilities | CAD 1,577 | ||||
Guarantee Obligations Current Carrying Value | 577 | ||||
Letters of Credit Outstanding, Amount | CAD 37 | CAD 33 | |||
Other Assets, Noncurrent, Total | 9,420 | 2,974 | |||
TECO Energy Inc [Member] | |||||
Guarantor Obligations [Line Items] | |||||
Letters of Credit Outstanding, Amount | 80 | $ 59 | CAD 124 | $ 95 | |
Financial Standby Letter of Credit [Member] | Emera Inc | Bear Swamp Power Company Limited Liability Company [Member] | |||||
Guarantor Obligations [Line Items] | |||||
Letters of Credit Outstanding, Amount | $ | 24 | ||||
Financial Standby Letter of Credit [Member] | TECO Coal [Member] | |||||
Guarantor Obligations [Line Items] | |||||
Repayments of Lines of Credit with Bonds on Divestiture of Subsisdiary | 54 | $ 40 | |||
Financial Standby Letter of Credit [Member] | Nova Scotia Power Inc. [Member] | Pension Plan [Member] | |||||
Guarantor Obligations [Line Items] | |||||
Letters of Credit Outstanding, Amount | CAD 47 |
Cumulative Preferred Stock (Nar
Cumulative Preferred Stock (Narrative) (Details) - CAD CAD / shares in Units, CAD in Millions | Aug. 17, 2015 | Dec. 31, 2016 | Dec. 31, 2015 |
Class of Stock [Line Items] | |||
Net Proceeds from Issuance of Redeemable Preferred Stock | CAD 709 | CAD 709 | |
Number of shares issued and outstanding | 29,000,000 | 29,000,000 | |
Series A Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Number of redeemable preferred shares issued | 6,000,000 | 3,864,636 | |
Conversion of Stock, Shares Converted | 2,135,364 | ||
Number of shares issued and outstanding | 6,000,000 | 3,864,636 | |
Annual Dividend Per Share | CAD 0.6388 | ||
Amount per share used to determine dividend per share | CAD 25 | ||
Term of Canada government bond yield | 5 years | ||
Series A Preferred Stock [Member] | Up To And Excluding August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 0.6388 | ||
Percentage rate used to determine dividend rate | 1.84% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series A Preferred Stock [Member] | Up To And Excluding August 15, 2018 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.025 | ||
Percentage rate used to determine dividend rate | 2.65% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series A Preferred Stock [Member] | Up To And Excluding February 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.0625 | ||
Percentage rate used to determine dividend rate | 2.63% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series B Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Number of redeemable preferred shares issued | 2,135,364 | ||
Number of shares issued and outstanding | 2,135,364 | ||
Annual Dividend Per Share | CAD 0.5724 | ||
Amount per share used to determine dividend per share | CAD 25 | ||
Percentage rate used to determine dividend rate | 1.84% | ||
Series B Preferred Stock [Member] | August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | CAD 25 | ||
Series B Preferred Stock [Member] | August 15, 2023 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25 | ||
Series B Preferred Stock [Member] | February 15, 2025 [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 B Preferred Stock [Member] | After August 15, 2018 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series B Preferred Stock [Member] | After February 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series C Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Amount per share used to determine dividend per share | CAD 25 | ||
Term of Canada government bond yield | 5 years | ||
Series C Preferred Stock [Member] | Up To And Excluding August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 0.6388 | ||
Percentage rate used to determine dividend rate | 1.84% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series C Preferred Stock [Member] | Up To And Excluding August 15, 2018 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.025 | ||
Percentage rate used to determine dividend rate | 2.65% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series C Preferred Stock [Member] | Up To And Excluding February 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.0625 | ||
Percentage rate used to determine dividend rate | 2.63% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series F Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Amount per share used to determine dividend per share | CAD 25 | ||
Term of Canada government bond yield | 5 years | ||
Series F Preferred Stock [Member] | Up To And Excluding August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 0.6388 | ||
Percentage rate used to determine dividend rate | 1.84% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series F Preferred Stock [Member] | Up To And Excluding August 15, 2018 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.025 | ||
Percentage rate used to determine dividend rate | 2.65% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series F Preferred Stock [Member] | Up To And Excluding February 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Annual Dividend Per Share | CAD 1.0625 | ||
Percentage rate used to determine dividend rate | 2.63% | ||
Outstanding share redemption price per share | CAD 25 | ||
Series D Preferred Stock [Member] | August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
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] | February 15, 2025 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25 | ||
Series D Preferred Stock [Member] | After August 15, 2015 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series D Preferred Stock [Member] | After August 15, 2018 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series D Preferred Stock [Member] | After February 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series G Preferred Stock [Member] | August 15, 2020 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25 | ||
Series G Preferred Stock [Member] | August 15, 2023 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25 | ||
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 August 15, 2015 [Member] | |||
Class of Stock [Line Items] | |||
Outstanding share redemption price per share | 25.5 | ||
Series G 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] | 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] | |||
Annual Dividend Per Share | 1.125 | ||
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 | CAD 25 |
Cumulative Preferred Stock (Det
Cumulative Preferred Stock (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Aug. 17, 2015 | |
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 | CAD 709 | CAD 709 | |
Series A Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 0.6388 | ||
Preferred Stock, Shares Outstanding | 3,864,636 | 6,000,000 | |
