Topic:"Cost Recovery" in M12451

gged while children are at school. And no one is home. Showers/laundry/using the stove to cook. It just keeps adding up.It is impossible to keep up with the continuous rise in the cost of electricity. I am not the only person in this sinki...

AI summary Sarah Ross, a Nova Scotian resident, expresses frustration over escalating electricity costs imposed by Nova Scotia Power (NSP), calling it a crisis that burdens households. She criticizes NSP's consistent rate increases and highlights the disparity between rising costs and executive compensation, deeming the situation 'unfeasible' and 'outrageous.'

1) Among the highest residential rates in Canada Halifax residents paid about 19.46¢/kWh (for 1,000 kWh/month, before taxes) as of April 1, 2024—far above cities like Montréal (8.05¢/kWh) and Winnipeg (10.53¢/kWh). This gap places a heavy...

AI summary Halifax residents pay 19.46¢/kWh (as of April 2024) for residential electricity, significantly higher than cities like Montréal (8.05¢/kWh) and Winnipeg (10.53¢/kWh). This disparity imposes financial strain on households and small businesses in Nova Scotia, one of Canada's most expensive provinces to live in.

Support for 2026-2027 GRA - Further to the letter filed with the Nova Scotia Energy Board (NSEB or Board) on September 2, - 2025, Nova Scotia Power Incorporated (NS Power or Company) is filing this General Rate - Application for 2026-2027...

AI summary Nova Scotia Power Incorporated (NS Power) submits a 2026-2027 General Rate Application (GRA) supported by customer representatives after a collaborative process. The GRA is based on a Cost-of-Service Study (COSS) and excludes cybersecurity attack costs. It reflects negotiated outcomes with reduced costs due to regulatory efficiencies.

Overview of 2026-2027 GRA - NS Power submits this GRA to the Board to request approval of revenue requirements for the - utility and request adjustments to electricity rates for 2026 and 2027, effective January 1, 2026 - and 2027. - The NS...

AI summary NS Power seeks approval for 2026-2027 rate increases (1.8% and 2.4%) to fund system reliability, resilience, and decarbonization goals. Residential rates would rise 3.8% and 4.1%, while industrial rates decrease. The proposal emphasizes cost-effectiveness, citing benchmarking showing NS Power's costs align with industry norms. The application aims to balance reliability, affordability, and customer needs amid rising costs.

Roadmap of the Application - This application is organized into several key components, each critical to determining the - proposed rate adjustments: - 1. Status of Prior GRA-Related Directives: An update on the various directives from the...

AI summary The application outlines components for determining rate adjustments, including prior GRA directives, load forecasts, fuel costs, operating expenses, depreciation, rate base, capital structure, revenue requirements, cost-of-service studies, rate design, proposed rates, and regulatory changes. NS Power collaborates with customer advocates to balance affordability, reliability, and clean energy goals.

Nova Scotia Power's Request - In this GRA, Nova Scotia Power is seeking an order from the Board approving the following: - 1. The 2026 and 2027 revenue requirements as described in Section 11 to enable NS Power to recover the prudent and r...

AI summary Nova Scotia Power is requesting regulatory approval for various items, including revenue requirements for 2026 and 2027, adjustments to the Fuel Adjustment Mechanism, amendments to the FAM Plan of Administration, and deferrals related to securitization and depreciation. It also seeks approval for specific deferrals, updated studies, and continuation of a Storm Cost Recovery Rider pilot.

Overview - NS Power is seeking approval of new Base Cost of Fuel (BCF) amounts for FAM customers in - 2026 and 2027 as set out in FOR-07 Attachment 1 . - Fuel and purchased power are direct pass-through costs, with customers paying the act...

AI summary NS Power is requesting approval for new Base Cost of Fuel (BCF) amounts for FAM customers in 2026 and 2027. Fuel costs are passed directly to customers and audited annually. The BCF rates have been adjusted to smooth fuel cost increases over the two-year period, resulting in an over-collection in 2026 and an under-collection in 2027. The forecasted fuel and purchased power costs total $1.8 billion over the two-year test period.

7 OPERATING COSTS

AI summary Section 7 of the regulatory proceeding document outlines operating costs, referencing key acronyms such as FFO, CFFO, and DBRS. It highlights the involvement of entities like the Nova Scotia Energy Board (NSEB) and programs including the Fuel Adjustment Mechanism (FAM). The section sets context for cost analysis and regulatory considerations.

• Wage increases for both union and non-union employees. • Inflationary increases of 2 percent annually for non-labour costs. • Administrative overhead allocated to capital consistent with the Company's established practice consistent with...

AI summary The text outlines various cost factors included in the General Rate Application (GRA), such as wage increases, inflationary adjustments, administrative overhead, pension expenses, and storm-related costs. It also notes a significant increase in pension expenses and a projected rise in rates from 2027 to 2028.

8 DEPRECIATION AND REGULATORY DEFERRALS

AI summary This section addresses depreciation and regulatory deferrals in a Nova Scotia regulatory proceeding, focusing on methodologies and considerations related to asset valuation and cost recovery. Key entities include the Nova Scotia Energy Board (NSEB) and other stakeholders involved in rate-setting and cost-of-service studies.

to the recreational use of the waterway. In the case of the Tusket Hydro System, a reduction in the water table through decommissioning the Hydro System, would result in effects on residential wells. In addition to the foregoing, in the ca...

AI summary The decommissioning of Nova Scotia's Tusket, Wreck Cove, and Mersey hydroelectric systems could impact residential wells and jeopardize reliability standards set by NERC and NPCC. NS Power argues against including decommissioning costs in customer rates until broader stakeholder discussions occur, citing the need to mitigate rate pressure while ensuring grid reliability.

- expense is forecast to be $9.1 million in 2026 and $9.3 million in 2027. Figure 8-3 – 2026-2027 Regulatory Amortizations ($ Million) Amortizations 2026 2027 Non-Standard Meters 2.4 - Hurricane Fiona Cost Recovery 3.4 3.4 Roseway Hydro De...

AI summary The document outlines forecasted expenses for 2026 and 2027, with a focus on amortization costs related to various projects and initiatives, including the AMI project, Hurricane Fiona recovery, and decommissioning costs.

9 RATE BASE

AI summary The section titled '9 RATE BASE' is part of a regulatory proceeding in Nova Scotia, involving entities such as the Nova Scotia Energy Board (NSEB) and Dominion Bond Rating Service (DBRS). Key terms include Funds From Operations (FFO), Cash Flow From Operations (CFFO), and the Fuel Adjustment Mechanism (FAM). The context includes references to regulatory processes and acronyms relevant to energy pricing and cost-of-service studies.

Requested Capital Structure and Cost of Capital - It is a well-established regulatory principle and is codified in the Public Utilities Act (PUA) that - NS Power's approved Capital Structure and Cost of Capital must be sufficient to allow...

AI summary The document discusses NS Power's request to maintain a 9.0% ROE and 40% equity ratio, contrasting with Concentric Evidence's recommendation of 9.9% ROE and 45% equity. It emphasizes the need to balance customer affordability with financial stability, referencing the Public Utilities Act and the role of the Storm Cost Recovery Rider in aligning NS Power's risk profile with proxy utilities.

12 COST OF SERVICE - NS Power is applying for both fuel rate increases and non-fuel rate increases. The proposed Cost- - of-Service Study (COSS) methodology is as set out in Appendix 12A , for which the Company - seeks approval. The propos...

AI summary NS Power seeks approval for a Cost-of-Service Study (COSS) methodology to justify both fuel and non-fuel rate increases. Consensus exists with Customer Representatives on using Appendix 12A and SR-01 Attachments for the 2026-2027 GRA. Future proceedings will address the Minimum System methodology, PHP's responsibility for High Voltage transmission costs, and apportionment of Maritime Link assessment costs.

Fuel-Related COSS - A traditional BCF Application considers setting BCF rates for a test period based on the fuel cost - requirement in accordance with COSS methodology and as prescribed in the FAM Plan of - Administration. Consistent with...

AI summary The document outlines the traditional approach to setting Base Cost of Fuel (BCF) rates using Cost-of-Service Study (COSS) methodology and the Fuel Adjustment Mechanism (FAM) Plan of Administration. It details the allocation of fuel costs among rate classes via the revised Plan of Administration (POA) and notes updates to the FAM POA due to stakeholder engagement, with supporting details in Appendix 6B and SR-01 Attachments 5 and 6.

PHP COSS Treatment - NS Power anticipates filing an application for approval of a new above-the-line (ATL) Tariff - applicable to PHP and PHP has committed to take service under the ATL tariff effective January - 1, 2026, or such later dat...

AI summary NS Power plans to file a new above-the-line (ATL) tariff for PHP, effective January 1, 2026, with ADC service as a rider. A deferral account (PHP Deferral) is requested to address revenue variances if the tariff or ADC rider differs from GRA COSS assumptions or if service isn't available by 2026.

13 ANY RESULTING COSTS OR REFUNDS WOULD BE ALLOCATED TO ATL

AI summary The document states that any resulting costs or refunds from the proceeding would be allocated to ATL, though the specific entity or organization represented by ATL is not explicitly defined in the provided text.

CUSTOMERS FOR RECOVERY IN A FUTURE PROCEEDING. RATE DESIGN

AI summary The document discusses considerations for customers in recovery processes within a future regulatory proceeding, focusing on rate design implications. Key entities and acronyms related to energy regulation and financial metrics are referenced, with potential implications for rate structures and customer impact.

DSM Rider - In the 2023-2024 GRA, the NSEB approved NS Power's application for a DSM Rider. The DSM - costs are billed as part of the energy charge on customers' bills. Since the GRA, the NSEB has - approved the DSM Rider for 2024 and 2025...

AI summary The NSEB approved the DSM Rider for 2024 and 2025, and NS Power proposes continuing to recover DSM program costs through the rider. The 2025 legislation extended the DSM Supply Agreement with EfficiencyOne, capping recoverable costs at $63.75 million. Changes to the Balance Adjustment (BA) calculation include annual volume variance adjustments and an End of Approved DSM Term Adjustment.

Storm Cost Recovery Rider - In the Board's 2023-2024 GRA Decision, it approved the Storm Cost Recovery Rider (SCRR) on - a three-year pilot basis, providing for recovery of OM&G restoration costs for Level 3 and 4 - storms in the years 202...

AI summary The Nova Scotia Energy Board (NSEB) approved the Storm Cost Recovery Rider (SCRR) as a three-year pilot in the 2023-2024 GRA Decision, allowing NS Power to recover Level 3/4 storm costs. NS Power seeks continuation for 2026-2027. Customer advocates raised concerns about the SCRR's asymmetry, which was mitigated by the pilot period and PUA amendments.

NS Power proposes the base rate allowances for storm restoration OM&G costs during the GRA period as set out in [Figure 13-2](#page-84-0) below. Figure 13-2 – Storm Restoration OM&G Costs (Levels 1-4) Level 1 & 2 ($ million) Level 3 & 4 ($...

AI summary NS Power is proposing base rate allowances for storm restoration OM&G costs during the GRA period, as outlined in Figure 13-2. The NSEB previously emphasized the importance of a formalized Climate Adaptation Plan to support prudency assessments in SCRR applications.

Distribution Tariff - With respect to service in the Renewable to Retail Market, NS Power has reviewed and updated - charges for the distribution and retail services offered under the Distribution Tariff (DT) and - Distribution Tariff Rate...

AI summary NS Power is updating the Distribution Tariff (DT) and Distribution Tariff Rates (DTR) to address gaps in cost recovery for transmission-connected Large Industrial Rate (LIR) customers migrating to Licensed Retail Suppliers (LRS) under the Renewable to Retail (RTR) market. Proposed changes include separate charges for distribution- and transmission-connected customers and inclusion of Storm Cost Recovery Rider (SCRR) and Demand Side Management (DSM) provisions.

Rate-setting Process Overview - Once the revenue requirement has been established, it is apportioned among rate classes based on - their usage through COSS. The COSS results provided foundation for determination of class - revenue responsi...

AI summary The rate-setting process establishes revenue requirements, apportions them among rate classes via COSS, and adjusts classes outside the 95-105 revenue-to-cost ratio band. Adjustments inform customer rate revisions, ensuring equitable revenue distribution based on usage and cost allocations.

16 RELIEF REQUESTED - NS Power seeks an order approving the following: - 1. The 2026 and 2027 revenue requirements as described in Section 11 to enable NS Power to recover the prudent and reasonable costs of providing service to customers...

AI summary Nova Scotia Power is requesting regulatory approval for various financial and operational measures, including revenue requirements for 2026 and 2027, amendments to the Fuel Adjustment Mechanism Plan of Administration, deferrals related to the Decarbonization Deferral Account and EIFEL, and updates to the Cost-of-Service Study. The request also includes continuation of the Storm Cost Recovery Rider pilot and adjustments to the Base Cost of Fuel amounts.

NS Power 2026-2027 General Rate Application NON-CONFIDENTIAL PR-01 Attachment Description PR-01 Attachment 2 n Medium Industrial Tariff PR-01 Attachment 2 o Large Industrial Tariff PR-01 Attachment 2 p Municipal Tariff PR-01 Attachment 2 q...

AI summary NS Power is proposing 2026-2027 rate changes, including tariffs for industrial, municipal, and outdoor lighting services, along with the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR). Attachments detail various rate structures and cost recovery mechanisms.

DSM COST RECOVERY RIDER The Demand Side Management Cost Recovery Charge (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Demand Side Management Cost Recovery Rider, shall apply, in addition to t...

AI summary The Demand Side Management Cost Recovery Rider establishes a charge (in cents per kilowatt-hour) applicable to the current rate year's Tariff, to be applied in addition to the energy charge. This charge is specified within the DCR Rider framework.

STORM COST RECOVERY RIDER Storm Cost Recovery charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.

AI summary The Storm Cost Recovery Rider applies additional charges or credits (in cents per kilowatt-hour) to the Tariff for the current rate year, in addition to the energy charge.

SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required to make a c...

AI summary Special conditions outline metering requirements, customer cost responsibilities for primary metering, transformer ownership for non-standard services, and load integrity obligations. Adjustments to kWh usage and system integrity factors (reliability, harmonics, voltage flicker) are specified. Customers must ensure their operations do not compromise power supply stability.

SCHEDULE 1: SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE This service is required to schedule the movement of power through, out of, within, or into an Operating Area. This service can be provided only by the operator of the Operating A...

AI summary Schedule 1 outlines the Scheduling, System Control and Dispatch Service, which is required to manage power movement within an Operating Area. The service must be provided by the Operating Area operator or Transmission Provider, with charges passed through to Transmission Customers. Monthly fees apply, and costs are reflected as pass-through charges if the Operating Area operator performs the service.

SCHEDULE 2: REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES SERVICE In order to maintain transmission voltages on the Transmission Provider's transmission facilities within acceptable limits, generation facilities (in the Opera...

AI summary Schedule 2 outlines requirements for Reactive Supply and Voltage Control from Generation Sources Service to maintain transmission voltages within acceptable limits. The Transmission Provider or Operating Area operator must provide this service, with charges based on set rates. Transmission Customers must purchase the service, with costs passed through if the Operating Area operator performs the service.

SCHEDULE 5: OPERATING RESERVE – SPINNING RESERVE SERVICE Spinning Reserve Service is needed to serve load immediately in the event of a system contingency. Spinning Reserve Service may be provided by generating units that are on-line and l...

AI summary Spinning Reserve Service ensures immediate load support during system contingencies, provided by on-line generating units operating below maximum output. The Transmission Provider must offer this service when serving load within its Operating Area, while the Transmission Customer must purchase it or arrange alternatives. Monthly charges apply, with costs passed through if the Operating Area operator provides the service.

SCHEDULE 6: OPERATING RESERVE – SUPPLEMENTAL RESERVE SERVICE Supplemental Reserve Service (also referred to as Contingency Reserve – Supplemental) is needed to serve load in the event of a system contingency; however, it is not available i...

AI summary Schedule 6 outlines the Supplemental Reserve Service, required to address system contingencies within a short timeframe. It may be provided by on-line unloaded units, quick-start generation, or interruptible load. Transmission Customers must purchase this service from the Transmission Provider or arrange alternatives. Monthly charges apply, with costs passed through if the Operating Area operator provides the service.

Operating Reserve – Supplemental (30-minute)

AI summary The document pertains to a regulatory proceeding concerning the 'Operating Reserve – Supplemental (30-minute)' mechanism. It involves Nova Scotia Power Inc. (NSPI) and the Nova Scotia Energy Board (NSEB), with references to the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR). The proceeding likely addresses operational reserve requirements and cost recovery frameworks.

DEMAND SIDE MANAGEMENT (DSM) COST RECOVERY RIDER The Demand Side Management Cost Recovery Charge (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Demand Side Management Cost Recovery Rider, shal...

AI summary The Demand Side Management Cost Recovery Rider imposes an additional charge per kilowatt-hour on the Tariff for the current rate year, applied alongside the energy charge. This mechanism enables cost recovery for demand-side management initiatives.

STORM COST RECOVERY RIDER Storm Cost Recovery charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.

AI summary The Storm Cost Recovery Rider outlines charges or credits in cents per kilowatt-hour applicable to the current rate year's Tariff, in addition to the energy charge.

ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...

AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs beyond those included in its revenue requirement, subject to approval by the Nova Scotia Energy Board. If actual costs are below the approved amount, the underspend is tracked and may be returned to customers after reaching a threshold. The Rider includes specific charges and cost allocation methods.

3 OATT in $/kW Tariff Storm Riders in cents per kWh3 Small General, Small General Time-of-Use, Small General Critical Peak Pricing 0.000 General, General Time-of-Use, General Critical Peak Pricing, Multi-unit Residential Building Time-of-U...

AI summary The document lists the Open Access Transmission Tariff (OATT) in dollars per kilowatt and shows that all tariff categories have a Storm Riders rate of 0.000 cents per kWh. It also notes that if a Storm Cost Recovery Rider (SCRR) application is required, the Company will submit it by April 30th to be effective in the following year.

DEMAND SIDE MANAGEMENT COST RECOVERY RIDER (DCRR) The monthly amount computed under each of the rate schedules to which this DSM Cost Recovery Rider is applicable shall be increased or decreased by the DCRR at a class-specific rate per kil...

AI summary The Demand Side Management Cost Recovery Rider (DCRR) adjusts monthly rates based on a class-specific formula (DCRR = PCR + BA) applied to kilowatt-hour consumption under applicable rate schedules. This mechanism recovers DSM program costs through consumption-based rate adjustments.

PCR = Program Cost Recovery The PCR includes all estimated costs for the upcoming calendar year for the DSM Plan that has been requested by the Franchise Holder and approved by the NSEB (Approved DSM). It includes the cost of planning, dev...

AI summary The Program Cost Recovery (PCR) encompasses estimated costs for the approved Demand Side Management (DSM) Plan, including planning, implementation, and administrative expenses. Costs are allocated per rate schedule using Schedule B's methodology, as approved by the Nova Scotia Energy Board (NSEB).

BA = Balance Adjustment The BA is comprised of two components: - (1) BA1 = Annual Volume Variance Adjustment calculated for each rate class separately on a previously completed calendar year basis and is used to reconcile the difference be...

AI summary The Balance Adjustment (BA) consists of two components: BA1, which reconciles revenue variances using a two-year lag, and BA2, which adjusts for discrepancies between approved DSM funding and actual expenditures. Both components ensure accurate billing based on historical data and program costs.

DSM Cost Allocation Method - Step 1 Allocate the class and participation benefits by directly assigning 100% of the DSM investment identified for each participating customer class. - Step 2 For NS Power bundled service customers, divide th...

AI summary The DSM Cost Allocation Method outlines a five-step process for allocating Demand Side Management (DSM) costs. It involves assigning DSM investments to customer classes, calculating program cost recovery based on electricity sales, direct billing for Wholesale/Renewable to Retail (RtR) customers, and annual/term-end true-ups referenced in Balance Adjustment (BA) sections. The method applies to NS Power bundled service and market-specific recovery mechanisms.

DSM COST RECOVERY RIDER The Demand Side Management Cost Recovery Charge (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Demand Side Management Cost Recovery Rider, shall apply, in addition to t...

AI summary The Demand Side Management Cost Recovery Rider (DCR) imposes an additional charge (in cents per kilowatt-hour) on the Tariff for the current rate year, to be applied alongside the energy charge. This mechanism allows Nova Scotia Power Inc. (NSPI) to recover costs associated with demand-side management programs.

STORM COST RECOVERY RIDER Storm Cost Recovery Ccharges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.

AI summary The Storm Cost Recovery Rider establishes charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year. These charges apply in addition to the energy charge, as outlined in the rider.

STORM COST RECOVERY RIDER Storm Cost Recovery Ccharges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.

AI summary The Storm Cost Recovery Rider establishes charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, in addition to the energy charge. These adjustments are designed to recover costs associated with storm-related events.

SCHEDULE 1: SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE This service is required to schedule the movement of power through, out of, within, or into an Operating Area. This service can be provided only by the operator of the Operating A...

AI summary Schedule 1 outlines the Scheduling, System Control and Dispatch Service, required for power movement within an Operating Area. The service is provided by the Operating Area operator or Transmission Provider, with charges passed through to Transmission Customers. Monthly fees apply, reflecting costs incurred by the Operating Area operator if it performs the service.

(11) Light Emitting Diode (LED) – Operating, Maintenance, and Capital (full charge) Data Cada Watts kWh per per mo onth ($) Othor Rate Code Watts month 2023 2024 - Other 724 55 18 6.75 7.02 740 190 63 15.02 15.15 741 261 87 17.38 17.48 742...

AI summary The document presents a table detailing Light Emitting Diode (LED) rate codes, associated wattage, kWh consumption, and monthly costs for 2023–2027. Rate codes 724, 740–743 are listed with varying wattage and cost adjustments over time, including deleted and updated values. The data reflects changes in pricing structures for LED-related charges.

STORM COST RECOVERY RIDER Page 3 of 3 Tariff Storm Riders in cents per kWh3 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use...

AI summary The document outlines the Storm Cost Recovery Rider (SCRR) and specifies that no storm riders are applied to various tariff categories, with a rate of 0.000 cents per kWh. It also details the process for submitting SCRR applications by April 30th to recover actual storm costs and compare them with forecasted recoveries.

RESPONSIBILITIES OF FRANCHISE HOLDER It is the responsibility of the holder of the electric efficiency and conservation franchise granted under Section 79C of the Public Utilities Act (Franchise Holder) to apply to the Nova Scotia Utility...

AI summary The Franchise Holder must seek NSUAREB approval for DSM activities and costs. NS Power must apply annually by October 1 for DCRR amounts and monthly fund DSM costs approved by NSUAREB under Section 79C of the Public Utilities Act.

DEMAND SIDE MANAGEMENT COST RECOVERY RIDER (DCRR) The monthly amount computed under each of the rate schedules to which this DSM Cost Recovery Rider is applicable shall be increased or decreased by the DCRR at a class-specific rate per kil...

AI summary The DCRR adjusts monthly amounts for applicable rate schedules using a class-specific rate formula (DCRR = PCR + BA), reflecting Nova Scotia's regulatory framework for demand-side management cost recovery.

PCR = Program Cost Recovery The PCR includes all estimated costs for the upcoming calendar year for the DSM Plan that has been requested by the Franchise Holder and approved by the NSUAREB (Approved DSM). It includes the cost of planning,...

AI summary The Program Cost Recovery (PCR) encompasses estimated annual costs for approved Demand Side Management (DSM) programs, including planning, implementation, and administrative expenses. Costs are allocated per rate schedule using Schedule B's methodology. The DSM Plan was requested by the Franchise Holder and approved by the NSUAREB.

BA = Balance Adjustment The BA is comprised of two components: (1) BA1 = Annual Volume Variance Adjustment – is calculated for each rate class separately on a previously completed calendar year basis and is used to reconcile the difference...

AI summary The Balance Adjustment (BA) comprises two components: BA1, which reconciles revenue differences using a two-year lag, and BA2, which adjusts for DSM program costs. These mechanisms ensure accurate billing based on actual usage and expenditures.

2025 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2025 to December 31, 2025 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for 2025, including its components PCR and BA. It explains that the Balance Adjustment (BA2) for 2023 will be applied over the 2027-2031 term and will be based on revenue collected between February 2, 2023, and December 31, 2023, compared to DSM costs incurred during that period.

DSM Cost Allocation Method Approach There are 3 kinds of cost benefits resulting from DSM: - (1) System—avoided future infrastructure and related costs, reduced fuel costs, and contribution to achieving environmental and emissions restrict...

AI summary The document outlines three categories of benefits from Demand Side Management (DSM): system-wide, class-based, and participation-specific. It argues that DSM costs should be allocated based on the level of benefit received by customer classes, with those receiving more benefits contributing more. However, precise allocation is challenging due to the nature of DSM programs.

Allocation of DSM Program Costs System benefits are allocated to all applicable customer classes in accordance with the Cost of Service Study (COSS) methodology reflecting allocation of generation rate base as per the most recent rate case...

AI summary System benefits from DSM programs are allocated to customer classes using the Cost of Service Study (COSS) methodology based on the latest rate case decision. Remaining costs are assigned proportionally to participating classes according to their investment in DSM programs.

Method - Step 1 Allocate the system benefits to all applicable customer classes, as 25% of the total Approved DSM program costs, in accordance with the COSS methodology per the most recent rate case decision. - Step 21 Allocate the class a...

AI summary The document outlines a six-step method for allocating and recovering Demand Side Management (DSM) program costs. Key steps include distributing system benefits, calculating class-specific recovery amounts, and adjusting for actual experiences. Recovery methods differ for bundled service customers versus Wholesale/Renewable to Retail market participants, with annual true-ups based on Balance Adjustment (BA) guidelines.

DEMAND SIDE MANAGEMENT COST RECOVERY RIDER (DCRR) Page 5 of 5 - For bundled service customers other than those who take service in the Wholesale Market (whether in whole or in part), this approach applies to classes as a whole (not to indi...

AI summary The DCRR applies differently to bundled service customers and Wholesale Market participants. For non-Wholesale Market bundled customers, the approach applies to classes as a whole, while Wholesale Market customers are treated individually. The method applies to total Approved DSM costs.

Baseline Data NS Power Customers Customers Meter Reads Opt-out Customers 7.3 Section 1.0 Schedule of load research charges One rate for all equipment types Bi-monthly Monthly The capital costs of metering equipment to be recovered will be...

AI summary The document outlines the baseline data for load research charges and installation charges related to metering equipment. It details the incremental capital costs of AMR meters compared to non-AMR meters and provides installation charge rates for different service types, including single phase and three phase services.

The following schedule of charges shall apply to customers requesting Load Research information. (Note: Customers must provide access to a shared phone line for data collection via automatic meter reading equipment): - a) Recovery of the C...

AI summary The document outlines the schedule of charges for Load Research information, including recovery of capital costs, setup, analysis and reporting, and specialized customer analysis, each with a 25% markup on actual costs incurred by the company.

SCHEDULE OF LOAD RESEARCH CHARGES The capital costs of non-standard metering equipment (meters with advanced capabilities) to be recovered will be the incremental cost of the non-standard meter installed compared to an equivalent standard...

AI summary The document outlines that capital costs for non-standard metering equipment (advanced meters) will be recovered based on the incremental cost compared to equivalent standard meters, focusing on the difference in expenses between the two types of metering systems.

2.0 Recovery of Installation Charges When organizes organized and paid by NSPI, recovery of telephone line installation charges will be at cost. Single Phase Service Self-Contained $ 48.00 59.00 Single Phase Service, Transformer Rated and...

AI summary The text outlines the recovery of telephone line installation charges by NSPI at cost, listing specific fees for different service types.

Regulation 7.3 Load Research Charges Page 2 of 2 3.0 Recovery of Operational Charges $ 226.00 217.00 4.0 Load Research Setup $ 116.00 5.0 Analysis and Reporting Base Package See Charge per Billing Period Options Data File 43.00 Load profil...

AI summary The document outlines various charges related to Load Research, including setup, analysis, and reporting options, with specific costs listed for different types of reports and analyses. It provides a detailed breakdown of fees associated with operational charges, data files, and specialized analysis.

2.0 Recovery of Installation Charges When organized and paid by NSPI, recovery of telephone line installation charges will be at cost. $ 59.00 Single Phase Service Self-Contained $ 160.00 Single Phase Service, Transformer Rated and Three P...

AI summary The text outlines the recovery of telephone line installation charges by NSPI at cost, with specific charges listed for different service types.

Load Research Charges Page 2 of 2 3.0 Recovery of Operational Charges $ 217.00 4.0 Load Research Setup $ 116.00 5.0 Analysis and Reporting Base See Charge per Billing Period Package Options Data File 43.00 Load profile for each day for eac...

AI summary The document outlines various charges associated with load research, including setup, analysis, and reporting. It provides a detailed breakdown of costs for different types of reports and analyses, such as load profiles, power factor plots, and specialized hourly analysis.

TABLE OF STANDARDIZED FILINGS AND ATTACHMENTS Attachment 1 – COS Procedures Attachment 1a – Cost of Service Methodology Attachment 1b – Determination of Revenue Responsibilities by Rate Class Attachment 1c – Fuel and Purchased Power Relate...

AI summary The document lists standardized filings and attachments for a regulatory proceeding, covering cost-of-service methodologies, revenue responsibilities, fuel costs, unmetered services pricing, OATT calculations, and distribution tariff computations for 2026-2027. Attachments include partially confidential data and rate component tables.

2026-2027 GRA Direct Evidence Appendix 1A Page 2 of 7 REDACTED (CONFIDENTIAL INFORMATION REMOVED) OP-01 NS Power / Emera Regulated Annual Reports Attachment 1 – NS Power 2024 Q3 MD&A Attachment 2 – NS Power 2024 Financial Statements Attach...

AI summary This document contains direct evidence from the 2026-2027 GRA proceeding, including NS Power and Emera's annual reports, financial statements, and proposed tariffs with various attachments related to domestic, general, and industrial service tariffs, as well as the Fuel Adjustment Mechanism and Storm Cost Recovery Rider.

PR-02 Cost Support for Proposed Regulation Changes Attachment 1 – AMI Opt-out Fee Development Attachment 2 – Miscellaneous Charges Development (Partially Confidential) Regulation 7.3 Schedule of Load Research Monitoring, Reporting and Anal...

AI summary The document outlines attachments related to AMI opt-out fee development and miscellaneous charges, alongside references to Regulation 7.3 concerning load research monitoring, reporting, and analytical charges. It pertains to cost support for proposed regulatory changes in Nova Scotia.

2026-2027 GRA Direct Evidence Appendix 1B Page 4 of 4 REDACTED (CONFIDENTIAL INFORMATION REMOVED) OT Overtime OTE Overhead Transmission Equipment PCB Polychlorinated Biphenyls PCR Program Cost Recovery (for DSM) PHB Port Hawkesbury Biomass...

AI summary This document is an appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing a list of acronyms and their expansions relevant to energy regulation, infrastructure, and financial terms. The content is redacted, with confidential information removed, and focuses on technical, operational, and regulatory terminology used in the proceeding.

2026-2027 GRA Direct Evidence Appendix 3A Page 1 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding, focusing on direct evidence. Key elements include regulatory considerations, cost recovery mechanisms, and potentially rate design issues, though specific details are confidential.

2. Storm Rider and Stakeholder Engagement The Board issued the following directive with respect to filing its application for a Storm Rider and the stakeholder engagement for agreement on the presentation of materials at para. 338 of the 2...

