Regulatory Assets and Liabilities |
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| 15. Regulatory Assets and Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulatory Assets and Liabilities | 15. REGULATORY ASSETS AND LIABILITIES 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 applicable 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
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. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC. 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. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring 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 its regulator. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory, operating, maintenance or general or property, plant and equipment, depending on the nature of the item being economically hedged. Storm Restoration Regulatory Asset This asset represents storm restoration costs, primarily incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are self-insured. On September 1, 2019, Dorian struck Grand Bahama Island as a Category 5 hurricane, with sustained winds of approximately 285 kilometres per hour. The hurricane stalled over the island for several days, causing significant damage to, or destruction of, homes and businesses served by GBPC. GBPC’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain. It is currently estimated that restoration costs for GBPC self-insured assets will be approximately $15 million USD. In January 2020, the GBPA approved the recovery of these costs through rates over a five-year period. Approximately $12 million USD ($15 million CAD) of these estimated costs were incurred in 2019, and recorded as a regulatory asset. Restoration costs associated with Hurricane Matthew in 2016 are being amortized over five years and included in rate base as approved by the Grand Bahama Port Authority (“GBPA”) for full recovery. The balance as at December 31, 2019 is $23 million. Stranded Cost Recovery Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base for 2019 and 2018 and is expected to be included in future years. Environmental Remediations This asset is primarily related to PGS costs associated with 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. DSM Deferral The UARB approved 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 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. 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, 2019, totalled $740 million (2018 – $759 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”). 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. Accumulated Reserve – Cost of Removal (“COR”) This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC 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 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”). As approved on December 6, 2019 as part of NSPI’s three-year fuel stability plan, differences between actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be recovered or returned to customers after 2022. 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. In September 2019, Tampa Electric incurred approximately $8 million USD in storm restoration preparation costs for Hurricane Dorian. These costs were charged to the storm reserve regulatory liability. Regulatory Environments Florida Electric Utility Tampa Electric is regulated by the FPSC. Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Tampa Electric’s approved regulated return on equity (“ROE”) range for 2019 and 2018 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 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. As of December 31, 2019, Tampa Electric has invested approximately $820 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). Tampa Electric expects to invest an additional $30 million USD in these projects through 2021. AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 554 MW or $96 million USD annually in estimated revenue requirements for in-service projects. Tampa Electric expects to file its final SoBRA petition for the January 1, 2021 tranche in 2020. On December 10, 2019, the FPSC approved Tampa Electric’s petition to reduce base rates and charges reflecting reduction of the state income tax from 5.5 per cent to 4.46 per cent retroactive from January 1, 2019. The base rate reduction of approximately $5 million USD due to customers is subject to true-up, and the actual rate reduction may vary from year to year. On October 3, 2019, the FPSC issued a rule to implement a storm protection cost recovery clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Subject to final approval of the FPSC rule, Tampa Electric expects to file a storm protection plan with the FPSC in Q2 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 due to 2018 US tax reform benefits. On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs as a result of Hurricane Irma in 2017, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income. Canadian Electric Utilities 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 2019 and 2018 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 Act, was enacted by the Province of Nova Scotia in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In March 2016, in accordance with the Electricity Plan Act, NSPI announced that it would not file a General Rate Application (“GRA”) for non-fuel electricity rates for the 2017 through 2019 period. The UARB approved NSPI’s three-year fuel stability plan for 2017 through 2019, which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for each of these three years. On December 6, 2019, the UARB approved NSPI’s three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. For the years 2020 to 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from or returned to customers after 2022. The decision further directed that annual excess non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM. In September 2017, the UARB approved NSPI’s interim assessment payment to NSP Maritime Link Inc. (“NSPML”) of the costs associated with the Maritime Link when it is in service. The UARB approved annual payment for 2019 is $111 million and as of December 31, 2019, $101 million of that has been paid. The payments are subject to a holdback of $10 million pending UARB agreement that a minimum of $10 million 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, 2019, NSPI has recorded a $6 million holdback payable to NSPML. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payments of $110 million and $111 million for 2018 and 2019 respectively, reflect 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 through 2019 fuel rates and were 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 and in 2019, a further $35 million was refunded. The UARB decision to reduce the assessment payable to NSPML in 2018 and 2019 results in the Company recording amounts collected from customers as a FAM regulatory liability, with no material impact on earnings. The UARB’s decision to approve NSPI’s 2020 through 2022 Fuel Stability Plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The reduced assessment will be refunded to most customers through a reduction incorporated into their 2020 through 2022 rates and the remaining customers will receive a one-time on bill credit in 2020.The credit to customers will be approximately $40 million plus interest in 2020, with the remaining $12 million plus interest to be returned to customers subsequent to 2022.