Series A Preferred Stock [Member] | TECO Energy Inc [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 0.6388 | ||
Preferred Stock, Redemption Price Per Share | CAD 25 | ||
Preferred Stock, Shares Outstanding | 3,864,636 | 3,864,636 | |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | CAD 95 | CAD 95 | |
Series B Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 0.5724 | ||
Preferred Stock, Shares Outstanding | 2,135,364 | ||
Series B Preferred Stock [Member] | TECO Energy Inc [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Redemption Price Per Share | CAD 25 | ||
Preferred Stock, Shares Outstanding | 2,135,364 | 2,135,364 | |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | CAD 52 | CAD 52 | |
Dividends Payable Nature | Floating | ||
Series C Preferred Stock [Member] | TECO Energy Inc [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 1.025 | ||
Preferred Stock, Redemption Price Per Share | CAD 25 | ||
Preferred Stock, Shares Outstanding | 10,000,000 | 10,000,000 | |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | CAD 245 | CAD 245 | |
Series E Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 1.125 | ||
Series E Preferred Stock [Member] | TECO Energy Inc [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | 1.125 | ||
Preferred Stock, Redemption Price Per Share | CAD 26 | ||
Preferred Stock, Shares Outstanding | 5,000,000 | 5,000,000 | |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | CAD 122 | CAD 122 | |
Series F Preferred Stock [Member] | TECO Energy Inc [Member] | |||
Class of Stock [Line Items] | |||
Preferred Stock, Dividends Per Share, Declared | CAD 1.0625 | ||
Preferred Stock, Redemption Price Per Share | CAD 25 | ||
Preferred Stock, Shares Outstanding | 8,000,000 | 8,000,000 | |
Proceeds From Issuance Of Preferred Stock And Preference Stock Net | CAD 195 | CAD 195 |
Non-controlling Interest In 164
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, 2016BSD / shares | |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Redemption Price Per Share | BSD 1,000 |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend | 7.25% |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, Next Three Years | 8.50% |
Preferred Stock Per Cent Per Annum Fixed Cumulative Preferential Dividend, Four Fiscal Years Thereafter | 10.00% |
Non-controlling Interest In 165
Non-controlling Interest In Subsidiaries (Non-controlling interest in subsidiaries ) (Details) - CAD shares in Millions, CAD in Millions | Dec. 17, 2015 | Dec. 31, 2016 | Mar. 22, 2016 | Dec. 31, 2015 | |
Noncontrolling Interest [Line Items] | |||||
Stockholders' Equity Attributable to Noncontrolling Interest | CAD 112 | CAD 134 | |||
Icd Utilities Limited [Member] | |||||
Noncontrolling Interest [Line Items] | |||||
Stockholders' Equity Attributable to Noncontrolling Interest | CAD 53 | 52 | |||
Emera (Caribbean) Incorporated Parent [Member] | |||||
Noncontrolling Interest [Line Items] | |||||
Stockholders' Equity Attributable to Noncontrolling Interest | [1] | CAD 25 | |||
Indirect Wholly-owned Subsidiary, Shares Acquired | 2.6 | 0.7 | |||
Equity Method Investment, Ownership Percentage | 95.50% | 80.70% | |||
Controlling Interest Ownership Percentage By Parent | 100.00% | 95.50% | 95.50% | ||
Grand Bahama Power Company Limited [Member] | |||||
Noncontrolling Interest [Line Items] | |||||
Noncontrolling Interest, Amount Represented by Preferred Stock | CAD 34 | CAD 34 | |||
Dominica Electricity Services Ltd. [Member] | |||||
Noncontrolling Interest [Line Items] | |||||
Stockholders' Equity Attributable to Noncontrolling Interest | CAD 25 | CAD 23 | |||
Noncontrolling Interest, Ownership Percentage by Parent | 51.90% | ||||
[1] | (1) On December 17, 2015, an indirect wholly owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent. On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares (which owns 51.9 per cent share of Domlec), increasing Emera's ownership interest in ECI from 95.5 to 100 per cent. |
Non-controlling Interest In 166
Non-controlling Interest In Subsidiaries (Preferred Shares Authorized) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Noncontrolling Interest [Line Items] | ||
Number of shares issued and outstanding | 29,000,000 | 29,000,000 |
Nova Scotia Power Inc. [Member] | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized, Unlimited | Unlimited | |
Number of shares issued and outstanding | 0 | 0 |
Preferred Stock Value Outstanding | CAD 0 | CAD 0 |
Grand Bahama Power Company Limited [Member] | Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares [Member] | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized | 35,000,000,000 | |
Number of shares issued and outstanding | 35,000,000,000 | 35,000,000,000 |
Preferred Stock Value Outstanding | CAD 34 | CAD 34 |
Supplementary Information To Co
Supplementary Information To Consolidated Statements Of Cash Flows (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) in Operating Capital [Abstract] | ||
Increase (Decrease) in Accounts Receivable | CAD (104) | CAD (19) |
Increase (Decrease) in Income Taxes Receivable | (23) | (22) |
Increase (Decrease) in Inventories | 88 | (2) |
Increase (Decrease) in Other Current Assets | (18) | 9 |
Increase (Decrease) in Accounts Payable | 162 | (45) |
Increase (Decrease) in Income Taxes Payable | 14 | (32) |
Increase (Decrease) in Other Current Liabilities | 15 | 9 |
Increase (Decrease) in Operating Capital, Total | (134) | 102 |
Interest Paid | 480 | 196 |
Income Taxes Paid, Net | 57 | 124 |
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | ||
Stock Issued During Period, Value, Dividend Reinvestment Plan | 103 | 78 |
Debt Instrument, Convertible, Beneficial Conversion Feature | CAD 43 | CAD 0 |
Stock-based Compensation (Narra
Stock-based Compensation (Narrative) (Details) - CAD | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock Issued During Period, Shares, Conversion of Units | 51,990,000 | 0 | |
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 | 4,000,000 | |
Allocated Share-based Compensation Expense | CAD 1,000,000 | CAD 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 | CAD 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 | CAD 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 | 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 | CAD 2,000,000 | 1,000,000 | |
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Cash Received | 16,000,000 | 2,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value | CAD 13,000,000 | CAD 1,000,000 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit | CAD 20.42 | CAD 19.88 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Upper Range Limit | CAD 46.19 | CAD 42.71 | |