AI summary The Nova Scotia Energy Board (NSEB) directed NS Power to include detailed storm restoration, hardening, and vegetation management costs in each Storm Rider application during a three-year trial period. Stakeholder engagement was required to determine information presentation. NS Power filed its first Storm Rider Application in 2024 for 2023 costs and will not file for 2026 due to no Level 4 storms.

5. Cost of Service Study and Line Loss Study Stakeholder Engagement The Board's directive is found at para. 367 of the 2023-2024 GRA Decision: The Board concurs that the COSS and Line Loss Study should be updated to reflect a number of dev...

AI summary The Nova Scotia Energy Board (NSEB) mandates updates to NS Power's Cost of Service Study (COSS) and Line Loss Study to reflect system changes since 2013, including renewable integration, gas generation, and grid storage. The Board requires semi-annual progress reports starting January 31, 2024, and a review of cost allocation methodologies.

2026-2027 GRA Direct Evidence Appendix 3A Page 4 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED) NS Power has undertaken an updated Cost of Service Study and Line Loss Study. This included an extensive consultation process. In accordance...

AI summary NS Power conducted updated Cost of Service and Line Loss Studies, following the Board's directive, with biannual stakeholder engagement updates since 2024. Studies are included in Appendices 12A, B, and C of the GRA.

2026-2027 GRA Direct Evidence Appendix 3A Page 6 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary Redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding, focusing on direct evidence. Context involves regulatory considerations for utility rate structures, cost recovery mechanisms, and potential impacts on customer classes.

11. Alternative Treatment of -16 MW in AGC The Board's directive on this item is set out at para. 482 of the 2023-2024 GRA Decision: Prior to the next GRA, NS Power is directed to explore alternative treatment of the - 16 MW requirement an...

AI summary The Nova Scotia Energy Board directed NS Power to explore alternative treatment of -16 MW in AGC to avoid double-charging transmission customers, as outlined in the 2023-2024 GRA Decision. NS Power addressed this in its report (SR-01 Attachment 1e).

2026-2027 GRA Direct Evidence Appendix 3A Page 7 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED) supplementary reserve, so the CBAS charges reflect that actual use of those assets. However, considering Mr. Marshall's questioning of the c...

AI summary The text addresses the need for NS Power to clarify its calculation methodology for spinning reserve and 10-minute supplementary reserve utilization in CBAS charges, as directed by a regulatory proceeding. NS Power has responded to this directive in SR-01 Attachment 1e.

2027 - A. Simple Average of short-term debt outstanding- $284.3 million - B. Twelve-month Average of short-term debt outstanding- $336.5 million - C. Interest on short-term debt- $10.9 million Simple Average cost of short-term debt (C/A)-...

AI summary The text calculates the cost of short-term debt using two methods: a simple average and a twelve-month average. The simple average results in a 3.85% cost, while the twelve-month average yields 3.25%, based on provided figures for debt outstanding and interest expenses.

2026-2027 GRA Direct Evidence Appendix 3B Page 16 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, with confidential information removed. It is part of a regulatory process involving utility cost recovery and rate design considerations.

Critical Spares The critical spares option is used to prepare for the failure of the asset. The critical spare would be kept in inventory, or readily available from approved suppliers, to enable a relatively quick replacement and return-to...

AI summary The critical spares strategy involves maintaining inventory or supplier access for essential components to ensure rapid replacement of failed assets, minimizing operational disruptions and customer impact. Spares are considered based on asset complexity, lead times, and cost, with classification into operating or capital expenditures depending on the component type. For example, pole-top transformers may be kept in inventory due to their relatively low cost and quick installation requirements.

2026-2027 GRA Direct Evidence Appendix 3B Page 44 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted page from the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 3B, part of a Nova Scotia regulatory proceeding. No substantive content is visible due to redaction, but it is associated with cost recovery, rate design, and regulatory processes.

Senior Directors (Asset Management and Environment) - Provide visible leadership and strategic direction for the climate adaptation planning and programs; - Ensure the Climate Adaptation Plan achieves its intended outcomes related to impro...

AI summary Senior Directors are tasked with leading climate adaptation planning, ensuring organizational resiliency, prioritizing climate-related risks, allocating resources for adaptation programs, and holding leaders accountable for implementation and performance outcomes.

2026-2027 GRA Direct Evidence Appendix 3B Page 46 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It includes a list of acronyms and terms relevant to energy regulation, cost recovery mechanisms, and infrastructure planning, though the actual content is confidential and removed.

2026-2027 GRA Direct Evidence Appendix 3B Page 54 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - Monitoring Plan : Creating a robust climate data and weather monitoring plan to continually collect observations of key climate variables...

AI summary NS Power outlines a climate monitoring plan to collect data on key climate variables, allocate resources for monitoring, collaborate with external organizations, enhance in-house data collection technologies, and benchmark empirical data against climate projections to inform climate change pathways.

2026-2027 GRA Direct Evidence Appendix 3C Page 9 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is a redacted page from Appendix 3C of the 2026-2027 General Rate Application (GRA) proceeding. It contains confidential information removed, focusing on regulatory evidence related to cost recovery, rate design, and energy management programs in Nova Scotia.

3.1 Enhanced Risk Profiling

AI summary The section '3.1 Enhanced Risk Profiling' is part of a regulatory proceeding document, but no detailed content is provided beyond a list of acronyms related to energy regulation, utility operations, and environmental legislation.

9.1 Emergency Services Restoration Plan NS Power has an Emergency Services Restoration Plan (ESRP) that is deployed to co-ordinate restoration response for events that are expected to result in customer outages of longer than 36 hours or 5...

AI summary NS Power's Emergency Services Restoration Plan (ESRP) coordinates restoration for outages exceeding 36 hours or 50,000 customers over 24 hours. First filed in 2004, it is reviewed annually and updated based on storm drills. The plan emphasizes resource allocation, interagency coordination, and safety protocols, including wildfire response activation.

REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 7 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing confidential information. Key acronyms related to energy regulation, cost recovery, and infrastructure are listed, though no substantive content is visible due to redaction.

REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 13 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary Redacted section of the 2026-2027 GRA Direct Evidence Appendix, focusing on regulatory proceedings related to rate applications and cost recovery mechanisms. Key terms include DSM, AA, and F&PP, though specific details are confidential.

1 Figure 8 - CONFIDENTIAL 2024-2027 Comparison of Cost of Fuel/MWh 4 Figure 9 - 2024 Breakdown of BCF by Fuel and Purchased Power Type

AI summary Confidential figures compare fuel costs from 2024-2027 and detail the 2024 breakdown of Base Cost of Fuel (BCF) by fuel type and purchased power. The analysis focuses on fuel cost trends and composition, critical for regulatory decision-making in Nova Scotia's energy sector.

REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 14 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary Redacted page from a 2026-2027 GRA Direct Evidence Appendix in a Nova Scotia regulatory proceeding. Contains confidential information removed, with a list of acronyms related to energy regulation, cost recovery, and operational metrics.

REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 27 of 38

AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It includes technical and regulatory terminology related to energy management, cost recovery mechanisms, and utility operations, though no specific content or arguments are visible due to redaction.

1 1.3.2 ML Assessment and Depreciation 2 - 3 In accordance with the requirements of the Maritime Link Cost Recovery Regulations, NSPML - 4 submits annual applications to recover forecast costs attributable to the Maritime Link from NS - 5...

AI summary NSPML submits annual applications to recover forecast costs for the Maritime Link from NS Power, including projected costs of $200.5 million in 2026 and $203.9 million in 2027, as required by the Maritime Link Cost Recovery Regulations.

REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 36 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is part of a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, with confidential information redacted. It references regulatory processes involving cost recovery, rate adjustments, and energy management systems, though specific details are omitted.

REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Direct Evidence Appendix 6A Page 2 of 10

AI summary The document is a redacted page from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 6A. It is page 2 of 10, with confidential information removed. The GRA process involves rate-setting and cost recovery mechanisms for utility services.

2026-2027 GRA Direct Evidence Appendix 6A Page 5 of 10 REDACTED (CONFIDENTIAL INFORMATION REMOVED) establishing customer fuel rates to recover or return the FAM deferral amount, and as noted in Section [1.3](#page-163-0) below, NS Power fi...

AI summary The document outlines the process for establishing customer fuel rates to recover or return the FAM deferral amount using 12 months of actual fuel data (October to September). The total deferral amount is divided by the upcoming year's sales forecast to determine the AA rate.

2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 1 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary Redacted appendix for the 2026-2027 General Rate Application (GRA) in Nova Scotia, focusing on direct evidence. The document is part of a regulatory proceeding involving cost recovery mechanisms and energy management systems, with confidential information removed.

2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 8 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Wholesale Market Backup/Top-up Service Tariff (BUTU). - 2. For ATL and BUTU classes the following costs and credits - a. NS Power's...

AI summary The document outlines cost allocation methodologies for Wholesale Market Backup/Top-up Service Tariff (BUTU) and Above-the-Line (ATL) classes, including fuel costs, biofuel expenses, import costs, and export credits. Fuel costs are allocated based on energy contribution, while demand-related costs use load factors and peak contributions. Scaling via revenue-to-cost ratios ensures alignment with approved rates.

3.2.2 Solid Fuel Solid fuel costs are collected into three categories: Inventoried Costs, Costs Directly Applied, and Costs Expensed Through Plant Fuel Handling Adjustments. Those categories include the following costs:

AI summary Solid fuel costs are categorized into three types: Inventoried Costs, Costs Directly Applied, and Costs Expensed Through Plant Fuel Handling Adjustments. These categories encompass various associated expenses, reflecting a structured approach to cost management within the regulatory proceeding.

3.2.5 Light Starter Oil - LFO (Light Fuel Oil) Commodity Consumed - Transportation Cost - Quality Testing and Inventory Measurement Costs - GHG Emission Compliance Program costs Costs of this type are normally recorded in the following acc...

AI summary This section outlines costs related to Light Fuel Oil (LFO) including transportation, quality testing, inventory measurement, and GHG compliance. These costs are recorded in specific accounts within NS Power's Chart of Accounts, such as 502550 REG FUEL LIGHT OIL CONSUMED.

2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 20 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. No substantive content is visible due to redaction, but it is part of a regulatory process involving cost recovery, rate design, and utility operations.

3.2.16 BTL Costs - Spill energy payments under the Wholesale Market Non-Dispatchable Supplier Spill Tariff - Fuel cost incurred in providing service under the Wholesale Market Backup/Top-up Service tariff, less revenue received under the W...

AI summary The section outlines two components of BTL costs: spill energy payments under the Wholesale Market Non-Dispatchable Supplier Spill Tariff and net fuel costs under the Wholesale Market Backup/Top-up Service tariff, adjusted for revenue and non-fuel items.

3.2.17 GHG Emission Compliance Program Costs - The cost of Fund Credits under the Nova Scotia GHG Output Based Pricing System (OBPS) emissions compliance programs. - Transaction fees for purposes of purchasing GHG OBPS Fund Credits). Costs...

AI summary The document outlines costs related to GHG emission compliance programs in Nova Scotia, specifically the cost of Fund Credits under the OBPS and transaction fees for purchasing these credits. These costs are recorded in account 503400 under NS Power's Chart of Accounts.

2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 21 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 6B, page 21 of 33. It contains redacted confidential information related to regulatory proceedings in Nova Scotia. The GRA process involves cost recovery mechanisms, rate design, and evidence submission for utility services.

2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 28 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, focusing on direct evidence. Confidential information has been removed, limiting the visibility of specific arguments or data.

2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...

AI summary The Balancing Adjustment Component (BA) corrects over/under-recovery from the Actual Adjustment Component (AA) and may defer fuel/purchased power costs with Board approval. The Fuel Adjustment Mechanism (FAM) includes AA and BA, with AA calculated annually based on fuel cost differences and BA managing prior adjustments and deferred costs.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 9 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) costs of the Port Hawkesbury biomass plant. c. d. In-province purchased power from all other sources than wind and biomass will be...

AI summary The document discusses the classification of costs for the Port Hawkesbury biomass plant and the categorization of in-province purchased power (excluding wind and biomass) as demand and energy, similar to NS Power's fixed cost base load generation.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 10 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) e. Maritime Link imports under Nova Scotia Block will be classified to energy and demand on the basis of the system load factor a...

AI summary The document outlines methods for classifying and allocating costs related to Maritime Link imports, non-firm imports, and biomass generation. It specifies allocations based on system load factors, coincident contribution to system peaks, and energy requirements, with adjustments using revenue-to-cost ratios to align fuel costs with rate revenues.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 12 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) refund any under or over-recovery due to prior adjustments. These adjustments may include variances in actual and forecasted sale...

AI summary The document outlines mechanisms for refunding under/over-recoveries from prior adjustments, including variances in sales volumes, BCF amounts, and interest. The BA component may include fuel-related factors requiring Board approval, with 2024 BA under-recoveries deferred from the 2020-2022 Fuel Stability Plan included in the balance.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 13 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Allowable fuel expenses will include normal, recurring, non-capital expenses that have been prudently incurred. Discrepancies bet...

AI summary The document outlines allowable fuel expenses, including normal, recurring, non-capital expenses and discrepancies supported by surveys. Exceptional costs are reviewed by the Small Working Group. NS Power acknowledges audit and approval by the Nova Scotia Energy Board (NSEB).

3.2.5 Light Starter Oil - LFO (Light Fuel Oil) Commodity Consumed - Transportation Cost - Quality Testing and Inventory Measurement Costs - GHG Emission Compliance Program costs Costs of this type are normally recorded in the following acc...

AI summary The text outlines costs associated with Light Fuel Oil (LFO) including commodity consumption, transportation, quality testing, inventory measurement, and GHG emission compliance. These costs are recorded in NS Power's Chart of Accounts under code 502550.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 23 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This document is part of the 2026-2027 General Rate Application (GRA) proceedings, focusing on direct evidence related to cost recovery and rate adjustments. Key entities include Nova Scotia Power and the Nova Scotia Energy Board, with topics covering rate design and DSM cost recovery mechanisms.

3.4 Deferrals During the 2023-20242026-2027 GRA Period, NS Power may include prior FAM deferrals for certain rate classes (Large General, Medium Industrial, and Large Industrial) in order to save additional interest charges which would acc...

AI summary NS Power may include prior Fuel Adjustment Mechanism (FAM) deferrals for Large General, Medium Industrial, and Large Industrial rate classes during the 2023-2024 to 2026-2027 General Rate Application (GRA) period to avoid additional interest charges by deferring amounts until the end of the period.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 24 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This redacted page from the 2026-2027 GRA Direct Evidence Appendix 6B discusses confidential aspects of a regulatory proceeding, likely involving rate applications, cost recovery mechanisms, and energy management programs. Key focus areas include DSM, DER, and administrative cost allocations.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 26 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted page from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). It includes a direct evidence appendix focusing on cost recovery mechanisms, though specific details are omitted due to confidentiality.

2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 33 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 20242026-2027 GRA Period refers to the period beginning January 1, 20236 and ending December 31, 20247 or to such time as determi...

AI summary The document outlines the 2026-2027 GRA period, defining terms like GRLF Revenue, Net Generation by Fuel Type, and NSPEMI. It discusses over/under-recovery of fuel costs and balance adjustments for prior years, impacting customer refunds or recoveries.

APPENDIX 7A – OM&G COSTS BY GROUP APPE: NDIX 7A – OM&G COSTS BY GROUP 1 1.1 OM&G Costs by Group 2 1.2 Inflationary Increases 6 1.3 Power Production 6 1.4 Enterprise Asset Management and Project Implementation 10 1.5 Energy Delivery 11 1.5....

AI summary Appendix 7A details the categorization of OM&G (Operations, Maintenance, and General) costs across groups such as inflationary increases, power production, enterprise asset management, energy delivery, customer experience, environmental services, and corporate adjustments. It outlines subsections including T&D contractor management, grid modernization, cyber security, and executive compensation.

& Project Implementation groups. Please see Appendix 7B for a restatement of 2024 GRA Compliance costs from the 2023-2024 GRA Compliance filing to the current structure of NS Power's operating groups. NS Power's Customer Experience and Inn...

AI summary NS Power has reorganized its operating groups, moving Meter Services to Regional Operations within Energy Delivery to align with its current corporate structure. The Customer Experience and Innovation group now includes functions like Customer Service, Grid Modernization, and Smart Meter Operations. Appendix 7B details 2024 GRA Compliance costs, while Appendix 7A provides OM&G costs by group. NS Power has further broken down the Customer Service group for transparency to the NSUARB and stakeholders.

1.5.6 NSIESO Transition As noted above, NS Power has forecast costs to be removed from its 2026 and 2027 revenue requirement due to the transition of some current NS Power responsibilities to the NSIESO. The forecast assumes this will occu...

AI summary NS Power forecasts costs related to transitioning responsibilities to NSIESO in 2026 and 2027, impacting revenue requirements. The phased transition includes generation interconnection and system planning in 2026, and Control Centre operations in 2027. NS Power will seek recovery or refund from NSEB once the transition is complete, though timing depends on NSIESO management appointments and plan refinement.

1.7 Environmental Services and Policy The Environmental Services and Policy group is responsible for completing environmental monitoring and compliance activities. Actual 2024 operating expense for the Environment team was $3.1 million as...

AI summary The Environmental Services and Policy group manages environmental compliance, with 2024 expenses exceeding the GRA forecast due to higher-than-expected inflation. The GRA budget for Environment is projected to decrease in 2025 and increase slightly in 2026-2027.

Corporate Adjustments As noted above, Corporate Adjustments are credits and expenses that are not assigned to a specific business unit or functional area. These mainly include administrative overhead allocated to capital and certain payrol...

AI summary Corporate Adjustments include administrative overhead and payroll costs not tied to specific business units. Recoveries increased from $46.4 million in 2024 to $56.5 million, driven by higher administrative overheads, capital investment, and interest expenses. Further increases are projected for 2025 to 2027 due to changes in capital investment, staffing, and compensation expenses.

1.9.1 Executive Compensation Report Section 64B (2) of the PUA provides as follows: Recovery of executive remuneration 64B (1) In this Section, "report" means the report required by subsection (2). (2) Nova Scotia Power Incorporated shall...

AI summary Nova Scotia Power Incorporated is required by Section 64B (2) of the PUA to submit an executive compensation report to the Board, detailing executive employees' positions and remuneration recoverable in electricity rates, with the report attached as Board Confidential Appendix 7E.

Figure 7A-15: Pension Expense (Recovery) Components 2014 vs 2022-2024 Line Item (FOR 2024 ($ million) 01) Compliance 2026 2027 Payroll Matching for DC and DB OM&G (Labour Plans Expense) 11.7 16.2 16.5 Current Service Cost of DB Plan OM&G (...

AI summary The figure compares pension expense recovery components in 2014 with projections for 2022-2024, highlighting changes in payroll matching, current service costs, and non-current service pension recovery. The data shows increasing expenses for defined contribution and defined benefit plans, with adjustments for supplementary executive retirement plans and interest expenses.

Redacted 2026 Forecast 2026 Forecast 202/ Forecast 36200 Energy Use (Non-Elect - - - - - - 36250 Pensioner Benefits - - - - - - 36200 Energy Use - - - - - - 33750 Rent - - - - - - 36300 Gen.Cost Recovery - - - - - - 33850 Non Reg.Cost Reco...

AI summary The text presents a table with various cost and revenue categories, including energy use, pensioner benefits, rent, and depreciation expense, along with forecasted figures for 2026 and other years. The data includes values such as internal services, warranty contracts, training, and administrative overheads, with some entries marked as redacted or not available.

(in Thousands of $) 530050 Regular Labour 530200 Overtime Labour 530250 Sales Comm.Salaries 530300 Term Labour 530350 Loaned Op.Labour 530360 Borrowed Operating Labour 530400 Loaned Cap. Labour 530550 Labour Clearing Total Labour 530900 Of...

AI summary The document presents a detailed breakdown of labor and operational costs categorized under various expense codes, including regular labour, overtime labour, sales commissions, term labour, and other related expenses. It includes data for 2024 actuals, 2025 budget, and forecasts for 2026 and 2027, alongside compliance and actuals figures.

pt/Info.Software 194 187 177 180 (17) (10) 536100 Rental/Mtnce equipment/software - - - - - - 532850 Appl. Software - - - - - - - - - - - - 532900 Comp.Hrdwr & Op.Sftwr 532950 Directors' Fees & Exp - - - - - - 533100 Ext. Legal & Audit 42...

AI summary The text presents financial data related to various categories such as rental/maintenance equipment, software, legal and audit expenses, shareholder meetings, advertising, meals and entertainment, employee benefits, insurance, energy use, rent, cost recovery, training, personal equipment, severance costs, commissions, write-offs, recoveries, other goods and services, and relocation expenses, with figures for 2024 and forecasts for 2026 and 2027.

Tufts Cove & Combustion Turbines (in Thousands of $) 2024 2026 2026 Forecast vs 2024 2026 Forecast vs 2024 2026 Forecast vs 2025 2027 Forecast vs 2026 536200 Energy Use (Non-Elect - - - - - - - 536250 Pensioner Benefits - - - - - - - 53620...

AI summary The table presents financial data related to Tufts Cove and Combustion Turbines, including various costs and recoveries from 2024 to 2027. It outlines figures for training and development, personal equipment, and other goods and services, with forecasts showing increases in certain categories over time.

Energy Delivery Services 2024 2026 Forecast 2026 Forecast 2026 Forecast 2027 Forecast 536300 Gen.Cost Recovery - - - - - - - 533850 Non Reg.Cost Recovery 0 1 - - (0) (1) - 534500 Internal Serv. Received - - - - - - - 534550 Warranty & Serv...

AI summary The table presents financial data related to Energy Delivery Services, including cost recovery, training and development, severance costs, and administrative overheads for various years. It outlines expenses and forecasts for 2024, 2026, and 2027, providing insight into financial planning and projections for the sector.

Transmission & Distribution Contractor Management 2024 Compliance 2026 Forecast vs 2024 2026 Forecast vs 2024 2026 Forecast vs 2025 2027 Forecast vs 2026 536200 Energy Use - - - - - - 533750 Rent 0 - - - (0) - 536300 Gen.Cost Recovery - -...

AI summary The document presents a table with financial data related to transmission and distribution contractor management for the years 2024 and 2026, including various categories such as energy use, rent, cost recovery, training and development, personal equipment, and miscellaneous revenue.

Administration 530050 Regular Labour 530200 Overtime Labour Compliance Restated 2024 Actual vs 2024 vs 2024 vs 2025 vs 2026 > Labour increase due to additional resources required to support customer growth and in customer-requested work, a...

AI summary The document outlines various financial changes and expenses related to labour, commissions, contracts, freight, and other goods and services. Key factors include increased labour costs due to customer growth and salary escalations, changes in commissions linked to inflation, and reductions in expenses due to the GRA Settlement Agreement.

Grid Modernization & Customer Integration (in Thousands of $) 536300 Gen.Cost Recovery - 6 - - - (6) - 533850 Non Reg.Cost Recovery 534500 Internal Serv. Received (47) - - - - - - - 47 - - - - - 534550 Warranty & Service Contracts 347 377...

AI summary The text presents a financial table detailing various cost recovery and expense categories, including warranty and service contracts, training and development, personal equipment, and customer recovery, across different years and responsibility areas. It provides a breakdown of figures in thousands of dollars.

1. Compensation Restrictions Section 64B(8) of the Act restricts the amount of compensation for executive employees of NS Power that is recoverable in electricity rates: - (8) Nova Scotia Power Incorporated shall not recover from any rate,...

AI summary Section 64B(8) of the Act restricts Nova Scotia Power Incorporated from recovering executive employee bonuses, incentives, or other remuneration (except prescribed by regulations) in electricity rates approved by the Board.

estimated future yielded estimated survivor curves from which the average service lives were derived. A general understanding of the function of the plant and information with respect to the reasons for past retirements and the expected fu...

AI summary The document discusses the estimation of survivor curves and service lives for plant assets, incorporating insights from operating and management personnel. It recommends NSPI adopt specific accrual rates for book and ratemaking purposes, as detailed in Table 1 of Part VI of the report.

928,138- 41- 2008 1,998,048 1,450,529 73 842 0 1,449,687- 73- 2009 2,525,530 1,501,116 59 0 1,501,116- 59- 2010 1,065,117 2,404,531 226 0 2,404,531- 226- 2011 6,034,847 806,378 13 0 806,378- 13- 2012 5,329,993 608,282 11 0 608,282- 11- 201...

AI summary The text presents a table with financial data across various years, showing values such as revenue, expenses, and other financial metrics. It includes figures for each year from 2008 to 2023, along with totals. The data appears to be related to financial reporting, possibly involving cost recovery, revenue requirements, and accounting policies.

4 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS $ 44,455 SUB-TOTAL (excluding contingency): $ 31,365,613 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 25% $ 7,841,403 GRAND TOTAL: $ 39,207,016 NOTE: The Demolition Estimate is b...

AI summary The document provides an estimate for demolition and environmental remediation costs, including a 25% contingency allowance. The estimate is based on previous site visits, limited drawings, past experience, and consultation with a contractor, but no actual quotes were obtained. Environmental remediation costs are based on site size, brownfield development, and potential contamination levels.

p in 2021. This area historically had scrap metals and minor items (overhead doors, conveyor structure, metal lighting mast, complete with fixtures and roof trusses) stockpiled here, which have been removed from the site. Applied inflation...

AI summary The text discusses the historical removal of scrap metals and minor items from a site, the application of an inflation factor to 2021 estimates, and the reduction of annual capital costs for progressive reclamation activities from 2021 through 2024, adjusted based on the published CPI and the higher costs associated with smaller programs.

Parent CI Number : - Asset Location : 1455 - 1455 Transmission Plant General Budget Version UARB Submissions Archaeological Assessments 532500 Consulting LOT 1 $ 67,825 $ 67,825 Line Design LOT 1 $ Sub-Total 175,626 $ $ 175,626 243,451 533...

AI summary The document outlines various costs associated with a transmission plant project, including archaeological assessments, legal and audit expenses, and administrative overhead. It provides a breakdown of budget submissions and actuals, highlighting variances and reasons such as project management, engineering, and procurement activities.

Asset Location : - Budget Version UARB Submissions 1455 1455 Transmission Plant General Capital Item Accounts Original Cost $ 33,950 Account Original Budget Submission Final Project Actuals Variance Reason for Variance 455300 Other Income-...

AI summary The document details budget variances for the Transmission Plant General under the Nova Scotia Utility and Review Board (NSUARB) submissions. Key variances include reductions in labour and materials costs due to fewer structures needing replacement, as determined by favorable Lidar & Thermal studies.

Reason for Variance The final costs of $2,982,714 for the project were $767,760 lower than the original submission of $3,750,474, primarily due to the use of internal versus external labour. At the time of the original submission, the Proj...

AI summary The final project cost was significantly lower than the original submission due to the use of internal labour instead of external resources. This change led to cost savings across most budget categories and eliminated the need for contingency funds, although some costs increased due to market conditions and unforeseen requirements.

67N Onslow 345 kV Node Swap Title: Description Unit Quantity Unit Estimate Total Estimate Cost Support Reference Completed Similar Projects (FP#'s) Meals Lot 1 $ 2,353 $ 2,353 Sub-Total $ $ - 2,353 AFUDC 605050 Interest Capitalized $ 534,8...

AI summary The document outlines cost estimates for the 67N Onslow 345 kV Node Swap project, including meal expenses, AFUDC, vehicle and administrative overheads, and total estimated costs. It also includes a comparison between original submission budgets and final application costs.

h. Regulatory Risk 2 There have been decisions by the UARB where operating and capital costs have been disallowed. 3 Cost disallowances are always within the scope of utility regulation, but in Concentric's 4 experience, significant disall...

AI summary The text discusses regulatory risks faced by Nova Scotia Power Inc. (NSPI), including cost disallowances by the Utility and Review Board (UARB), such as the 2018 AMI decision and treatment of operating expenses. It also mentions the impact of amortizing costs from Hurricane Fiona and penalties under the Public Utilities Act.

Criteria Score Deemed Equity Below Average Allowed ROE Good Energy Cost Recovery Below Average Capital and Operating Cost Recovery Good Cost of Service vs. Incentive Rate Excellent Mechanism Political Interference Poor Stranded Cost Recove...

AI summary The document presents a table with various criteria and their respective scores, highlighting areas such as 'Deemed Equity' and 'Allowed ROE.' The section '2 e. Capital Cost Recovery' is mentioned, indicating a focus on capital cost recovery mechanisms.

NS Power's financial model for the opt-out charges is attached in PR-02 Attachment 1 . The model includes the estimated incremental costs that will be incurred as a result of providing customers the option to retain non-standard meter serv...

AI summary NS Power has updated its financial model for AMI opt-out charges, incorporating changes such as a 33% supervisor oversight factor, updated WACC and labour rates, and revised workload forecasts based on actual opt-out customer data. These changes aim to ensure accurate cost recovery from opt-out customers.

Non-standard Meter Service (AMI) Opt-out Fee 2026-2027 GRA Direct Evidence Appendix 13A Page 9 of 14 The concept of non-participant[11](#page-122-0) contributions to the AMI capital project costs, as these costs are embedded in rates, is b...

AI summary The document discusses the rationale for non-participant contributions to the AMI capital project costs, based on shared infrastructure principles. It explains that even opt-out customers benefit from the infrastructure and should contribute to its cost. OTA billing has become standard, and opt-out meter reading is treated as a pass-through cost to opt-out customers.

Cost of Service Study Redacted 1 LIST OF APPENDICES 2 3 Appendix 12A(1) NS Power Cost of Service Model Run Iterations 4 Appendix 12A(2) NS Power Data Request Responses 5 Appendix 12A(3) NS Power Presentations and Slide Decks 6 Appendix 12A...

AI summary The redacted Cost of Service Study includes appendices detailing NS Power's model iterations, data requests, presentations, jurisdictional scans, memos, and formal session schedules. The document was filed on September 18, 2025, as part of a regulatory proceeding.

Cost of Service Study Redacted

AI summary The document title indicates a redacted section of a Cost of Service Study, suggesting sensitive or confidential information has been omitted. The study likely examines utility cost allocation, service life factors, and regulatory considerations, though specifics are not disclosed.

1 1.0 INTRODUCTION 2 3 In the Nova Scotia Energy Board's (NSEB, Board) decision on Nova Scotia Power Inc's NS - 4 Power, Company) general rate application (GRA), dated February 2, 2023, the Board approved a - 5 settlement agreement requiri...

AI summary The Nova Scotia Energy Board (NSEB) mandated Nova Scotia Power Inc. (NS Power) to update its Cost of Service Study (COSS) by December 31, 2025, reflecting developments like renewable integration and grid-scale storage. NS Power submitted the application after stakeholder collaboration, with unresolved issues identified despite extensive input from advocates and industry groups.

decks provided by NS Power and its consultants, - 25 appended as Appendix 12A(3) , jurisdictional scans, appended as Appendix 12A(4) , and - 26 memorandums, appended as Appendix 12A(5) . 27 - 28 At the outset of the COS process, NS Power p...

AI summary The document references decks provided by NS Power and its consultants, including jurisdictional scans and memorandums, as part of the Cost of Service Study (COSS) process. NS Power presented background information on the COSS to stakeholders, including a review of general principles and a detailed walkthrough of the current COSS approved in 2013.

