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Regulatory Assets and Liabilities | 12 Months Ended
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Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract] |
REGULATORY ASSETS AND LIABILITIES | 16. REGULATORY Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs a re charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. Regulatory Assets and Liabilities Regulatory assets and liabilities consisted of the following:
As at |  | December 31 |  | December 31
millions of Canadian dollars |  | 2017 |  | 2016
Regulatory assets |  |  |  |
Deferred income tax regulatory assets | $ | 667 | $ | 632
Pension and post-retirement medical plan |  | 345 |  | 373
Storm reserve |  | 59 |  | -
Environmental remediations |  | 41 |  | 49
Unamortized defeasance costs |  | 32 |  | 39
2015 demand side management ("DSM") deferral |  | 28 |  | 32
GBPC Hurricane Matthew restoration |  | 28 |  | 28
Stranded cost recovery |  | 25 |  | 27
Cost-recovery clauses |  | 17 |  | 12
Deferrals related to derivative instruments |  | 15 |  | 15
Debt basis adjustment |  | 13 |  | 19
Deferred bond refinancing costs |  | 7 |  | 9
Other |  | 99 |  | 87
| $ | 1,376 | $ | 1,322
Current | $ | 138 | $ | 80
Long-term |  | 1,238 |  | 1,242
Total regulatory assets | $ | 1,376 | $ | 1,322
Regulatory liabilities |  |  |  |
Deferred income tax regulatory liabilities |  | 1,116 |  | 26
Accumulated reserve - cost of remova l |  | 894 |  | 990
Deferrals related to derivative instruments |  | 182 |  | 230
Regulated fuel adjustment mechanism |  | 177 |  | 94
Cost-recovery clauses |  | 51 |  | 153
Self-insurance fund (notes 7 and 32) |  | 28 |  | 30
Bill reduction credit |  | 4 |  | 10
Storm reserve |  | - |  | 75
Other |  | 16 |  | 31
| $ | 2,468 | $ | 1,639
Current | $ | 226 | $ | 362
Long-term |  | 2,242 |  | 1,277
Total regulatory liabilities | $ | 2,468 | $ | 1,639
Deferred Income Tax Regulatory Asset and Liability To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. As a result of the US Tax Cuts and Jobs Act of 2017 (“the Act”) being enacted during 2017, the Company has provisionally revalued its United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company has reduced its US regulated net deferred income tax liabilities by $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of t he applicable regulator. The Company is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred c osts of pension and post-retirement benefits at Emera Florida and New Mexico. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Storm Reserve The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $1 0 million USD of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million USD of storm costs to the storm reserve, reducing the balance in the storm reserve to $46 million USD. On September 10, 2017, Tampa Electric was impacted by Hurricane Irma. The estimated cost of restoration is $105 million USD, of which $93 million USD was charged to the storm reserve, $8 million USD was charged to capital expenditures and $4 million USD was charged to OM&G. The $93 million USD charged to the storm reserve exceeded the $46 million USD balance by $47 million USD, which h as been recorded as a regulatory asset on the balance sheet. This regulated asset is included in rate base. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory ass et. Tampa Electric petitioned the FPSC on December 28, 2017 for the recovery of the estimated storm costs in excess of the reserve for several named storms, including Hurricane Irma, and to replenish the balance in the reserve to the $56 million USD level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. Environmental Remediation s This asset is primarily related to PGS costs associated with the environmental remediation at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. Unamortized Defeasance Costs Up on privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as at December 31, 2017, totalled $0.7 billion (2016 – $0.8 billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as approved by the UARB. 2015 DSM Deferral Effective January 1, 2015, NSPI must purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. 2015 Program Costs were deferred to a regulatory asset and are recoverable from customers over an eight-year period which began in 2016. The UARB directed EffficiencyOne to review the financing options through which they would borrow the 2015 deferral amount fr om a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. In December 2016, EffficiencyOne secured the financing and advanced funds to NSPI to finance the 2015 DSM deferral. This was set up as a payable on th e Consolidated Balance Sheets, included in current and long-term other liabilities. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne thereby reducing the liability. Hurricane Matth ew Restoration This asset represents restoration costs incurred by GBPC in 2016 associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The Grand Bahama Port Authority (“GBPA”) has approved full re covery of these storm restoration costs. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine during 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base for 2016 to 2018. Cost Recovery Clauses These assets and liabilities are related to TEC and NM G C clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. Debt Basis Adjustment This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the date TECO Energy acquired NMGC. In accordance with purchase accounting standards, NMGC’s long-term debt was valued at fair value on the Consolidated Balance Sheets. In accordance with the stipulation agreement with the NMPRC, an offsetting regulatory asset was recorded in order to eliminate the effects of purchase accounting on rate payers. The asset does not earn a return and is not inclu ded in the regulatory capital structure. It is amortized over the term of the related debt instrument. Deferrals Related to Derivative Instruments Tampa Electric, PGS, NMGC, NSPI and GBPC defer changes in fair value of derivatives that are documented a s economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in fuel for generation and purchased power, inventory or property, plant and equipment, de pending on the nature of the item being economically hedged. Tampa Electric deferrals related to derivative instruments are recovered through cost-recovery mechanisms on a dollar-for-dollar basis in the year following the settlement of the derivative posi tion. Deferred Bond Refinancing Costs This asset represents Tampa Electric and NMGC costs associated with refinancing debt. It does not earn a return but is instead included in the capital structure, which is used in the calculation of the weighted aver age cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instruments. Accumulated Reserve – Cost of Removal This regulatory liability represents the non-ARO C ost of R emoval (“COR”) reserve in Tampa Electric and NSPI. AROs are costs for legally required removal of property, plant and equipment. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as ne w assets are put into service. Fuel Adjustment Mechanism Differences between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year are deferred to a fuel adjustment mechanism (“FAM”) regulatory asset or liability and recovered from or returned to customers in a subsequent year. For the years 2017 to 2019, differences between actual fuel costs and fue l revenues recovered from customers will be recovered or returned to customers after 2019, as required under the Electricity Plan Act. Bill Reduction Credit This regulatory liability represents NMGC’s stipulation agreement commitment to provide an annua l bill reduction credit to customers of $4 million USD per year through June 30, 2018, as part of Emera’s acquisition of TECO Energy. Regulatory Environments Emera Florida and New Mexico Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to c ollect total revenues equal to their cost of providing service, plus an appropriate return on invested capital. Base Rates - Tampa Electric Tampa Electric’s target regulated return on equity (“ROE”) range is 9.25 per cent to 11.25 per cent. B ased on a Stipulation and Settlement Agreement in 2013 Tampa Electric receive d a revenue increase of $110 million USD effective January 1 7, 2017, the date Tampa Electric’s Polk Power Station went into service. The agreement also provided that Tampa Electric could not file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE fell below 9.25 per cent before that time. If its earned ROE rose above 11.25 per cent any party to the agreement other than Tampa Ele ctric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54 per cent from investor sources of capital. In September 2017, Tampa Electric announced its intention to invest approximately $850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. A settlement agreement was filed with the FPSC requesting a solar base rate adjustment ("SoBRA") that provides for the recovery, upon in-service, of up to 60 0 MW of investments in utility-scale solar projects that will be phased in from late 2018 through early 2021. The Tampa Electric settlement agreement contains a provision whereby the impacts of tax reform will be offset by a reduction in base rates within 1 20 days of when tax reform becomes law. On November 6, 2017, the FPSC approved the settlement agreement that replaced the existing 2013 agreement and extended it another four year years through 2021. On December 12, 2017, TEC filed its petition along wit h supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the sp ring of 2018. On January 30, 2018, Tampa Electric filed with the FPSC a settlement agreement which, if approved, will allow Tampa Electric to net the estimated amount of storm