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 | CAD 8,000,000 | CAD 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 | CAD 3,000,000 | 3,000,000 | |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | CAD 0 | CAD 0 | 1,000,000 |
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 | CAD 11,000,000 | 10,000,000 | |
Number Of Trading Days | 50 days | ||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | CAD 4,000,000 | CAD 3,000,000 | |
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) - CAD / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Stock-Based Compensation [Abstract] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | CAD 2.8 | CAD 2.66 |
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 | 0.66% | 0.73% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 4.08% | 3.65% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 15.45% | 14.58% |
Stock-based Compensatin (Stock
Stock-based Compensatin (Stock Options) (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
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 | 620,000 | 80,000 | |
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 | 620,000 | 80,000 | |
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 | CAD 2.8 | CAD 2.66 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options | CAD 3 | CAD 3 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years 4 months 24 days | 2 years 3 months 18 days | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 5 years 8 months 21 days | 5 years 3 months 18 days | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | CAD 21 | CAD 17 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value | CAD 2 | CAD 1 | |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Beginning Balance | 2,927,068 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | 615,100 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | (622,168) | ||
Ending Balance | 2,920,000 | 2,927,068 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number | [1],[2] | 1,399,875 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract] | |||
Beginning Balance | CAD 33.07 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price | 46.19 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | 25.65 | ||
Ending Balance | 37.42 | CAD 33.07 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price | [1],[2] | CAD 33.35 | |
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 | 615,100 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | (622,168) | ||
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 | CAD 25.65 | ||
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] | 615,100 | |
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 | CAD 2.8 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | |||
Beginning Balance | [3] | 1,453,486 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | [3] | 615,100 | |
Sharebased Compensation Arrangement By Sharebased Payment Award Options Nonvested Options Forfeited Number Of Shares | [3] | (548,461) | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares | [3] | 0 | |
Ending Balance | [3] | 1,520,125 | 1,453,486 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Beginning Balance | CAD 2.64 | ||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | 2.8 | ||
Sharebased Compensation Arrangement By Sharebased Payment Award Options Nonvested Options Forfeited Weighted Average Grant Date Fair Value | 2.68 | ||
Ending Balance | CAD 2.69 | CAD 2.64 | |
Stock Option Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years 3 months 18 days | 2 years 6 months | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 2 years 3 months 18 days | 5 years 6 months | |
[1] | As at December 31, 2016 the fair value of options that vested in the year was $2 million (2015 - $1 million). | ||
[2] | As at December 31, 2016, the weighted average remaining term of vested options was 5.7 years with an aggregate intrinsic value of $17 million (2015 - 5.3 years, $21 million). | ||
[3] | As at December 31, 2016 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 2.4 years (2015 - $3 million, 2.3 years). |
Stock-based Compensation (Emplo
Stock-based Compensation (Employee and Director DSUs ) (Details) | 12 Months Ended |
Dec. 31, 2016CAD / sharesshares | |
Employee [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 606,646 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 74,855 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 570 |
Ending Balance | shares | 680,931 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | CAD / shares | CAD 26.27 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | CAD / shares | 37.6 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | CAD / shares | 46.58 |
Ending Balance | CAD / shares | CAD 27.5 |
Director [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 362,750 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 69,429 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 36,381 |
Ending Balance | shares | 395,798 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | CAD / shares | CAD 31.36 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | CAD / shares | 43.67 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | CAD / shares | 27.42 |
Ending Balance | CAD / shares | CAD 33.88 |
Performance Share Unit Plan [Member] | Employee [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |
Beginning Balance | shares | 497,496 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares | 280,950 |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | shares | 208,999 |
Ending Balance | shares | 560,880 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Beginning Balance | CAD / shares | CAD 34.5 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | CAD / shares | 40.6 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | CAD / shares | 34.39 |
Ending Balance | CAD / shares | CAD 37.55 |
Stock-based Compensation (Em172
Stock-based Compensation (Employee PSUs) (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Employee [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | ||
Beginning Balance | 606,646 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 74,855 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | 570 | |
Ending Balance | 680,931 | 606,646 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Beginning Balance | CAD 26.27 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | 37.6 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | 46.58 | |
Ending Balance | CAD 27.5 | CAD 26.27 |
Performance Share Unit Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract] | ||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | CAD 4 | CAD 3 |
Performance Share Unit Plan [Member] | Employee [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | ||