On November 27, 2019, the UARB approved the 2020 interim cost assessment recovery from NSPI for costs associated with the Maritime Link of $145 million, subject to a holdback of up to $10 million. Refer to the NSPML section below for further details. Pursuant to the FAM Plan of Administration, NSPI’s fuel costs are subject to independent audit. In July 2018, the FAM audit results relating to fiscal 2016 and 2017 were publicly released. A UARB regulatory process is in progress with a hearing held on January 13, 2020. NSPML Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent. On November 27, 2019, the UARB approved NSPML’s interim assessment for recovery of 2020 Maritime Link costs from NSPI of approximately $145 million (2019 - $111 million). The total recovery of $145 million includes approximately $115 million of operating and maintenance, debt financing and equity financing costs, and approximately $30 million for depreciation and amortization of financing costs. This payment is subject to a holdback of up to $10 million. Recovery of the $115 million of operating and maintenance, debt financing and equity financing costs began on January 1, 2020. Beginning June 1, 2020, recovery of the $30 million of depreciation and amortization of financing costs will be included in NSPI customer rates, with payment of this recovery to NSPML to begin on the earlier of the confirmation of delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric facility, and November 1, 2020. NSPML expects to file a final cost assessment with the UARB in 2020.
Other Electric Utilities 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 2019 and 2018 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 2019 and 2018. 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 (2018 – 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. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is negotiating the terms of the new licenses under the amended legislation. 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 2019 and 2018. All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides opportunity to recover all fuel costs in a timely manner. The approved calculation of the fuel charge is adjusted monthly and reported to the regulator. 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 tariff review policy with new rates submitted every three years. GBPC’s approved regulated return on rate base was 8.5 per cent for 2019 (2018 - 8.5 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 the all-in rate for electricity (fuel and base rates) would be held at 2016 levels over the five-year period from 2017 through 2021. 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 2019 and 2018. Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides opportunity to recover substantially all fuel costs in a timely manner. Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. 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. 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 and Cast Iron/Bare Steel Pipe Replacement costs, including a return on capital invested incurred in developing and implementing energy conservation programs. The Cast Iron/Bare Steel Pipe Replacement clause is 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 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 reduced its 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 during 2020 regardless of its earned ROE at the time, provided the new rates do not become effective before January 1, 2021. On February 7, 2020, PGS notified the FPSC that it is planning to file a new base rate proceeding in April 2020 for new rates effective January 2021. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. The approved ROE for NMGC is 9.1 per cent, on an allowed equity capital structure of 52 per cent. 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. On July 17, 2019, the NMPRC approved a rate increase for NMGC effective August 2019, and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD. The deferred income tax regulatory liability of $11 million ($8 million USD) recorded at December 31, 2018 to reflect deferred tax benefits was recognized in revenue in Q2 2019. The NMPRC also approved the utility’s weather adjustment mechanism. Beginning in August 2019, the NMPRC approved a change in the treatment of net operating loss carryforwards. As a result of this change, a tax benefit of approximately $7 million ($5 million USD) was recognized in earnings in Q3 2019. On December 23, 2019, NMGC filed a future year rate case on December 23, 2019 for new rates effective January 2021. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure. The estimated annual incremental revenue requirement is approximately $13 million USD. A decision from the NMPRC is expected in late 2020. 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 Canada Energy Board (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. |
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