23 5.6 Treatment of Battery in the COSS 24 - 25 NS Power is in the process of building battery storage that is presently functionalized to 26 transmission. However, it was identified that most participating stakeholders were of the view th...

AI summary NS Power proposes functionalizing battery storage to generation, but stakeholders argue it should serve transmission. The discussion centers on classifying battery assets within the Cost of Service Study (COSS), impacting cost recovery and resource categorization.

18 5.12 Decarbonization Deferral Account (DDA) 19 20 As a result of federal and provincial legislation regarding decarbonization, NS Power is required 21 to phase out coal generation, which will include addressing associated marine unloadi...

AI summary NS Power seeks to recover costs from retiring coal generation assets via the Decarbonization Deferral Account (DDA), approved by the Board on May 21, 2024. The DDA serves as a rate stabilization tool, with NS Power proposing it be classified and allocated similarly to other such tools. This addresses transition costs from decommissioning coal facilities by 2030 under federal and provincial decarbonization mandates.

3 Allocators are used to determine cost responsibility. As noted above, costs classified to demand 4 are associated with the cost of providing required capacity to serve customers. For this reason, 5 looking at the drivers of system peaks...

AI summary The document discusses how NS Power allocates demand costs using a fixed 3CP approach, focusing on winter peak months to determine cost responsibility. This method considers system peak drivers and balances volatility in cost allocation across the three coldest months of the year.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 1 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Exhibit Reference Cells Modification formulae revised to receive no classification Exh 6 D172:M194 Allocations of transmission energy ex...

AI summary The document outlines modifications to the 2026-2027 GRA Direct Evidence Appendix 12A(1), including adjustments to transmission energy expense allocations, updates to values using the BCF file, and reclassifications to avoid division-by-zero errors in calculations.

3 Notes on COSS Model Runs: - 4 All changes to the model cells are denoted with orange highlighting. - 5 Model runs 1, 2, 4, 10a, 10b, and 11 require updates to the Base Cost Fuel ("BCF") file that is an - 6 input into the COSS. Revised ve...

AI summary The document discusses updates to the Base Cost Fuel (BCF) file in the COSS model runs, noting that changes create a mismatch between ATL revenues and costs, which is addressed by adjusting the Profit/Loss figures for BTL classes in specific model runs.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 7 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document refers to the Cost of Service Study Process under matter number NSUARB M11475, which is part of the 2026-2027 General Rate Application (GRA) direct evidence. The study is likely related to determining the cost of service for utility providers in Nova Scotia.

6 COSS Model Run #3, Transmission Classified as 100% Demand: - 7 The classification of a portion of Transmission as Energy is removed so all rate base and costs are - 8 classified as 100% Demand. The sections of the COSS that allocate Ener...

AI summary In COSS Model Run #3, Transmission is reclassified as 100% Demand, removing its classification as Energy. This adjustment zeros out sections of the COSS that allocate Energy-related Transmission to rate classes to avoid cell reference errors.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 8 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document refers to the Cost of Service Study Process as part of the Nova Scotia Utility and Regulatory Board (NSUARB) proceeding numbered M11475. It is part of the 2026-2027 General Rate Application (GRA) direct evidence, specifically Appendix 12A(1), and is marked as confidential.

CONFIDENTIAL 1 COSS Model Run #6, Transmission Subfunctionalized to EHV and HV: 2 The current COSS includes subfunctionalization between EHV and HV but both subfunctions use 3 the same allocators. The allocators applicable to the HV subfun...

AI summary The document outlines various COSS model runs that adjust how costs are allocated across different subfunctions and classifications. These include changes to transmission subfunctionalization, distribution cost allocation, service allocation based on meter costs and customer count, and reclassification of generation based on capacity factors.

9 Details of the changes mate in each model are provided below. Exhibit Reference Cells Modification 1. NSP Positions All changes in models 2-5 (Some models require new rows so reference cells in the combined model may be a few cells lower...

AI summary This section outlines changes made in various models, particularly focusing on the classification of intermediate generation and adjustments to transmission demand. Specific cells and exhibits are referenced for modifications, including the splitting of intermediate generation from steam and the removal of further classifications in transmission demand.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 14 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding. It outlines the methodology and considerations involved in conducting a cost of service study, which is a key component in determining appropriate rates for utility services.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 15 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document references the Cost of Service Study Process under the NSUARB M11475 proceeding, indicating that it is part of a broader regulatory analysis related to cost of service studies.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 17 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding, indicating it is related to the analysis of costs associated with utility services in Nova Scotia.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 18 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary This document refers to the Cost of Service Study Process under the NSUARB M11475 matter. It is part of the 2026-2027 GRA Direct Evidence Appendix 12A(1), which includes redacted confidential information.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 19 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)

AI summary The document refers to the Cost of Service Study Process under NSUARB M11475, which is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(1). The study is likely related to analyzing the costs associated with service delivery for regulatory proceedings.

8 COSS Model Run #16 Equivalent Peaker Method: - 9 This model run classifies non-fuel generation costs using the equivalent peaker method. NSP does - 10 not build new CT or coal units so the cost per kW of capacity is based on Capital Cost...

AI summary This section describes the use of the equivalent peaker method in the COSS Model Run #16 to classify non-fuel generation costs. Nova Scotia Power uses capital costs from the U.S. Energy Information Administration to determine the cost per kW of capacity, with calculations detailed in the BCF file.

THEORY UNDERPINNING THE MINIMUM SYSTEM STUDY - Dr. Pavlovic claims that the Minimum Size Method has no theoretical, practical or empirical basis to - classify a portion of the distribution system cost as customer-related.[1](#page-59-0) Th...

AI summary Dr. Pavlovic argues that the Minimum Size Method (MSS) lacks theoretical, practical, or empirical support for classifying distribution system costs as customer-related. This contradicts industry practice and NARUC endorsement, as well as findings by Concentric showing widespread use of MSS by Canadian utilities.

Description of the MSS - Distribution system costs are incurred to move electricity from generation and transmission facilities - to individual customers that are distributed geographically throughout the service territory of a - utility....

AI summary The document discusses the Minimum Size Method (MSS) for allocating distribution system costs between demand-related and customer-related components. It explains that distribution costs are influenced by both the number of customers and the peak load, and references the NARUC Manual for methodology. An example of the MSS application by Concentric is provided.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 32 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - the system. The minimum system cost represents the customer-related costs, whereas the total c...

AI summary The text discusses two methods for allocating distribution costs: the Zero Intercept Study and the Minimum Size Selection. The Zero Intercept Study uses regression analysis to estimate customer-related costs, but it is criticized for potential statistical unreliability. The Minimum Size Selection method involves selecting the smallest currently installed assets for cost allocation. These methods are outlined in the NARUC Manual.

2026-2027 GRA Direct Evidence Appendix 12A(1) Page 36 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) CONCENTRIC EVIDENCE: GRA COSS ELEMENTS 100% demand-related.[7](#page-64-0) This assertion, however, fails to recognize the fact that a...

AI summary The text argues that a portion of distribution system costs is not demand-related, as some infrastructure is required regardless of peak demand. The Minimum Size Method (MSS) is used to calculate non-variable distribution costs, which should not be allocated based on demand due to their fixed nature.

CONCENTRIC EVIDENCE: GRA COSS ELEMENTS 1 Minimum level of load-carrying capacity is appropriate under a minimum sized system 2 The Resource Insight evidence claims that if the minimum size used in the MSS has some load 3 carrying capacity,...

AI summary The text discusses the allocation of minimum system costs and the relevance of the NARUC Manual. It argues that minimum system costs should be treated as equally beneficial to all customers and highlights the continued relevance of the NARUC Manual in cost allocation, despite its last revision in 1992.

NON-CONFIDENTIAL 1 Request DR-12: 2 3 Please provide the hourly operating cost, including fuel, purchased power, and any other 4 relevant variable costs (transmission fees, environmental control inputs, disposal costs, etc.) 5 for the 2019...

AI summary The company does not track actual hourly operating costs and only provides monthly and quarterly cost data through FAM reports, in response to a request for detailed hourly operating cost information from 2019 to 2023.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines the Cost of Service Study Process as part of the NSUARB M11475 proceeding, with NSPI providing responses to data requests from the Commission. It focuses on the methodology and data required for the study.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests 1 approximately $44 million over the last 10 years. Pursuant to the 2023-24 GRA Decision 2 (M10431), these assets have not been included in rate base, until:...

AI summary NSPI has responded to data requests regarding the Cost of Service Study Process, highlighting that approximately $44 million has been spent over the last 10 years and that assets have not been included in rate base until certain financial conditions are met. Transmission investments totaling $255 million between 2014-2023 were made to replace deteriorated assets.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study Process under NSUARB M11475. It provides information relevant to the regulatory proceeding on cost of service studies.

Elapsed Time Percent Customer Contribution Up to 1 year 0 Year 1-2 20% Year 2-3 40% Year 3-4 60% Year 4-5 80% After 5 Years 100% Where the new requirement represents or indicates an expansion or upgrade of the prior facilities, the reduced...

AI summary The table outlines the percentage of customer contribution over time for a service upgrade or expansion, with increasing customer contribution as elapsed time increases. The reduced contribution applies only to costs related to equivalent service provision from prior facilities.

2.12 REFUNDS OF CAPITAL CONTRIBUTIONS Line/Service Extensions Less Than 184m Customers will be provided with 92 metres of line/service extension at no cost, as provided for under Regulation 2.6. Any line/service extensions in excess of 92...

AI summary The regulation outlines the policy for refunds of capital contributions for line/service extensions less than 184m. Customers receive 92m free, with additional extensions and connections subject to customer costs. Refunds are provided to contributors based on the number of additional customers connected within ten years, minus an administration fee.

Line/Service Extensions Longer Than 184m Customers will be provided with 92 metres of line/service extension at no cost. Any line/service extensions in excess of 92 metres will be at the cost of the customer. If any additional customers ar...

AI summary Customers are provided with 92 metres of line/service extension at no cost, with any additional length charged to them. Refunds are available for capital contributions if additional customers connect within ten years, but are reduced by 10% and capped at 90% of the original contribution. No refunds are issued after fifteen years.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 793 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 3 of 12 COSS CA DR-53 Attachment 1 Page 3 of 62 Nova Scotia Power Cost...

AI summary This document outlines the methodology used in the Nova Scotia Power Cost of Service Study from January 2022, as part of the 2022-2024 GRA and related appendices. It is part of a partially confidential submission in a regulatory proceeding.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 801 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 11 of 12 COSS CA DR-53 Attachment 1 Page 11 of 62 Nova Scotia Power Co...

AI summary The document outlines the methodology used in the Nova Scotia Power Cost of Service Study, detailing how various costs such as bad debt, depreciation, and interest are allocated across customer classes. The allocation is based on factors like gross write-off experience, number of customers, and total rate base. Exhibit 7 is used to verify the accuracy of the cost allocation analysis.

2.2 Pricing of Unmetered Services - The Street/crosswalk Lighting Study contained below in Section 3, focuses on determining capital - and maintenance costs. Revenue responsibilities for electricity, fixture maintenance, and fixture - capi...

AI summary This section discusses the pricing of unmetered services, focusing on how costs are allocated between shared and direct categories. It outlines a three-step costing process—functionalization, classification, and allocation—to determine the cost responsibilities of the Unmetered Class based on cost causation and infrastructure utilization.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 814 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1d Page 5 of 11 COSS CA DR-53 Attachment 1 Page 24 of 62 Nova Scotia Power Unm...

AI summary The document discusses the determination of unmetered electricity rates for streetlight fixture maintenance, including the allocation of capital costs using the Cost of Service Study (COSS) methodology. The rates are structured with a demand charge and declining block energy charges, and are subject to changes in GRA proceedings.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study process under NSUARB M11475. It provides insights into the procedural and analytical aspects of the study.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary The document outlines the Cost of Service Study Process under NSUARB M11475, focusing on NSPI's responses to data requests related to the study.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines the responses provided by NSPI to data requests made by the CA in the context of the Cost of Service Study Process under NSUARB M11475.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 893 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 5 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - the system. The minimum syst...

AI summary The document discusses two methods for allocating costs in distribution systems: the Zero Intercept Study and the Minimum Size Selection. The Zero Intercept Study uses regression analysis to estimate customer-related costs but is criticized for potential statistical unreliability. The Minimum Size Selection method relies on current minimum installation standards for distribution assets.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 899 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 11 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS

AI summary This document is a partially confidential appendix from a 2026-2027 GRA Direct Evidence submission, specifically COSS CA DR-61 Attachment 1. It includes a reference to a redacted image and mentions 'Concentric Evidence: GRA COSS Elements', indicating it is part of a cost-of-service study related to a regulatory proceeding.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 900 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 12 of 19

AI summary This document is a partially confidential appendix from a 2026-2027 GRA Direct Evidence submission, specifically COSS CA DR-61 Attachment 1, page 12 of 19. It includes a redacted image and appears to be part of a regulatory proceeding involving cost-of-service studies and related documentation.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 902 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 14 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS SECTION 4:

AI summary The document is a partially confidential appendix from a 2026-2027 GRA (likely a regulatory proceeding) related to a Cost of Service Study (COSS) and includes evidence regarding DR-61. The content is redacted and only partially visible, with a reference to 'CONCENTRIC EVIDENCE: GRA COSS ELEMENTS' and 'SECTION 4'.

POLES SUB-FUNCTIONALIZATION - Secondary customers do not pay twice when combination poles are allocated between - primary and secondary. - The Resource Insight evidence asserts that Concentric's treatment of combination poles (i.e., poles...

AI summary The text discusses the allocation of combination poles between primary and secondary voltage in the sub-functionalization study. It refutes the claim that secondary customers are being charged twice for the same pole, explaining that costs are allocated based on unit cost ratios, ensuring no double counting.

POLE ATTACHMENT RATE - Net Pole Investment and Depreciation Expense - Mr. Briggs's evidence disagrees with the derivation of the net pole investment included in the - Company's calculation of the pole attachment fee proposed in the applica...

AI summary The document discusses discrepancies in the calculation of net pole investment and depreciation expense in the context of pole attachment rates. Mr. Briggs disputes the inclusion of certain Distribution Plant and General Plant costs in the Company's calculation, but the text argues that the methodology used, which includes non-pole assets, was previously accepted by the Board and the CRTC.

8 Figure 1 9 10 11 (b) Figure 2 provides a list of the selected feeder sections including general characterization 12 of the feeder (e.g., rural/suburban/urban, residential/mixed/commercial/industrial) PARTIALLY CONFIDENTIAL 2026-2027 GRA...

AI summary Figure 1 and Figure 2 are referenced in the document, with Figure 2 providing a list of selected feeder sections characterized by location and usage type. The document also mentions the Cost of Service Study Process (NSUARB M11475) and NSPI responses to CA data requests.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines the Cost of Service Study Process under NSUARB M11475 and includes NSPI's responses to data requests from the Commission. It focuses on the methodology and data analysis involved in the study.

2 (i) NS Power did not collect this information as part of this survey. 3 (ii) Please refer to Figure 2 above for the data related to the Phases in each Feeder 4 Section. 5 (iii) The underground conductor is in conduit. 6 (iv) NS Power did...

AI summary The text discusses the lack of data collection by NS Power in certain areas, and references a Cost of Service Study Process under NSUARB M11475, including responses to data requests by CA.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines Nova Scotia Power Inc.'s responses to data requests from the Canadian Association regarding the Cost of Service Study process under NSUARB M11475.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary The document pertains to the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests from the Canadian Association.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary The document outlines the Cost of Service Study Process under NSUARB M11475 and includes NSPI's responses to data requests from the Canadian Association. It focuses on the procedural aspects of the study and the information provided by NSPI.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 933 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines NSPI's responses to data requests from the Canadian Association under the Cost of Service Study Process, as part of the NSUARB M11475 proceeding.

REDACTED (CONFIDENTIAL INFORMATION REMOVED) PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 942 of 1218 COSS CA DR-75 Attachment 1 has been filed electronically. PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidenc...

AI summary The document contains a partially confidential appendix from a 2026-2027 GRA proceeding, referencing an electronically filed attachment labeled 'DR-75 Attachment 1' and mentioning 'COSS CA'. The content is heavily redacted and lacks detailed discussion.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 946 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines NSPI's responses to data requests from the Canadian Association as part of the Cost of Service Study Process under NSUARB M11475. It is part of the 2026-2027 GRA Direct Evidence Appendix.

- 21 per year are as follows: # of Interruption Events Total Duration (Hours: Minutes) 2024 YTD 2 2:48 2023 6 20:02 2022 10 37:16 3 M05473, NS Power 2013 Cost of Service Study, NS Power Application, Appendix H – 2013 COS Strawman Report V1...

AI summary The text presents a table showing the number of interruption events and total duration for the years 2022, 2023, and 2024 YTD. It also references a 2013 Cost of Service Study and a 2022-2024 General Rate Application, highlighting discussions around interruptible supply credit allocation and cost-of-service studies.

REDACTED (CONFIDENTIAL INFORMATION REMOVED) PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 947 of 1218 Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests

AI summary This document outlines the Cost of Service Study Process under NSUARB M11475, detailing NSPI's responses to data requests from the Canadian Association. It is part of the 2026-2027 GRA Direct Evidence Appendix 12A(2).

NON-CONFIDENTIAL 1 Request DR-87: 2 3 Reference: Information requests were made of NS Power by John Wilson on behalf of the 4 Consumer Advocate in his memo "Outstanding Requests for COSS Process" sent via email 5 on September 20, 2024. 6 7...

AI summary The document discusses a request by the Consumer Advocate, represented by John Wilson, for a review of how DSM costs are currently allocated between customer classes and system benefits. NS Power explains that the current 75/25 split was established in a 2010 Settlement Agreement and lacks supporting cost studies. They propose alternative allocation methods based on projections from the 2023-2025 DSM Plan proceeding.

NON-CONFIDENTIAL 1 • effectiveness of DSM Programs designed for individual ate classes in reducing their 2 electricity usage. 3 4 Option Two: 5 6 The system cost benefit for each individual class was defined as the cost savings a class wou...

AI summary The text discusses the effectiveness of DSM programs for different electricity rate classes, analyzing the system cost benefits and changes in cost distribution when one class does not participate. The split of cost savings shifted from 75/25 to 93.2/7.2, with changes in non-fuel embedded costs impacting participating and non-participating classes differently.

Criteria - Cost Causation defined by proximity of arithmetic average of multipoint peaks under various CP methods to annual system peak (or 1CP) - Cost Redistribution Effect among rate classes measured as % change in annual revenues - Stab...

AI summary The text outlines criteria for evaluating cost causation and redistribution effects in rate-making processes, referencing proximity of arithmetic averages to annual system peaks, stability of cost allocation results, and precedents from other Canadian jurisdictions. It also references a partially confidential attachment from a proceeding.

Findings - The winter peak methods provide for more stable cost allocation results from year to year but rank worse under cost causation criterion than corresponding unconstrained methods. - oIt takes as many as 88CP to match stability off...

AI summary The winter peak methods provide more stable cost allocation results but perform worse under cost causation criteria. The average cost redistribution effects on the Domestic class are minor, while effects on other classes are more significant. Analysis using ANL yields more volatile results.

REDACTED (CONFIDENTIAL INFORMATION REMOVED) CONFIDENTIAL COSS IG DR-6 Attachment 1 Page 1 of 1PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1016 of 1218

AI summary The text is a partially confidential attachment from a regulatory proceeding, referencing a 2026-2027 GRA Direct Evidence Appendix. It includes a redacted page from a document related to a cost-of-service study or integrated resource plan, suggesting it may involve energy efficiency, resource planning, or regulatory compliance topics.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1022 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests

AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study process under NSUARB M11475. It provides information relevant to the regulatory review of NSPI's cost structures and service delivery.

NON-CONFIDENTIAL 1 Request DR-10: 2 3 Please provide the details that go into calculating the current Interruptible credit based on 4 the cost of a CT peaking unit. 5 6 • Does the current interruptible credit pricing based on a CT peaking...

AI summary The response to Request DR-10 explains that the current interruptible credit does not include estimates for avoided carbon tax. The credit is designed to compensate customers for standby readiness, not for energy cost avoidance, and is based on marginal avoided generation capacity costs using the peaker deferral method.

Input Assumptions - 1. Capital costs are for a 50MW combustion Turbine (Frame) from E3 Resource Option Study using 2021 nominal values; - 2. Fixed Operating costs are derived from E3 Resource Option Study using 2021 nominal values - 3. Scr...

AI summary The input assumptions outline capital and operating costs for a 50MW combustion turbine based on 2021 values from the E3 Resource Option Study. Assumptions include the incorporation of AFUDC into system costs, no administrative overhead, and annual escalation of FO&M costs at 2%.

1,084,134 $1,030,227 $976,320 $922,413 Taxes Equity Return $1,293,774 $1,239,866 $1,185,959 $1,132,052 $1,078,145 $1,024,237 $970,330 $916,423 $862,516 $808,609 $754,701 $700,794 $646,887 $592,980 $539,072 $485,165 $431,258 $377,351 $323,4...

AI summary The text presents a series of financial figures related to taxes, equity return, fixed O&M, interest, and depreciation over multiple periods. These figures are part of a financial analysis or regulatory proceeding, likely involving cost recovery, revenue requirements, and accounting policies.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests 1 Request DR-16: 2 3 Please explain how customer contributions are allocated in the Cost of Service study, and if 4 they are directly tracked to the benefit o...

AI summary NSPI explains that customer contributions to capital costs are not tracked at the individual level but are applied to reduce the overall capital cost of assets. These reduced costs are then allocated to customer classes based on the Cost of Service methodology, providing benefits at the class level rather than individually.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to MEU Data Requests 1 Request DR-1: 2 3 Information requests were made of NS Power by James MacDuff on behalf of the MEUs in 4 his e-mail "CTD with Elenchus consensus summary fo...

AI summary The MEUs have requested information from NS Power regarding the alignment of cost of service treatment for bundled and unbundled services in RtR and wholesale markets, including OATT and riders. NS Power has not yet provided the requested analysis, which the MEUs believe is essential for the integrated COSS review process.

NON-CONFIDENTIAL 1 Fixed-generation BUTU and RtR rates are calculated by the same COSS-based embedded 2 cost methodology, however, there is a phase-in adjustment applied to the BUTU rates in 3 2023 to limit the forecast revenue increase to...

AI summary The text explains the methodology for calculating BUTU and RtR rates using a COSS-based embedded cost approach, with a phase-in adjustment in 2023 to limit revenue increases. It also outlines how demand and energy charges are calculated, and summarizes the basis for FAM and non-FAM costs in different rate categories.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests 1 Request DR-1: 2 3 With reference to NS Power's initial position document Issue # 1a please indicate which 4 specific generation assets NS Power believes wi...

AI summary NSPI responds to a data request regarding the classification of generation assets in the Cost of Service Study. It states that only steam units operating below future system load factors and not retiring before 2030 (Tufts Cove 1, 2, and 3) will be classified based on annual capacity factors. Other units, like LM6000 and combined cycle units, will retain their current classification.

COSS PHP DR-1 Attachment 1 Page 1 of 1 \ Data provided is taken from the 2022 Evergreen IRP, scenario CE1-E1-R2.

AI summary The document references data from the 2022 Evergreen Integrated Resource Plan (IRP), scenario CE1-E1-R2, which is used in the Cost of Service Study (COSS) for Peak Hour Pricing (PHP) DR-1 Attachment 1.

NON-CONFIDENTIAL exceed the number of operating hours typically expected from a peaking unit4 1 there remains 2 energy-related cost causation behind investment in these units. However, a significant 3 reduction in operating hours of such u...

AI summary NS Power argues that adjusting the classification method of peaking units from system load factor to individual unit capacity factor better reflects energy-related cost causation. The ELCC approach, which classifies more costs to demand as operating hours increase, is criticized for potentially misrepresenting cost causation for base load units.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1089 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests

AI summary This document outlines NSPI's responses to data requests from the PHP as part of the Cost of Service Study Process under NSUARB M11475. It is part of the 2026-2027 GRA Direct Evidence Appendix.

NON-CONFIDENTIAL 1 Request DR-20: 2 3 Please explain how the contractual provisions and operational characteristics of the 4 Maritime Link inform the current COSS allocation and treatment. 5 6 Response DR-20: 7 8 The justification of the c...

AI summary The response to Request DR-20 explains that the current COSS allocation and treatment of the Maritime Link is based on the Strawman Report filed in 2017, and that the contractual provisions and operational characteristics have not changed significantly since then.

Cost of Service Classification of the Maritime Link Strawman Report 1 The purpose of this Report is to summarize the various options available with respect to the Cost 2 of Service allocation of the Maritime Link for the purposes of facili...

AI summary This report outlines the cost of service classification options for the Maritime Link, aiming to facilitate consensus among stakeholders. The report emphasizes that cost of service studies do not affect revenue recovery but focus on fair revenue apportionment among customer classes. NS Power seeks input by January 27, 2017, and plans to discuss the matter in a February 2017 meeting.

Cost of Service Classification of the Maritime Link Strawman Report 1 The Company also proposed that the Nova Scotia Block be treated in the same manner as NS 2 Power-owned hydro generation. This means that its costs would be classified to...

AI summary The document discusses the proposed cost of service classification for the Nova Scotia Block, suggesting it be treated similarly to NS Power-owned hydro generation. Energy and demand costs would be allocated based on system load factors and coincident system peaks, aligning with NS Power's COSS practices.

Cost of Service Classification of the Maritime Link Strawman Report 1 should be allocated in proportion to the average of peak demands for the three winter months.[9](#page-179-0) 2 3 4 Mr. Wallach expressed concern that the Hydro-allocati...

AI summary The document discusses the allocation of costs for the Maritime Link project, with Mr. Wallach expressing concerns about the Hydro-allocation approach and its departure from past practices. NS Power argues that its benefits-based approach is consistent with the 2013 COS proceeding and the approved methodology, while also highlighting the distinctiveness of the Nova Scotia Block in terms of service delivery and costing treatment.

REDACTED 1 • Confidential Attachment 2: 2023 BCF COSS with all purchases, other than wind 2 and Maritime Link, classified to energy based on weighted average system 3 generation factor reflective of steam generation classified as above. 4...

AI summary The document discusses the 2023 BCF COSS with various classifications of generation and purchases, including the use of weighted average system generation factors and operating factors for classification purposes. It references model runs and revised case details.

REDACTED 1 Request DR-30: 2 3 Provide a model run that incorporates all of NSPI's lastest changes to its proposed COSS 4 positions that would apply post 2030 (ie. incorporating all currently planned plant fuel 5 conversions and all plant r...

AI summary A request (DR-30) is made for a model run that incorporates NSPI's latest changes to its proposed Cost of Service Study (COSS), including post-2030 plant fuel conversions, retirements, and the treatment of PHP load as an above-the-line customer. The response refers to confidential attachments that have been removed due to confidentiality.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to SBA Data Requests 1 Request DR-1: 2 3 For each generating unit, please provide: 4 5 (a) Annual revenue requirements for fixed costs 6 7 (b) Annual O&M costs 8 9 (c) Nameplate...

AI summary NSPI responded to data requests regarding the Cost of Service Study (COSS) process by explaining that it does not track annual revenue requirements and O&M costs for each generating unit separately. It also noted that depreciation and O&M costs are grouped into plant types and shared costs are included in the 'OM&G' tab of a prior general rate application.

NON-CONFIDENTIAL 1 Request DR-2: 2 3 Provide NS Power's most recent costs for lowest capital cost peaking combustion turbines 4 that are natural gas fired as per the most recent IRP: 5 6 (a) Capital costs 7 8 (b) Cost of money to determine...

AI summary The document requests Nova Scotia Power's most recent costs for natural gas-fired peaking combustion turbines, including capital costs, cost of money, unit life, O&M, and equivalent capacity. NS Power responds that Frame CTs were the lowest cost option in the 2022 Evergreen IRP, providing capital costs of $1,278 per KW.

MEMORANDUM TO: Nova Scotia Power, Inc. FROM: Bickey Rimal, Concentric Energy Advisors DATE: January 2022 RE: GRA Allocated Cost of Service and Miscellaneous Charges Matters The purpose of this memorandum is to provide the results of: - Con...

AI summary This memorandum from Concentric Energy Advisors to Nova Scotia Power Inc. reviews the company's allocated class cost of service (CCOS) model, concluding that it is reasonable, follows industry-accepted methodology, and produces accurate results. The model uses a three-step process: cost functionalization, classification, and allocation, which are described in detail.

its treatment of overhead costs, taking into account the input of stakeholde[rs](#page-22-1). 7 Based on Concentric's review, the approach taken by the Company is reasonable and appropriate. The Company's proposed functionalization factors...

AI summary The document reviews the treatment of overhead costs in the 2013 COSS Proceeding, noting that Nova Scotia Power Inc.'s approach is reasonable and appropriate based on Concentric's review. The company's functionalization factors are based on cost causation and feedback from senior managers, with consensus achieved by most parties.

tions sampled. The ratio of these costs was used to subfunctionalize overhead conductors between primary and secondary. The same methodology was replicated to sub-functionalize underground conductors. Concentric then conducted additional a...

AI summary Concentric used a methodology to sub-functionalize overhead and underground conductors between primary and secondary systems and classified distribution system costs as demand-related or customer-related using a minimum system study. This approach aligns with industry practices outlined in the Electric Utility Cost Allocation Manual by NARUC.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1151 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-4 Attachment 1 Page 6 of 7 The underlying data used to calculate the fee are cost based and the...

AI summary The document outlines the methodology for calculating pole attachment fees by NS Power, based on cost considerations. The fee is determined by allocating indirect and direct costs associated with poles between NS Power and third-party attachers. The allocation is based on the proportion of usable space occupied by non-power attachments, with a final adjustment for the average number of non-power attachments per pole. The fee is deemed reasonable and minimizes cross subsidization.

COSS SBA DR-6 Attachment 1 Page 7 of 24 281050 LT ACCRUED PENSION LIAB NSPI 283270 LT REGULATORY EMISSION COMPLIANCE 283300 LT UNEARNED REVENUE LIAB 283450 LONG TERM ACCRUED INTEREST 283500 LT DSU RSU 283900 LT LIABILITIES OTHER 283950 LT...

AI summary The document presents a list of long-term liabilities and revenue-related accounts, including pension liabilities, regulatory compliance costs, accrued interest, and liabilities related to demand-side management. It also includes revenue and cost recovery entries related to time-of-use pricing, small generators, and other regulatory matters.

COSS SBA DR-6 Attachment 1 Page 8 of 24 413250 REG RES ACCRUED FAM BA FUEL COST 413310 REG METERED OUTDOOR REC LIGHTS NON FUEL ENERGY 413330 REG METERED OUTDOOR REC LIGHTS FAM AA FUEL COST 413350 REG METERED OUTDOOR REC LIGHTS DSM COST REC...

AI summary The text lists various regulatory account codes related to fuel costs, energy usage, and cost recovery riders for different customer categories and usage types, including time-of-use and small generation. These codes are part of a financial and regulatory framework for Nova Scotia Power.

COSS SBA DR-6 Attachment 1 Page 9 of 24 414540 REG LARGE GENERAL FAM AA FUEL COST 414550 REG LARGE GENERAL FAM BA FUEL COST 414610 REG GENERAL TIME OF USE NON FUEL DEMAND BASE 414620 REG GENERAL TIME OF USE NON FUEL ENERGY ALLHOURS 414630...