cost recovery against the utility’s estimated 2018 tax reform benefits. Any di fference would be trued up and recovered from or returned to customers in 2019. Beginning in January 2019 Tampa Electric would reflect the full impact of tax reform on Tampa Electric’s base rates, provided that the FPSC’s determinations have been finalize d. A decision is expected in March 2018. Base Rates - PGS Prior to 2016, PGS’s base rates were based upon an ROE of 10.75 per cent, with a range between 9.75 per cent and 11.75 per cent. In December 2016, PGS entered into a settlement agreement with the Office of Public Counsel (“OPC”) regarding its filed depreciation study. The settlement agreement resulted in new depreciation rates that reduce annual depreciation by $16 million USD in 2016 and accelerated the amortization of the regulated asset rel ated to the Manufactured Gas Plant (“MGP”) environmental remediation costs. In addition, the bottom of the ROE range was decreased from 9.75 per cent to 9.25 per cent. The new bottom of the range will remain until the earlier of new base rates establishe d in PGS’s next general rate proceeding or December 31, 2020. The top of the range will continue to be 11.75 per cent and the ROE of 10.75 per cent will continue to be used for the calculation of return on investment for clauses. On February 7, 2017 the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement. As part of the settlement, PGS and OPC agreed that at least $32 million USD of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites will be amortized over the period 2016 through 2020. At least $21 million USD will be amortized over a two year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense. The PGS settlement does not contain a provision for US tax reform. On January 9, 2018, the OPC filed a gen eric docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS. Base Rates - NMGC NMGC’s base rates were established in 2012 through a settlement agreement. As a condition of the 2016 NMPRC order (the “Order”) approving the acquisition of TECO Energy, NMGC will not seek an increase in base rates to be effective prior to December 31, 2017, and NMGC will continue to provide an annual bill reduction credit of $4 million USD through June 30, 2018. NMGC plans to file a rate case in 2018. NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Public Utilities Act”) and is subject to regulation under the Public Utilities Act by th e UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated ROE range for 2017 and 2016 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of f uel c osts through regularly scheduled rate adjustments. Differences between actual f uel c osts a nd amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. I n December 2 015, the Province enacted the Electricity Plan Imple mentation (2015) Act, (“Electricity Plan Act”), which required NSPI to file a three-year stability plan for fuel c osts and a General Rate Application (“GRA”) for non-fuel costs if required. I n July 2016, the UARB approved a Consensus Agreement between NSP I and customer representatives related to the Rate Stability Plan for fuel costs for 2017 through 2019 which resulted in an average annual increase of 1.1 per cent for each of these three years. Subsequently, certain customer representatives requested cha nges resulting in amended rates t hat were approved by the UARB in November 2016 and result in an average annual rate increase of 1.5 per cent for each of these three years. In December 2016, the UARB approved NSPI’s applic ation to refund over-recovered f uel c osts from 2016 to customers. The over-recovered 2016 f uel c osts of $36 million were refunded to customers through a one-time credit on their bills in 2017 and allocated to customers based on their individual electricity usage in 2016. The amount ref unded to customers includes 2016 excess non-fuel revenues of $5 million. On September 11, 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link starting when the Maritime Link is in service. The Maritime Link completed commissioning and entered service on January 15, 2018. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects NSPML’s proposal to reduce the assessment by deferring $53 million in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being recovered from customers, NSPI will provide a one-time credit to customers, including interest, in 2018 of approximately $1 7 million, 2019 of approximately $36 million and 2020 of approximately $53 million, as the payments from NSPI to NSPML are not required. NSPI is also required to hold back $10 million from the interim assessment payment to NSPML in 2018 and 2019. The release of such amou nts is subject to providing evidence to the UARB that at least that amount of benefit from the Maritime Link has been realized for NSPI customers in that year. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM.
