Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

14. REGULATORY

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes 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.

Regulatory Assets and Liabilities

As at		December 31		December 31
millions of Canadian dollars		2018		2017
Regulatory assets
Deferred income tax regulatory assets	$	775	$	667
Pension and post-retirement medical plan (1)		453		380
Cost recovery clauses		75		17
Environmental remediations		31		41
Hurricane Matthew restoration		28		28
Stranded cost recovery		28		25
Unamortized defeasance costs		26		32
Demand side management ("DSM") deferral		24		28
Deferrals related to derivative instruments		10		15
Storm reserve		4		59
Other		115		119
	$	1,569	$	1,411
Current	$	165	$	138
Long-term		1,404		1,273
Total regulatory assets	$	1,569	$	1,411
Regulatory liabilities
Deferred income tax regulatory liabilities		1,218		1,116
Accumulated reserve - cost of removal		955		894
Regulated fuel adjustment mechanism		161		177
Deferrals related to derivative instruments		116		182
Storm reserve		76		-
Cost recovery clauses		30		51
Self-insurance fund (note 31)		30		28
Other		24		20
	$	2,610	$	2,468
Current	$	251	$	226
Long-term		2,359		2,242
Total regulatory liabilities	$	2,610	$	2,468
(1) The December 31, 2017 pension and post-retirement medical plan regulatory asset includes a prior period reclassification of $35 million from AOCI, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to note 10 for further details.

Deferred Income Tax Regulatory Assets and Liabilities

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.

In 2017, as a result of enactment of the US Tax Cuts and Jobs Act of 2017, the Company revalued its United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company 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 the applicable regulator.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and post-retirement benefits at Emera Florida and New Mexico, and Emera Maine. It is included in rate base and earns a rate of return as permitted by the FPSC, New Mexico Public Regulation Commission (“NMPRC”) and Maine Public Utilities Commission (“MPUC”), as applicable. It is amortized over the remaining service life of plan participants.

Cost Recovery Clauses

These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year.

Environmental Remediations

This asset is primarily related to PGS costs associated with the environmental remediation at Manufactured Gas Plant (“MGP”) 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.

Hurricane Matthew 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 recovery 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 2018 and 2017 and is expected to be included in future years.

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, 2018, totalled $759 million (2017 – $726 million). 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 permitted by the Nova Scotia Utility and Review Board (“UARB”).

DSM Deferral

The UARB approved the implementation of the 2015 DSM deferral set at $35 million for 2015 and recoverable from customers over an eight year period beginning in 2016.

The UARB directed EfficiencyOne to review the financing options through which EfficiencyOne 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. In December 2016, EfficiencyOne secured financing and $31 million was advanced to NSPI to finance the 2015 DSM deferral. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne. This has been set up as a liability in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on the Consolidated Balance Sheets.

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 as approved by the respective regulators. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, 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.

Accumulated Reserve – Cost of Removal

This regulatory liability represents the non-ARO 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 new assets are put into service.

Regulated Fuel Adjustment Mechanism

This regulated liability is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year, and 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 fuel revenues recovered from customers will be recovered or returned to customers after 2019, as required under the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”).

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. Tampa Electric and PGS 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.

On September 10, 2017, Tampa Electric was impacted by Hurricane Irma and incurred total restoration costs of approximately $102 million USD. The amount charged to the storm reserve exceeded the balance in the reserve by $47 million USD, which was recorded as a regulatory asset on the balance sheet. This regulated asset was included in rate base. On December 28, 2017, Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve to the $56 million USD level that existed at October 31, 2013. On March 1, 2018, the FPSC approved a settlement agreement authorizing the utility to net the amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. At December 31, 2018, Tampa Electric’s storm reserve liability was $56 million USD.

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 collect total revenues equal to their cost of providing service, plus an appropriate return on invested capital.

Tampa Electric

Tampa Electric’s approved regulated return on equity (“ROE”) range is 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.25 per cent is used for the calculation of the return on investments for clauses.

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing it the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in a subsequent year.

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. On November 6, 2017, the FPSC approved a settlement agreement allowing a solar base rate adjustment ("SoBRA") that provides for the recovery, upon in-service, of up to 600 MW of investments in utility-scale solar projects phased in from late 2018 through early 2021. On May 8, 2018, the FPSC approved Tampa Electric’s first SoBRA. This SoBRA represents 145 MW and $24 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in September 2018. On October 29, 2018, the FPSC approved Tampa Electric’s second SoBRA. This SoBRA represents 260 MW and $46 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in January 2019.

As discussed in the Storm Reserve section above, in September 2017, Tampa Electric was impacted by Hurricane Irma and incurred restoration costs in excess of the balance in its storm reserve. Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve. The FPSC approved a settlement agreement filed by Tampa Electric authorizing the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. In Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $19 million USD to offset tax reform benefits. This deferral was amortized over the balance of the year as a credit against recognition of storm expense. In total, OM&G expense due to the allowed netting of the storm cost recovery with tax reform benefits, net of amortization of first quarter tax reform benefits, was approximately $103 million USD for the year ended December 31, 2018. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved a reduction in base rates of $103 million USD annually beginning in 2019 as a result of lower tax expense.

PGS

The approved ROE range for PGS is 9.25 per cent to 11.75 per cent, based on an allowed equity capital structure of 54.7 per cent. Absent any rate case filing, the bottom of the range will increase to 9.75 per cent in 2021. An ROE of 10.75 per cent is used for the calculation of return on investments for clauses.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its purchased gas adjustment clause. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC.