AI summary The document lists various rate codes related to fuel costs, time-of-use pricing, demand base, energy charges, and revenue for different customer classes, including large, small, and medium industrial and general customers. These codes are part of a regulatory proceeding and appear to be associated with cost recovery and rate structures.

COSS SBA DR-6 Attachment 1 Page 10 of 24 415660 REG LARGE IND INTERRUPT RIDER REVENUE 415710 REG LARGE IND WHSLE MARKET BACKUPTOP UP NON FUEL DEMAND BASE 415720 REG LARGE IND WHSLE MARKET BACKUPTOP UP FAM BASE FUEL 415730 REG LARGE IND WHS...

AI summary The document contains a list of revenue codes related to various regulatory riders and programs, including load retention, shore power, and unmetered revenue. These codes are part of a regulatory proceeding and may be associated with cost recovery, demand-side management, and other energy-related topics.

COSS SBA DR-6 Attachment 1 Page 13 of 24 504450 REG GRID SALES FUEL DIESEL 505050 REG FUEL AFFILIATES 507050 REG FAM INCENTIVE 507100 REG FUEL ADJUSTMENT 507150 REG FIXED COST RECOVERY ADJUSTMENT 507200 REG RATE STABILIZATION ADJ FIXED COS...

AI summary This document contains a list of regulatory codes related to fuel, labour, expenses, and other operational categories. It includes entries such as fuel adjustment, fixed cost recovery, and various labour and expense classifications. These codes are part of a larger regulatory and financial framework, but specific details are redacted.

COSS SBA DR-6 Attachment 1 Page 15 of 24 533550 INSURANCE 533700 CORPORATE CREDIT CARD CLEARING 533750 RENT 533800 FLEET REPAIRS 533850 NON REGULATORY COST RECOVERY 533900 COST RECOVERY 533950 COST RECOVERY PREFERRED COMPENSATION UNITS 534...

AI summary This document lists various cost categories and financial items related to corporate and operational expenses, including insurance, rent, fleet repairs, warranty service contracts, training development, commissions, write-offs, and others. These items are likely part of a financial or regulatory filing related to cost recovery and corporate operations.

3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...

AI summary NS Power's Fuel Adjustment Mechanism (FAM) operates on an annual cycle with an over/under recovery mechanism, consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The AA is calculated based on the over- or under-recovery of the Base Cost of Fuel at the end of September, while the BA manages deferred fuel and purchased power costs approved by the Board.

3.2 Allowable Fuel and Purchased-Power Costs This section of the POA provides a framework for the fuel and purchased-power costs eligible for recovery through the FAM. Those costs will include allowable fuel expenses plus purchased-power e...

AI summary This section of the Plan of Administration outlines the framework for allowable fuel and purchased-power costs recoverable through the Fuel Adjustment Mechanism. It includes normal, recurring, non-capital expenses, discrepancies supported by surveys, and exceptional costs reviewed by the Small Working Group. These costs are subject to audit and approval by the Nova Scotia Utility and Review Board.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1198 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-7 Attachment 1 Page 19 of 33 FAM POA Main Document (Redline) – Revision 11 / February 2023

AI summary This document is a partially confidential appendix from a 2026-2027 General Rate Application (GRA) proceeding, including a redline version of the Fuel Adjustment Mechanism (FAM) Plan of Administration (POA) as of February 2023. It is part of a Cost of Service Study (COSS) and includes references to other studies and mechanisms such as the Fuel Adjustment Mechanism Adjustment (FAMAA) and Balancing Adjustment riders (BARIDERS).

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1201 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-7 Attachment 1 Page 22 of 33 FAM POA Main Document (Redline) – Revision 11 / February 2023

AI summary This document is a revision of the FAM POA Main Document, part of the 2026-2027 GRA Direct Evidence Appendix. It includes a redline version from February 2023 and is related to the Cost of Service Study (COSS) and the Fuel Adjustment Mechanism (FAM).

3.3 Calculation of Fuel Costs The fuel costs in the Base Cost of Fuel recovered through the FAM include allowable fuel and purchased power expenses (as noted in section 3.1 above) less revenues from exported power.

AI summary This section discusses the calculation of fuel costs under the Fuel Adjustment Mechanism (FAM), which includes allowable fuel and purchased power expenses, excluding revenues from exported power.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1216 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SNS DR-1 Attachment 1 Page 1 of 1 All values presented are from the 2022 Evergreen IRP scenario CE1-E1-...

AI summary The document provides a cost-of-service study (COSS) attachment from the 2022 Evergreen Integrated Resource Plan (IRP) scenario CE1-E1-R2, which is part of a partially confidential regulatory proceeding related to the 2026-2027 GRA.

Board Directive - GRA The 2022-2024 GRA Settlement Agreement provided as follows regarding the Line Loss Study and COSS: NS Power must file a Cost of Service Study and a Line Loss Study prior to filing its next GRA or December 31, 2025, wh...

AI summary The 2022-2024 GRA Settlement Agreement requires NS Power to file a Cost of Service Study and Line Loss Study, with stakeholder engagement, prior to the next GRA or December 31, 2025. The NSUARB directed semi-annual progress reports starting January 31, 2024. Costs may be deferred and recovered through future rates with Board approval.

The GRA Decision provided as follows: [361] In this proceeding, several concerns were raised about NS Power's cost of service methodologies applied in this GRA. These concerns included the use of the minimum system study for the classifica...

AI summary The GRA Decision addresses concerns about NS Power's cost of service methodologies, including the use of the minimum system study and LF/3CP method for cost classification. The Board agrees to update the COSS and Line Loss Study to reflect recent system developments and directs semi-annual progress reports starting in 2024.

Meeting Objectives - Introduce experts - Develop a shared understanding of industry practices re: cost of service - Share information - Collaborate with intent to develop initial issues list and identify topics requiring further examinatio...

AI summary The meeting objectives focus on introducing experts, discussing industry practices related to cost of service, sharing information, and collaborating to develop an initial issues list. The meeting will take place on a without prejudice basis and will not be recorded without consent.

Elenchus Approach to the Review - Facilitate NS Power's Stakeholder Process ‐ technical sessions, with goal being to: - Assist in clarifying and understanding the concerns and views of all parties - Distinguish between interest‐based and p...

AI summary The Elenchus Approach to the Review outlines a structured process to facilitate NS Power's stakeholder engagement, clarify stakeholder concerns, and review NS Power's cost allocation methodologies. It also includes a survey of utility practices in Canada and the US, and the preparation of evidence for filing with the Nova Scotia Utility and Review Board.

Purpose of the January 18th Session (Kick-off) - Canvass stakeholders to determine the parts of NS Power's COSS methodology that need to be explained in greater detail in future tech sessions. Future technical sessions will assist stakehol...

AI summary The January 18th session aims to engage stakeholders in reviewing NS Power's Cost of Service Study (COSS) methodology, identify areas requiring updates due to developments since 2013, and determine the implications of proposed changes on allocated costs. The session will also establish a timeline for future discussions.

Reference Documents - As baseline, NARUC, Electric Utility Cost Allocation Manual, January 1992. What has changed in the last 30 years? Comments invited. - Cost Allocation Modernization references, such as: - Electric Cost Allocation for a...

AI summary The document references historical and modern cost allocation practices, including the NARUC Electric Utility Cost Allocation Manual and recent stakeholder suggestions. It also cites previous Nova Scotia Power evidence, NSUARB decisions, and discussions from past COSS projects, including the Maritime Link Project and deferred projects from 2014–2016.

Cost Allocation Methodologies – Conceptual Overview - Directly allocated costs Exclusive use by class (rare) - Shared Utility Assets and Expenses - > We all benefit from sharing - > Electrons flow through common infrastructure - Cost Causa...

AI summary This section provides an overview of cost allocation methodologies, emphasizing the use of cost causality as the main criterion for allocating shared utility assets and expenses. The goal is to achieve fair and reasonable rates, with rate design being a subsequent step that may incorporate policy considerations.

Cost Allocation Methodology – Three Basic Steps - > Functionalization: - Generation, Transmission, Distribution, Retail - Categorization or classification: - > Energy, Demand, Customer - > Allocation: - > Use Cost Drivers: kWh, kW, Custome...

AI summary The document outlines a three-step cost allocation methodology for electricity systems: functionalization, categorization, and allocation using cost drivers such as kWh, kW, and customer count. It also notes that fairness principles focus on cost recovery based on fully allocated embedded costs, though actual rates may differ due to policy considerations like conservation and clean energy incentives.

Allocation - Costs allocated to customer classes (cost drivers correspond to cost classifications) - Primary Allocators (costs shared by proportionate use) - ➤ kWh (energy including losses) - > kW (demand including losses) - > # of custome...

AI summary The document discusses the allocation of costs to customer classes based on various cost drivers, including kWh, kW, number of customers, and direct assignments such as streetlights. It outlines methods for allocating shared costs proportionally and compares total allocated costs to class revenue to assess revenue/cost ratios.

Cost-related Attributes: - 4. Static efficiency of the use of rate classes and rate blocks in discouraging wasteful use of the service, while promoting all justified types and amounts of use. - 5. Reflections of all of the present and futu...

AI summary The text outlines key cost-related attributes for rate design, emphasizing efficiency, fairness, and equity in cost allocation. It highlights the need to consider both private and social costs and benefits, avoid discrimination, and promote innovation in response to changing demand and supply patterns.

Agenda - 1. Introduction and Project Description - 2. Generic Background on Cost Allocation Methodologies - 3. NS Power's Existing COSS Methodology - 4. Effect of Transitional and Technological Changes on COSS - 5. Survey - 6. Next Steps

AI summary The agenda outlines the topics to be discussed in a proceeding, including an introduction, background on cost allocation methodologies, NS Power's existing cost of service study (COSS) methodology, the impact of transitional and technological changes on COSS, a survey, and next steps.

NS Power's COS Spreadsheet Calculation Process - Data Input Collection: Input Data, Input Data Two - Class Usage: Exh 9a 9c - o Usage based allocator factors in Exh 8a - Rate Base apportionment to rate classes - o Functionalization: Exh 2...

AI summary This document outlines NS Power's Cost of Service (COS) spreadsheet calculation process, including data input collection, class usage, rate base apportionment, cost apportionment, and cost summaries. Exhibits and external sources are referenced for methodology and analysis.

1995 COS Generic Hearing (NSPI864) - Classification of generation and transmission should reflect the intent of the asset: - o All generation costs associated with environmental compliance and fuel conversion to be classified as energy-rel...

AI summary The document discusses the classification of generation and transmission costs, emphasizing the need to align them with the intent of the assets. It suggests that environmental compliance and fuel conversion costs should be energy-related, while fixed costs of Steam and Hydro generation and transmission should be based on annual system load factor. The Equivalent Peaker method was rejected due to inconsistent calculations, and transmission is treated as an extension of generation. Fuel costs are to be allocated on a monthly basis to reflect seasonality.

2013 COS Generic Hearing (M05473) - Upheld status quo regarding the most significant elements of the 1995 COS design - SLF-based classification and 3CP Allocation of non-fuel costs of base load generation and transmission was favored over...

AI summary The 2013 COS Generic Hearing (M05473) upheld the 1995 COS design's core elements, including SLF-based classification and 3CP allocation, but noted pending decisions on distribution costs. Adjustments were made to better align with cost causation and asset utilization, including sub-functionalizing purchased power costs and using a formulaic approach for billing and call center costs.

2016 Renewable to Retail Hearing (M06214) - In response to NSUARB IR-01 and Multeese DR-30 NSPI discussed treatment of RtR rates and revenues in COS. - Test year RtR revenues to be treated as an offset to the test year revenue requirement...

AI summary NSPI discussed the treatment of Renewable to Retail (RtR) rates and revenues in the Cost of Service (COS) during the 2016 Renewable to Retail Hearing (M06214). RtR revenues are to be treated as an offset to the revenue requirement from above-the-line classes, with non-fuel cost charges determined iteratively.

COS Treatment of Maritime Link - 2017-2019 Fuel Stability Plan (M07348) UARB approves Settlement Agreement wherein parties agree to conduct consultations to address COS treatment of ML costs. - Following stakeholder consultations NS Power...

AI summary The document outlines the treatment of Maritime Link (ML) costs within the Cost of Service (COS) framework. A 2017-2019 Fuel Stability Plan (M07348) led to consultations, resulting in a strawman report recommending that Nova Scotia Block costs be classified as NS Power-owned hydro based on the SLF. Surplus energy, representing non-firm imports, was fully classified to energy, and all approved FAM rates reflect this treatment.

Overview - DSM Cost Recovery Process - 2023-2025 DSM Resource Plan - Regulatory Background behind Cost Allocation Methodology - DSM Cost Allocation Methodology

AI summary The text outlines an overview of topics including the DSM Cost Recovery Process, the 2023-2025 DSM Resource Plan, and the regulatory background and methodology for DSM cost allocation.

Regulatory background behind current DSM Cost Allocation Approach - The current cost allocation methodology was approved by the Board in its 2010 DSM Plan and 2010 DSM Rider Decision (NSUARB-NSPI-P-884(2). Board's findings were as follows....

AI summary The current DSM cost allocation methodology was approved by the Board in its 2010 DSM Plan and 2010 DSM Rider Decision. It recognizes three types of cost benefits from DSM: System, Class, and Participation. The recovery of DSM costs is based on the level of benefit received by customer classes, with 75% of costs directly assigned to rate classes and 25% apportioned via the COSS methodology.

Allocation of DSM Program Costs - Step 1 Allocate the system benefits to all applicable customer classes, as 25% of the total Approved DSM program costs, in accordance with the COSS methodology per the most recent rate case decision. - Ste...

AI summary The document outlines a six-step process for allocating Demand Side Management (DSM) program costs among customer classes. It involves distributing system and class benefits, calculating recovery amounts, and adjusting annually based on actual experience. The allocation follows the COSS methodology and applies to both bundled service and wholesale customers.

DSM Cost Allocation Results # Tabi e 3: 2024 PCR - Anocation 01 2024 prog grann costs annong rate Classes COLUMN Α В С D E F G Н I FORMULA Table 1 Column H Table 2 Column K A + C E/G E / 12 System Ben expenditure C d to classe c ucina Part...

AI summary The document presents a table detailing the allocation of demand-side management (DSM) costs across various rate classes in 2024. It includes breakdowns of system benefits expenditure, participating costs, and PCR riders, with percentages and monetary figures for each category. The data highlights the distribution of costs among residential, industrial, and municipal classes, along with associated charges and payments.

Methods considered in the past proceedings In its 1993 COS Application (NSPI864), in response to UARB's earlier directive to propose a methodology which would classify costs associated with fuel conversion and environmental compliance to e...

AI summary In past proceedings, NSPI proposed the Equivalent Peaker (EP) method for classifying generation costs, but it was rejected by the Board as impractical. The SLF-based method was adopted instead. In 2013, NS Power proposed maintaining the SLF method but also presented alternate methods like PD, EP, and TD, which were rejected due to complexity and lack of industry use.

Time-differentiated Method considered in 2013 COS - Of interest to this proceeding; where parties indicated interest in finding a time-differentiated (TD) COS method that would better align cost apportionment to rate classes with timediffe...

AI summary The time-differentiated (TD) method for calculating the cost of service (COS) was considered in the 2013 proceeding. Mel Whalen, the Board's consultant, highlighted imperfections in TD methods, noting they oversimplify generation planning and fail to account for long-term forecasts, public policy, and technology changes. He also questioned the equitability of TD-based solutions and their poor prediction of on-peak generation capacity costs.

NS Power's Position on classification of Transmission in past COS Proceedings - In its 1993 COS Application (NSPI864) NS Power proposed unbundling of transmission from production costs and classifying it 100% to demand cost allocated to ra...

AI summary NS Power has historically proposed different methods for classifying transmission costs in its COS Applications, including unbundling from production costs and allocating based on 3CP or 12CP. The UARB has influenced these classifications, and NS Power argues that 12CP better reflects the physical and operational realities of its transmission system.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 132 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary This page from the 2026-2027 GRA Direct Evidence Appendix 12A(3) includes a figure that is likely related to cost of service studies or system loss factors, but the content is redacted and confidential.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 146 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Comments on NB Power COSS Filings (April 11, 2024) Page 2 of 4

AI summary This document contains comments on NB Power's Cost of Service Study (COSS) filings submitted on April 11, 2024. The text is part of a larger regulatory proceeding and includes redacted confidential information.

2. Definition of POD Method The NB Power evidence defines the POD method as allocating "the energy classified costs by looking at the cost of providing energy in each hour instead of assuming that each kilowatt-hour served throughout the y...

AI summary The document defines the POD method, which allocates energy classified costs based on hourly dispatch and probability of dispatch. E3 suggests improvements, such as including operating reserves and excluding dispatch for exports and interruptible loads. The method requires significant data and process changes for full implementation.

3. Application of POD Method The NB Power POD method analysis assigns generation capacity (non-fuel) costs equally to all hours in which they are used. (Exh. NBP2.03, p. 15) The cost-of-service workbook provided by NB Power does not includ...

AI summary The NB Power POD method assigns non-fuel generation capacity costs equally across all hours of use. The analysis compares the POD method to the variable energy method and suggests they are similar to a class energy allocation, though verification is not possible due to incomplete supporting calculations in the provided workbook.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 148 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Comments on NB Power COSS Filings (April 11, 2024) Page 4 of 4 using forecast data while the HCM method is challenged for application...

AI summary The text discusses challenges in applying the HCM method to NS Power due to the lack of hourly LMP data, requiring NS Power to calculate hourly generation costs using fuel cost, purchased power costs, and other dispatch cost inputs.

2.2 Average and Peak with Time of Use (TOU) Method - 7 The average and peak with time of use method increases the granularity of the data used in - 8 allocation of the energy classified costs by looking at the cost of providing energy in e...

AI summary The average and peak with time of use (TOU) method provides a more granular approach to allocating energy classified costs by considering hourly generation costs and loss of load probability (LOLP). However, it requires additional data not currently available in NB Power's systems and raises confidentiality concerns that may impact transparency in cost allocation.

2.4 Marginal Cost Method 5 During the procedural conference of June 28, 2023, the final approved scope listed the marginal 6 cost allocation model as optional. Marginal cost modeling has the advantage of being relatively 7 simple to implem...

AI summary The marginal cost allocation model is deemed unsuitable for NB Power's class cost allocation study due to its volatility, inaccuracy in reflecting long-term costs, and confidentiality concerns. E3's analysis highlights discrepancies between marginal costs and actual costs, and no vertically integrated Canadian utility uses this method for CCAS.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 151 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Excerpt from Exh. Overview of Cost Allocation Methodologies

AI summary The excerpt provides an overview of cost allocation methodologies relevant to the 2026-2027 GRA Direct Evidence Appendix 12A(3). It outlines approaches used to distribute costs among different service categories or customer groups.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 152 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Overview of Cost Allocation Methodologies included in this analysis however, it would be appropriate to include them in future analys...

AI summary The document discusses cost allocation methodologies, highlighting the inclusion of fixed costs for generators dispatched for exports and interruptible load in customer class allocations. It notes that this approach may not accurately reflect the reason for dispatch and suggests that future analyses should consider excluding such data for better accuracy.

Table 4: Pros and cons of Probability of Dispatch method Pros Cons Removes a layer of subjectivity because it removes the need to classify overall fixed costs to energy and capacity. Potentially more accurate in assigning costs of resource...

AI summary The Probability of Dispatch method has pros such as reducing subjectivity in cost classification and potentially more accurate cost assignment. However, it has cons like high data requirements, not considering the rationale for investments, and volatility due to system changes. The method assigns generator costs equally across usage hours, potentially misrepresenting investment rationale.

Timing of COS Transition - § Now is the time to make changes to reflect rapidly evolving NS Power system. - § ELCC generating resource cost functionalization is both more forward looking and more dynamic than current methodologies. - § COS...

AI summary The document emphasizes the need for updating the Cost of Service (COS) model to better reflect the current and evolving NS Power system, advocating for a more dynamic and forward-looking approach that focuses on cost-causation and the role of assets rather than ownership.

Issuelb - Should the use ofllourly Production Costing for Cost Allocation? SBA View - The SBA would like this to be examined carefully and quickly in this process to ultimately propose changes in COSS methodology to the UARB. Issue 1 c - I...

AI summary The SBA recommends careful and quick examination of hourly production costing for cost allocation to propose changes in COSS methodology to the UARB. It also believes its preferences from Issue 1a will capture the effects of a more diverse generation portfolio on cost allocation methodology.

Issue le-Unconventional generation, including PPAs. Maritime Link; DDA? SBA View - The SBA discussion of Issue 1 a and 1 a(i) addresses the PP As and special function transmission such as the Maritime Link. The SBA does not believe that th...

AI summary The SBA discusses Issue 1 a and 1 a(i), focusing on PPAs and special function transmission like the Maritime Link. It argues that the DDA should not influence the cost allocation of investment cost recovery but may affect total revenue requirements.

Purpose of Minimum System Study - The Minimum System Study is used in the COSS for the classification of distribution costs between customer-related and demand-related. - The need to classify distribution costs is described in NARUC Electr...

AI summary The Minimum System Study is used in the COSS to classify distribution costs between customer-related and demand-related. This classification is based on the NARUC Electric Utility Cost Allocation Manual, which emphasizes that distribution costs are driven by both reaching customers and maintaining capacity to meet peak demands.

10b. Classify All Generation that is Currently Classified by SLF by Capacity Factor - ➢ Purpose: Analyse the impact of allocating all generation costs that are currently classified by the SLF by the weighted average capacity factor of that...

AI summary This section discusses the analysis of allocating generation costs based on the weighted average capacity factor rather than the Steam Load Factor (SLF). The change shifts cost classifications from energy to demand, with lower load factor classes bearing more cost responsibility.

2. New Intermediate Generation Sub-function Classified to Demand and Energy by Weighted-Average Capacity Factor - ➢ Purpose: Identify "Intermediate Generation" assets and costs and classify by the weighted-average capacity factor instead o...

AI summary This section discusses the classification of 'Intermediate Generation' assets, specifically Tufts Cove units 1, 2, and 3, using a weighted-average capacity factor instead of the Steam Load Factor (SLF). This change results in a shift of classified costs from energy to demand, with a relatively small overall impact due to the 10% contribution of intermediate generation to total steam generation.

1. NSP Positions - ➢ Purpose: Combine the changes made in COSS model runs 2, 3, 4, and 5. - ➢ Model Notes: The classification of Transmission 100% to demand is not applied to grid scale storage. - ➢ Overall Impact: There is an overall shif...

AI summary NSP is proposing to combine changes from multiple COSS model runs, noting that transmission costs classified as 100% demand impact cost classification, with some offset from increased generation costs due to changes in SLF and the inclusion of PHP.

DSM Model Scenario - ➢ NSP was asked to model the impact of changing the classification of DSM costs attributable to the MEUs to be 100% based on direct customer costs. - ➢ Currently 75% of costs are assigned directly to rate classes and 2...

AI summary NSP was asked to model the impact of changing the classification of DSM costs attributable to the MEUs to be 100% based on direct customer costs. Currently, 75% of costs are assigned directly to rate classes, while 25% is classified as System Benefit and allocated using the COSS methodology. The four OATT municipalities currently receive 100% customer-related costs and no System Benefit allocation. BUTU costs are classified as 100% customer-related.

Differences in Transmission Revenue Requirements Expense (In thousands of 2013 2014 dollars) OATT COSS % Var OATT COSS % Var Operating, Maintenance and General OM&G) $26,586 $26,104 2% $26,762 $26,286 2% Depreciation $24,072 $26,167 -8% $2...

AI summary The text presents tables comparing transmission revenue requirements for different years, highlighting changes in expenses such as operating, maintenance, depreciation, and fixed cost recovery deferral between OATT and COSS for 2013, 2014, and 2023. The data shows significant variations in expense percentages and amounts over time.

Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: October 11, 2024 Re: Written Response regarding Decarbonization Deferral Account (DDA) The COSS work plan outlines the following item for NS Power to pro...

AI summary NS Power outlines its approach to the Decarbonization Deferral Account (DDA) in response to stakeholder concerns. The DDA is used to defer costs related to retiring coal-fired assets and decommissioning facilities by 2030. The Board approved the DDA in May 2024, and NS Power proposes treating it as a regulatory asset for cost of service (COS) purposes.

2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 3 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) October 11, 2024 Memo to Participants in COSS Stakeholder Process

AI summary This memo, dated October 11, 2024, is addressed to participants in the Cost of Service Study (COSS) stakeholder process. It is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(5) and is marked as confidential.

Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: October 11, 2024 Re: Written Response regarding General Plant The COSS work plan outlines the following item for NS Power to provide a written response:

AI summary NS Power is responding to a written request from the COSS Stakeholder Process regarding General Plant. The request is part of the COSS work plan, which outlines specific items for NS Power to address.

2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 6 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted page from a 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(5), which contains confidential information. It is part of a regulatory proceeding related to rate applications and cost-of-service studies.

Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: November 1, 2024 Re: Written Response regarding Decarbonization Deferral Account (DDA) - Updated The COSS work plan outlines the following item for NS Po...

AI summary NS Power outlines its position on the Decarbonization Deferral Account (DDA) in response to the COSS Stakeholder Process. The DDA is a regulatory asset used to recover costs from retiring coal-fired assets by 2030. NS Power proposes treating the DDA as a regulatory asset in the same manner as other assets for cost-of-service (COS) purposes, citing historical practices from previous GRA filings.

2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 7 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) November 1, 2024 Memo to Participants in COSS Stakeholder Process - Func�onalized among the four service areas of genera�on, transmiss...

AI summary This memo outlines the methodology for func�onalizing and classifying costs across different service areas and rate classes as part of the 2026-2027 GRA Direct Evidence Appendix 12A(5) process.

2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 9 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document is a redacted page from a 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(5), which includes confidential information. It is part of a regulatory proceeding related to rate applications and cost-of-service studies.

Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: November 1, 2024 Re: Written Response regarding General Plant - Updated The COSS work plan outlines the following item for NS Power to provide a written...

AI summary This memorandum from NS Power to participants in the COSS Stakeholder Process outlines the need for a written response regarding General Plant, as part of the COSS work plan.

The five-year forecast within the 2024 ACE plan shows that the investment level in general plant, which includes IT software and communication investments continues to be an area of significant investment and warrants a refinement in its C...

AI summary The 2024 ACE plan highlights continued significant investment in general plant, including IT software and communication, suggesting the need for a refined approach to the cost of service (COS).

2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 13 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Status Quo CTD Referen ce NS Power Position (Pre Resolution Session) NS Power Updated Position (Following Resolution Session) Justifi...

AI summary The document discusses NS Power's proposal to classify all generation assets based on SLF, eliminating the need to subfunctionalize generation assets. This approach is justified as it aligns with industry practices, supports system stability, and provides a simpler and more consistent method for cost-of-service classification.

Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: December 6, 2024 Re: Written Response regarding General Plant – Update 2 The COSS work plan outlines the following item for NS Power to provide a written...

AI summary This memorandum from NS Power provides a written response regarding the General Plant as part of the COSS Stakeholder Process. It outlines the work plan for NS Power to address stakeholder concerns and provide necessary information.

2026-2027 GRA Direct Evidence Appendix 12A(6) Page 2 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) presentation included information on the DSM cost recovery process, the 2023-2025 DSM resource plan, regulatory background behind the cur...

AI summary The presentation detailed the DSM cost recovery process, the 2023-2025 DSM resource plan, and the regulatory background of the current DSM cost allocation methodology. NS Power also responded to questions about Bill 404 and its potential impact on the Cost of Service Study.

2026-2027 GRA Direct Evidence Appendix 12A(6) Page 4 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - Session 7: June 3, 2024 - o Full-day session - o Topics: Distribution functionalization (transmission vs distribution); subfunctionaliz...

AI summary The sessions discussed distribution functionalization, cost of service treatment for bundled and unbundled services, and line loss studies. NS Power presented their positions, and intervenors provided feedback. Topics included allocation of service drop costs, use of AMI data, and alignment of OATT with COSS.

1 EXECUTIVE SUMMARY 2 Nova Scotia Power Inc. ("NS Power") retained Elenchus Research Associates 3 ("Elenchus") in December 2023 to assist the company during its cost of service study 4 ("COSS") review process. The goal of this process was...

AI summary NS Power retained Elenchus Research Associates to assist with its cost of service study review process. The goal was to refine NS Power's methodology in light of developments since the 2013 COSS, including increased renewable integration, gas-fired generation, and grid-scale battery storage. Elenchus provided context on ratemaking principles and cost allocation practices.

2026-2027 GRA Direct Evidence Appendix 12B Page 6 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1000000 Onc :hus .i ius -6- NSP COSS Consultation Report Draft April 25, 2025

AI summary The document provides a redacted excerpt from a consultation report by NSP related to the Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B, which contains confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 7 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -7- NSP COSS Consultation Report Draft April 25, 2025 - 1 responsibility because they typically support multiple functions and aren't drive...

AI summary NS Power has proposed refinements to its Cost of Service Study (COSS) to better align cost allocation with current operational realities and customer classes. These include adjustments for PHP's rate class, DSM benefits, and line loss studies. Elenchus supports these changes, stating they improve cost recovery and alignment with industry evolution.

2026-2027 GRA Direct Evidence Appendix 12B Page 8 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -8- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B and contains redacted confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 10 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -10- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study, dated April 25, 2025, and is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is marked as confidential and redacted.

1 1.2 THEORY OF COST ALLOCATION - 2 In the electricity industry, electricity is generated, primarily in large power plants, then - 3 transmitted over high voltage transmission lines, after which it is transformed to lower - 4 voltages and...

AI summary This section outlines the theory of cost allocation in the electricity industry, explaining how shared assets and expenses are distributed among customer classes using a cost allocation study. The methodology relies on principles such as cost causality, benefit derived, government policy alignment, timing of recovery, simplicity, and acceptability.

2026-2027 GRA Direct Evidence Appendix 12B Page 12 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1 enc hile ıwə -12- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a consultation report draft from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B, which contains redacted confidential information.

11 1.3.2 COST RELATED - 12 Fairness and equity are understood to mean that the utility's assets and expenses have - 13 been apportioned to the customer classes in a manner that has cost causality as the main - 14 criterion. The methodologi...

AI summary The text discusses the principles of fairness, equity, and economic efficiency in utility cost apportionment. It emphasizes cost causality as a key criterion for allocating assets and expenses to customer classes, and highlights the importance of rate design in promoting operational and dynamic efficiency, as well as resource conservation.

2026-2027 GRA Direct Evidence Appendix 12B Page 14 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -14- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, part of the 2026-2027 GRA Direct Evidence Appendix 12B, with confidential information redacted.

2026-2027 GRA Direct Evidence Appendix 12B Page 15 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -15- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, and is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 16 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -16- NSP COSS Consultation Report Draft April 25, 2025 - 1 with the current methodology, and present alternative methodologies. In additio...

AI summary NS Power conducted stakeholder consultations and discussions to refine the Cost of Service Study methodology, responding to 152 data requests and providing 31 model scenarios to assess alternative approaches.

2026-2027 GRA Direct Evidence Appendix 12B Page 17 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -17- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, which is part of the 2026-2027 GRA Direct Evidence Appendix 12B. The content is redacted and contains confidential information.

4 Table 2 – Summary of NS Power Proposed Methodology Status Quo Change Generation • Allocation except for treatment of purchased power • No initial classification to energy for environmental and fuel conversion reasons • Use system load fa...

