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Regulatory Assets and Liabilities | 12 Months Ended
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Dec. 31, 2020
7. Regulatory Assets and Liabilities |
Regulatory Assets and Liabilities | 16. REGULATORY ASSETS AND LIABILITIES Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or t olls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the app licable regulator, or due to regulatory precedent establis hed for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charge d to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future reve nues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognize d 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 |  | 2020 |  | 2019
Regulatory assets |  |  |  |
Deferred income tax regulatory assets | $ | 887 | $ | 862
Pension and post-retirement medical plan |  | 394 |  | 380
Deferrals related to derivative instruments |  | 65 |  | 81
Cost recovery clauses |  | 49 |  | 13
Storm restoration regulatory asset |  | 41 |  | 38
Environmental remediations |  | 28 |  | 26
Stranded cost recovery |  | 26 |  | 27
Demand side management ("DSM") deferral |  | 15 |  | 19
Unamortized defeasance costs |  | 13 |  | 19
Other |  | 66 |  | 87
| $ | 1,584 | $ | 1,552
Current | $ | 165 | $ | 121
Long-term |  | 1,419 |  | 1,431
Total regulatory assets | $ | 1,584 | $ | 1,552
Regulatory liabilities |  |  |  |
Deferred income tax regulatory liabilities |  | 933 |  | 985
Accumulated reserve - cost of remova l |  | 865 |  | 891
Storm reserve |  | 62 |  | 62
Cost recovery clauses |  | 31 |  | 53
Self-insurance fund (note 32) |  | 28 |  | 29
Regulated fuel adjustment mechanism |  | 21 |  | 115
Deferrals related to derivative instruments |  | 15 |  | 42
Other |  | 6 |  | 4
| $ | 1,961 | $ | 2,181
Current | $ | 129 | $ | 295
Long-term |  | 1,832 |  | 1,886
Total regulatory liabilities | $ | 1,961 | $ | 2,181
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 year s, a regulatory asset or liability is recognized as appropriate. Pension and Post-Retirement Medical Plan This asset is primarily related to th e 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 and New Mexico Public Regulation Commission (“NMPRC”) 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 genera tion and purchased power, inventory, operating, maintenance or general or property, plant and equipment, depending on the nature of the item being economically hedged. 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 a subsequent period. 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, Hurricane Dori an 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. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $1 5 million USD of costs related to the storm over a five-year period. The recovery was implemented through rates on January 1, 2021. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge over a five-year period. Additional details on the recovery are included under the Grand Bahama Power Company Limited section below. The balance of the regulatory asset as at December 31, 2020 is $18 million USD. Environmental Remediations This asset is primarily related to PGS costs associated with 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. T he timing of recovery is based on a settlement agreement approved by the FPSC. 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 and is expected to be included in rates in future years. DSM Deferral The Nova Scotia Utility and Review Board (“UARB”) approved implementation of the 2015 DSM deferral set at $35 million in 2015 and recoverable from customers over an 8-year period beginning in 2016. The UARB directed EfficiencyOne, a franchisee appointed by the Province of Nova Scotia to provide NSPI wit h electricity efficiency and conservation activities under the Public Utilities Act, 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 beh alf of its customers in 2015. In December 2016, EfficiencyOne secured financing and $31 million was advanced to NSPI to finance the 2015 DSM deferral. In February 2017, EfficiencyOne advanced an additional $2 million to NSPI. As NSPI collects the associate d amounts from customers over the remaining three 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 t he 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 inte rest streams to match the related defeased debt, which as at December 31, 2020, totalled $582 million (2019 – $740 million). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amorti zed over the life of the defeased debt as permitted by the UARB. 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 equ ipment, 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. 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 re gulatory 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 m illion USD in storm restoration preparation costs for Hurricane Dorian. These costs were charged to the storm reserve regulatory liability. Regulated Fuel Adjustment Mechanism This regulated liability is the difference between actual fu el 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. 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. The UARB’s decision to a pprove the Fuel Stability Plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM. 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 regul ated return on equity (“ROE”) range for 2020 and 2019 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. Fuel Recovery 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. Base rates On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting incremental revenue requirements of approximately $280 million USD to $295 million USD, effective January 2022. Tampa Electric’s proposed rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investm ent, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $130 million USD to recover the costs of the second phase of the Big Bend modernization p roject and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes and files its detailed case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and a decision by the FPSC is expected by the end of 2021. 