Regulatory Assets and Liabilities	12 Months Ended
Regulatory Assets and Liabilities	Dec. 31, 2023
Regulatory Assets and Liabilities [Abstract]
Regulatory Assets and Liabilities	6. 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 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, 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. As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 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 years, a regulatory asset or liability is recognized as appropriate. TEC Capital Cost Recovery for Early Retired Assets This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and is recovered as a separate line item on customer bills for a period of 15 years . This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section below. NSPI FAM NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel- related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred 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 subsequent periods. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Cost Recovery Clauses These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in FV 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 UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, other income, inventory, or OM&G, depending on the nature of the item being economically hedged. Storm Cost Recovery Clauses TEC and PGS Storm Reserve: The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. TEC 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 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC Storm Reserve” in the Florida Electric Utility section below. NSPI Storm Rider: NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $ 10 million in a given year. GBPC Storm Restoration: This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are not covered by commercial insurance. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $ 15 million USD of 2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below. 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. The timing of recovery is based on a settlement agreement approved by the FPSC. Stranded Cost Recovery Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $ 21 million USD stranded cost through electricity rates; it is included in rate base and expected to be included in rates in future years. NMGC Winter Event Gas Cost Recovery In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $ 108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause (“PGAC”). On June 15, 2021, the NMPRC approved recovery of $ 108 million USD and related borrowing costs in customer rates over a period of 30 months from July 1, 2021, to December 31, 2023. Accumulated Reserve – COR This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of PP&E value upon retirement that are not legally required. This 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. NMGC Gas Hedge Settlements This regulatory liability represents regulatory deferral of gas options exercised above strike price but settled subsequent to the period end. The value from cash settlement of these options flows to customers via the PGAC. Other Regulatory Assets and Liabilities Comprised of regulatory assets and liabilities that are not individually significant. Regulatory Environments and Updates Florida Electric Utility TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent (2022 – 10.20 per cent) is used for the calculation of the return on investments for clauses. Base Rates: On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $ 290 to $ 320 million USD and additional adjustments of approximately $ 100 million USD and $ 70 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024. On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $ 22 million USD was approved by the FPSC on November 17, 2023. Fuel Recovery and Other Cost Recovery Clauses: TEC 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 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 subsequent periods. On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under- recovery of $ 518 million USD over a period of 21 months . The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $ 170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023. The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $ 169 million USD, and was spread over customer bills from April 1, 2022 through December 2022. Big Bend Modernization Project: TEC invested $ 876 million USD, including $ 91 million USD of AFUDC, between 2018 and 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it was in the best interests of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $ 636 million USD and $ 267 million USD in accumulated depreciation were reclassified to a regulatory asset on the balance sheet. TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years , effective January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. Storm Reserve: In September 2022, TEC was impacted by Hurricane Ian, with $ 119 million USD of restoration costs charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $ 56 million USD, for a total of $ 131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $ 134 million USD. It also changed the collection of the expected remaining balance of $ 29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC. In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $ 35 million USD, which were charged to the storm reserve regulatory asset, resulting in minimal impact to earnings. Storm Protection Cost Recovery Clause and Settlement Agreement: The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022. 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 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 a reasonable return to investors. NSPI’s approved regulated ROE range for 2023 and 2022 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 of approved rate base. General Rate Application (“GRA”): On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increases of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates effective on February 2, 2023. Fuel Recovery: For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period. On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $ 117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $ 117 million on behalf of Invest Nova Scotia over a 10 -year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. Storm Rider: The storm rider was effective as of the GRA decision date. The application for deferral and recovery of the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the year after the application. Total major storm restoration expense for 2023 was $ 31 million, of which $ 21 million was deferred to the storm rider. Hurricane Fiona: On October 31, 2023, NSPI submitted an application to the UARB to defer $ 24 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023, the $ 24 million is deferred to “Other long-term assets”, pending UARB approval. Maritime Link: The Maritime Link is a $ 1.8 billion (including AFUDC) 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 interim assessment payments to NSPML at that time. Any difference between the amounts recovered from customers through rates and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program: As of December 31, 2022, the FAM included a cumulative $ 166 million in fuel costs related to the accrued purchase of emissions credits and $ 6 million related to credits purchased from provincial auctions. On March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $ 166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $ 6 million were not refunded and no further costs were incurred to achieve compliance with the Cap-and- Trade Program. Extra Large Industrial Active Demand Tariff: On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $ 51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings. NSPML Equity earnings 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. Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and delivery will continue over the next 35 years pursuant to the agreements. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 billion less $ 9 million of costs ($ 7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $ 12 million ($ 8 million related to 2022 and $ 4 million relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the UARB increased the monthly holdback amount from $ 2 million to $ 4 million beginning December 1, 2023. On December 21, 2023, NSPML received approval to collect up to $ 164 million (2023 – $ 164 million) from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $ 4 million a month, as discussed above. 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 range for 2023 and 2022 was 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint, based on an allowed equity capital structure of 54.7 per cent. Base Rates: On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $ 118 million USD increase to base revenues which includes $ 11 million USD transferred from the cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $ 107 million USD. This reflects a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent.  A final order was issued on December 27, 2023, with the new rates effective January 2024. The 2020 PGS rate case settlement provided the ability to reverse a total of $ 34 million USD of accumulated depreciation through 2023. PGS reversed $ 20 million USD of accumulated depreciation in 2023 and $ 14 million USD in 2022. Fuel Recovery: PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. 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. Recovery of Energy Conservation and Pipeline Replacement Programs: The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are required by Florida law and approved and monitored by the FPSC. PGS also has a 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. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under the rider. 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 2023 and 2022 was 9.375 per cent on an allowed equity capital structure of 52 per cent. Base Rates: On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $ 49 million USD in annual base revenues primarily as a result of increased operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 per cent. Fuel Recovery: NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust 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. NMGC received approval of its PGAC Continuation in December 2020, for the four-year period ending December 2024. Integrity Management Programs (“IMP”) Regulatory Asset: A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Saint John 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 North America Canada Partnership. 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 CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. Other Electric Utilities BLPC BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base was 10 per cent for 2023 and 2022. Licenses: BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted. Base Rates: In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $ 1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $ 50 million USD, prior year benefits recognized on remeasurement of deferred income taxes of $ 5 million USD, and accumulated depreciation of $ 16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order. On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. Fuel Recovery: BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is adjusted on a monthly basis and reported to the FTC for approval. Clean Energy Transition Program (“CETP”): On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP. Fuel Hedging: On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50 /50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. GBPC 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. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.32 per cent for 2023 (2022 – 8.23 per cent). Base Rates: There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $ 3.5 million USD. The rates include a regulatory ROE of 12.84 per cent. Fuel Recovery: GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner. Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted monthly, in-line with actual fuel costs. Storm Restoration Costs – Hurricane Matthew: As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.