AI summary NS Power proposes changes to its methodology for classifying and allocating costs related to generation, transmission, and distribution. Key changes include refunctionalizing radial-to-generation, using system load factors for classification, and creating new storage sub-functions. These changes aim to improve cost allocation and align with updated regulatory practices.

7 4.1.1.3 ELENCHUS OPINION - 8 Elenchus agrees it is appropriate to continue to maintain the current sub-functionalization - 9 of rate base and OM&A by type of generation. The primary purpose of sub-functionalizing - 10 accounts is to sepa...

AI summary Elenchus supports maintaining the current sub-functionalization of rate base and OM&A by type of generation, arguing that it provides greater clarity and transparency in the cost of service study model compared to consolidating into a single generation function.

2026-2027 GRA Direct Evidence Appendix 12B Page 20 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The second second On IC en -20- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix 12B, which includes a consultation report draft from NSP's Cost of Service Study (COSS) dated April 25, 2025.

2026-2027 GRA Direct Evidence Appendix 12B Page 21 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -21- NSP COSS Consultation Report Draft April 25, 2025 - 1 or point to point service so this proposed change better aligns NS Power's tran...

AI summary Nova Scotia Power (NSP) proposes to reclassify a grid-scale storage facility from the Transmission function to a new Generation Storage sub-function due to its primary generation purpose. Elenchus supports this reclassification for accurate cost allocation and future storage projects.

2026-2027 GRA Direct Evidence Appendix 12B Page 22 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -22- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, as part of the 2026-2027 GRA Direct Evidence Appendix 12B. It includes redacted confidential information and is part of a regulatory proceeding.

4.2.1.3 ELENCHUS OPINION 5 The system load factor method is a simple and pragmatic approach to classifying costs 6 that are functionalized as generation costs as energy- and demand-related in a manner 7 that ignores the cost difference acr...

AI summary The Elenchus opinion critiques the system load factor method for allocating generation costs, noting that it oversimplifies by ignoring differences between supply resources. It raises concerns about the impact of new facilities on cost allocation and suggests that a more granular approach may not be equitable in the short term. The opinion emphasizes the need for a methodology that balances cost causality and fairness.

2026-2027 GRA Direct Evidence Appendix 12B Page 25 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -25- NSP COSS Consultation Report Draft April 25, 2025 - 1 reasonable rates that ultimately determines whether the methodology is appropri...

AI summary The text discusses the system load factor approach used in NS Power's cost allocation process, emphasizing that embedded costs are determined by historic decisions and not current use, highlighting the diversity of assets resulting from long-term capital investment.

4.2.2.3 ELENCHUS OPINION - 6 Classifying fuel, imports, and export revenues to energy is appropriate as those costs are - 7 incurred directly to provide energy to customers. This is consistent with common practice - 8 and ratemaking princi...

AI summary The text discusses the appropriate classification of fuel, import, and export revenues to energy, aligning with common practice and ratemaking principles. It supports NS Power's proposal to classify costs based on system load factor and aligns with their methodology for purchases and generation.

2026-2027 GRA Direct Evidence Appendix 12B Page 27 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 10000 On IC en ш U > -27- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a consultation report from Nova Scotia Power's Cost of Service Study (COSS) draft dated April 25, 2025, which is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information and appears to be part of a regulatory proceeding.

2026-2027 GRA Direct Evidence Appendix 12B Page 28 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -28- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a consultation report from Nova Scotia Power's Cost of Service Study (COSS) draft dated April 25, 2025, part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is redacted and contains confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 29 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) ODC hile enc -29- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft of the NSP COSS Consultation Report from April 25, 2025, part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is marked as redacted and contains confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 30 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -30- NSP COSS Consultation Report Draft April 25, 2025

AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, as part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information.

2026-2027 GRA Direct Evidence Appendix 12B Page 31 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -31- NSP COSS Consultation Report Draft April 25, 2025 - 1 Therefore, Elenchus supports removing the distinction and merging EHV and HV wi...

AI summary The document discusses NS Power's proposed refunctionalization of radial-to-generation and transmission storage within the cost of service study model. Elenchus supports the refunctionalization of radial-to-generation from Transmission to Generation and the creation of a transmission storage sub-function to better classify and allocate costs.

5.3 ALLOCATION - 5.3.1 GENERAL TRANSMISSION - 5.3.1.1 NSP CURRENT APPROACH - Demand-classified EHV and HV transmission is allocated to rate classes using the same - 3CP allocator used to allocate demand-classified generation costs. - Energ...

AI summary NS Power proposes maintaining the current method of allocating demand-classified transmission costs using the 3CP allocator, while eliminating the energy classification of transmission costs. Elenchus supports this approach, aligning with NS Power's proposal to use a single sub-function for EHV and HV transmission costs in the revised cost of service study model.

12 6.1.1.3 ELENCHUS OPINION - 13 NS Power's functionalization of Distribution to sub-functions is reasonable and - 14 consistent with the sub-functions used by other vertically-integrated utilities across - 15 Canda. This level of sub-func...

AI summary The text argues that NS Power's division of Distribution into sub-functions is reasonable and consistent with other utilities in Canada. It also suggests that creating a distribution storage sub-function is prudent, even without current facilities, due to future developments in the electricity sector and potential cost savings.

2026-2027 GRA Direct Evidence Appendix 12B Page 41 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -41- NSP COSS Consultation Report Draft April 25, 2025 - 1 load can create counterintuitive and controversial results that are detached fr...

AI summary The document discusses the limitations of the basic customer method for cost allocation, highlighting inconsistencies with cost causality. It compares this method to the minimum system and zero-intercept methods, noting that the latter two are used by some Canadian utilities but not universally. The zero-intercept method, while used by some, can produce counterintuitive results.

2026-2027 GRA Direct Evidence Appendix 12B Page 42 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -42- NSP COSS Consultation Report Draft April 25, 2025 - 1 In Elenchus' view the minimum system method is the method most aligned with cos...

AI summary The document discusses NS Power's current and proposed methodologies for classifying and allocating distribution storage and demand-classified distribution. Elenchus supports NS Power's approach, arguing that using a weighted average classification aligns with cost causality principles and appropriately allocates distribution storage costs.

7.2.3 ELENCHUS OPINION - General plant provides support to the generation, transmission, and distribution functions - and there generally is no clear cost driver for these costs. The overall approach to - classifying and allocating general...

AI summary The opinion discusses the classification and allocation of general plant costs, emphasizing the need for periodic reviews to ensure accurate cost assignment. It supports breaking out computer software and communications equipment for more precise allocation and highlights the importance of aligning with Canadian methodologies.

7.3.2 NSP PROPOSED APPROACH - 7 NS Power has refined the COSS to facilitate scenarios that allocate costs to PHP as a - 8 separate rate class PHP's loads and customer characteristics would be included in the - 9 derivation of allocators as...

AI summary NSP has refined the COSS to allocate costs to PHP as a separate rate class, ensuring its loads and customer characteristics are included in the derivation of allocators. PHP, being a transmission-connected customer, will not receive any allocation of distribution costs.

7.4.2 ELENCHUS OPINION - 4 The study conducted by BBA is consistent with, or in many cases more detailed, than line - 5 loss studies used in other jurisdictions across Canada. In Elenchus' view the results - 6 produced by BBA are appropria...

AI summary The Elenchus opinion supports the use of BBA's study in NS Power's cost of service analysis, noting its consistency and detail compared to other jurisdictions in Canada. The study is deemed appropriate for deriving loss-adjusted energy and demand allocators.

7.5.2 ELENCHUS OPINION - This weighted average approach effectively treats DDA costs as overhead-type costs in - the same manner as general plant. Though the costs are related to the generation - function, the need to recover DDA costs is...

AI summary The weighted average approach treats DDA costs as overhead-type costs, similar to general plant, despite their origin in legislation requiring NS Power to decarbonize. This raises concerns about whether DDA costs should be recovered based on the asset's original function or spread more broadly.

11 7.6.1 CURRENT RATE RIDER METHODOLOGY - 12 NS Power applies a DSM rate rider to recover the costs of EfficiencyOne. The rate rider - 13 is calculated based on the costs of DSM programs applicable to each class and an - 14 assessment of N...

AI summary NS Power uses a DSM rate rider with a 75%/25% weighting to recover EfficiencyOne costs, where 75% is based on program costs per class and 25% on system benefits, determined by judgment.

2026-2027 GRA Direct Evidence Appendix 12B Page 53 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -53- NSP COSS Consultation Report Draft April 25, 2025

AI summary The document is a consultation report from NSP's Cost of Service Study (COSS) draft dated April 25, 2025, as part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is redacted and contains confidential information.

8 CONCLUSIONS 2 As stated in the Introduction the goal of this process was to identify appropriate changes 3 to NS Power's COSS in light of developments including the greater integration of wind 4 and other renewables, the addition of a gr...

AI summary The document discusses the need for refinements to NS Power's Cost of Service Study (COSS) methodology due to changes in technology and generation mix, such as increased renewables and gas-fired generation. It emphasizes that the fundamental principles of cost allocation remain unchanged, but adjustments are necessary to equitably assign costs to customer classes.

2026-2027 GRA Direct Evidence Appendix 12B Page 55 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -55- NSP COSS Consultation Report Draft April 25, 2025 1 of the functionalization of projects within general plant will better align suppo...

AI summary This text discusses refinements to NS Power's Cost of Service Study (COSS) to better align support costs with specific functions, address unique costing approaches for PHP, and update DSM rate rider weightings based on customer class. It also highlights a new line loss study conducted by BBA, which provides a more accurate basis for allocating line losses among rate classes.

In conclusion, the evaluation of network losses by segment to determine loss allocation factors and demand line losses provides valuable insights on the impact of each customer on the NS Power network. Transmission, distribution and second...

AI summary The evaluation of network losses by segment to determine loss allocation factors and demand line losses provides insights into customer impact on the NS Power network. Data from transmission, distribution, and secondary systems were used to support the estimation, forming a foundation for cost-of-service assessment.

This document describes the plan for administering Nova Scotia Power Inc.'s (NS Power) Fuel Adjustment Mechanism (FAM), which was approved by the Nova Scotia Utility and Review Board (Board) in its decision letter issued on December 11, 20...

AI summary This document outlines the administration plan for NS Power's Fuel Adjustment Mechanism (FAM), approved in 2008. It explains how the Base Cost of Fuel is calculated, reset, and used to adjust customer rates based on actual fuel costs. The FAM includes provisions for audits, stakeholder input, and interest calculations on over/under-recovery amounts.

2.0 FAM COMPONENTS Each January 1 through December 31 period shall constitute a distinct FAM year. Under the FAM, an adjustment will normally be calculated once per year to reflect the over/-under recovery. The FAM adjustment will consist...

AI summary The Fuel Adjustment Mechanism (FAM) operates on an annual basis, with adjustments calculated once per year to recover fuel and purchased power costs. The mechanism comprises two components designed to address over or under recovery during each FAM year.

2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...

AI summary The Balancing Adjustment Component (BA) ensures correction of over/under-recovery from the Actual Adjustment Component (AA) by refunding or recovering costs from customers. It may also defer fuel and purchased power costs with specific Board approval.

3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...

AI summary NS Power's Fuel Adjustment Mechanism (FAM) uses an annual formula combining Actual Adjustment (AA) and Balance Adjustment (BA) to manage fuel costs. AA reflects over/under recovery of fuel costs, with October-December adjustments deferred to the following year. BA manages prior adjustments and deferred costs approved by the Board. The mechanism aims to align revenues with actual fuel expenses across rate classes.

IV. Schedule 1 – FAM Calculation The remaining items are calculated in 'Schedule 1 – FAM Calculation': a) Line 1: links the 'Base Cost of Fuel per kWh' calculated in line 13 of 'Schedule 2b – COS Base Fuel'. - b) Line 2: links the 'Actual...

AI summary This section outlines the calculation process for the Fuel Adjustment Mechanism (FAM) as detailed in Schedule 1. It explains how various lines link to other schedules and calculations, including the determination of over/under recovery amounts, interest calculations, and the breakdown of fuel costs by rate class.

M-2 SUMMARY OF COST RECOVERY (Non-Confidential) - Summary of Base Cost of Fuel (BCF) actual and budget amounts for year to date and current month - Provides running balance to be recovered, forecast (over)/under recovery for remainder of t...

AI summary This document provides a summary of cost recovery for the Fuel Adjustment Mechanism (FAM), including actual and budget amounts for the Base Cost of Fuel (BCF), Actual Adjustment (AA), and Balancing Adjustment (BA) components. It outlines running balances, forecasts for the remainder of the year, and interest calculations.

(Confidential and Non-Confidential Versions) - Provides details per month for CBL Energy charge, Accrual Booked and Accrual Reversed which links back to report on M-1 - Breaks down the CBL Energy charges by Fuel and Purchased Power charge,...

AI summary The text provides a monthly breakdown of CBL Energy charges, including Fuel and Purchased Power, Operating and Maintenance, and Fixed Cost Recovery, along with actual and target energy figures and total billed charges, referencing report M-1.

Actual Adjustment Component (AA) Year Beginning AA Balance Recovered Prior to Current Month Opening Balance as of Month 1, Year Recovered/(Refunded) in Current Month Closing Balance as of Month Day, Year Recovered/(Refunded) Remainder of t...

AI summary The document outlines the Actual Adjustment Component (AA), detailing the balance recovered prior to the current month, the opening balance as of a specific date, the amount recovered or refunded in the current month, the closing balance as of a specific date, and the remainder of the year interest on the AA balance.

CONFIDENTIAL Cost Centre=PTA (Point Aconi) Pe riod-to-date - > <- Y ear-to-date - > Full Year Prior YTD C urr/Prior YT Actual Forecast Variance Actual Forecast Variance Forecast Actual Variance Solid Fuel Tonnes MMBTU Costs $ per Tonne $ p...

AI summary The document presents a detailed table of fuel and purchased power costs for Point Aconi, including various fuel types such as solid fuel, natural gas, biomass, bunker C, and diesel. It lists actual and forecasted costs, variances, and adjustments, including FX adjustments and total fuel and purchased power costs.

Operations NSPI's earnings are most directly impacted by the range of ROE and capital structure approved by the NSEB, the prudent management and approved recovery of operating costs, electric sales volumes, weather, the approved recovery o...

AI summary NSPI's 2025 earnings are projected to rise but remain below the NSEB-approved ROE range, influenced by higher sales volumes, increased capital investment ($680M), and cost recovery mechanisms. The company emphasizes investments in system reliability and service.

FINANCIAL REVIEW OF 2025

AI summary The document outlines the financial review for 2025, focusing on regulatory proceedings under Nova Scotia's energy framework. Key areas include cost recovery, rate design, and compliance with regulatory standards, though detailed analysis is not provided in the excerpt.

NSPI has a contractual obligation to pay NSP Maritime Link Inc. ("NSPML"), a related party, for the use of the Maritime Link over approximately 38 years from its January 15, 2018, in-service date. On November 29, 2024, NSPML received NSEB...

AI summary NSPI is required to pay NSPML for the use of the Maritime Link over 38 years. NSEB approved NSPML to collect up to $197 million from NSPI in 2025, including $158 million from the annual cost assessment and $39 million for repaying a federal loan guarantee.

2026-2027 GRA OP-01 Attachment 3 Page 11 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate...

AI summary The FPSC approved a rate case decision in February 2025, which was later challenged but ultimately upheld. A motion for reconsideration was denied, except for minor corrections. Additionally, a petition for recovery of $466 million USD in storm-related costs was approved, subject to a true-up mechanism. Capital investments in the Florida Electric Utility segment are expected to reach $1.7 billion USD in 2025.

NSPML Equity earnings from NSPML in 2025 are expected to be consistent with 2024. The NSPML investment is recorded as "Investments subject to significant influence" on Emera's Consolidated Balance Sheets. On July 18, 2025, NSPML submitted...

AI summary NSPML expects consistent equity earnings in 2025 compared to 2024. It has submitted applications to recover costs for the Maritime Link and submarine cable protection, with decisions expected in Q4 2025. NSPML also received approval to collect funds from NSPI in 2025, with a holdback mechanism in place.

Cash Flow from Operating Activities Net cash provided by operating activities decreased $394 million to $799 million for the six months ended June 30, 2025, compared to $1,193 million for the same period in 2024. Cash from operations befor...

AI summary Net cash provided by operating activities decreased to $799 million for the six months ended June 30, 2025, compared to $1,193 million in 2024. This decrease was primarily due to unfavourable changes in working capital, including accounts payable and receivable, inventory, and trade receivables, partially offset by increases in fuel over-recoveries and new base rates.

As at June 30 December 31 millions of dollars 2025 (1) 2024 Regulatory assets Deferred income tax regulatory assets $ 1,274 $ 1,227 TEC capital cost recovery for early retired assets 710 737 Storm cost recovery clauses 447 613 Pension and...

AI summary The text provides a table showing regulatory assets and liabilities for various entities as of June 30, 2025, and December 31, 2024. It includes items such as deferred income tax, cost recovery clauses, and environmental remediations. A note mentions that NMGC's assets and liabilities were classified as held for sale following an agreement announced by Emera on August 5, 2024.

Storm Reserve: On February 4, 2025, the FPSC approved TEC's petition for the recovery of $466 million USD of costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton, and the associated interest to rep...

AI summary The FPSC approved TEC's petition to recover $466 million USD in costs related to multiple hurricanes, to be replenished over an 18-month period with a true-up mechanism. These costs are part of regulatory assets and liabilities that are not individually significant.

NSPML On July 18, 2025, NSPML submitted an application to the NSEB requesting recovery of approximately $199 million in Maritime Link costs for 2026. On May 21, 2025, NSPML submitted an application to the NSEB for approval of a $33 million...

AI summary NSPML has submitted applications to recover costs related to the Maritime Link and submarine cable protection, totaling approximately $232 million. NSPML was approved in 2024 to collect up to $197 million from NSPI in 2025, with a potential holdback of up to $4 million per month.

Superfund and Former Manufactured Gas Plant Sites Previously, TEC had been a potentially responsible party ("PRP") for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured...

AI summary The Florida utilities are liable for environmental remediation costs at superfund and former manufactured gas plant sites, with an estimated aggregate financial liability of $16 million as of June 30, 2025. These costs are recoverable through customer rates, and the liability is reflected in long-term liabilities. The estimates assume other PRPs are creditworthy, though uncertainties exist.

Tampa Electric • In March 2023, the FPSC approved recovery of $518M USD of fuel underrecoveries over a period of 21 months and the recovery of $131M USD of storm costs over 12 months at Tampa Electric. Recovery began April 1, 2023.

AI summary In March 2023, the FPSC approved the recovery of $518M USD in fuel underrecoveries over 21 months and $131M USD in storm costs over 12 months at Tampa Electric, with recovery beginning April 1, 2023.

Recent Regulatory Activity In March 2023, the FPSC approved Tampa Electric's fuel and storm costs filings. Beginning April 1, 2023, Tampa Electric began to recover the 2022 fuel under-recovery of $518M USD over a period of 21 months and th...

AI summary In March 2023, the Florida Public Service Commission (FPSC) approved Tampa Electric's fuel and storm costs filings. Starting April 1, 2023, Tampa Electric began recovering a 2022 fuel under-recovery of $518M USD over 21 months and a $131M USD storm reserve regulatory asset over 12 months.

Regulatory Arrangements • In December 2022, the UARB approved the recovery of ~$164M in Maritime Link costs for 2023.

AI summary In December 2022, the UARB approved the recovery of approximately $164M in Maritime Link costs for 2023.

Cash Flow Drivers: - + Fuel and storm deferral recovery of $678M in 2023 at Tampa Electric - Collected final outstanding balances in New Mexico related to Winter Storm Uri - Increased cash flow from operations from regulated utilities driv...

AI summary The cash flow drivers include fuel and storm deferral recovery at Tampa Electric, collections from New Mexico related to Winter Storm Uri, increased cash flow from regulated utilities due to new rates and growth, additional fuel and storm deferrals at NSPI, and increased financing costs.

Recovery of fuel and storm cost deferrals - Effective fuel and storm mechanisms at Tampa Electric and NSPI - Will recover 100% of 2022 fuel and storm deferrals at TEC by the end 2024 - New fuel rates + agreement with Province of NS stabili...

AI summary The document discusses the recovery of fuel and storm cost deferrals, highlighting effective mechanisms at Tampa Electric and NSPI, the recovery plan for TEC by 2024, and a new agreement with the Province of Nova Scotia to stabilize fuel deferrals at NSPI.

2. Earnings Growth • Translate rate base growth into earnings growth by managing capital deployment with timing of regulatory filings and through prudent cost management

AI summary The text discusses translating rate base growth into earnings growth by managing capital deployment through the timing of regulatory filings and prudent cost management.

Regulatory Arrangements • In December 2023, the UARB approved the recovery of ~$164M in Maritime Link costs for 2024.

AI summary In December 2023, the UARB approved the recovery of approximately $164 million in Maritime Link costs for 2024.

Regulatory Arrangements • In December 2023, the UARB approved the recovery of ~$164M in Maritime Link costs for 2024.

AI summary In December 2023, the UARB approved the recovery of approximately $164M in Maritime Link costs for 2024.

1 Includes $648M USD, or $856M CAD related to fuel and storm cost under-recoveries at Tampa Electric funded with short term debt.

AI summary The text mentions a financial figure of $648M USD, or $856M CAD, related to fuel and storm cost under-recoveries at Tampa Electric, which was funded with short-term debt.

Regulatory Arrangements • In December 2023, the UARB approved the recovery of ~$164M in Maritime Link costs for 2024.

AI summary In December 2023, the UARB approved the recovery of approximately $164M in Maritime Link costs for 2024.

1 Includes $648M USD, or $856M CAD related to fuel and storm cost under-recoveries at Tampa Electric funded with short term debt.

AI summary The text mentions a financial figure of $648M USD or $856M CAD related to fuel and storm cost under-recoveries at Tampa Electric, funded with short-term debt.

Balanced Rate Case Outcome at Tampa Electric Enables Customer Focused Investment ROE midpoint of 10.5% with range of 9.5% - 11.5% No change to equity thickness of 54% No Stay Out period requirement Operating expenses and capital expenditur...

AI summary The rate case outcome at Tampa Electric sets a return on equity (ROE) midpoint of 10.5%, with no changes to equity thickness or a 'Stay Out' period. Operating expenses and capital expenditures were largely approved, with 72% of a combined 2-year request approved, leading to a total revenue increase of $281M USD.

Regulatory Arrangements In November 2024, the UARB approved the recovery of ~$158M of Maritime Link Costs for 2025, and an additional ~$42M of financing costs in relation to the $500M of additional Federally guaranteed debt

AI summary In November 2024, the UARB approved the recovery of approximately $158M in Maritime Link Costs for 2025 and an additional $42M in financing costs related to $500M of federally guaranteed debt.

Storm Cost Recovery Received approval for recovery of ~ $464M USD in storm costs 18-month recovery period began March 1, 2025

AI summary The document indicates approval for the recovery of approximately $464M USD in storm costs, with an 18-month recovery period beginning on March 1, 2025.

Rate Case $281M USD total revenue increase 3 Increase in ROE midpoint to 10.5% from 10.2% and no change to equity thickness of 54% 99% of operating expenses and capital expenditures approved No stay out period required Storm Cost Recovery...

AI summary The rate case approved a $281M USD revenue increase, raised ROE midpoint to 10.5%, and allowed recovery of $464M USD in storm costs over an 18-month period starting March 1, 2025. 99% of operating expenses and capital expenditures were approved, and no stay out period was required.

Storm Cost Recovery Received approval for a storm rider in 2025 to collect $22M of unrecovered storm restoration costs

AI summary Approval was received in 2025 for a storm rider to collect $22M in unrecovered storm restoration costs.

Fuel and Storm Cost Normalization Adjustments OPERATING CASH FLOW PRE-WC (CAD $M) 2024 2025 2026 2027 TEC – under (over) recovery of fuel costs (196) 12 - - TEC – under (over) recovery of storm costs 507 (342) (221) - NSPI – under (over) r...

AI summary The table presents operating cash flow data related to fuel and storm cost normalization adjustments for TEC and NSPI from 2024 to 2027. It shows fluctuations in under (over) recovery of fuel and storm costs, with significant variations across years and entities.

Fuel and Storm Cost Normalization Adjustments OPERATING CASH FLOW PRE-WC (CAD $M) 2024 2025 2026 2027 TEC – under (over) recovery of fuel costs (196) 12 - - TEC – under (over) recovery of storm costs 507 (342) (221) - NSPI – under (over) r...

AI summary The document presents operating cash flow data related to fuel and storm cost normalization adjustments for the years 2024 to 2027. It details under and over recovery amounts for both TEC and NSPI, with significant variations across the years.

Rate Case $281M USD total revenue increase 3 Increase in ROE midpoint to 10.5% from 10.2% and no change to equity thickness of 54% 99% of operating expenses and capital expenditures approved No stay out period required Storm Cost Recovery...

AI summary The rate case includes a $281M USD revenue increase, a raise in ROE midpoint to 10.5%, approval of 99% of operating expenses and capital expenditures, and approval to recover $464M USD in storm costs over an 18-month period starting March 1, 2025.

Storm Cost Recovery Received approval for a storm rider in 2025 to collect $22M of unrecovered storm restoration costs

AI summary Approval was received in 2025 for a storm rider to collect $22M in unrecovered storm restoration costs.

Storm Cost Recovery Received approval for recovery of ~ $464M USD in storm costs 18-month recovery period began March 1, 2025

AI summary The document outlines the approval for the recovery of approximately $464M USD in storm costs, with an 18-month recovery period beginning on March 1, 2025.

Storm Cost Recovery - Received approval for recovery of ~$464M USD in storm costs - 18-month recovery period began March 1, 2025 1. $185M USD in 2025, $87M USD in 2026 and $9M USD in 2027

AI summary Approval has been granted to recover approximately $464M USD in storm costs over an 18-month period starting March 1, 2025, with amounts of $185M USD in 2025, $87M USD in 2026, and $9M USD in 2027.

quires judgement at times. Therefore, the Board reserves the right to adjust incentive payouts in either direction to satisfy itself that there is close alignment between performance and compensation. For the 2024 Financial portion of the...

AI summary The Board adjusted the 2024 Financial portion of the Emera Corporate Scorecard to neutralize the impact of timing differences in fuel and storm cost recoveries and the strategic asset sale of LIL. These adjustments were made to ensure close alignment between performance and compensation.

10 11 2024 Compliance ($) 2024 Actual ($) 2025 Forecast ($) 2026 GRA ($) 2027 GRA ($) Write-offs 7,020,166 7,065,126 5,679,110 5,792,692 Recoveries (2,637,532) (1,852,485) (1,553,956) (1,585,035) Commissions 457,642 167,325 1,036,855 1,057...

AI summary The document presents financial data for 2024 and forecasts for subsequent years, including write-offs, recoveries, commissions, and net debt. It also outlines the FAM mechanism for returning earnings above approved ranges to customers and references deferred cost recovery mechanisms in GRA Direct Evidence Section 8. Additionally, it notes the absence of material natural gas resale contracts over the last two years.

18.561 19.243 0.682 3.7% Domestic Service Time-of-Day Tariff Customer Charge $/mo 19.17 20.24 1.07 5.6% Energy Charges (December to February) Peak Period Base cost of fuel ¢/kWh 8.236 8.959 0.723 8.8% Non-fuel ¢/kWh 14.329 15.647 1.318 9.2...

AI summary The document outlines changes in domestic service time-of-day tariff rates, including customer charges, energy charges, and adjustments like Fuel Adjustment Mechanism (FAM), Demand Side Management (DSM), and System Cost Recovery Rider (SCRR). Key figures show increases in non-fuel costs and significant reductions in FAM AA, impacting overall energy rates by up to 100% in some categories.

IA POWER INC. 2027 REACTIVE SUPPLY AND VOLTAGE CONTROL RATE DESIGN (1) (2) (3) (4) (5) (6) (7) (8) (9) Revenue Billing On-Peak Off-Peak On-Peak Off-Peak Requirement Determinants Yearly Monthly Weekly Daily Daily Hourly Hourly ($000/yr) (MW...

AI summary The document presents a revenue requirement analysis for Reactive Supply and Voltage Control in 2027, including Point-to-Point and Network Services costs. It also mentions the absence of a 2027 FCR Deferral, indicating no deferred costs related to fuel cost recovery.

- 1. To maintain its current return on common equity of 9.0%, with an earnings band of 8.75% to 9.25%. The common equity ratio would also remain at 40%. - 2. The BCF amounts attributable to FAM customers be set at $927.3 million for 2026 a...

AI summary Nova Scotia Power Inc. (NSP) proposes maintaining a 9.0% return on common equity, setting BCF amounts for 2026-2027, administrative amendments, deferring study costs, a securitization approach to save $90M, potential interest expense deferrals, a Port Hawkesbury Paper deferral, and an updated depreciation study excluding certain assets.

2026-2027 General Rate Application (M12451) NSPI Responses to Bates White Information Requests 1 Request IR-12: 7 on hand for each type of solid fuel at each location, there is a lag between when the purchase 8 occurs and when the fuel exp...

AI summary NSPI explains the methodology for recognizing fuel expenses, noting a lag between purchase and recognition. Fuel procurement is based on annual consumption requirements, and transportation costs are included in the weighted average cost. Natural gas consumption forecasts are provided, sourced from Market Gas and the TransCanada Pipeline.

REDACTED 1 (f) The costs of Goose Harbour Lake Wind including ITC offset are expected to be similar to 2 Green Choice. NS Power has not isolated the impact on fuel costs of the Province's clean 3 energy transition as they directly relate t...

AI summary The text discusses the expected cost similarities between Goose Harbour Lake Wind and Green Choice, noting that NS Power has not isolated the impact of the clean energy transition on fuel costs. It also mentions the decrease in fixed cost recovery and ongoing Active Demand Control service by PHP, referencing GRA BW IR-18.

CONFIDENTIAL (Attachment Only) 1 Request IR-19: 2 3 2026-2027 GRA Appendix 1-6 PCON, Appendix 6B (Redline). 4 5 (a) Please explain the edit to move the BUTU reference at pages 7-8. 6 7 (b) Please explain the revisions to item 4 on pages 8-...

AI summary The document contains a request and response related to the 2026-2027 General Rate Application (GRA) by Nova Scotia Power Inc. (NSPI). It addresses edits to the BUTU rate class, revisions to item 4, and the inclusion of specific costs in the POA. The response references a 2023 application (M11127) and a Board decision on the Amended BUTU Tariff.

[[email protected]](mailto:[email protected]) Keith Bourne Regulatory Specialist Nova Scotia Power Inc. PO Box 910 Halifax, NS B3J 2W5 Dear Mr. Bourne: M11127 – Nova Scotia Power Inc. (NSPI) – Plan of Administration Update –...

AI summary Nova Scotia Power Inc. (NSPI) submitted a revision to its Fuel Adjustment Mechanism (FAM) Plan of Administration (POA) to include four new costs. The Board, Consumer Advocate, Small Business Advocate, and Industrial Group opposed the inclusion of these costs, arguing that shifting operating costs to fuel costs would allow NSPI to recover expenses through the FAM rather than reducing expenses and improving efficiency.

REDACTED 1 (b) Please provide revised cost-of-service models (2026-2027 GRA SR-01 Att 02 and 2 2026-2027 GRA SR-01 Att 03) and other related attachments using the PHP 3 Interruptible system coincident demand of 57,000 kW to calculate the P...