Beginning Balance | 497,496 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 280,950 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised | 208,999 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures | 8,567 | |
Ending Balance | 560,880 | 497,496 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Beginning Balance | CAD 34.5 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | 40.6 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Exercises in Period, Weighted Average Grant Date Fair Value | 34.39 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | 37.54 | |
Ending Balance | CAD 37.55 | CAD 34.5 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract] | ||
Beginning Balance | CAD 21.5 | |
Ending Balance | CAD 25.5 | CAD 21.5 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - Emera Inc - NSP Maritime Link Inc. [Member] - Available-for-sale Investment and Restricted Cash [Member] - CAD CAD in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Variable Interest Entity [Line Items] | ||
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets | CAD 315 | CAD 188 |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | CAD 577 | CAD 1,007 |
SUPPLEMENTAL FINANCIAL INFOR174
SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statements of Income) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues [Abstract] | ||
Regulated electric | CAD 3,437 | CAD 2,141 |
Regulated | 499 | 52 |
Non-regulated | 341 | 596 |
Total operating revenues | 4,277 | 2,789 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 1,222 | 815 |
Regulated cost of natural gas | 177 | 0 |
Regulated fuel adjustment | 61 | 42 |
Non-regulated fuel for generation and purchased power | 313 | 336 |
Non-regulated direct costs | 29 | 19 |
Operating, maintenance and general | 1,137 | 666 |
Provincial, state, and municipal taxes | 195 | 63 |
Depreciation and amortization | 588 | 340 |
Total operating expenses | 3,722 | 2,281 |
Operating Income (Loss) | 555 | 508 |
Income from equity investments | 100 | 108 |
Other income (expenses), net | 174 | 141 |
Interest expense, net | (585) | (212) |
Income before provision for income taxes | 244 | 545 |
Income tax expense (recovery) | (22) | 93 |
Net income | 266 | 452 |
Non-controlling interest in subsidiaries | 11 | 25 |
Net income of Emera Incorporated | 255 | 427 |
Preferred stock dividends | 28 | 30 |
Net income attributable to common shareholders | 227.2 | 397.2 |
Comprehensive income attributable to common shareholders | 228 | 911 |
Consolidation, Eliminations [Member] | ||
Revenues [Abstract] | ||
Regulated electric | (2) | (2) |
Regulated | 0 | 0 |
Non-regulated | (33) | (42) |
Total operating revenues | (35) | (44) |
Operating expenses | ||
Regulated fuel for generation and purchased power | 0 | 0 |
Regulated cost of natural gas | 0 | 0 |
Regulated fuel adjustment | 0 | 0 |
Non-regulated fuel for generation and purchased power | (4) | (5) |
Non-regulated direct costs | (23) | (30) |
Operating, maintenance and general | (8) | (8) |
Provincial, state, and municipal taxes | 0 | 0 |
Depreciation and amortization | 0 | 0 |
Total operating expenses | (35) | (43) |
Operating Income (Loss) | 0 | (1) |
Income (Loss) from Subsidiaries, before Tax | (150) | (270) |
Income from equity investments | 0 | 0 |
Intercompany income (expenses), net | (46) | (164) |
Other income (expenses), net | 0 | 0 |
Interest expense, net | 0 | (134) |
Income before provision for income taxes | (196) | (301) |
Income tax expense (recovery) | 0 | 0 |
Net income | (196) | (301) |
Non-controlling interest in subsidiaries | 4 | 12 |
Net income of Emera Incorporated | (200) | (313) |
Preferred stock dividends | (50) | (41) |
Net income attributable to common shareholders | (150) | (272) |
Comprehensive income attributable to common shareholders | (283) | (755) |
Parent Company [Member] | ||
Revenues [Abstract] | ||
Regulated electric | 0 | 0 |
Regulated | 0 | 0 |
Non-regulated | 0 | 0 |
Total operating revenues | 0 | 0 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 0 | 0 |
Regulated cost of natural gas | 0 | 0 |
Regulated fuel adjustment | 0 | 0 |
Non-regulated fuel for generation and purchased power | 0 | 0 |
Non-regulated direct costs | 0 | 0 |
Operating, maintenance and general | 37 | 54 |
Provincial, state, and municipal taxes | 0 | 0 |
Depreciation and amortization | 2 | 1 |
Total operating expenses | 39 | 55 |
Operating Income (Loss) | (39) | (55) |
Income (Loss) from Subsidiaries, before Tax | 150 | 270 |
Income from equity investments | 18 | 37 |
Intercompany income (expenses), net | 203 | 156 |
Other income (expenses), net | 135 | 91 |
Interest expense, net | 226 | 46 |
Income before provision for income taxes | 241 | 453 |
Income tax expense (recovery) | (14) | 25 |
Net income | 255 | 428 |
Non-controlling interest in subsidiaries | 0 | 0 |
Net income of Emera Incorporated | 255 | 428 |
Preferred stock dividends | 28 | 30 |
Net income attributable to common shareholders | 227 | 398 |
Comprehensive income attributable to common shareholders | 228 | 911 |
Subsidiary Issuer [Member] | ||
Revenues [Abstract] | ||
Regulated electric | 0 | 0 |
Regulated | 0 | 0 |
Non-regulated | 0 | 0 |
Total operating revenues | 0 | 0 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 0 | 0 |
Regulated cost of natural gas | 0 | 0 |
Regulated fuel adjustment | 0 | 0 |
Non-regulated fuel for generation and purchased power | 0 | 0 |
Non-regulated direct costs | 0 | 0 |
Operating, maintenance and general | 0 | 0 |
Provincial, state, and municipal taxes | 0 | 0 |
Depreciation and amortization | 0 | 0 |
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 | 101 | 0 |
Other income (expenses), net | 0 | 0 |
Interest expense, net | 85 | 0 |
Income before provision for income taxes | 16 | 0 |
Income tax expense (recovery) | 7 | 0 |
Net income | 9 | 0 |
Non-controlling interest in subsidiaries | 0 | 0 |
Net income of Emera Incorporated | 9 | 0 |
Preferred stock dividends | 0 | 0 |
Net income attributable to common shareholders | 9 | 0 |
Comprehensive income attributable to common shareholders | 19 | 0 |
Guarantor Subsidiaries [Member] | ||
Revenues [Abstract] | ||
Regulated electric | 1,665 | 283 |
Regulated | 451 | 0 |
Non-regulated | 378 | 419 |
Total operating revenues | 2,494 | 702 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 560 | 70 |
Regulated cost of natural gas | 177 | 0 |
Regulated fuel adjustment | 0 | 0 |
Non-regulated fuel for generation and purchased power | 261 | 277 |
Non-regulated direct costs | 0 | 0 |
Operating, maintenance and general | 647 | 148 |
Provincial, state, and municipal taxes | 152 | 21 |
Depreciation and amortization | 330 | 79 |
Total operating expenses | 2,127 | 595 |
Operating Income (Loss) | 367 | 107 |
Income (Loss) from Subsidiaries, before Tax | 0 | 0 |