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, 20 19. As a result, Tampa Electric refunded $12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income. On August 20, 2018, the FPSC approved a reduction in base rates of $103 million USD annually begin ning in 2019 as a result of lower tax expense due to 2018 US tax reform benefits. Solar Base Rate Adjustments Included in Base Rates As of December 31, 2020, Tampa Electric has invested $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 202 1. AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects. The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $5 million USD true-up was returned to customers in 2020. The true-up s for SoBRA tranche s 3 and 4 will be filed in 2021 and 2022, respectively. Storm Protection Cost Recovery Clause and Settlement Agreement On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) 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. Tam pa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million USD base rate reduction for SPP program costs previously recover ed in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 millio n USD in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million USD of costs removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery beg a n in Janu ary 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025. The June 9, 2020 settlement agreement approved by the FPSC disclosed abov e also included approval of Tampa Electric’s petition to eliminate its $16 million USD accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. Big Bend Modernization Project Tampa Electric has invested approximately $526 million USD through December 31, 2020 to modernize the Big Bend Power Station. The modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. On June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 1, 2020 and December 31, 2020, the balance sheet included $304 million ($223 million USD) and $255 million ($200 million USD) respe ctively, in electric utility plant and $123 million ($90 million USD) and $112 million ($88 million USD) respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the F PSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric was not required to request an asset recovery schedule for retired assets until the next depreciation study. On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedules with the FPSC. Tampa Electric plans to retire Big Bend Unit 3 in 2023. Similar to the retirement plan for Unit 1 and Unit 2, Tampa Electric will continue to account for its existing investment in Unit 3 in electric utility plant and depreciate the assets using the curren t depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“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 t o 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 a reasonable return to investors. NSPI’s approved regulated ROE range for 2020 and 2019 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, approved by UARB which enables it to seek recovery of its fuel costs from customers through regularly scheduled fuel 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. NSPI is currently operating under a three-year f uel s tability p lan which results in an average annual overall rate increase of 1.5 per cent to recover f uel c osts for the period of 2020 through 2022. These rates include recovery of Maritime Link costs. The Maritime Link is a $1.6 billion transmission project including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments to NSPML at that time. The UARB approved 2020 interim cost assessment recovery payment to NSPML was $145 million and as of December 31, 2020 $135 million has been paid. The payments were subject to a holdback of $10 million pending UARB agreement that a minim um 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 pa y to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. For 2020, NSPI has recorded a $4 million holdback payable to NSPML. On December 16, 2020, the UARB approved NSPML’s 2021 interim cost assessmen t recovery from NSPI of Maritime Link costs of approximately $172 million subject to a holdback of $10 million on similar terms as previously approved by the UARB. It also includes a potential long-term deferral of up to $23 million in depreciation expense dependent upon the timing of commencement of the Nova Scotia Block (“NS Block”). Refer to the NSPML section below for further detail. As part of a three-year f uel s tability p lan, electricity rates have been set to include the $145 million approved Maritime Link assessment for 2020 and estimate amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the Fuel Stability Plan and those approved by the UARB through the NSP ML interim assessment application will be addressed through the FAM. In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being developed by Nalcor Energy, the approved Maritime Link interim assessment payments re flected a reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. NSPI refunded the reduced 2018 NSPML assessment to customers in 2018 and 2019, by providing a credit to customers of $17 million and $35 million, respectively. The UARB’s decision to approve NSPI’s 2020-2022 f uel s tability p lan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The majority of the reduced assessment was refunded to most customers through a reduction incorporated into their 2020 rates and the remaining customers received a one-time on bill credit in 2020. As at December 31, 2020, $40 million plus interest has been refunded to cu stomers, with the remaining $12 million plus interest to be returned to customers subsequent to 2022. Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On August 21, 2020, the FAM audit results for 2018 and 2 019 were filed with the UARB. A hearing was held in January 2021 and a decision is expected in Q 2 2021. On March 13, 2020, the UARB’s decision on the FAM audit findings and recommendations relating to fiscal 2016 and 2017 was released. The final recommendations did not include any disallowances. 