AI summary The document requests revised cost-of-service models and updated proposed rates for 2026 and 2027, along with explanations for Power Factor Adjustments. The response outlines the calculation method for PHP interruptible credit using power factors of 1.06 and 1.02 for 2026 and 2027, respectively, and multiplies annual kVA demand by proposed Large Industrial Credits.

Our Base-Case Scenario Assumptions Key Metrics • Stable economic conditions in the service territory, with a modest increase in the customer base • Continued use of regulatory cost recovery mechanisms. The utility will not experience any a...

AI summary The base-case scenario assumes stable economic conditions, continued use of regulatory cost recovery mechanisms, and stable capital structure for NSPI. Key metrics include FFO/total debt and debt/debt and equity ratios over several years.

Our Base-Case Scenario Assumptions Key Metrics • No material persistent impact from the COVID-19 pandemic; • Stable regulatory regime in Nova Scotia with no material adverse regulatory decisions; 2019a 2020e 2021f FFO to debt (%) 13.4 13-1...

AI summary The base-case scenario assumes no material impact from the pandemic, stable regulation in Nova Scotia, and a 1.5% annual base rate increase from 2020 to 2022. Capital spending and dividend payments are estimated at around C$350 million and C$175 million annually, with commodity costs passed through to customers.

Credit Highlights Overview Key strengths Key risks Low-risk, vertically integrated regulated electric utility with no exposure to nonutility operations. High reliance on riskier coal-based generation. Generally credit-supportive regulatory...

AI summary Nova Scotia Power (NSPI) is a low-risk, vertically integrated utility with a credit-supportive regulatory framework, but faces challenges due to reliance on coal-based generation and financial metrics at the lower end of the risk profile. The fuel stability plan covers only the fuel component, with base rates increasing by 1.5% annually through 2022, and regulatory lag may occur if variances arise. NSPI is expected to file for new base rates for the nonfuel component by 2023, which could alleviate financial pressure.

Credit Highlights The provincial government of Nova Scotia recently proposed to compensate Nova Scotia Power Inc. (NSPI) about $117 million to offset the deferred fuel cost liability. NSPI generally recovers the incurred fuel cost from cus...

AI summary The provincial government of Nova Scotia proposed compensating Nova Scotia Power Inc. (NSPI) with $117 million to offset deferred fuel cost liability. This compensation will be recovered from customers over 10 years, reducing immediate pressure on customer bills. However, NSPI is expected to recover the remaining $278 million through future rate adjustments, which could increase customer bills.

FAM Regulatory Liability – Balance as at January 1, 2017 (CAD million) (94) Net over-recovery of current period fuel costs (66) Impact of the Maritime Link interim assessment decision (12) Application of non-fuel revenues (13) Interest on...

AI summary This chunk presents the balance of the Fuel Adjustment Mechanism (FAM) regulatory liability as of January 1, 2017, and September 30, 2017. It includes components such as net over-recovery of fuel costs, the impact of the Maritime Link interim assessment decision, application of non-fuel revenues, interest on the FAM balance, and a one-time refund to customers for 2016 fuel costs.

- In December 2016, the NSUARB approved NSPI's application to refund over-recovered fuel costs from 2016 to customers; as a result, a one-time refund of $36 million was issued, as recorded above in the FAM regulatory liability. - In Septem...

AI summary In 2016, the NSUARB approved a refund of over-recovered fuel costs to customers, totaling $36 million. In 2017, the NSUARB approved interim assessment payments for the Maritime Link Project, with adjustments due to delays from the Muskrat Falls Project. These costs are being recovered through fuel rates, with credits provided to customers in subsequent years.

Regulatory Environment Assessment Criteria 1. Deemed Equity Ratio Score Excellent Good Satisfactory Below Average Poor Analysis NSPI's target regulated ROE is based on an actual five-quarter average regulated common equity component of up...

AI summary The document evaluates NSPI's regulatory environment, noting its target regulated ROE based on a 37.5% common equity ratio. Capital costs over $250,000 are pre-approved by the regulator, with AFUDC recovery during construction. NSPI operates under a COS model, allowing recovery of operating expenses and return on approved capital investments.

mix when the Muskrat Falls project starts producing full power (expected in early 2020). NSPI expects to recover prudently incurred costs associated with the program through the regulatory framework. NSPI's business risk assessment (BRA) o...

AI summary NSPI expects to recover costs through the regulatory framework, citing a low business risk assessment. Fuel costs are subject to audit by NSUARB, and NSPI's high electricity rates may hinder timely cost recovery. NSPI plans to maintain its debt-to-capital ratio within regulatory limits through flexible dividend policies.

1. Low-risk regulated electricity business The current regulatory framework is based on a cost-of-service (COS) methodology, in which the Company is allowed to recover all prudently estimated operating expenses and to earn a reasonable ret...

AI summary The current regulatory framework for NSPI uses a cost-of-service methodology, allowing recovery of operating expenses and a reasonable return on capital investments. NSPI's target ROE range is considered reasonable. A fuel adjustment mechanism is in place to manage fuel price fluctuations, with differences deferred and collected or refunded to customers.

- In September 2017, the NSUARB approved an interim assessment payment to NSPML of the costs associated with the Maritime Link Project which entered into service on January 15, 2018. The NSUARB approved annual payments of $110 million in 2...

AI summary In September 2017, the NSUARB approved interim assessment payments to NSPML for the Maritime Link Project. Annual payments of $110 million and $111 million were approved for 2018 and 2019, with $71 million paid by September 30, 2018. Due to deferred costs related to depreciation, NSPI provided customer credits of $17 million, $36 million, and $53 million in 2018, 2019, and 2020, respectively.

Regulation (CONTINUED) - NSPI is required to withhold $10 million from the interim assessment payment each year. The release is subject to providing evidence to the NSUARB that, at least, the amount of benefit from the Maritime Link Projec...

AI summary NSPI must withhold $10 million annually from interim payments until benefits from the Maritime Link Project are realized. The Province amended the Environment Act to establish a cap-and-trade program for carbon emissions starting in 2019. NSPI expects to recover prudently incurred carbon reduction costs from customers. DBRS evaluates the regulatory environment for NSPI based on eight factors.

Summary - The Company operates under a COS model wherein NSPI can recover all prudently incurred costs from providing electricity and earnings are primarily affected by the NSUARB-approved range of ROE and capital structure. - Fuel cost in...

AI summary The Company operates under a COS model where NSPI recovers prudently incurred costs and earns based on NSUARB-approved ROE. Fuel costs increased in 2018 due to commodity prices and payments to NSPML. Net income remained stable as NSPI earned its maximum ROE. Operating costs in 9M 2019 rose due to Hurricane Dorian, but were offset by non-fuel revenues. Earnings above the ROE band are applied to the FAM.

Assessment of Regulatory Framework Criteria Score Analysis 4. Capital and Operating Cost Recovery Excellent Good Satisfactory Below Average Poor Capital costs over $1,000,000 are generally pre-approved by the regulator, but there is some m...

AI summary The document assesses the regulatory framework for NSPI, noting that capital costs above $1,000,000 are pre-approved by the regulator, with AFUDC included in recovery. NSPI operates under a COS model, allowing recovery of operating expenses and return on capital investments. The 2013 Electricity Reform Act and Electricity Plan Act have had a modest impact on NSPI.

(2) Regulatory lag NSPI faces some regulatory risk with respect to the timeliness of full cost recovery, although this risk is lower now than when the FAM was not in place. Although the FAM allows the Company to recover fluctuating fuel ex...

AI summary NSPI faces regulatory risk related to the timeliness of full cost recovery, though this risk has decreased since the FAM was implemented. The FAM allows recovery of fluctuating fuel costs, but adjustments are annual and subject to NSUARB approval. The 2020–22 FSP outlines that discrepancies between actual fuel costs and recovered amounts should be resolved after 2022. DBRS Morningstar anticipates reduced fuel price volatility once the Muskrat Falls project begins contributing renewable energy.

Page 9 of 14 Assessment of Regulatory Framework 7. Stranded Cost Recovery Excellent Good Satisfactory Below Average Poor The NSUARB disallowed the recovery of some, but not a material amount of, fuel-related costs. 8. Rate Freeze Excellent...

AI summary The document discusses the assessment of the regulatory framework, noting that stranded cost recovery is rated as excellent, good, or satisfactory. It also highlights that residential electricity rates in Nova Scotia are higher than the Canadian average, which may affect cost recovery for NSPI. Financial data, including assets, liabilities, and equity, is presented for various years.

1. Low-risk regulated electricity business The Company's current regulatory framework is based on a cost-of-service (COS) methodology, under which NSPI can recover all prudently estimated operating expenses and earn a reasonable return on...

AI summary NSPI operates under a cost-of-service regulatory framework that allows recovery of operating expenses and a reasonable return on capital. DBRS Morningstar finds the ROE range reasonable but notes that recent provincial intervention in the GRA process has increased regulatory risk and instability for the company.

2022 Summary/Outlook - EBIT decreased for LTM 2022 because of higher depreciation. - Net income before nonrecurring items increased though because of higher other income. 2 Adjusted for accumulated other comprehensive income. - DBRS Mornin...

AI summary In 2022, EBIT decreased due to higher depreciation, though net income before nonrecurring items increased due to higher other income. DBRS Morningstar expects NSPI's earnings to be pressured in 2023 and 2024, with base rates limited to a 1.8% increase, but additional DSM and fuel rate increases allowed. NSPI must find operational efficiencies and reduce capex to achieve its allowed ROE.

Good Satisfactory Below Average Poor Criteria Score Analysis 1. Deemed Equity Excellent Good Satisfactory Below Average Poor NSPI's target-regulated ROE is based on an actual five-quarter average-regulated common equity component of up to...

AI summary The document evaluates NSPI's regulatory framework, focusing on deemed equity, allowed ROE, energy cost recovery, capital and operating cost recovery, COS versus incentive rate mechanism, political interference, and stranded cost recovery. Key points include ROE caps under Bill 212, fuel cost recovery through FAM and FSP, and regulatory impacts from political interference.

2026-2027 General Rate Application (M12451) NSPI Responses to GT Information Requests 1 Request IR-14: 18 driving an increase in the utilization of Talent Management services from Emera and cost 19 allocation to NS Power. 1 Request IR-17:...

AI summary The document outlines NSPI's responses to information requests regarding the 2026-2027 General Rate Application. It discusses a team formed in 2024 to identify cost savings, which incurred $0.3 million in consulting expenses. These costs are not expected to continue as ongoing expenses are assumed to be offset by savings.

NON-CONFIDENTIAL 1 Request IR-25: 3 As it relates to the decommissioning costs of the Wreck Cove, Mersey, and Tusket 4 hydroelectric assets, please provide a schedule reconciling all amounts that have been 5 historically recovered in custo...

AI summary The document outlines a request for a schedule reconciling decommissioning costs recovered in customer rates for the Wreck Cove, Mersey, and Tusket hydroelectric assets. NS Power has recovered some amounts for Wreck Cove and Tusket but none for Mersey. They also state they would consider securitization for future decommissioning costs if required.

- 2 be collected through a rider. The revenue requirement of the rider will depend primarily on the - 3 interest rate, repayment term, and repayment structure of securitized debt. - 4 This net savings could be as much as approximately $90...

AI summary The text discusses a potential revenue requirement reduction of up to $90 million over a two-year period through securitization of thermal assets, assuming interest-only repayments at a 4% interest rate. This would reduce the revenue requirement from $140 million to $50 million under the current setup.

- 11 financing cost to the benefit of customers. 1 Request IR-40: 2 3 Considering NS Power's proposal to securitize the costs of assets that were previously 4 proposed to be added to the DDA, please fully explain the continued purpose of t...

AI summary NS Power explains that securitization of DDA assets will reduce the DDA balance but that sustaining capital investments and decommissioning costs will still need to be recovered. NS Power also notes that the Cost of Removal regulatory account has been tracked since 2016, though full reconciliation by project is limited due to a cyber incident.

Appendix "A" GRA Element Settlement Terms Storm Cost Recovery Rider a) The Storm Cost Recovery Rider will be implemented as described in the Draft GRA, subject to the following: (a) the Storm Cost Recovery Rider will not be implemented on...

AI summary The Storm Cost Recovery Rider is to be implemented on a pilot basis for 2026 and 2027, with costs eligible for the rider, rather than as a permanent measure as initially proposed.

PCR = Program Cost Recovery The PCR includes all estimated costs for the upcoming calendar year for the DSM Plan that has been requested by the Franchise Holder and approved by the NSUAREB (Approved DSM). It includes the cost of planning,...

AI summary The Program Cost Recovery (PCR) encompasses all estimated costs for the upcoming year for the Approved DSM Plan, including planning, development, implementation, and administrative expenses. It is calculated using the cost allocation methodology outlined in Schedule B of the tariff.

2025 DSM Cost Recovery Rider Charges Effective: January 1, 20265January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Ja...

AI summary The document outlines the 2025 Demand Side Management (DSM) Cost Recovery Rider (DCRR) charges, including Program Cost Recovery (PCR) and Balance Adjustment (BA), effective from January 1, 2025, to December 31, 2025. It also explains how the Balance Adjustment for 2023 will be calculated and applied over the 2027-2031 term.

Allocation of DSM Program Costs System benefits are allocated to all applicable customer classes in accordance with the Cost of Service Study (COSS) methodology reflecting allocation of generation rate base as per the most recent rate case...

AI summary System benefits from DSM programs are allocated to all customer classes based on the Cost of Service Study methodology. Remaining costs are assigned to participating classes in proportion to their investment in the programs.

Regulated Statements of Income For the Three months ended Year ended millions of Canadian dollars December 31 December 31 Actual Test Year Prior Year Actual Test Year Prior Year 2024 2024 2023 2024 2024 2023 Operating revenues $ 478 $ 468...

AI summary The document presents Regulated Statements of Income for a utility company, comparing actual and test year figures for operating revenues, expenses, and net income across three months and year-ended periods in 2023 and 2024. Key items include fuel adjustment mechanisms, demand side management cost recovery riders, and income before income taxes.

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

AI summary The text discusses regulatory assets and liabilities, explaining that regulatory assets are deferred costs expected to be recovered through future rates, while regulatory liabilities are obligations to refund customers or reduce future revenues. Management's judgment on the probability of recovery or settlement determines their recognition in income.

Storm Rider: NSPI has a UARB approved a storm rider for each of 2023, 2024 and 2025, which gives NSPI the ability to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given ye...

AI summary NSPI has a UARB-approved storm rider allowing recovery of major storm restoration costs exceeding $10 million annually. In 2024, the UARB approved the recovery of $24 million deferred in 2023, to be recovered over 12 months starting January 1, 2025.

FAM: On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, whic...

AI summary The UARB approved the sale of the FAM regulatory asset to Invest Nova Scotia, resulting in a decrease in the asset and the collection of amortization and financing costs from customers over 10 years. An audit of NSPI's fuel costs found a disallowance of $3 million for fiscal 2020 and 2021, which was returned to customers through the FAM. The audit for fiscal 2022 and 2023 was released, and a regulatory hearing is scheduled for March 2025.

NSPI has a contractual obligation to pay NSPML, a related party, for the use of the Maritime Link over approximately 38 years from its January 15, 2018, in-service date. On November 29, 2024, NSPML received UARB approval to collect up to $...

AI summary NSPI is obligated to pay NSPML for the use of the Maritime Link over 38 years. NSPML received approval to collect up to $197 million from NSPI in 2025, including $158 million from the annual cost assessment and $39 million for repaying the federal loan guarantee.

Regulatory and Political Risk NSPI is subject to complex legislative and regulatory frameworks that impact matters such as industry, business, rates and cost structures, revenue requirements, allowable ROE, capital structure, rate base and...

AI summary NSPI operates under a complex regulatory framework that affects its rates, costs, and operations. Regulatory approval is required for rate changes, and delays or disallowances could cause financial harm. Changes in government or policy could also impact regulatory stability and outcomes, potentially leading to a Material Adverse Effect.

General Economic Risk The Company has exposure to the macro-economic conditions in Nova Scotia. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity, and in turn the Company's...

AI summary The Company faces economic risks due to macroeconomic conditions in Nova Scotia, which can affect customer affordability of rate increases and impact financial results, credit risk, and regulatory cost recovery.

Environmental Legislation and Climate Change NSPI is subject to environmental laws and regulations as set by both the Government of Canada and the Province of Nova Scotia (the "Province"). NSPI continues to work with both levels of governm...

AI summary NSPI must comply with environmental laws from Canada and Nova Scotia, which may increase costs and pose operational risks. NSPI expects to recover these costs through its regulatory framework and continues to collaborate with government to manage emissions and minimize customer impact.

Storm Rider: On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and incremental financing costs deferred to NSPI's storm rider in 2023 to be recovered over a 12-month period beginning on January 1...

AI summary The UARB approved the recovery of $24 million in major storm restoration and incremental financing costs deferred to NSPI's storm rider in 2023, to be recovered over a 12-month period starting January 1, 2025.

FAM and FAM Regulatory Deferral NSPI has a UARB approved FAM, allowing NSPI to recover fluctuating fuel and certain fuel-related costs from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs a...

AI summary NSPI has a UARB-approved FAM allowing recovery of fuel costs from customers. Recent developments include the sale of a portion of the FAM regulatory asset to Invest Nova Scotia, the refund of $4 million to customers following audit findings, and an ongoing regulatory process related to audit results for fiscal 2022 and 2023.

Working Capital As at December 31, 2024, NSPI's working capital decreased to $468 million from $553 million in 2023 primarily due to changes in inventory, changes in cash collateral positions on derivative instruments, and changes in accou...

AI summary NSPI's working capital decreased from $553 million in 2023 to $468 million as of December 31, 2024, mainly due to changes in inventory, cash collateral positions, and accounts payable, partially offset by changes in accounts receivable. The company expects to meet future liquidity and capital needs through internal cash flows, short-term credit facilities, and long-term financing.

Regulatory and Political Risk NSPI is subject to complex legislative and regulatory frameworks that cover material aspects of their businesses. These frameworks influence key factors such as rates and cost structures, revenue requirements,...

AI summary NSPI operates under a complex regulatory framework that impacts rates, cost recovery, and capital investments. Regulatory approvals are required for significant business changes, and delays or disallowances could lead to Material Adverse Effects. Changes in government or policy could also impact regulatory stability and outcomes.

Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. NSPI may enter foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases and capita...

AI summary NSPI is exposed to foreign exchange risk, particularly from USD-denominated fuel purchases. To mitigate this, NSPI uses forward contracts to lock in CAD costs for USD. The regulatory framework allows recovery of prudently incurred foreign exchange costs. As of December 31, 2024, NSPI had forward contracts covering 51% of 2025 USD requirements and 18% of anticipated USD needs in 2025.

Interest Rate Risk: NSPI utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. The allowed range of ROE will generally follow the direction...

AI summary NSPI uses a mix of fixed and floating rate debt, exposing it to interest rate risk. The allowed ROE range follows interest rate trends with a lag. 95% of NSPI's debt is fixed rate as of December 31, 2024, with an average term of 17 years. Debt costs are recovered from customers.

Commodity Price Risk The Company's fuel supply is subject to commodity price risk. The Company's fuel supply is exposed to broader global market conditions, which may include impacts on delivery reliability and price, despite contracted te...

AI summary The Company's fuel supply is exposed to commodity price risk due to global market conditions, which can affect delivery reliability and price. Prolonged fuel price increases may impact rate affordability and customer consumption. NSPI aims to hedge 75-100% of fuel costs in 2025 and 50-90% in 2026, adjusting as needed to maintain cost stability.

System Operating and Maintenance Risks The safe and reliable operation of electric generation transmission and distribution systems is critical to NSPI's operations. There are a variety of hazards and operational risks inherent in operatin...

AI summary The document outlines the various operational and maintenance risks faced by NSPI in managing its electric generation, transmission, and distribution systems. These risks include mechanical failures, natural disasters, cyberattacks, and supply chain disruptions, which could negatively impact customer confidence, public safety, and result in Material Adverse Effects. The regulatory framework allows for the recovery of prudently incurred costs.

9 SAIDI 2019 2020 2021 2022 2023 2024 2 3 Reference: Exhibit N-3 GRA Direct Evidence, Section 1.2 Overview of 2026-2027 GRA 4 5 On page 10 of the application, NS Power proposed that as of January 1, 2027, compounded 6 rate increases for re...

AI summary NS Power proposed a 8.06% compounded rate increase for residential customers over one year, from January 1, 2026, to January 1, 2027. The response clarifies that the increase is split into two separate years (2026 and 2027) with average increases of 1.8% and 2.4%, respectively, and highlights efforts to reduce costs and mitigate rate impacts for customers.

13 Figure 2: Contribution to CHI by Outage Cause 2019-2023 (Including all Storms) 14 \ These cause codes have been adjusted from the original Electricity Canada methodology as discussed above to illustrate the 15 additional contribution fr...

AI summary Figure 2 illustrates the contribution to customer hours of interruption (CHI) by outage cause from 2019 to 2023, including all storms. The cause codes have been adjusted from the original Electricity Canada methodology to account for additional contributions from tree contacts within adverse weather. The plan aims to align with this analysis and allocate investment to address the impacts of tree contacts and adverse weather on the power system.

4.0 STORM HARDENING – VEGETATION MANAGEMENT 2025-2029 Forecast Investment: $265.0 million Estimated Performance Standards SAIDI Reduction: 0.70 to 1.25 hours 6 The Storm Hardening - Vegetation Management Program is designed to proactively...

AI summary The Storm Hardening - Vegetation Management Program aims to reduce tree contact with power lines, which is the primary cause of outages. The program involves widening distribution and transmission corridors, establishing new rights-of-way, and trimming/removing trees near power lines to improve system reliability and reduce power interruptions.

Section 4 of the Community Solar Program Regulations provides "A subscriber must not be charged any additional fees by NSPI or a project owner to participate in the community solar program," and Section 5 provides "A subscriber is billed b...

AI summary The document discusses the proposed revision to Section 3.2.8 of the POA, focusing on how costs related to renewable energy programs, such as the Community Solar Program, are handled when they cannot be recovered from participants. The revision aims to capture these costs through the FAM mechanism.

Please see the table below: 2022 2023 2024 Operating Costs ($ million) 279.8 325.71 328.5 Increase ($ million) 45.9 2.8 Percent Change 16.4% 0.9% Forecast Operating Costs ($ million) 283.6 288.8 297.4 Percentage Variance to Forecast -1.3%...

AI summary The text presents a table showing operating costs for 2022, 2023, and 2024, including increases and percentage changes. It also mentions the recovery of approximately $21.8 million through the 2025 Storm Cost Recovery Rider (SCRR).

REDACTED 1 Request IR-51: 7 initiatives or processes to increase efficiencies and reduce costs for customers. 8 9 Response IR-54: 10 11 In addition to the numerous initiatives identified in s. 1.5.7, which will continue throughout the 12 2...

AI summary The response outlines various initiatives and processes aimed at increasing efficiencies and reducing costs for customers, including the GRA process, cost-saving efforts, and collaborations with stakeholders to achieve savings through measures like the purchase of receivables and adjustments to sulphur emission regulations.

NON-CONFIDENTIAL 1 Request IR-62: 25 (c) Talent Management is handled by NS Power's Parent company Emera and costs are 26 allocated to NS Power in accordance with the Board-approved Affiliate Code of Conduct 27 and Cost Allocation Manual....

AI summary The text discusses NS Power's approach to Talent Management, which is centralized under its parent company Emera, with costs allocated to NS Power following the Board-approved Affiliate Code of Conduct and Cost Allocation Manual. Increased staffing levels at NS Power have led to higher utilization of these services. The text also notes challenges in comparing NS Power to other utilities due to structural and operational differences.

(b) Please confirm, or explain otherwise, that the proposed reserve imbalance to be recovered over five years is $26,114,146, as shown below: 391.10 Furniture and Equipment (919,412) 391.31 Computer Equipment - Hardware 416,440 391.32 Comp...

AI summary The document requests confirmation of a proposed reserve imbalance amount of $26,114,146 to be recovered over five years and asks about the benefits to ratepayers from using amortization accounting compared to annual incremental depreciation expenses.

CONFIDENTIAL (Attachment Only) relatively disproportionate output. Perhaps most importantly, the role they play within Nova Scotia's social, economic, environmental, and political framework is what truly makes them unique and why any decis...

AI summary NS Power argues that decommissioning costs for certain assets should not be included in customer rates at this time, as there is insufficient clarity on the likelihood and extent of decommissioning. They propose a measured approach to mitigate rate pressure while initiating a broader discussion involving all stakeholders.

2026-2027 GRA NSEB IR-85 Confidential Attachment 1 has been removed due to confidentiality. 1 Request IR-86: 2 3 Reference: Exhibit N-7, Appendix 8E 4 5 NS Power notes it has excluded the costs of decommissioning the Wreck Cove, Mersey and...

AI summary The document outlines a request (IR-86) related to the decommissioning costs of hydroelectric assets (Wreck Cove, Mersey, and Tusket) and how their exclusion from depreciation rates impacts cost recovery and rate pressure for customers. The request also asks for justification regarding the assumption that these assets will be operated in perpetuity and never decommissioned, and whether NS Power believes these facilities will never need decommissioning.

Request IR-95: On page 93 of the Board Decision [2022 NSUARB 18] in M10206 (NSPML) dated February 9, 2022, the Board advised that it would not permit recovery by NS Power of operating costs of Lingan 2 beyond August 15, 2022, without furth...

AI summary The document discusses the recovery of operating costs for Lingan Unit 2 by NS Power, referencing past Board decisions and current applications. The Board previously limited recovery of these costs beyond August 2022, but later allowed recovery until 2024. NS Power now seeks approval for operating costs in 2025, 2026, and 2027, citing the unit's role in supporting capacity during the GRA period.

16 17 Capital Project Depreciation Incurred at Net book value at 23 (c) The Benchmarking Analysis Report in OP-03 Attachment 1 did not include a comparison 24 of working capital requirement. 1 Request IR-99: 2 3 Reference: Exhibit N-17, SR...

AI summary The text discusses Nova Scotia Power's need to make tax installments in 2026 related to preferred share dividends and the delay in receiving cash from an Investment Tax Credit (ITC) until 2027. This delay necessitates an increase in working capital to finance the earnings without the corresponding cash receipt.

Page 12 of 13 Assessment of Regulatory Framework Page 12 of 13 Criteria Score Analysis Page 12 of 13 1. Deemed Equity Page 12 of 13 Page 12 of 13 Excellent Good Satisfactory Below Average Poor NSPI's target-regulated ROE is based on an act...

AI summary The document assesses the regulatory framework for NSPI, focusing on deemed equity, allowed ROE, energy cost recovery, capital and operating cost recovery, COS versus incentive rate mechanisms, political interference, stranded cost recovery, and rate freezes. Bill 212 is highlighted as a key legislative change impacting NSPI's regulatory environment and cost recovery mechanisms.

January 28, 2025 What's new: Nova Scotia Power Inc. (NSPI) recently received a Canadian federal loan guarantee to securitize C$500 million of current and future fuel balances at NSPI; the company used proceeds toward reducing debt at NSPI....

AI summary Nova Scotia Power Inc. (NSPI) received a Canadian federal loan guarantee to securitize C$500 million in fuel balances, reducing debt and regulatory lag. This, along with provincial support, will improve NSPI's credit measures and reduce rate impacts on customers. S&P Global Ratings revised Emera and its subsidiaries' outlook to stable from negative due to these developments.

1 Request IR-127: 2 - 3 Please provide a table, similar to the table in Exhibit N-9, Appendix 12A(3), on p. 242 of 310, - 4 comparing allocated costs under the existing and proposed cost of service methodologies. 5 6 Response IR-127: 7

AI summary The request asks for a table comparing allocated costs under existing and proposed cost of service methodologies, similar to one in Exhibit N-9. A response is indicated but not provided in the text.

1 2027 COSS Change on Total Allocated Costs in $ Million Revenue to Expense Ratio 10 thoroughly considered in this jurisdiction when NS Power completes its next cost-of-service 11 study, which is expected no later than December 31, 2025" [...

AI summary The text discusses a request related to the 2027 Cost of Service Study (COSS) by Nova Scotia Power (NSP), including a query about the impact of reclassifying distribution classifications from the minimum system methodology to 100% demand classification, and a request for a revised Figure 14-1. Nova Scotia Power has not completed the computation for this alternative scenario and refers to Attachment 1 for further details.

NON-CONFIDENTIAL 1 Request IR-133: 2 3 Reference: Exhibit N-3 GRA Direct Evidence, Section 13 Rate Design 4 - 5 On page 81 of the application, NS Power notes its proposed increases in the customer charges - 6 for domestic and small general...

AI summary The request asks NS Power to provide a table comparing proposed customer charges and energy rates with those based on the 2026-2027 COSS, noting that proposed increases have been capped relative to direct cost changes.

5 customer-related costs from the COSS, any costs that are not recovered through the customer

AI summary The text references customer-related costs from the Cost of Service Study (COSS) and mentions costs not recovered through the customer, indicating a discussion on cost recovery mechanisms.

1 Request IR-137: 2 3 Reference: OATT Updates SR-01 Attachment 1e 4 5 On page 32 of 42, NS Power stated: 6 7 However, as part of developing this consensus GRA, it was agreed that 8 for the 2026-2027 test periods the costing approach will u...

AI summary The document discusses a costing amendment related to interruptible loads under the Large Industrial Rate class, specifically the use of 50% of estimated average hourly demand for 10-minute operating reserve. This decision was made through consensus discussions and references a prior Board decision (M10431).

Request IR-138: Reference: OATT Updates SR-01 Attachment 1e On page 42 of 42, NS Power stated: … NS Power conducted an analysis of historical day-ahead dispatch plans for the years 2021 to 2023. On average, the Combustion Turbines (CTs) we...

AI summary NS Power adjusted the cost allocation for 30-Minute Supplemental Reserve in the GRA application based on historical data showing Combustion Turbines (CTs) fulfilled 35% of the requirement. A question was raised regarding the dollar impact of this adjustment.

(a) Please refer to the following figure; only OATT Schedules 5 and 6 are impacted by this change. OATT Revenue (as proposed in 2026-2027 GRA) OATT Revenue (fully cost based) Dollar Impact 2026 2027 2026 2027 2026 2027 Schedule 5 and 6 Ope...

AI summary The text discusses changes in demand charges for various tariff classes in 2026, attributing the decreases to a shift in responsibility for non-fuel costs, particularly due to the Domestic class taking on a larger share of these costs compared to 2023. This is linked to the updated cost of service study and the inclusion of PHP as an above.

(b) Any storm underspend could be returned to customers effective January 1 of the following year; however, if the SCRR was structured in that manner it could result in an SCRR application every year, regardless of its materiality. Structu...

AI summary The text discusses the structure of the Storm Cost Recovery Rider (SCRR), noting that returning underspend to customers annually could lead to frequent SCRR applications, regardless of their significance. Instead, the proposed structure allows NS Power to make SCRR applications only after three consecutive years or when the underspend reaches $2.5 million, ensuring applications are made only when there is a material amount to recover.

Proposed DCRR Framework If approved, the proposed DCRR framework would be in effect during the 2027-2031 DSM Term. For example, the 2028 DCRR would include: (b) The proposed DCRR framework adds a BA 2 component to the BA to reconcile, by r...

AI summary The proposed DCRR framework would be effective during the 2027-2031 DSM Term. It introduces a BA2 component to balance differences between approved and actual DSM expenditures by rate class. This aims to reduce rate volatility by spreading variances over a four-year recovery period, starting in year two of the following Term.