Income from equity investments | 0 | 5 |
Intercompany income (expenses), net | (107) | 0 |
Other income (expenses), net | 24 | 21 |
Interest expense, net | 127 | 28 |
Income before provision for income taxes | 157 | 105 |
Income tax expense (recovery) | 48 | 35 |
Net income | 109 | 70 |
Non-controlling interest in subsidiaries | 0 | 0 |
Net income of Emera Incorporated | 109 | 70 |
Preferred stock dividends | 31 | 15 |
Net income attributable to common shareholders | 78 | 55 |
Comprehensive income attributable to common shareholders | 205 | 303 |
Non-Guarantor Subsidiaries [Member] | ||
Revenues [Abstract] | ||
Regulated electric | 1,774 | 1,860 |
Regulated | 48 | 52 |
Non-regulated | (4) | 219 |
Total operating revenues | 1,818 | 2,131 |
Operating expenses | ||
Regulated fuel for generation and purchased power | 662 | 745 |
Regulated cost of natural gas | 0 | 0 |
Regulated fuel adjustment | 61 | 42 |
Non-regulated fuel for generation and purchased power | 56 | 64 |
Non-regulated direct costs | 52 | 49 |
Operating, maintenance and general | 461 | 472 |
Provincial, state, and municipal taxes | 43 | 42 |
Depreciation and amortization | 256 | 260 |
Total operating expenses | 1,591 | 1,674 |
Operating Income (Loss) | 227 | 457 |
Income (Loss) from Subsidiaries, before Tax | 0 | 0 |
Income from equity investments | 82 | 66 |
Intercompany income (expenses), net | (151) | 8 |
Other income (expenses), net | 15 | 29 |
Interest expense, net | 147 | 272 |
Income before provision for income taxes | 26 | 288 |
Income tax expense (recovery) | (63) | 33 |
Net income | 89 | 255 |
Non-controlling interest in subsidiaries | 7 | 13 |
Net income of Emera Incorporated | 82 | 242 |
Preferred stock dividends | 19 | 26 |
Net income attributable to common shareholders | 63 | 216 |
Comprehensive income attributable to common shareholders | CAD 59 | CAD 452 |
SUPPLEMENTAL FINANCIAL INFOR175
SUPPLEMENTAL FINANCIAL INFORMATION (Condensed Consolidated Statement of Financial Position) (Details) - CAD CAD in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | CAD 404,000 | CAD 1,073,000 | CAD 221,000 |
Restricted Cash and Cash Equivalents, Current | 87,000 | 19,000 | |
Receivables, Net, Current | 1,014,000 | 578,000 | |
Income Taxes Receivable, Current | 33,000 | 12,000 | |
Inventory, Net | 472,000 | 314,000 | |
Derivative Instruments and Hedges, Assets | 145,000 | 250,000 | |
Regulatory Assets, Current | 80,000 | 94,000 | |
Other Assets, Current | 276,000 | 256,000 | |
Total current assets | 2,511,000 | 2,596,000 | |
Property, Plant and Equipment, Net | 17,290,000 | 6,469,000 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 48,000 | 49,000 | |
Deferred income taxes | 125,000 | 32,000 | |
Derivative instruments | 131,000 | 168,000 | |
Pension and post-retirement assets | 9,000 | 9,000 | |
Regulatory assets | 1,242,000 | 605,000 | |
Net investment in direct financing lease | 488,000 | 480,000 | |
Investments subject to significant influence | 947,000 | 1,145,000 | |
Available-for-sale investment | 48,000 | 116,000 | |
Goodwill | 6,213,000 | 264,000 | 222,000 |
Due from related parties | 0 | 0 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 169,000 | 106,000 | |
Total other assets | 9,420,000 | 2,974,000 | |
Assets, Total | 29,221,000 | 12,039,000 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 961,000 | 16,000 | |
Current portion of long-term debt | 476,000 | 274,000 | |
Accounts payable | 1,242,000 | 394,000 | |
Income taxes payable | 19,000 | 8,000 | |
Derivative instruments | 325,000 | 349,000 | |
Regulatory liabilities | 362,000 | 112,000 | |
Pension and post-retirement liabilities | 58,000 | 7,000 | |
Other current liabilities | 281,000 | 207,000 | |
Total current liabilities | 3,724,000 | 1,367,000 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 14,268,000 | 3,735,000 | |
Intercompany long term debt | 0 | 0 | |
Deferred income taxes | 1,672,000 | 762,000 | |
Convertible debentures (2015 represented by instalment receipts) | 8,000 | 681,000 | |
Derivative instruments | 150,000 | 96,000 | |
Regulatory liabilities | 1,277,000 | 353,000 | |
Asset retirement obligations | 170,000 | 109,000 | |
Pension and post-retirement liabilities | 669,000 | 303,000 | |
Other long-term liabilities | 467,000 | 299,000 | |
Total long-term liabilities | 18,681,000 | 6,338,000 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 4,738,000 | 2,157,000 | 2,016,000 |
Preferred Stock, Value, Issued | 709,000 | 709,000 | |
Contributed surplus | 75,000 | 29,000 | |
Accumulated other comprehensive Income | 106,000 | 137,000 | |
Retained earnings | 1,076,000 | 1,168,000 | |
Total Emera Incorporated equity | 6,704,000 | 4,200,000 | |
Non-controlling interest in subsidiaries | 112,000 | 134,000 | |
Total equity | 6,816,000 | 4,334,000 | CAD 3,705,000 |
Liabilities and Equity, Total | 29,221,000 | 12,039,000 | |
Consolidation, Eliminations [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 0 | (14,000) | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
Receivables, Net, Current | 0 | 0 | |
AccountsReceivableRelatedPartiesCurrent | (646,000) | (248,000) | |
Income Taxes Receivable, Current | 0 | 0 | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | (13,000) | (17,000) | |
Regulatory Assets, Current | 0 | 0 | |
Prepaid Expense, Current | 0 | 0 | |
Due from Related Parties, Current | 0 | 0 | |
Other Assets, Current | 0 | 0 | |
Total current assets | (659,000) | (279,000) | |
Property, Plant and Equipment, Net | 0 | 0 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 0 | 0 | |
Deferred income taxes | (38,000) | (34,000) | |
Derivative instruments | (12,000) | (34,000) | |
Pension and post-retirement assets | 0 | 0 | |
Regulatory assets | 0 | 0 | |
Net investment in direct financing lease | 0 | 0 | |
Investments In Subsidiaries | (8,349,000) | (6,042,000) | |
Investments subject to significant influence | 0 | 0 | |
Available-for-sale investment | 0 | 0 | |
Goodwill | 0 | 0 | |
Due from related parties | 0 | 0 | |
Intercompany notes receivable | (6,504,000) | (5,805,000) | |
Other investments - intercompany | (2,270,000) | (98,000) | |
Other long term assets | (19,000) | 0 | |
Total other assets | (17,192,000) | (12,013,000) | |
Assets, Total | (17,851,000) | (12,292,000) | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | (14,000) | |
Current portion of long-term debt | 0 | 0 | |
Accounts payable | 0 | 0 | |
Intercompany payable | (646,000) | 0 | |
Income taxes payable | 0 | (221,000) | |
Derivative instruments | (13,000) | (17,000) | |
Regulatory liabilities | 0 | 0 | |
Pension and post-retirement liabilities | 0 | 0 | |
Due to related party | 0 | 0 | |
Other current liabilities | 0 | 0 | |
Total current liabilities | (659,000) | (252,000) | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 0 | 0 | |