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. In 2012, the FPSC approved a new Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The FPSC approved a replacement program of approximately 5 per cent, or 800 kilometres, of the PGS system at a cost of approximately $80 million USD over a 10-year period. As part of the depreciation study settlement agreement approved by the FPSC in February 2017, the Cast Iron/Bare Steel clause was expanded to allow recovery of accelerated replacement of certain obsolete pipe.

On February 7, 2017, the FPSC approved a settlement agreement which resulted in new depreciation rates that reduce annual depreciation by $16 million USD and accelerate the amortization of the regulated asset related to the MGP environmental remediation costs. As part of the settlement, PGS and the Office of Public Counsel 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, with at least $21 million USD amortized over a two year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million USD and $16 million USD, respectively, of this amortization expense.

The 2017 PGS settlement agreement does not contain a provision for tax reform. On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility to amortize $11 million USD of its MGP environmental regulatory asset and net it against its estimated 2018 tax reform benefits. Beginning in January 2019, PGS will lower base rates by $12 million USD to reflect the impact of tax reform and reduce depreciation rates by $10 million USD in accordance with the settlement agreement.

PGS is permitted to initiate a general base rate proceeding if it forecasts that ROE will fall below its allowed range.

NMGC

The approved ROE for NMGC is 10 per cent, on an allowed equity capital structure of 52 per cent. NMGC’s rates were established in a 2012 rate case settlement and were frozen until December 31, 2017 per the June 2016 NMPRC order (the “Order”) approving Emera’s acquisition of TECO Energy. NMGC filed a rate case, including the prospective impact of tax reform, on February 26, 2018. A hearing in the rate case was held on September 24, 2018, where an uncontested stipulation on the rate request was presented. A second hearing on the rate case related to 2018 tax reform benefits was held on December 17, 2018. As of December 31, 2018, NMGC recorded a regulatory liability of $8 million USD to reflect 2018 tax reform benefits. A decision by the NMPRC on the rate case and on 2018 tax reform benefits is expected in 2019.

NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020.

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 the 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 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 approved regulated ROE range for 2018 and 2017 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.

The Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”), was enacted by the Province of Nova Scotia in December 2015, 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. In July 2016, the UARB approved a Consensus Agreement between NSPI 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 changes resulting in amended rates that 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 September 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link when it is in service. The Maritime Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments. As of December 31, 2018, $96 million has been paid to NSPML. The UARB approved annual payment for 2019 is $111 million. The payments are subject to a holdback of $10 million in each of 2018 and 2019 pending UARB agreement that a minimum of $10 million per year in benefits from the Maritime Link are realized for NSPI customers. 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. As of December 31, 2018, NSPI has recorded a $2 million holdback payable to NSPML.

In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects a $53 million reduction in NSPML’s assessment 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 is providing a credit to customers, including interest, as the payments from NSPI to NSPML are not required in those years. In 2018, $17 million was refunded. The credit to customers will be approximately $36 million in 2019 and $53 million in 2020.

After 2019 and the Rate Stability Plan, the timing and amounts payable to NSPML and NSPI’s future rate recoveries of the Maritime Link costs will be subject to regulatory filings with the UARB, with expected filings in 2019 and 2020.

Emera Maine

Emera Maine’s distribution operations and stranded cost recoveries are regulated by the MPUC. The transmission operations are regulated by the FERC. Rates for these are established in distinct regulatory proceedings. US tax reform benefits, resulting from the lower tax rate, were reflected in distribution and transmission rates effective July 1, 2018, with other components being deferred to be addressed in future 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. In June 2018, the MPUC approved a 5.3 per cent distribution rate increase. This increase was effective July 1, 2018 and is based on a 9.35 per cent ROE and a common equity component of 49 per cent. Prior to July 1, 2018, the allowed ROE was 9.0 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 2018 and 2017 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 transmission assets is 11.07 to 11.74 per cent for 2018 and 2017.

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 transmission investments and expenses. The current allowed ROE for transmission operations is 9.6 per cent (2017 – 9.6 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 accounting orders issued by the MPUC.

The Barbados Light & Power Company Limited

BLPC is regulated by the Fair Trading Commission, an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. 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 was 10 per cent for 2018 and 2017.

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 approved calculation of the fuel charge is adjusted monthly.

In December 2018, the Government of Barbados signed the Income Tax Amendment Act into law. This legislation which is effective January 1, 2019, created a new corporate income tax rate schedule and eliminated certain tax credits. At the date of enactment, BLPC was required to remeasure its deferred income tax liability at the new lower corporate income tax rate, resulting in recognition of an income tax recovery of $9.6 million USD of which $6.9 million USD was deferred as a regulatory liability.

Grand Bahama Power Company Limited

GBPC is regulated by the GBPA. The GBPA 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 8.5 per cent for 2018 (2017 - 8.8 per cent). In December 2018, the GBPA approved GBPC’s regulated return on rate base of 8.44 per cent for 2019.

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.

Dominica Electricity Services Ltd

Domlec 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 was 15 per cent for 2018 and 2017.

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.

Dominica experienced unprecedented damage as a result of Hurricane Maria in September 2017, reducing the customer base from approximately 36,000 to 26,000 at December 31, 2018. Many homes were destroyed and have not been rebuilt at this time. Domlec has fully restored power to all customers who request power and are able to receive it. Domlec maintains insurance for its generation fleet and, subsequent to Hurricane Maria, has obtained specialized insurance for its transmission and distribution networks.

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.