M12273 – NS Power, Cybersecurity Incident Monthly Update 2, page 3. October 1, 2025. 1 associated expenditures in its revenue requirement. As provided in part (c), NS Power's training, etc.) that are not directly required by opt-out custom...

AI summary NS Power explains that the AMI project provides system-wide benefits, including outage detection and reliability, which all customers, including those who opted out, benefit from. The company proposes an AMI opt-out fee to cover the incremental costs of non-standard meter service for those who opt out.

NON-CONFIDENTIAL 1 o Travel time estimates based on the actual location of opt-out customers and 2 organized by meter route; 3 o Forecast workload volumes based on the actual numbers of opt-out 4 customers to date and bi-annual read rates;...

AI summary The document compares actual 2024 costs and projected 2026 costs for opt-out meter service, highlighting a 'doubling effect' in cost-per-read that is explained by fixed and variable cost components not scaling linearly. Per-customer costs remain stable, indicating no actual doubling occurs.

CONFIDENTIAL (Attachments Only) 1 Request IR-2: 2 3 Refer to GRA Appendix 12A, Cost of Service Study Process, section 5.1. 4 5 (a) Describe and provide all sensitivity analysis and modelling the Company has 6 conducted to conclude that "in...

AI summary The document outlines a request for detailed sensitivity analysis and modeling related to the cost of service study (COSS) conducted by the Company. It also asks for explanations of how increased granularity may affect COSS and requests examples of inconsistencies that could arise. Additionally, the request seeks information on how generation assets are classified under the proposed SLF approach and the current classification method.

CONFIDENTIAL (Attachment Only) 1 Request IR-4: 2 3 Refer to GRA Appendix 12A, Cost of Service Study Process, section 5.3. 4 5 6 (a) Provide the Board's Decision on the Cost of Service proceeding in 1995 (NSPI864). 7 (b) Explain why reduced...

AI summary The text outlines several requests related to the Cost of Service Study and transmission system design by NSPI. It asks for the Board's 1995 decision, explains the relevance of coal generation reduction to transmission classification, and seeks clarification on transmission cost definitions, wind generation's impact on system design, and the factors driving system costs with increased renewable energy.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 4 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 4 - following four primary areas relating to Cost of Service Methodology to be addressed during the generic hearing: - 1. Methods of attribu...

AI summary The document outlines four primary areas of Cost of Service Methodology to be addressed during a generic hearing, including cost attribution, cost-relating methods, seasonal cost allocation, and customer class cost allocation. The Company proposed using the Equivalent Peaker method, unbundling transmission costs, modifying the Cost of Service Study presentation, and allocating fuel costs monthly.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 7 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 7 - Mr. Brockman testified that the Equivalent Peaker Method of classification for generation plant is a more fair and rational approach. Re...

AI summary The testimony discusses the classification of generation and transmission costs, with differing opinions on the Equivalent Peaker Method and the Average and Excess method. Concerns are raised about NSPI's proposed reclassification of costs to energy, arguing it may be unreasonable and inconsistent with industry norms.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 9 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 9 - of generation fixed costs. There are two approaches that could be used, those relating to system planning and those relating to system o...

AI summary The discussion focuses on methods for allocating generation and transmission costs, with emphasis on the peaker proxy method and long-run marginal costs. Mr. Baker suggests classifying transmission costs similarly to generation, while Dr. Chamberlin advocates for using long-run marginal costs to determine demand/energy splits and highlights the limitations of the peaker method.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 10 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 10- class demand to total system demand, utilizing the class average for the three winter month coincident peaks. - 4. Average and Excess O...

AI summary The document discusses methods for allocating peak demand and energy-related costs to customer classes based on coincident and non-coincident peaks, as well as energy generation requirements. It highlights the use of three winter month coincident peaks for a fairer allocation of excess demand costs.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 12 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 12 - Mr. Kehoe testified that allocation procedures become incredibly complex when one tries to influence how customers will use electricit...

AI summary The document discusses various allocation methodologies for electricity costs, with experts like Mr. Baker and Dr. Chamberlin discussing the merits of different approaches such as non-coincident demands, coincident peak, average and excess, and marginal costs. Mr. Dominie also suggests allocating fuel costs on a monthly basis to better reflect seasonal usage variations.

his six examples. Prior to presenting the Board's findings with regard to the subject of classification, a discussion of the concepts is necessary in order to establish a framework for the decision. The cost of service study includes the c...

AI summary The document discusses the classification of costs in a cost of service study, distinguishing between fixed and variable costs, and how they are allocated to demand, energy, and customer categories. The allocation methods vary, and different techniques have been used, with testimony focusing on these classifications during hearings.

ign. For this reason, the Board requests NSPI to provide the long run marginal cost of demand and energy at the point of generation and at various voltage levels in the system at future rate hearings. 2026-2027 GRA Synapse IR-4 Attachment...

AI summary The Board requests NSPI to provide the long run marginal cost of demand and energy at various voltage levels in future rate hearings. It reviews different demand cost allocation methodologies and evaluates their merits and drawbacks, noting concerns about complexity and data requirements.

Seasonality The Board is of the opinion that seasonal cost variations must be defined within the context of the approved cost of service methodology. 2026-2027 GRA Synapse IR-4 Attachment 1 Page 23 of 24 REDACTED (CONFIDENTIAL INFORMATION...

AI summary The Board emphasizes the need to define seasonal cost variations within the approved cost of service methodology. It outlines how fixed costs should be classified based on energy and demand factors, and directs the use of a '3 Coincident Peak' method for allocating fixed costs. The Board also requests detailed information on long run marginal costs and load factors in future studies.

2026-2027 General Rate Application (M12451) NSPI Responses to Synapse Information Requests 1 Request IR-6: 2 3 Refer to GRA Appendix 12A, Cost of Service Study Process, section 6.1. 4 5 (a) For each distribution sub-function classified usi...

AI summary The document outlines information requests related to the 2026-2027 General Rate Application (M12451) by NSPI, focusing on the Cost of Service Study (COSS) and the minimum system study for distribution sub-functions. The requests include identifying customer- and demand-related portions of sub-functions, equipment capacities, and data classification methods.

NON-CONFIDENTIAL 1 Request IR-1: 29 Securitization Rider as part of this GRA. It will be the subject of a separate application. 30 For those reasons, NS Power is not currently in a position to respond to this question. 1 What is relevant f...

AI summary NS Power is proposing a securitization rider as part of the GRA, which will allow the recovery of approximately $700 million in rate base over a longer period, using 100% debt financing due to provincial government backing. This is expected to result in customer savings despite any rate impact.

9.1 Capital Process In support of its organizational and Asset Management objectives, NS Power utilizes the Asset Management Mechanism to inform and make risk-based decisions. This matrix, aligned with the matrices in NS Power's CEJC, prov...

AI summary NS Power uses a risk-based Asset Management Mechanism to evaluate and prioritize capital decisions. While the mechanism provides a starting point for risk evaluation, it emphasizes the need for SME input due to potential data limitations. Risk considerations include safety, environmental impact, and business sustainability, with final decisions balancing risk, affordability, and operational needs.

NON-CONFIDENTIAL 1 Request IR-25: 14 $0.8 million for decommissioning of the Tusket hydro system to December 31, 2024. NS Power 15 has not recovered any amounts related to decommissioning of the Mersey hydro system. 16 17 NS Power does not...

AI summary The document discusses decommissioning costs for hydro systems, including Tusket and Mersey, and the potential for securitization of these costs. NS Power states it would consider all factors for cost recovery if decommissioning were required in the future. There is also a request for expanded amortization details related to regulatory amortizations and Roseway Hydro Decommissioning.

- 2 be collected through a rider. The revenue requirement of the rider will depend primarily on the - 3 interest rate, repayment term, and repayment structure of securitized debt. - 4 This net savings could be as much as approximately $90...

AI summary The document discusses the potential revenue savings from securitizing unrecovered net book value of thermal assets, estimating up to $90 million in savings over a two-year period if initial repayments are interest-only at a 4% rate, compared to the current $140 million revenue requirement.

- 11 financing cost to the benefit of customers. 1 Request IR-40: 2 3 Considering NS Power's proposal to securitize the costs of assets that were previously 4 proposed to be added to the DDA, please fully explain the continued purpose of t...

AI summary NS Power explains that securitization of DDA assets will reduce the DDA balance but not eliminate future costs, including sustaining capital and decommissioning. It also notes that the Cost of Removal account has been tracked since 2016, though full reconciliation is hindered by a cyber incident.

4 Figure 1 – Summary of findings, observations and conclusions # Report section Findings, observations, and conclusions 4. Regulatory amortization expense We have reviewed the regulatory amortizations included in NS Power's 2024 Actuals an...

AI summary The document reviews regulatory amortization expenses for NS Power, including amounts forecasted for 2026 and 2027, driven by factors such as non-standard meters, Hurricane Fiona cost recovery, and retired tidal assets. The review found no unreasonable aspects in the amortizations included in the GRA.

- 3 Figure 2 Breakdown of Forecast Revenue Requirement by Category ($ millions) 2026F 2027F Notes Fuel & purchased power 918.6 918.4 [1] FAM fuel cost deferral 8.9 (10.7) [1] OM&G 351.8 357.9 Demand side management expense 63.8 63.8 [1] De...

AI summary The document presents a forecast revenue requirement breakdown for 2026 and 2027, highlighting categories such as fuel and purchased power, FAM fuel cost deferral, OM&G, and return on equity. It notes that certain items are outside the scope of the analysis, including fuel and purchased power, FAM fuel cost deferral, DSM expense, and return on equity.

ion Requests – IR-14. N-27 (C) – NSPI Responses to NSEB Information Requests – IR-62. N-6 – 2026-2027 GRA Direct Evidence Appendix 7C page 18. N-23 (C) – NSPI Responses to GT Information Requests – IR-19. o The above increases are partiall...

AI summary The text discusses increases in operating, maintenance, and general (OM&G) costs for NS Power Corporate Groups, partially offset by non-regulated cost recovery and savings from other goods and services. The Board is encouraged to seek more details on the savings challenge mentioned.

2 4.1 Scope - 3 Nova Scotia Power has a number of regulatory amortizations which have a direct impact on the overall revenue - 4 requirement for each year. Regulatory amortization is the process in which Nova Scotia Power recovers certain...

AI summary Nova Scotia Power uses regulatory amortization to recover costs over time, stabilizing electricity rates and preventing sudden rate increases. This includes both previously approved deferrals and new proposals from the GRA.

Figure 16 – Regulatory amortizations [153](#page-43-0) 18 ($ millions) 2024C 2024A 2025F 2026F 2027F Non-standard Meters 2.6 2.4 2.4 - Hurricane Fiona Cost Recovery - 1.7 3.4 3.4 Deferred Decarbonization Asset 4.5 - - - Total previously ap...

AI summary The document outlines regulatory amortizations related to various projects and costs, including non-standard meters, Hurricane Fiona cost recovery, and deferred decarbonization assets. It references a Board decision (M08349) allowing NS Power to recover the undepreciated costs of meters from the AMI project over five years, with full recovery expected by 2027.

4.4 Conclusion We have reviewed the regulatory amortizations included in NS Power's 2024 Actuals and 2025 Budget, as well as 2024 Compliance, 2026 Forecast and 2027 Forecast. Our procedures included reviewing the methodology of proposed re...

AI summary The review of NS Power's regulatory amortizations for 2024 and 2025 shows forecast amounts of approximately $8.1 million in 2026 and $8.3 million in 2027, driven by non-standard meters, Hurricane Fiona cost recovery, and Annapolis Tidal Retired Assets. The review found no unreasonable aspects in the amortizations included in the GRA.

2 6.1 Scope - 3 Interest expense includes interest and other expenses and AFUDC, FAM, and DSM rider deferral interest. Included in - 4 revenue requirement are the following amounts related to interest expense:

AI summary The scope section outlines that interest expense includes interest, AFUDC, FAM, and DSM rider deferral interest, and these amounts are included in the revenue requirement.

28 6.4 Conclusion We have reviewed interest and other expenses included in NS Power's 2024 Actuals and 2025 Budget, as well as 2024C, 2026 Forecast, and 2027 Forecast. Our procedures included recalculating interest and other expenses based...

AI summary The review of NS Power's financial forecasts for interest and other expenses indicates that these are expected to increase from 2026 to 2027, primarily due to deferred interest on assets to be securitized in 2026. The review found no unreasonable aspects in the 2026 and 2027 forecasts.

NS Power GRA, page 41, lines 9 to 13. 1 ALG procedure to a large reserve surplus. For clarity, the reserve deficiency for these 20 the filing of the current depreciation study, notwithstanding that it was prepared based on 21 December 31,...

AI summary The document discusses the impact of NS Power's proposal to securitize general plant investment on intergenerational equity. It argues that securitization shifts the burden of depreciation costs to future customers, who would otherwise pay higher depreciation expenses. The ALG procedure is highlighted as a factor contributing to this shift in cost recovery.

Q: What is the implication of this proposal? - A: The Traditional Method of recovering net salvage costs is the most technically correct and reasonable method of recovering net salvage costs from customers. By linking the recovery of the c...

AI summary The implication of NS Power's proposal to cease collecting final salvage costs is that future customers may bear disproportionate costs, or customers no longer benefiting from the assets may have to pay for them. NS Power acknowledges this implication but supports the change due to uncertainty about future salvage costs.

consider all relevant factors to determine the best approach for cost recovery of these decommissioning activities. Q: Do you have any other items regarding this proposal that you want to bring to the Board's attention? A: Yes. I note that...

AI summary The text discusses the need for NS Power to reconcile net salvage costs for decommissioning activities, emphasizing the importance of transparency in cost recovery. It also highlights the need for the Board to decide whether unspent salvage funds should be refunded or offset future costs. A reconciliation of interim and final salvage costs is recommended as part of the next depreciation study.

Q: Is NS Power requesting any specific relief in regards to its securitization proposal at this time? A: No, except for its request to be permitted to recover its weighted average cost of capital (WACC) on any depreciation and financing co...

AI summary NS Power is not requesting specific relief for its securitization proposal, except for the ability to recover its weighted average cost of capital (WACC) on depreciation and financing costs if the securitization is delayed beyond December 31, 2025.

Accounting, Finance, Tax and Regulatory Consultant January 2016 – Present Emrydia Consulting Corporation (owner) - Preparation of evidence and expert testimony both written and oral on a variety of areas, including cost-of-service, revenue...

AI summary The document outlines the professional experience of an accounting, finance, tax, and regulatory consultant with Emrydia Consulting Corporation since 2016. The individual has prepared evidence, expert testimony, and conducted studies on topics such as cost-of-service, revenue requirement, depreciation, and cost of capital.

Regulatory Specialist (Consultant) November 2012 – July 2015 AltaLink L.P. - Drafted or coordinated the drafting of AltaLink's 2012/2013 Deferral Account Application and 2015/2016 GTA, including responses to information requests, updates t...

AI summary The individual served as a Regulatory Specialist for AltaLink L.P. from 2012 to 2015, drafting and coordinating various regulatory applications, assisting in proceedings, and improving internal processes related to reporting and cost management.

7. Nova Scotia Energy Board - a. Nova Scotia Power 2026 General Rate Application Depreciation and revenue requirement matters. - 8. Maryland Public Service Commission - a. Potomac Electric Power Company 2025 Rate Case Docket No. 9820 Reven...

AI summary The document lists various regulatory proceedings across Nova Scotia, Maryland, and New Brunswick, focusing on rate applications, revenue requirements, depreciation, cost-of-capital, and deferral account matters. These proceedings involve multiple utility companies and regulatory bodies.

13. Alberta Utilities Commission - a. ATCO Electric Ltd. 2026-2027 General Tariff Application Proceeding 30323 – Revenue requirement, depreciation, income tax, and related matters. - b. ATCO Electric and ATCO Gas Review and Variance Applic...

AI summary This section lists multiple regulatory proceedings handled by the Alberta Utilities Commission, covering topics such as revenue requirements, depreciation, income tax, alternative rate plans, and cost-of-capital. These proceedings involve various utilities and regulatory matters related to tariff applications and cost recovery.

SUMMARY OF ORIGINAL COST, PROPOSED ACCRUAL RATES AND AMOUNTS FUNCTION ORIGINAL COST AT DECEMBER 31, 2019 ACCRUAL RATE TOTAL ACCRUAL AMOUNT Hydro Production $212,814,291 2.35 $5,006,398 Other Production $39,763,942 5.51 $2,191,067 Substatio...

AI summary The document provides a summary of original costs and proposed accrual rates and amounts for various functions including Hydro Production, Substation, Transmission, and Distribution as of December 31, 2019. It outlines the original costs and the corresponding accrual rates and total accrual amounts for each function.

The company has performed a site specific decommissioning cost estimate for each of its 23 owned hydroelectric generating units and 6 thermal units. The site specific engineering decommissioning cost studies were the basis for the net salv...

AI summary The company has conducted site-specific decommissioning cost estimates for its hydroelectric and thermal units. It plans to maintain hydro plants as long as economic, with interim retirements requiring cost recovery from customers. Full decommissioning has not been performed, and environmental costs remain uncertain.

ACCOUNTS 361.12, 361.13 AND 361.15 - OVERHEAD CONDUCTOR - ALUMINUM REGULAR COST OF REMOVAL REUSE G R O S S S A L V A G E FINAL NET SALVAGE YEAR RETIREMENTS AMOUNT PCT AMOUNT PCT AMOUNT PCT AMOUNT PCT 1976 114,352 32,493 28 0 10,057 9 22,43...

AI summary The document presents a table showing the retirement, cost of removal, reuse, gross salvage, and net salvage values for overhead conductor - aluminum from 1976 to 2016. The data includes amounts and percentages for each year, with adjustments made to COR amounts from 2005-2010 to align with new 2011 company guidelines.

6 II. Summary of Fuel Cost-Related Rate Increases 7 8 Q. Please generally describe how NSPI recovers fuel and purchased power costs. 9 A. NSPI's approach is complex. In short, NSPI recovers most (over 90%) of its fuel and purchased power c...

AI summary NSPI recovers most of its fuel and purchased power costs through the Fuel Adjustment Mechanism (FAM), which consists of the Base Cost of Fuel (BCF), Actual Adjustment (AA), and Balancing Adjustment (BA). The BCF is based on forecasts, while AA reconciles differences between forecasted and actual costs, and BA addresses imbalances from non-FAM customers or non-fuel costs.

1 to interest and principal on the $500 million FLG are $41.5 million and $40.6 million, 2 respectively.21 As noted in the M11902 decision, the Board found: 22 3 … the Board finds that the recovery of payments relating to NSPML's approved...

AI summary The text discusses the recovery of payments related to a regulatory asset from NS Power's customers over the next 28 years, associating these payments with future service from the Maritime Link rather than historical costs. It also mentions the deferral of FAM costs and the forecasted liability at the end of 2026 and 2027.

PHP Deferral appears to be a reasonable Response to NSPI (NSEB) IR-1 Attachment 1, page 9. Response to NSPI (BW) IR-4 (c); see also Response to NSPI (BW) IR-17 (f). Response to NSPI (BW) IR-18 (f). mechanism for reconciling any deviations...

AI summary The document discusses the PHP Deferral mechanism for reconciling revenue deviations and addresses NSPI's sustaining capital expenditures at Lingan 2 during 2026 and 2027. It notes concerns over the significant cost and the unit's status in cold reserve.

21 Q. Please describe your conclusions and recommendations. 20 II. SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS 19 Company") cost of service study. 18 A. The purpose of this evidence is to address Nova Scotia Power's ("NS Power" or "the 17 Q...

AI summary The testimony addresses the misclassification of distribution system costs by NS Power using the minimum size method, which inflates residential customer costs. It recommends adopting the Basic Customer Method instead, aligning costs more accurately with customer numbers and directly related expenses like metering and billing.

However, considering the context of NS Power and parties' consensus agreement in this case, I recommend that the Board direct that use of the minimum system method – and several other COSS and rate design methodologies – be subject to a fu...

AI summary The text suggests that the use of the minimum system method and other COSS and rate design methodologies should be reconsidered in a future proceeding, given the context of NS Power and the consensus agreement among the parties involved.

III. COST OF SERVICE STUDY - Overview of Cost of Service Studies - Q. What is the purpose of a COSS? - A. A COSS is used to assign the utility's revenue requirement to each customer or rate class in proportion to the costs imposed on the s...

AI summary The purpose of a Cost of Service Study (COSS) is to allocate the utility's revenue requirement to customer classes based on the costs they impose on the system. The study involves functionalizing costs, classifying them based on cost drivers, and allocating them fairly. Concerns were raised about NS Power's use of a flawed minimum system methodology for classifying distribution costs.

1 nlllllber of customers will allocate the majority of these costs to the residential class. In 2 contrast, the COSS assigns demand-related costs based on the relative class non 3 coincident peak demand (NCP), to which the residential clas...

AI summary The discussion focuses on cost allocation methods for poles and wires, comparing customer-based and demand-based approaches. It critiques the minimum system method for being unreliable and recommends the Basic Customer Method as a more intuitive and data-based alternative for distributing costs.

3 Alaska Admin. Code § 48.540. 1 A. Yes. As recognized by the Staff of the Ontario Energy Board (OEB), "A Minimum 2 System has a certain load carrying capability which can be viewed as being demand 3 related. As a result, the customer-rela...

AI summary The text discusses the need for adjusting cost allocations based on the load carrying capacity of the minimum system to ensure fair distribution of demand-related costs among customers. It references the Ontario Energy Board's recommendation to account for peak load carrying capability (PLCC) and provides an example of how such adjustments are calculated.

of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota. November 1, 2024. Exhibit___(CJB-1), Schedule 8 p.9 (PDF p.126). Provided as Attachment LFE-83-1. - Redacted Evidence of Caroline Palmer Th...

AI summary The discussion addresses the minimum system study and its implications, including the allocation of demand-related costs and the recommendation for a load carrying capacity adjustment. Industry literature is referenced to support the view that minimum-size distribution equipment can be a demand-related cost. The impact of using the basic customer distribution classification on the Cost of Service Study (COSS) is also raised.

W per customer, applying the credit to the NCP demands used for determining minimum system - Q. What is the COSS impact of using the basic customer distribution classification? demand allocators. Testimony of the Electric Rate Design Panel...

AI summary The use of the basic customer distribution classification impacts the Cost of Service Study (COSS) output, affecting revenue to cost (R/C) ratios for different customer classes. The domestic R/C ratio increases, while the general demand R/C ratio decreases, indicating higher costs to serve higher-usage classes.

y explains that both NS Power and numerous customer representatives 14 support the outcomes requested in this GRA and that the parties do not require and are 36 2026-2027 GRA SR-01 Att 08. - Redacted Evidence of Caroline Palmer not seeking...

AI summary The witness explains that the consensus among parties in the GRA does not alleviate concerns about the Company's COSS methods, particularly the use of the minimum system methodology. They argue that acceptance of negotiated terms may not reflect endorsement of individual provisions and that concerns raised during the stakeholder process were not fully addressed.

ogies, particularly the use of the minimum system method for classifying distribution system costs, I recognize of the agreed-upon methods for future cases. N-3: Direct Evidence DE-03 – DE-04 p.8-9. that the parties have overcome their own...

AI summary The text discusses the use of the minimum system method for classifying distribution system costs, noting that while parties have settled on current methods, certain COSS methodologies should be revisited in the next GRA. Specific methods, such as NS Power's new approaches to classifying generation and transmission costs, are highlighted as requiring future Board determination.

N-9: 2026-2027 GRA Appendix 12A - Cost of Service Study Process – Redacted p.15-16. 1 • The potential for NS Power to use more granular and temporal allocators. Further 2 data analysis and discussion would likely be worthwhile in consideri...

AI summary The text discusses the potential for Nova Scotia Power to use more granular and temporal allocators in cost allocation, moving away from simplistic methods. It suggests that further data analysis and discussion would be beneficial in this regard.

lation. It is part of a broader and troubling pattern. Over the last four years, Nova Scotia Power has repeatedly returned to regulators seeking various forms of rate increases and additional charges. In January 2022, the utility applied f...

AI summary Nova Scotia Power has repeatedly sought rate increases over the past four years, including a 14% increase in 2022, additional increases through the fuel adjustment mechanism in 2024, and a storm cost-recovery rider in December 2024. The current General Rate Application proposes a 3.9% increase for 2026 and 2027, which could add $400 annually to a family’s electricity bill, raising concerns about affordability and customer trust.

lation. It is part of a broader and troubling pattern. Over the last four years, Nova Scotia Power has repeatedly returned to regulators seeking various forms of rate increases and additional charges. In January 2022, the utility applied f...

AI summary Nova Scotia Power has repeatedly sought rate increases over the past four years, including a 14% hike in 2022, an additional increase via the fuel adjustment mechanism in April 2024, and a storm cost-recovery rider in December 2024. The 2026 General Rate Application would impose a 3.9% increase, adding hundreds of dollars annually for families. This pattern raises concerns about stability and customer trust.

E. POSITION OF THE PARTIES AND INTERVENORS The Company seeks an increase in revenues of $105.4 million. Application, p. 2. UI attributes the revenue deficiency to four categories of factors driving its request, including, alleged methodolo...

AI summary The Company is requesting a $105.4 million revenue increase, citing issues with previous rate-setting methodologies, unrecovered costs, inflationary pressures, and environmental remediation expenses. The Company later reduced its request to $63.7 million, claiming it is sufficient to maintain service quality in Connecticut.

Proposed ($) Adjustments ($) Approved ($) Prior Approved (2022) 2,273,831,000 2,273,831,000 Adjustments Test Year Beginning Balance Correction - (265,839) (265,839) Net Metering 2,226,469 (2,226,469) - Municipal Dashboard 900,222 (900,222)...

AI summary The table outlines proposed, adjustment, and approved figures for Test Year Plant-in-Service Adjustments, including items like Net Metering, Municipal Dashboard, and All Other Proposed Plant Additions, with specific dollar amounts and adjustments made.

r No. 23); Decision, June 30, 2021, Docket No. 20-07-01, PURA Implementation of Section 3 of Public Act 19-35, Renewable Energy Tariffs and Procurement Plans (20-07-01 Decision) p. 54 (Order No. 22)). With respect to the Residential Renewa...

AI summary The Authority ordered UI to recover reasonable and prudently incurred expenses related to the RRES and NRES Programs through the Rate Adjustment Mechanism. UI argues that it does not recover capital costs through RAM and contends that recovery in base rates is appropriate to avoid intergenerational inequities.

iii. Municipal Dashboard In the instant proceeding, the Company seeks to include capital expenditures related to Project No. PRJ-002266, the municipal dashboard (Dashboard), in rate base. Interrog. Resp. RSR-251. The Dashboard is an online...

AI summary The Company is seeking to include capital expenditures for the municipal dashboard in rate base. However, the Authority denied this request, citing prior approval of the Dashboard as an operating expense and warning against segmenting project costs across multiple rate cases.

iv. Pole Attachment Make-Ready Capital Costs UI seeks to include $23,556,152 in capital additions in rate base relating to Project No. PRJ-002110, "Make Ready Cap – Pole Attachments" for costs incurred by the Company to perform engineering...

AI summary UI seeks to include $23.5 million in capital additions in rate base for pole attachment make-ready work, arguing it aligns with state broadband expansion goals. OCC recommends disallowing the full amount, claiming the costs should be borne by new attachers rather than ratepayers.

support future capacity and reliability needs, as well as to avoid later work that would disrupt traffic on the bridge and include costly roadway repairs. Late Filed Ex. 67; Hr'g Tr., 1101:5–1102:15. OCC recommends a disallowance of $1,776...

AI summary The Office of the Chief Counsel (OCC) recommends disallowing $1,776,064 related to 12 unused duct lines installed during the Barnum Avenue Bridge Replacement Project, arguing that the Company provided insufficient evidence justifying their necessity or benefit to customers.

vi. New Congress Getaway South The Company seeks recovery of $3,662,777 for Project No. PRJ-003425, relating to plant additions associated with the installation of duct infrastructure under a floodwall near the New Congress substation. [19...

AI summary The Company is requesting recovery of $3,662,777 for a project involving duct infrastructure installation near the New Congress substation. The Office of the Chief Counsel (OCC) argues that no energized cables are currently in the ducts and that a portion of the project may be reimbursable by NuPower, suggesting that general ratepayers should not bear the full cost.

a. Summary The Authority permits utilities to make pro forma adjustments to the test year plantin-service for plant additions identified in the application but made after the test year. Specifically, a utility is permitted to include new p...

AI summary The Authority allows utilities to adjust the test year plantin-service for plant additions made after the test year, provided they are used and useful and costs were prudently incurred. The Company proposed significant adjustments but failed to quantify savings or risks, and must provide this information in future requests. The Authority approved a portion of the requested adjustments.

separate line items . . . . Id., p. 43 (Order No. 11). Further, the Authority stated that "the approval of any implementation costs will be done through the appropriate RAM proceedings." Id., p. 30. With the launch of any new or innovative...

AI summary The document discusses the recovery of implementation costs for the LIDR program through the RAM, as ordered by the Authority. The Company did not seek recovery through RAM, citing that capital costs had not flowed through the SBC. However, the Company did not object to the Authority's order and failed to follow it, which is not permissible.

a. Summary The Authority approves a CWC allowance of $23,639,066 reflecting a reduction of $15,309,743 from the Company's proposed $38,948,809. Late Filed Ex. 1, Att. 2 Supp., Sch. B-1.0, Sch. B-4.0. The adjustments to the Company's propos...

AI summary The Authority approves a CWC allowance of $23,639,066, reducing the Company's proposed amount by $15,309,743. Adjustments include the exclusion of non-cash items, a revised collections lag, disallowance of the payment lag adjustment, and flow-through impacts of PURA's expense adjustments.

Expense Category PURA Expense Adjustment ($) CWC Adjustment Factor CWC Adjustment ($) Compensation (301,500) 0.1113 (33,557) Employee Benefits (227,626) 0.1468 (33,415) Income Tax (4,917,242) 0.0640 (314,703) Other O&M (14,971,618) 0.0261...

AI summary Table 10 presents the impact of expense adjustments on the Cost of Service Working Capital (CWC) for various expense categories, including compensation, employee benefits, income tax, and others. The table shows both the PURA expense adjustment and the corresponding CWC adjustment in dollars.

3. Material and Supplies The Company proposes the inclusion of $6,897,644 for distribution Materials and Supplies (M&S) in the working capital balance for Rate Year 2025/2026. The Company recorded distribution M&S of $7,940,791 in the Test...

AI summary The Company proposed a distribution Materials and Supplies (M&S) amount of $6,897,644 for the working capital balance in Rate Year 2025/2026, but the Authority approved a lower amount of $4,994,529 after adjustments.

The Company applied a 65.14% distribution allocation factor to its proposed $10,589,194 13-month average for total M&S, which includes distribution and transmission. Interrog. Resp. RRU-060, Att. 1. The 65.14% distribution allocation is de...

AI summary The Company applied a 65.14% distribution allocation factor to its proposed M&S balance, but the Authority found the significant increase in M&S from 2019 to 2023 unexplained. As a result, the Authority used the average M&S balance over the period, adjusted by the distribution factor, to determine the allowed distribution M&S balance.

2. Allowance for Bad Debts The Company proposed a pro forma adjustment to zero out the $14,700,000 Test Year allowance for bad debts in UI's proposed rate base. Sch. B-8.0. The Authority disallows the Company's pro forma adjustment to remo...

