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Summary of Significant Accounting Policies | 12 Months Ended
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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.

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