Intercompany long term debt | (6,501,000) | (5,823,000) | |
Deferred income taxes | (38,000) | (34,000) | |
Convertible debentures (2015 represented by instalment receipts) | 0 | 0 | |
Derivative instruments | (12,000) | (34,000) | |
Regulatory liabilities | 0 | 0 | |
Asset retirement obligations | 0 | 0 | |
Pension and post-retirement liabilities | 0 | 0 | |
Other long-term liabilities | (19,000) | 0 | |
Total long-term liabilities | (6,570,000) | (5,891,000) | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | (8,416,000) | (4,141,000) | |
Preferred Stock, Value, Issued | (891,000) | (696,000) | |
Contributed surplus | (151,000) | (178,000) | |
Accumulated other comprehensive Income | (159,000) | (76,000) | |
Retained earnings | (1,039,000) | (1,092,000) | |
Total Emera Incorporated equity | (10,656,000) | (6,183,000) | |
Non-controlling interest in subsidiaries | 34,000 | 34,000 | |
Total equity | (10,622,000) | (6,149,000) | |
Liabilities and Equity, Total | (17,851,000) | (12,292,000) | |
Parent Company [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 200,000 | 0 | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
Receivables, Net, Current | 1,000 | 2,000 | |
AccountsReceivableRelatedPartiesCurrent | 57,000 | 102,000 | |
Income Taxes Receivable, Current | 0 | 0 | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | 13,000 | 109,000 | |
Regulatory Assets, Current | 0 | 0 | |
Prepaid Expense, Current | 0 | 0 | |
Due from Related Parties, Current | 0 | 0 | |
Other Assets, Current | 2,000 | 9,000 | |
Total current assets | 273,000 | 222,000 | |
Property, Plant and Equipment, Net | 14,000 | 15,000 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 0 | 0 | |
Deferred income taxes | 31,000 | 0 | |
Derivative instruments | 12,000 | 35,000 | |
Pension and post-retirement assets | 0 | 0 | |
Regulatory assets | 0 | 0 | |
Net investment in direct financing lease | 0 | 0 | |
Investments In Subsidiaries | 8,349,000 | 6,042,000 | |
Investments subject to significant influence | 5,000 | 509,000 | |
Available-for-sale investment | 0 | 0 | |
Goodwill | 0 | 0 | |
Due from related parties | 0 | 0 | |
Intercompany notes receivable | 1,341,000 | 3,051,000 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 33,000 | 16,000 | |
Total other assets | 9,771,000 | 9,653,000 | |
Assets, Total | 10,058,000 | 9,890,000 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 14,000 | |
Current portion of long-term debt | 0 | 250,000 | |
Accounts payable | 6,000 | 17,000 | |
Intercompany payable | 534,000 | 0 | |
Income taxes payable | 0 | 52,000 | |
Derivative instruments | 14,000 | 17,000 | |
Regulatory liabilities | 0 | 0 | |
Pension and post-retirement liabilities | 0 | 0 | |
Due to related party | 0 | 0 | |
Other current liabilities | 54,000 | 51,000 | |
Total current liabilities | 608,000 | 401,000 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 2,338,000 | 464,000 | |
Intercompany long term debt | 366,000 | 2,631,000 | |
Deferred income taxes | 0 | 3,000 | |
Convertible debentures (2015 represented by instalment receipts) | 8,000 | 2,139,000 | |
Derivative instruments | 12,000 | 34,000 | |
Regulatory liabilities | 0 | 0 | |
Asset retirement obligations | 0 | 0 | |
Pension and post-retirement liabilities | 17,000 | 13,000 | |
Other long-term liabilities | 5,000 | 5,000 | |
Total long-term liabilities | 2,746,000 | 5,289,000 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 4,738,000 | 2,157,000 | |
Preferred Stock, Value, Issued | 709,000 | 709,000 | |
Contributed surplus | 75,000 | 29,000 | |
Accumulated other comprehensive Income | 106,000 | 137,000 | |
Retained earnings | 1,076,000 | 1,168,000 | |
Total Emera Incorporated equity | 6,704,000 | 4,200,000 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 6,704,000 | 4,200,000 | |
Liabilities and Equity, Total | 10,058,000 | 9,890,000 | |
Subsidiary Issuer [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 28,000 | 0 | |
Restricted Cash and Cash Equivalents, Current | 0 | 0 | |
Receivables, Net, Current | 0 | 0 | |
AccountsReceivableRelatedPartiesCurrent | 9,000 | 0 | |
Income Taxes Receivable, Current | 0 | 0 | |
Inventory, Net | 0 | 0 | |
Derivative Instruments and Hedges, Assets | 0 | 0 | |
Regulatory Assets, Current | 0 | 0 | |
Prepaid Expense, Current | 0 | 0 | |
Due from Related Parties, Current | 0 | 0 | |
Other Assets, Current | 0 | 0 | |
Total current assets | 37,000 | 0 | |
Property, Plant and Equipment, Net | 0 | 0 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 0 | 0 | |
Deferred income taxes | 0 | 0 | |
Derivative instruments | 0 | 0 | |
Pension and post-retirement assets | 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 | |
Available-for-sale investment | 0 | 0 | |
Goodwill | 0 | 0 | |
Due from related parties | 0 | 0 | |
Intercompany notes receivable | 4,558,000 | 0 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 0 | 0 | |
Total other assets | 4,558,000 | 0 | |
Assets, Total | 4,595,000 | 0 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 0 | 0 | |
Current portion of long-term debt | 0 | 0 | |
Accounts payable | 0 | 0 | |
Intercompany payable | 6,000 | 0 | |
Income taxes payable | 6,000 | 0 | |
Derivative instruments | 0 | 0 | |
Regulatory liabilities | 0 | 0 | |
Pension and post-retirement liabilities | 0 | 0 | |
Due to related party | 0 | 0 | |
Other current liabilities | 7,000 | 0 | |
Total current liabilities | 19,000 | 0 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 4,314,000 | 0 | |
Intercompany long term debt | 0 | 0 | |
Deferred income taxes | 1,000 | 0 | |
Convertible debentures (2015 represented by instalment receipts) | 0 | 0 | |
Derivative instruments | 0 | 0 | |
Regulatory liabilities | 0 | 0 | |
Asset retirement obligations | 0 | 0 | |
Pension and post-retirement liabilities | 0 | 0 | |
Other long-term liabilities | 0 | 0 | |
Total long-term liabilities | 4,315,000 | 0 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 242,000 | 0 | |
Preferred Stock, Value, Issued | 0 | 0 | |
Contributed surplus | 0 | 0 | |
Accumulated other comprehensive Income | 10,000 | 0 | |
Retained earnings | 9,000 | 0 | |
Total Emera Incorporated equity | 261,000 | 0 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 261,000 | 0 | |
Liabilities and Equity, Total | 4,595,000 | 0 | |
Guarantor Subsidiaries [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 48,000 | 19,000 | |
Restricted Cash and Cash Equivalents, Current | 1,000 | 1,000 | |
Receivables, Net, Current | 429,000 | 70,000 | |
AccountsReceivableRelatedPartiesCurrent | 11,000 | 51,000 | |
Income Taxes Receivable, Current | 5,000 | 9,000 | |
Inventory, Net | 273,000 | 48,000 | |
Derivative Instruments and Hedges, Assets | 33,000 | 46,000 | |
