Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

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 are 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 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 collect 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. Based on a Stipulation and Settlement Agreement in 2013 Tampa Electric would 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 place 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 allowed 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, 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 2016, PGS recorded $16 million USD of this amortization.

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.

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 regulated 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 year.

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 required 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, 2016, 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. Subsequently, 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 customer 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-recovered 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. The 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 transmission investments, adjusted for current year forecasted transmission investments. Effective June 1, 2016, transmission rates for the Bangor Hydro district increased by approximately 2 per cent in connection with its annual transmission formula rate filing (2015 – increased by 21 per cent). The increase is associated primarily with the recovery of increased 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.

Bangor Hydro District’s bulk transmission 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 current year forecasted investments. The participating transmission providers are also required to contribute 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, 2016, Bangor District’s regionally recoverable transmission investments and expenses increased by 9 per cent (2015 – decreased 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 allowed 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 operational 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 stranded 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 prior 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 (2015 – 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 addressed 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 remained 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 rates 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 ensure 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 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 rate base for 2016 and 2015 was 10 per cent.

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 approved the calculation of the fuel charge, which is adjusted on a monthly 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 provider 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 destroyed, 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 regulated 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 manner.

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 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.

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 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.

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 removal		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 the 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

Upon 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 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 from a commercial lender in order to repay 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, included 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 deferred 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 included 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 as 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 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 position.

Cost Recovery Clauses

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 instruments.

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 subsequent 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 Cost of Removal (“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 ratemaking 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 property, 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 named 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 surcharge 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.