For the |  | Year ended December 31
millions of Canadian dollars |  | 2017 |  | 2016
(Over) under recovery of current period Fuel costs | $ | - | $ | 29
Recovery from customers of prior years’ Fuel costs |  | - |  | 12
Application of non-fuel revenues |  | - |  | 20
Regulated fuel adjustment mechanism | $ | - | $ | 61
Emera Maine Emera Maine’s distribution operations and stranded cost recoveries are regulated by the Maine Public Utilities Commission (“MPUC”). The transmission operations are regulated by the FERC. The rates for these three elements are established in distinct regulatory proceedings. Distribution Operations Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. On December 21, 2016, Emera Maine’s distribution rates increased by 3.75 per cent, including the recovery, over five years, of approximately $4 million USD of costs associated with a major storm in Maine in 2014. Also, effective December 21, 2016, the allowed ROE was reduced by 0.55 per cen t to 9.00 per cent on a common equity component of 49 per cent. Transmission Operations Emera Maine’s transmission operations are split between two districts; Bangor Hydro District and Maine Public Service (“MPS”). Bangor Hydro District local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE for Bangor Hydro District local transmission operations for 2017 and 2016 is 10.57 per cent. Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. The allowed ROE range for Bangor Hydro bulk transmissio n assets is 11.07 to 11.74 per cent for 2017 and 2016. MPS District local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers based on a formula utilizing prior year actual transmi ssion investments and expenses. The current allowed ROE for transmission operations is 9.6 per cent (2016 – 10.2 per cent). Stranded Cost Recoveries Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and account ing orders issued by the MPUC. The Barbados Light & Power Company Limited BLPC is a vertically integrated utility and provider of electricity on the island of Barbados. BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 by the Fair Trading Commission (“The Rules”), Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on t he island until 2028. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on r ate base was 10 per cent for 2017 and 2016. All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has a pproved the calculation of the fuel charge, which is adjusted on a monthly basis. Grand Bahama Power Company Limited GBPC is a vertically integrated utility and sole provider of electricity on Grand Bahama Island. The GBPA regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered a nd a reasonable return earned. GBPC’s approved regulated return on rate base was 8.8 per cent for 2017 and 2016. In December 2017 the GBPA approved GBPC’s regulated return on rate base of 8.5 per cent for 2018. In December 2016, the GBPA approved t hat over a five-year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates. Dominica Electricity Services Ltd Domlec is an integrated utility on the island of Dominica and is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on r ate base was 15 per cent for 2017 and 2016. Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner. On September 19, 2017, Dominica experienced unprecedented damage as a result of Hurricane Maria, facing sustained winds of over 175 miles per hour. All 36,000 of Domlec’s customers lost power following the storm as the Company’s transmission and distribution assets were significantly im pacted. Domlec has implemented a restoration plan. Domlec maintains insurance for its generation fleet and, as with most utilities, transmission and distribution networks are self-insured. Management has completed its damage assessment and a n estimated impairment provision has been recorded at December 31, 2017. Emera’s portion of the estimated impairment provision is immaterial. Brunswick Pipeline Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified li quefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is c onsidered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.
millions of Canadian dollars |  | 2017 |  | 2016
FAM regulatory asset – Balance as at January 1 | $ | (94) | $ | (28)
Under (over) recovery of current year Fuel Costs |  | (29) |  | (29)
Rebate to (recovery from) customers of prior years’ Fuel Costs |  | (12) |  | (12)
FAM audit disallowance, including interest adjustment |  | - |  | -
Excess non-fuel revenues |  | (5) |  | (27)
Interest on FAM balance |  | (5) |  | 1
FAM regulatory asset (liability) – Balance as at December 31 | $ | (160) | $ | (113)

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- Definition The entire disclosure for detailed information about regulatory assets and liabilities, including current and noncurrent assets created when regulatory agencies permit the deferral of costs to the balance sheet that would otherwise be required to appear on the company's income statement and would be charged against current expenses or revenues, as well as current and noncurrent liabilities created when regulatory agencies permit. + References No definition available. + Details
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