Regulatory Assets, Current | 54,000 | 17,000 | |
Prepaid Expense, Current | 0 | 0 | |
Due from Related Parties, Current | 0 | 0 | |
Other Assets, Current | 44,000 | 4,000 | |
Total current assets | 898,000 | 265,000 | |
Property, Plant and Equipment, Net | 12,724,000 | 2,035,000 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 0 | 0 | |
Deferred income taxes | 18,000 | 47,000 | |
Derivative instruments | 2,000 | 0 | |
Pension and post-retirement assets | 0 | 0 | |
Regulatory assets | 647,000 | 100,000 | |
Net investment in direct financing lease | 13,000 | 0 | |
Investments In Subsidiaries | 0 | 0 | |
Investments subject to significant influence | 13,000 | 12,000 | |
Available-for-sale investment | 0 | 0 | |
Goodwill | 6,110,000 | 158,000 | |
Due from related parties | 0 | 0 | |
Intercompany notes receivable | 16,000 | 0 | |
Other investments - intercompany | 0 | 0 | |
Other long term assets | 85,000 | 13,000 | |
Total other assets | 6,904,000 | 330,000 | |
Assets, Total | 20,526,000 | 2,630,000 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 948,000 | 0 | |
Current portion of long-term debt | 436,000 | 6,000 | |
Accounts payable | 756,000 | 76,000 | |
Intercompany payable | 81,000 | 0 | |
Income taxes payable | 0 | 92,000 | |
Derivative instruments | 10,000 | 36,000 | |
Regulatory liabilities | 225,000 | 10,000 | |
Pension and post-retirement liabilities | 51,000 | 0 | |
Due to related party | 0 | 0 | |
Other current liabilities | 79,000 | 24,000 | |
Total current liabilities | 2,586,000 | 244,000 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 4,687,000 | 389,000 | |
Intercompany long term debt | 4,778,000 | 120,000 | |
Deferred income taxes | 1,193,000 | 343,000 | |
Convertible debentures (2015 represented by instalment receipts) | 0 | 0 | |
Derivative instruments | 0 | 0 | |
Regulatory liabilities | 973,000 | 12,000 | |
Asset retirement obligations | 61,000 | 0 | |
Pension and post-retirement liabilities | 433,000 | 93,000 | |
Other long-term liabilities | 213,000 | 61,000 | |
Total long-term liabilities | 12,338,000 | 1,018,000 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 4,177,000 | 312,000 | |
Preferred Stock, Value, Issued | 620,000 | 425,000 | |
Contributed surplus | 45,000 | 45,000 | |
Accumulated other comprehensive Income | 340,000 | 245,000 | |
Retained earnings | 420,000 | 341,000 | |
Total Emera Incorporated equity | 5,602,000 | 1,368,000 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Total equity | 5,602,000 | 1,368,000 | |
Liabilities and Equity, Total | 20,526,000 | 2,630,000 | |
Non-Guarantor Subsidiaries [Member] | |||
Assets, Current [Abstract] | |||
Cash, Cash Equivalents, and Short-term Investments | 128,000 | 1,068,000 | |
Restricted Cash and Cash Equivalents, Current | 86,000 | 18,000 | |
Receivables, Net, Current | 584,000 | 506,000 | |
AccountsReceivableRelatedPartiesCurrent | 569,000 | 95,000 | |
Income Taxes Receivable, Current | 28,000 | 3,000 | |
Inventory, Net | 199,000 | 266,000 | |
Derivative Instruments and Hedges, Assets | 112,000 | 112,000 | |
Regulatory Assets, Current | 26,000 | 77,000 | |
Prepaid Expense, Current | 0 | 0 | |
Due from Related Parties, Current | 0 | 0 | |
Other Assets, Current | 230,000 | 243,000 | |
Total current assets | 1,962,000 | 2,388,000 | |
Property, Plant and Equipment, Net | 4,552,000 | 4,419,000 | |
Other Assets, Noncurrent [Abstract] | |||
Income taxes receivable | 48,000 | 49,000 | |
Deferred income taxes | 114,000 | 19,000 | |
Derivative instruments | 129,000 | 167,000 | |
Pension and post-retirement assets | 9,000 | 9,000 | |
Regulatory assets | 595,000 | 505,000 | |
Net investment in direct financing lease | 475,000 | 480,000 | |
Investments In Subsidiaries | 0 | 0 | |
Investments subject to significant influence | 929,000 | 624,000 | |
Available-for-sale investment | 48,000 | 116,000 | |
Goodwill | 103,000 | 106,000 | |
Due from related parties | 0 | 0 | |
Intercompany notes receivable | 589,000 | 2,754,000 | |
Other investments - intercompany | 2,270,000 | 98,000 | |
Other long term assets | 70,000 | 77,000 | |
Total other assets | 5,379,000 | 5,004,000 | |
Assets, Total | 11,893,000 | 11,811,000 | |
Liabilities, Current [Abstract] | |||
Short-term debt | 13,000 | 16,000 | |
Current portion of long-term debt | 40,000 | 18,000 | |
Accounts payable | 480,000 | 301,000 | |
Intercompany payable | 25,000 | 8,000 | |
Income taxes payable | 13,000 | 77,000 | |
Derivative instruments | 314,000 | 313,000 | |
Regulatory liabilities | 137,000 | 102,000 | |
Pension and post-retirement liabilities | 7,000 | 7,000 | |
Due to related party | 0 | 0 | |
Other current liabilities | 141,000 | 132,000 | |
Total current liabilities | 1,170,000 | 974,000 | |
Liabilities, Noncurrent [Abstract] | |||
Long-term debt | 2,929,000 | 2,882,000 | |
Intercompany long term debt | 1,357,000 | 3,072,000 | |
Deferred income taxes | 516,000 | 450,000 | |
Convertible debentures (2015 represented by instalment receipts) | 0 | (1,458,000) | |
Derivative instruments | 150,000 | 96,000 | |
Regulatory liabilities | 304,000 | 341,000 | |
Asset retirement obligations | 109,000 | 109,000 | |
Pension and post-retirement liabilities | 219,000 | 197,000 | |
Other long-term liabilities | 268,000 | 233,000 | |
Total long-term liabilities | 5,852,000 | 5,922,000 | |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||
Common Stock, Value, Issued | 3,997,000 | 3,829,000 | |
Preferred Stock, Value, Issued | 271,000 | 271,000 | |
Contributed surplus | 106,000 | 133,000 | |
Accumulated other comprehensive Income | (191,000) | (169,000) | |
Retained earnings | 610,000 | 751,000 | |
Total Emera Incorporated equity | 4,793,000 | 4,815,000 | |
Non-controlling interest in subsidiaries | 78,000 | 100,000 | |
Total equity | 4,871,000 | 4,915,000 | |
Liabilities and Equity, Total | CAD 11,893,000 | CAD 11,811,000 |
SUPPLEMENTAL FINANCIAL INFOR176
SUPPLEMENTAL FINANCIAL INFORMATION Company (Condensed Consolidated Statement of Cash Flows) (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | CAD 1,053 | CAD 674 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | (8,409) | 0 |
Additions to property, plant and equipment | (1,031) | (427) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (276) | (136) |
Proceeds from Sale of Equity Method Investments | 665 | 282 |
Other investing activities | (54) | (22) |
Net cash used in investing activities | (9,105) | (124) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | 118 | (262) |
Proceeds from Issuance of Long-term Debt | 6,423 | 446 |
Proceeds from Convertible Debt | 1,413 | 681 |
Retirement of long-term debt | (273) | (90) |
Net repayments under committed credit facilities | (315) | (201) |
Proceeds from Issuance of Common Stock | 354 | 9 |