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 December 16, 2020 the UARB approved NSPML’s 2021 interim assessment for recovery of Maritime Link costs from NSPI of approximately $172 million (2020 - $145 million). This payment is subject to a holdback of $10 million on similar terms as previously approved by the UARB. Recovery of $115 million of operating and maintenance, debt financing and equity financing costs began on January 1, 2 021. Recovery of $57 million of depreciation and amortization will commence the sooner of the delivery of the NS Block or May 1, 2021. With cooperation of the Government of Canada, NSPML may also utilize up to $2 3 million of cash in a debt related reserve account to reduce the recovery of costs from NSPI in 2021, depending upon when the NS Block commences. NSPML will file a final cost assessment with the UARB after the commencement of the NS Block which is anticipated to take place in 2021. Other Electric Utilities The Barbados Light & Power Company Limited BLPC is regulated by the Fair Trading Commission (“FTC”), 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 licen se which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is currently 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 2020 and 2019. On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC in Q1 2021. BLPC has a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers 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 was 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 in come 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, all of which was recognized in earnings in Q1 2020. 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 8.34 per cent for 2020 (2019 - 8.5 per cent). In January 202 1, the GBPA approved GBPC’s regulated return on rate base of 8.37 per cent for 2021. In December 2016, the GBPA appr oved 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 ye ars, 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 1 5 per cent for 2020 and 2019. Domlec has a fuel pass-through mechanism which provides opportunity to recover substantially all prudently incurred 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. PGS’s approved ROE r ange for 2020 and 2019 was 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 was used for the calculation of return on investments for clauses. PGS recovers the costs it pays for gas s upply 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 a nd 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 replace ment 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 beginning in 2013. In February 2017, the FPSC approved an amendment to the cast iron bare steel rider to include certain plastic materials and pipe deemed obsolete by Pipeline and Hazardous Materials Safety Administration, totaling approximately 880 kilomet re s. PGS estimates that all cast iron and bare steel pipe will be removed from its system by 2022, with the replacement of obsolete plastic pipe continuing until 2028 under the rider. PGS was permitted to initiate a general base rate proceeding during 2020, provided the new rates do not become effective before January 1, 2021. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. T he settlement agreement allows for an increase to base rates by $58 million USD annually effective January 2021, which is a $34 million USD increase in revenue and $24 million USD increase of revenues previously recovered through the cast iron and bare ste el replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint. It provides PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 20 23 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were t o fall below 8.9 per cent before that time with an allowed equity in the capital structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process. 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. NMGC’s approved ROE for 2020 was 9.10 per cent and for 2019 ranged from 9.10-10.0 per cent. Beginning January 1, 2021, t he approved ROE is 9.375 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 m onthly 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 fil e 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 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024. NMGC filed a rate case in December 2019. NMGC reached an unopposed stipulated settlement of the case which was approved by the NMPRC in December 2020. The new rates reflect the recovery of capital investment in pipelines and related infrastructure and r esults in an increase in revenue of approximately $5 million USD annually effective January 2021.The stipulated settlement agreement includes an allowed regulatory ROE 9.375 per cent on an allowed equity capital structure of 52 per cent. Under the agreemen t base rates are frozen from January 1, 2021 to December 31, 2022, unless new federal tax rates are enacted, in which case NMGC can file for new rates to be effective earlier than January 1, 2023. On July 17, 2019, the NMPRC approved a rate increase for N MGC 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 were phased in over two years, resulting 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. This clause is designed to lower the variability of weather impacts during the heating season period of October through April annually. The Weather Normalization Mechanism will make customer rates and Company revenue more predictable by minimizing the impact of warmer than usual or colder than usual weather. Revenue increases or decreases captured in the weather normalization mechanism from October to April will be adjusted annually in October of the following heating season. 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. Brunswick Pipeline Brunswick Pipeline is a 145-k ilometre 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 agreem ent commencing in July 2009 with Repsol Energy Canada. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the C ER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

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