Dividends on common stock | (221) | (162) |
Dividends on preferred stock | (28) | (30) |
Dividends paid by subsidiaries to non-controlling interest | (5) | (14) |
Proceeds from (Payments for) Other Financing Activities | (18) | (21) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 7,448 | 221 |
Cash and Cash Equivalents, Period Increase (Decrease) | (669) | 852 |
Consolidation, Eliminations [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 171 | (171) |
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 | 9,179 | 2,482 |
Other investing activities | 0 | 1,331 |
Net cash used in investing activities | 9,179 | 3,813 |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | 14 | (4) |
Proceeds from Issuance of Long-term Debt | (5,081) | (1,048) |
Proceeds from Convertible Debt | 0 | 0 |
Retirement of long-term debt | 19 | 702 |
Proceeds from Long-term Lines of Credit | (6) | 0 |
Proceeds from Issuance of Common Stock | (4,202) | (2,390) |
Issuance of preferred stock, net of issuance costs | (195) | (6) |
Dividends on common stock | 254 | 162 |
Dividends on preferred stock | 49 | 40 |
Dividends paid by subsidiaries to non-controlling interest | (3) | (11) |
Proceeds from (Payments for) Other Financing Activities | (185) | (1,091) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | (9,336) | (3,646) |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | 0 | 0 |
Cash and Cash Equivalents, Period Increase (Decrease) | 14 | (4) |
Beginning Balance | (14) | (10) |
Ending Balance | 0 | (14) |
Parent Company [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 265 | 291 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | (2) | (7) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | (1) |
Proceeds from Sale of Equity Method Investments | 665 | 0 |
Repayment of Notes Receivable from Related Parties | (2,348) | (2,453) |
Other investing activities | 0 | (751) |
Net cash used in investing activities | (1,685) | (3,212) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | (14) | 4 |
Proceeds from Issuance of Long-term Debt | 2,037 | 0 |
Proceeds from Convertible Debt | (44) | 2,138 |
Retirement of long-term debt | (250) | 0 |
Proceeds from Long-term Lines of Credit | (210) | (39) |
Proceeds from Issuance of Common Stock | 354 | 9 |
Issuance of preferred stock, net of issuance costs | 0 | 0 |
Dividends on common stock | (221) | (162) |
Dividends on preferred stock | (28) | (30) |
Dividends paid by subsidiaries to non-controlling interest | 0 | 0 |
Proceeds from (Payments for) Other Financing Activities | 0 | 1,001 |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 1,624 | 2,921 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (4) | 0 |
Cash and Cash Equivalents, Period Increase (Decrease) | 200 | 0 |
Beginning Balance | 0 | 0 |
Ending Balance | 200 | 0 |
Subsidiary Issuer [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 29 | 0 |
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 | (4,416) | 0 |
Other investing activities | 0 | 0 |
Net cash used in investing activities | (4,416) | 0 |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | 0 | 0 |
Proceeds from Issuance of Long-term Debt | 4,187 | 0 |
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 | 242 | 0 |
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 | 4,429 | 0 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (14) | 0 |
Cash and Cash Equivalents, Period Increase (Decrease) | 28 | 0 |
Beginning Balance | 0 | 0 |
Ending Balance | 28 | 0 |
Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 481 | 190 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | (8,409) | |
Additions to property, plant and equipment | (633) | (66) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | 0 | (3) |
Proceeds from Sale of Equity Method Investments | 0 | 282 |
Repayment of Notes Receivable from Related Parties | (18) | 0 |
Other investing activities | (42) | (10) |
Net cash used in investing activities | (9,102) | 203 |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | 122 | 0 |
Proceeds from Issuance of Long-term Debt | 4,516 | 29 |
Proceeds from Convertible Debt | 0 | 0 |
Retirement of long-term debt | (6) | (420) |
Proceeds from Long-term Lines of Credit | 0 | (9) |
Proceeds from Issuance of Common Stock | 3,865 | 0 |
Issuance of preferred stock, net of issuance costs | 195 | 0 |
Dividends on common stock | 0 | 0 |
Dividends on preferred stock | (31) | (15) |
Dividends paid by subsidiaries to non-controlling interest | 0 | 0 |
Proceeds from (Payments for) Other Financing Activities | (18) | (11) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 8,643 | (426) |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | 7 | 14 |
Cash and Cash Equivalents, Period Increase (Decrease) | 29 | (19) |
Beginning Balance | 19 | 38 |
Ending Balance | 48 | 19 |
Non-Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities [Abstract] | ||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations | 107 | 364 |
Net Cash Provided by (Used in) Investing Activities [Abstract] | ||
Acquisition, net of cash acquired | 0 | |
Additions to property, plant and equipment | (396) | (354) |
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15) | (276) | (132) |
Proceeds from Sale of Equity Method Investments | 0 | 0 |
Repayment of Notes Receivable from Related Parties | (2,397) | (29) |
Other investing activities | (12) | (413) |
Net cash used in investing activities | (3,081) | (928) |
Net Cash Provided by (Used in) Financing Activities [Abstract] | ||
Proceeds from (Repayments of) Short-term Debt | (4) | (262) |
Proceeds from Issuance of Long-term Debt | 764 | 1,465 |
Proceeds from Convertible Debt | 1,457 | (1,457) |
Retirement of long-term debt | (36) | (372) |
Proceeds from Long-term Lines of Credit | (99) | (153) |
Proceeds from Issuance of Common Stock | 95 | 2,390 |
Issuance of preferred stock, net of issuance costs | 0 | 6 |
Dividends on common stock | (254) | (162) |
Dividends on preferred stock | (18) | (25) |
Dividends paid by subsidiaries to non-controlling interest | (2) | (3) |
Proceeds from (Payments for) Other Financing Activities | 185 | (55) |
Net Cash Provided by (Used in) Financing Activities, Continuing Operations | 2,088 | 1,372 |
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations | (54) | 67 |
Cash and Cash Equivalents, Period Increase (Decrease) | (940) | 875 |
Beginning Balance | 1,068 | 193 |
Ending Balance | CAD 128 | CAD 1,068 |
Uncategorized Items - ema-20161
Label | Element | Value |
Cash | us-gaap_Cash | CAD 996,000,000 |
Cash | us-gaap_Cash | 221,000,000 |
Cash Equivalents, at Carrying Value | us-gaap_CashEquivalentsAtCarryingValue | 183,000,000 |
Cash Equivalents, at Carrying Value | us-gaap_CashEquivalentsAtCarryingValue | CAD 77,000,000 |