AI summary The Company proposed removing $14,700,000 from the Test Year allowance for bad debts in the rate base, but the Authority rejected this adjustment. UI argued that the removal was not due to double counting but to align with previous practices, citing precedents from its gas affiliates. The Authority noted that the uncollectible expense reflected in the working capital calculation only accounted for about 30% of the total annual uncollectible expense.

Category Proforma Rate Year Beginning Balance ($) Proposed Rate Year Average ($) PURA Adjustment ($) Approved Rate Year Average ($) Regulatory Asset - SFAS 158 57,317,577 53,986,199 (53,986,199) - Pension Cost Recovery 1,853,470 926,735 (9...

AI summary The table outlines adjustments to various regulatory assets, including Regulatory Asset - SFAS 158, Pension Cost Recovery, Environmental Deferral, Isaias Penalty Over-Under, and Regulatory Proceeding Costs, showing a decrease in balances from the proforma rate year to the approved rate year.

1. Summary The Company proposes net accumulated deferred income taxes (ADIT) of $317,795,723 to offset rate base proposed for the Rate Year. Late Filed Ex. 1, Att. 2 Supp.; Sch. B-7.0; Sch. WP B-7.0. The ADIT amount represents the average...

AI summary The Company proposes using net accumulated deferred income taxes (ADIT) of $317,795,723 to offset the rate base for the Rate Year. The ADIT amount is the average of the beginning and ending balances. The Authority will adjust this amount by $1,017,632.

5. Five-Year Capital Plan UI proposed recovery in rates of plant additions through the end of the Rate Year. [Table 22, below,](#page-47-2) shows plant additions requested in the Application. Actual and Planned Plant Additions ($) 9/1/22-1...

AI summary UI proposed recovery in rates of plant additions through the end of the Rate Year. The Authority requires plant additions to be deemed prudent and used and useful before they can be recovered in rate base. Tables detail actual and planned plant additions and capital expenditures for the Test Year and the five-year capital plan (2024-2028).

a. Company's Financial Risk The Authority considers the financial risk of the Company as it compares to the Authority Proxy Group to determine if there are unique financial risks or risk mitigations to consider when establishing an ROE. Th...

AI summary The Authority evaluates the financial risk of the Company compared to the Authority Proxy Group and finds that UI's risk profile does not warrant special consideration in determining ROE. Bond ratings and risk mitigation mechanisms such as RAM and C&LM programs reduce financial risk, leading to the conclusion that UI's risk is comparable to other companies in the proxy group.

ration of its terms, the Authority made clear that ratepayers were not to bear any future costs associated with English Station other than those related to an environmental bulkhead repair. Id., p. 5. In the present proceeding, the Company...

AI summary The Authority determined that the Company failed to comply with its direction not to recover future costs related to English Station beyond those for environmental bulkhead repair. The Company stopped tracking internal labor costs related to English Station, leading to these costs being recovered through base distribution rates, violating the Authority's orders.

ii. Water Heater Rental Program As also discussed in Section [VI.A.17.j,](#page-185-0) [Water Heater Rental Program,](#page-185-0) below, in the Company's last rate case the Authority ordered UI to close participation to new customers in i...

AI summary The Water Heater Rental Program was ordered to be phased out by the Authority due to its unsustainability. The Company requested a new cost recovery mechanism for the phase-out, but the Authority declined and directed the program's phase-out to be completed by September 1, 2025.

a. Summary The Company proposes $5,613,847 in outside customer service expenses, which is the Company's $4,623,509 pro forma Test Year expense and a $990,338 pro forma Rate Year adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.0 WP, p....

AI summary The Company proposes to recover $5,613,847 in outside customer service expenses, but the Authority approves $5,339,511 for the Rate Year. The difference includes a pro forma Test Year expense and a Rate Year adjustment.

c. Outsource Call Taking Vendor The Company proposes a $910,055 expense for the Rate Year for outsource call taking vendors, which is the Company's $2,044,250 Test Year amount, with a ($1,134,195) adjustment made to the Rate Year amount to...

AI summary The Company proposes a $910,055 expense for outsource call taking vendors in the Rate Year, based on projected call volumes and cost per call, with adjustments for abandoned calls and distribution percentages. The Authority approves this amount, finding the methodology reasonable.

e. Contact Center Services The Company proposes $57,163 in contact customer services expenses for the Rate Year, which is the Company's $62,832 Test Year, with a ($9,975) pro forma adjustment, and a $4,306 inflation adjustment. Late Filed...

AI summary The Company requests $57,163 for contact center services for the Rate Year, but the Authority approves $52,857, rejecting the inflation adjustment due to the lack of measurable cost drivers based on per unit pricing contracts.

f. Billing, Autopay, Payment Agencies The Company proposes $1,842,802 for billing, auto pay, and payment agencies expenses for the Rate Year, which is the Company's $1,703,970 Test Year expense plus a $138,832 adjustment for inflation. Lat...

AI summary The Company requested $1,842,802 for billing, autopay, and payment agencies expenses for the Rate Year, including a $138,832 inflation adjustment. However, the Authority denied the inflation adjustment, citing insufficient evidence and historical data showing no correlation between expenses and inflation over the past five years, and approved the Test Year amount of $1,703,970.

g. Credit Card Fees The Company proposes $1,892,932 in credit card fee expenses for the Rate Year, which is an expense for which the Company did not report a Test Year expense but expects to incur in the Rate Year. [58](#page-107-0) Late F...

AI summary The Company proposes $1,892,932 in credit card fee expenses for the Rate Year, which it expects to incur but did not report in the Test Year. It seeks to use these expenses as a baseline for a deferral mechanism to be trued-up in the next rate case, citing the 22-08-08 Decision. However, the Authority allows recovery of $1,827,877 but refuses to defer these expenses for future years.

h. Service Performed by Affiliates The Company proposes $373,272 for customer services performed by affiliates, which is the Company's $345,150 Test Year amount plus a $28,122 adjustment for inflation. Late Filed Ex. 1, Att. 2 Supp., Sch....

AI summary The Company proposes $373,272 for customer services performed by affiliates, which includes an inflation adjustment. The Authority allows recovery of $345,150, the Test Year expense, to avoid double-counting wage inflation already included in the proposal.

i. Customer Programs The Company proposes $157,409 in customer programs expenses for the Rate Year, which is the Company's $139,572 Test Year expenses plus a $5,978 pro forma adjustment and an $11,859 inflation adjustment. Sch. WP C-3.03....

AI summary The Company proposes $157,409 in customer programs expenses for the Rate Year, including adjustments for inflation and pro forma costs. The Authority allows recovery of $145,550, citing the lack of reasonable justification for the proposed inflation adjustment. The Company disputes the Authority's finding of double counting but provides no supporting evidence.

a. Summary The Company proposes $6,565,685 in outside electric distribution system expenses, which the Company described as third-party work on operations and maintenance projects and third-party contractors supporting its efforts to proce...

AI summary The Company proposes $6,565,685 in outside electric distribution system expenses, categorized under 'Electric Operations,' 'Joint Use– Third Party Pole Attachments,' and 'Services Performed by Affiliates.' The Authority approves $3,587,764 for the Rate Year, with a summary table of the approved expenses.

Table 40: Allowed Outside Services– Electric Distribution System Expenses Expense Proposed ($) Adjustment ($) Approved ($) Electric Operations 3,115,402 (57,347) 3,058,055 Joint Use - Third-Party Pole Att. 2,612,117 (2,612,117) - Services...

AI summary Table 40 outlines the approved outside services for electric distribution system expenses, including adjustments made to various categories such as Electric Operations, Joint Use, and Services Performed by Affiliates. The total approved amount is significantly lower than the proposed amount due to adjustments.

ated backlog of 5,293 poles by the end of 2026. Interrog. Resp. RSR-174, Att. 1. Accordingly, the Company's projected contractor expense for the Rate Year is more appropriately stated as $849,631. As described in more detail below, the Com...

AI summary The Company estimates a backlog of 5,293 poles by 2026 and projects contractor expenses of $849,631 for the Rate Year. These expenses are to be covered by pole attachment fees and not recovered in base distribution rates.

d. Services Performed by Affiliates The Company proposes $838,166 in expenses related to services performed by affiliates for the Rate Year, which is the Company's $775,021 Test Year amount plus a $63,145 inflation adjustment. Late Filed E...

AI summary The Company requests $838,166 for affiliate services in the Rate Year, including $245,312 related to rate case efforts. The Authority allows recovery of $529,709. The record is unclear if the rate case expenses relate to the current proceeding or the last rate case in Docket No. 22-08-08, and those expenses are not recoverable.

a. Professional Services The Company proposes $230,117 in professional services expenses for the Rate Year, which is the Company's $1,172,211 Test Year expense minus a ($959,430) [64](#page-117-0) pro forma adjustment, plus a $17,336 gener...

AI summary The Company proposed $230,117 in professional services expenses for the Rate Year, but the Authority allowed only $212,781, rejecting the $17,336 inflation adjustment due to the fluctuation in expenses from 2019 to 2023.

b. Operational Smart Grids The Company proposes $5,101,497 in operational smart grid expenses for the Rate Year, which is the Company's $4,642,408 Test Year expense plus a $459,089 pro forma adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch....

AI summary The Company proposes $5,101,497 in operational smart grid expenses for the Rate Year, including adjustments for nonrecurring costs, vendor expenses, and inflation. The Authority permits the recovery of $4,755,763, adjusting for inflation factors and fixed-price contracts.

c. Process & Technology The Company proposes $1,165,553 in process and technology expenses in the Rate Year, which is the Company's $884,546 Test Year expense plus $208,939 in expenses related to implementing a quality management system (Q...

AI summary The Company proposed $1,165,553 in process and technology expenses for the Rate Year, but the Authority only allows $884,546. The Authority disallows $208,939 in QMS implementation costs due to speculative nature and $72,068 in inflation adjustment due to lack of evidence of reasonable change.

d. Audit Expense The Company seeks to recover $1,124,867 in direct audit expenses for the Rate Year, which is the Company's $1,040,122 reported Test Year expense plus an $84,745 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP...

AI summary The Company seeks to recover $1,124,867 in audit expenses for the Rate Year, but the Authority allows only 50% of the direct audit expenses, excluding an $84,745 inflation adjustment. The Authority determines that shareholders should bear the remaining 50% of the audit costs, citing the interests of ratepayers and stakeholders.

e. Facility Maintenance The Company proposes a $457,968 facility maintenance expense in the Rate Year, which is the $423,466 Test Year expense plus a $34,502 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C.3.06. The Authori...

AI summary The Company proposed $457,968 in facility maintenance expenses for the Rate Year, including a $34,502 inflation adjustment and $309,950 in nonrecurring fire suppression system repairs. The Authority removed the nonrecurring repair costs and questioned the validity of the inflation adjustment due to fluctuating expenses over the past four years, ultimately approving $113,516 in recoverable expenses.

f. IT, Security, & Safety The Company proposes $665,826 in Rate Year IT, security, and safety expenses, which is the Company's $615,665 Test Year expense plus a $50,161 inflation adjustment. Sch. WP C-3.06. The Authority permits the Compan...

AI summary The Company proposed $665,826 in IT, security, and safety expenses for the Rate Year, but the Authority allowed only $513,375, disallowing $110,565 in nonrecurring expenses related to an additional security guard and $41,824 in inflation adjustments due to inconsistent historical spending.

g. Services Performed by Affiliates The Company proposes that it recover $2,700 in services performed by affiliates, which is the Company's $34,696 Rate Year expense, a ($32,199) pro forma adjustment, plus a $203 generic inflation adjustme...

AI summary The Company seeks to recover $2,700 for services performed by affiliates, but the Authority reduces this amount to $2,497 after considering a pro forma adjustment and an inflation factor, as the Company did not adequately justify the increase in expenses.

h. Legal Expense The Company proposes that it recover $2,160,726 in the Rate Year for legal expenses, which is the Company's $2,669,579 Test Year expense, a ($671,637) [69](#page-122-0) pro forma adjustment, and a $162,784 inflation adjust...

AI summary The Company seeks to recover $2,160,726 in legal expenses for the Rate Year, based on adjusted Test Year expenses and an inflation factor. However, the Authority only allows $337,803 in recovery, citing issues with nonrecurring expenses, imprudent projections, and statutory bars on recovery.

6. Outside Services– Line Clearance The Company proposes $16,660,423 in line clearance expenses, which is the Company's $15,405,272 Test Year expense plus a $1,255,151 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.05; I...

AI summary The Company proposed $16,660,423 in line clearance expenses, including an inflation adjustment, for its UPZ and RM programs. The Authority approved $15,834,389, with reductions in UPZ expenses and increases in RM expenses.

ii. RM Expense The Company proposes $1,463,325 in RM expenses for the Rate Year, which is the Company's $1,353,082 Test Year expense plus a $128,243 inflation adjustment. The Authority allows $1,477,599 in RM expense for the Rate Year. The...

AI summary The Company requested $1,463,325 for RM expenses, including an inflation adjustment, but the Authority approved $1,477,599. The Authority found that using a generic inflation factor was inappropriate due to existing contract escalation factors. The RM program addresses hazardous conditions and customer requests and is separate from the UPZ program.

7. Storm Expense The Company proposes $6,623,074 in storm expenses for the Rate Year, which is the Company's $9,531,643 Test Year amount less a $2,908,569 Test Year pro forma adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.07. The Com...

AI summary The Company proposes $6,623,074 in storm expenses for the Rate Year, including minor storm expenses, a Handy Whitman adjustment, major storm expenses, and an annual storm reserve. The Authority allows $6,188,125 in storm expenses for the Rate Year. Previously, storm expenses were categorized by type, but the Company has now consolidated all storm activity into a new schedule.

b. Minor Storms The Company proposes a Rate Year cost of $2,919,689 in minor storm expenses. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.07a. UI derived this value by taking a threeyear average of its minor storm costs over the period of 2...

AI summary The Company proposed a minor storm expense of $2,919,689 for the Rate Year, calculated as a three-year average of 2021–2023 costs. However, the Authority disallowed a significant portion of external labor expenses due to insufficient documentation in 2022 and 2023, resulting in a reduction of $556,166 and $575,931 respectively.

c. Major Storms The Company states that there is no incremental major storm activity, either expense or deferral, reflected in the Rate Year on Schedule C-3.07a; however, it reflects a $14,844 Rate Year expense for major storms in this Sch...

AI summary The Company claims there is no incremental major storm expense in the Rate Year, but Schedule C-3.07a shows a $14,844 expense. The Authority disallows this amount, citing double recovery as the Company already has a cost recovery mechanism for major storms through storm deferral.

8. Environmental Remediation Expense The Company proposes to recover $3,800,144 in environmental remediation expenses, which is comprised of: the Company's $1,331,269 Test Year Expense; as well as a ($1,130,863) pro forma adjustment to eli...

AI summary The Company seeks to recover $3,800,144 in environmental remediation expenses, including adjustments for barred costs and deferral activities. The Authority approves the recovery of this amount for the Rate Year.

a. East Shore The Company proposes that it recover $3,744,144 in projected East Shore remediation expenses in the Rate Year, which represents half of the Company's expected $7,488,288 Rate Year expenses to conduct remediation activities at...

AI summary The Company proposes to recover $3,744,144 in projected East Shore remediation expenses for the Rate Year, representing half of its total expected costs. This is based on the 22-08-08 Decision, which allows deferral of the remaining costs. The East Shore site, a decommissioned gas plant, is being remediated under various environmental regulations.

b. Bridgeport Avenue The Company proposes to recover $56,000 in Rate Year expenses related to monitoring and reporting obligations for the Company's Bridgeport Avenue site, which is the Company's $41,591 Test Year expense plus a $14,409 ad...

AI summary The Company seeks to recover $56,000 in Rate Year expenses for groundwater monitoring at the Bridgeport Avenue site, which it sold in 2018. Post-remediation monitoring is required under the Connecticut Transfer Act. The Authority permits the recovery, finding the costs reasonable and noting that an alternative testing methodology may eliminate the need for further monitoring.

9. Computer Expense The Company proposes $4,702,214 in computer expenses for the Rate Year, which is the Company's $3,710,906 Test Year expense plus a $991,308 pro forma adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP-C-3.09. The Compa...

AI summary The Company proposes computer expenses of $4,702,214 for the Rate Year, including a $991,308 adjustment. These expenses are categorized into operational smart grid, customer service, and software licensing. The Authority approves $4,180,918 for recovery.

a. Operational Smart Grids The Company proposes $2,608,107 in OSG expenses for the Rate Year, which is the Company's $1,774,562 Test Year expense plus a $833,545 Rate Year adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.09 WP. The Tes...

AI summary The Company requested $2,608,107 in OSG expenses for the Rate Year, including $1,774,562 from the Test Year and an $833,545 adjustment. The Authority found that only $1,774,562 from the Test Year and $688,961 in new Rate Year expenses were reasonable, approving a total of $2,463,523 for recovery.

b. Customer Service The Company proposes $607,663 in customer service-related computer expenses for the Rate Year, which is the Company's $561,833 Test Year expense plus an inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3....

AI summary The Company proposed $607,663 in customer service-related computer expenses for the Rate Year, including an inflation adjustment. The Authority permitted recovery of $409,401 after determining that certain vendors would not be used and that an inflation adjustment was inappropriate.

c. Software Licensing The Company proposes $1,486,444 in software licensing expenses, which is the Company's $1,374,460 Test Year expense plus an inflation adjustment. Sch. WP C-3.09. The Authority permits the Company to recover $1,307,994...

AI summary The Company requested $1,486,444 in software licensing expenses, including an inflation adjustment. However, the Authority determined that the actual Test Year expense was $1,307,994 and rejected the inflation adjustment, allowing recovery of this amount for the Rate Year.

10. Transportation Expense The Company proposes $2,234,308 in transportation expenses in the Rate Year, which is the Company's $1,792,910 Rate Year expense, a $273,072 pro forma adjustment, and a $168,327 inflation adjustment. Late Filed E...

AI summary The Company proposes $2,234,308 in transportation expenses for the Rate Year, including adjustments for delayed repairs and aging fleet costs. The Authority permits $1,991,481 in recovery, adjusting for aging vehicles and rejecting the inflation adjustment due to insufficient justification.

11. Non-hardship Uncollectible Expense The Company proposes a total non-hardship uncollectible expense of $4,320,426 for the Rate Year, which is the Company's $3,452,950 Test Year expense, a ($109,926) pro forma adjustment, plus a $977,402...

AI summary The Company proposes a non-hardship uncollectible expense of $4,320,426 for the Rate Year, based on a seven-year average. The Authority approves $3,408,824, using a five-year average from 2020 to 2024, arguing that it better reflects current trends and excludes outdated data. The Company disputes the use of company-wide data instead of distribution-only data for the calculation.

a. Summary The Company proposes that it recover $49,832,152 in total compensation expense for the Rate Year, a $13,473,028 increase from the Test Year. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.15. The Authority permits the Company to recov...

AI summary The Company requests recovery of increased compensation expenses for the Rate Year, including adjustments for payroll and employee volunteer time. The Authority approves a slightly lower amount, adjusting for these factors. The calculation involves FTEs, salary escalations, and adjustments for vacancies and capitalization.

v. Volunteer Time The Company estimates that approximately $18,937 of Test Year employee expense compensated the Company's employees while volunteering for Avangrid events during working hours. Interrog. Resp. RRU-286; Interrog. Resp. OCC-...

AI summary The Company estimates $18,937 in employee expenses for volunteering during work hours for Avangrid events. The Authority argues that such costs should be borne by shareholders, not ratepayers, and does not permit recovery from ratepayers.

dence in the record that the program truly incentivizes employees, particularly if 100% of eligible employees receive employee incentive compensation. Interrog. Resp. OCC-294; Interrog. Resp. OCC-299. Thus, in balancing the interests of ra...

AI summary The Authority concludes that 61.5% of the Company's APA Plan goals are customer-focused, allowing recovery of $1,554 per employee in non-executive incentive compensation. Total recovery permitted is $1,591,402, reflecting a reduction in allowed FTEs.

d. Workers Compensation Expense The Company proposes a workers compensation expense of $426,356, or $433 per employee, for the Rate Year. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.16e. Based on the evidence presented, the Authority finds...

AI summary The Company proposed a workers compensation expense of $426,356 for the Rate Year, but the Authority approved a lower amount of $424,923 after considering evidence and adjusting for a reduction in Full Time Equivalents. The Authority found the Company's projection of $433 per employee reasonable.

e. 401(k) Expense The Company proposes a 401(k) expense of $3,009,488 in the Rate Year, or $4,799 per employee. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.16f. Based on the evidence presented, the Authority permits the Company to recover...

AI summary The Company proposed a 401(k) expense of $3,009,488 for the Rate Year, but the Authority approved $3,004,689 after determining the per employee expense was reasonable and adjusting for a reduction in Full Time Equivalent (FTE) employees.

ii. Scholarships The Company proposes to include a scholarship expense of $33,518 in the Rate Year, which includes $2,525 in an inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.16g. The Company did not provide any historical...

AI summary The Company proposes a $33,518 scholarship expense for the Rate Year, including a $2,525 inflation adjustment. However, the Authority rejects the inflation adjustment due to the lack of historical data supporting its connection to inflation and the absence of justification for using a generic adjustment.

iii. Life Insurance The Company requests that it recover $53,168 in life insurance expenses for the Rate Year, which is the Company's $49,163 Test Year expense plus a $4,005 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch...

AI summary The Company seeks to recover $53,168 in life insurance expenses for the Rate Year, including a $4,005 generic inflation adjustment. The Authority disallows the adjustment due to the lack of historical data demonstrating a correlation between life insurance expenses and inflation.

v. Student Loan Payments The Company proposes a $15,976 student loan payment expense for the Rate Year, which is the Company's $14,772 Test Year expense plus a $1,204 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.16g. T...

AI summary The Company seeks to recover $15,976 in student loan payments for the Rate Year, but the Authority disallows the expense, stating the Company has not demonstrated that the program is reasonable or necessary for safe and reliable service or maintaining staffing levels.

vi. Caregiver – Bright Horizons The Company proposes $37,444 in a caregiver program expense in the Rate Year. Interrog. Resp. OCC-257. [88](#page-149-0) The Authority disallows recovery of the $37,444 caregiver expense as the Company has n...

AI summary The Company proposed $37,444 in caregiver program expenses, but the Authority disallowed recovery as the Company failed to demonstrate that the expense is reasonable or necessary for safe service or staffing. The Company provides subsidized caregiver benefits but lacks specific data supporting their necessity.

a. Summary The Company proposes corporate service charge expenses of $31,124,964 for the Rate Year, which is the Company's $34,277,936 reported Test Year expense, a ($6,014,776) pro forma adjustment, and a $2,861,804 Rate Year adjustment,...

AI summary The Company requests $31,124,964 in corporate service charge expenses for the Rate Year, based on a Test Year expense of $34,277,936 and adjustments. The Authority approves $25,894,986 for recovery. Table 52 summarizes the adjustments made.

Category Proposed ($) Adjustment ($) Approved ($) Mass Formula Adjustment - (643,415) (643,415) Severance 45,818 (45,818) - Annual Bonus 2,390,106 (920,191) 1,469,915 Loyalty Gifts 223,227 (223,227) - Culture & Sport 1,282 (1,282) - Reloca...

AI summary The table presents the proposed, adjustment, and approved figures for various categories under Corporate Service Charges Expense, including items like Mass Formula Adjustment, Severance, Annual Bonus, and others, with total figures showing a reduction in approved amounts compared to proposed figures.

c. Severance Payments The Authority does not permit the Company to recover $45,818 in severance expenses allocated to UI in the Rate Year. Interrog. Resp. OCC-346 Supp. The Company asserts that employment contracts with severance arrangeme...

AI summary The Authority denies the Company's request to recover $45,818 in severance expenses, finding that the Company has not demonstrated that such payments are recurring, known, or measurable. The Authority also notes that the Company's claims are anecdotal and unsupported by data.

d. Annual Bonus The Authority does not permit the Company to recover $920,191 in annual bonus expenses allocated to UI in the Rate Year. The Company indicates that $2,390,106 in annual bonuses are included in its revenue requirement, which...

AI summary The Authority does not allow the Company to recover $920,191 in annual bonus expenses related to its Annual Performance Award (APA) Plan, as 38.5% of APA plan compensation aimed at shareholder objectives is not recoverable.

e. Loyalty Gifts The Authority does not permit the Company to recover $223,227 in loyalty gifts allocated to UI in the Rate Year. Interrog. Resp. RRU-365, Att. 1. The Company indicates that the allocated loyalty gifts encompass sign-on and...

AI summary The Authority denies the Company's request to recover $223,227 in loyalty gifts allocated to UI, citing the lack of evidence that the expenses are reasonable, necessary, or measurable. The Company's claims about the necessity of sign-on and retention bonuses were not supported by data or specific details.

h. Branding The Authority does not permit the Company to recover $1,163,747 in branding expenses allocated to UI in the Rate Year. The Company indicated that it removed $238,580 in Rate Year branding and communications expenses allocated t...

AI summary The Authority disallows the recovery of $1,163,747 in Iberdrola branding expenses by the Company, stating that the Company has not demonstrated that these expenses reflect prudent and efficient management or benefit the Company's operations. The Company claims the license provides access to technologies and supply chains that mitigate risks.

i. Investor Relations The Authority disallows an additional $65,801 in investor relations expenses that were not yet removed from the Company's proposed Rate Year corporate service charge. The Company indicated that it removed $219,610 of...

AI summary The Authority disallows $65,801 in investor relations expenses that were not removed from the Company's proposed Rate Year corporate service charge. The Company initially removed $219,610 in such expenses but was later allocated an additional $84,070. The Authority adjusted the disallowance to avoid double counting previously disallowed overlapping items.

k. Inflation The Authority concludes that the Company failed to demonstrate that its proposed $676,198 inflation adjustment for corporate services expenses represents a reasonable known and measurable adjustment and, accordingly, does not...

AI summary The Authority rejects the Company's proposed $676,198 inflation adjustment for corporate services expenses, citing a lack of reasonable, measurable justification and noting a decline in corporate service charges over the past five years.

i. Summary The Company proposes to recover $3,308,330 in compensation for all executive compensation expense, consisting of $3,075,408 for officers and $232,922 for directors. Late Filed Ex. 23, Att. 1, 2023 Test Year; Hr'g Tr., 526:4–527:...

AI summary The Company seeks to recover $3,308,330 in executive compensation expenses, including $3,075,408 for officers and $232,922 for directors. The Authority approves 75% of this amount, or $2,481,248, to be recovered in base rates. The requested amount includes allocations from ASC and AMC executive compensation to UI.

b. Advertising The Company proposes $150,754 in advertising expense for the Rate Year, which is the Company's $139,137 Test Year expense plus a $11,357 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.19. Although...

AI summary The Company proposes $150,754 in advertising expenses for the Rate Year, including a $11,357 inflation adjustment. However, the expenses primarily consist of customer communication costs, and the Board questions the validity of the inflation adjustment due to the lack of a clear inflation trend in advertising expenses since 2019. The Board permits recovery of $139,137, the Test Year total without the inflation adjustment.

c. Bank Fees The Company proposes to recover $204,782 in bank fees in the Rate Year, which is the Company's $189,355 Test Year expense plus a $15,427 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp. The Company stated that its...

AI summary The Company proposes to recover $204,782 in bank fees for the Rate Year, including a $15,427 generic inflation adjustment. However, the record shows fluctuating bank fees over recent years, and there is no evidence that the inflation adjustment is reasonable. The Board suggests recovering only the Test Year expense of $189,355 without the adjustment.

d. Membership Dues and Association Fees The Company proposes $239,398 in membership dues and association fee expenses for the Rate Year, which is the Company's $365,068 Test Year industry dues expense, a ($355,454) pro forma adjustment to...

AI summary The Company proposed $239,398 in membership dues and association fees for the Rate Year, but the Authority disallowed expenses related to EPRI and JD Power memberships. Only $9,614 in such expenses was permitted for recovery, citing General Statutes § 16-243gg(a), which prohibits recovery of costs related to trade associations.

e. Postage The Company proposes $6,657 in Rate Year postage expense, which is the Company's $6,155 Test Year expense plus a $502 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp. There is no evidence indicating that applying a g...

AI summary The Company proposed $6,657 in postage expenses for the Rate Year, based on its $6,155 Test Year expense plus a $502 generic inflation adjustment. However, the Authority permits only $6,155 in recovery due to lack of evidence supporting the generic inflation adjustment as a reasonable and measurable method.

f. Training The Company proposes $160,864 in the Rate Year for training expenses, which is the Company's $148,745 Test Year amount plus a $12,119 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.19. The Company, ho...

AI summary The Company proposed $160,864 in training expenses for the Rate Year, including a generic inflation adjustment. However, it failed to justify this adjustment as reasonable and measurable, leading to the approval of only $148,745, the Test Year amount, without the adjustment.

g. Travel Expense The Company proposes $1,015,051 in Rate Year travel expenses, which is the Company's $961,573 Test Year expense, a ($22,993) pro forma adjustment to remove entertainment costs barred from recovery under General Statutes §...

AI summary The Company proposed $1,015,051 in travel expenses for the Rate Year, but the Authority rejected the $76,471 generic inflation adjustment due to insufficient evidence of its reasonableness. The approved amount is $938,580, after removing entertainment costs and adjusting for inflation.

h. Other O&M The Company proposes that it recover $4,750,911 in the Rate Year for "other O&M" expenses, which is the Company's $5,731,385 Test Year expense, a ($1,338,395) pro forma adjustment, plus a $357,921 inflation adjustment. Late Fi...

AI summary The Company proposed to recover $4,750,911 in 'other O&M' expenses for the Rate Year, but the Authority determined that the Company did not justify using a generic inflation factor. The Authority approved a reduced recovery of $4,392,990, reflecting a pro forma adjustment.

Table 56: Approved Annual Amortization Expense (Deferral and Interim Period) Approved Balance, Nov. 1, 2025 ($) Allowed Carrying Costs ($) Total Deferred Amounts Amortized ($) Proposed Annual Amortization ($) Adjustment ($) Allowed Annual...

AI summary Table 56 presents the approved annual amortization expense for various items, including pension, OPEB, storm-related costs, and others, with details on balance, carrying costs, amortized amounts, and adjustments. It outlines the financial implications of deferral and interim periods.

b. Pension The Authority permits the Company to recover a total of $9,502,832 in pension deferral expenses over a three-year period for a Rate Year amortization expense of $3,167,611. The Company reported a pension deferral balance of $13,...

AI summary The Authority permits the Company to recover $9,502,832 in pension deferral expenses over three years, including $3,167,611 in amortization for the Rate Year. The Company's pension deferral balance increased to $13,053,936 as of August 2023, but the Authority did not approve carrying charges on the new $1,827,178 incremental pension costs. However, carrying charges will be permitted on this amount going forward as a regulatory asset.

c. OPEB The Authority approves an OPEB credit of ($1,175,847), which is to be amortized over a three-year period, resulting in a Rate Year credit of ($391,949). The Company reported a $1,576,130 deferred OPEB liability accrued as of August...

AI summary The Authority approves an OPEB credit of $1,175,847 to be amortized over three years, resulting in a Rate Year credit of $391,949. This follows the Company's reported deferred OPEB liability of $1,263,859 as of October 31, 2025, and adjustments made to remove $200,322 in net carrying credits.

e. Isaias Deferral and Customer Credit The Company proposes that it recover a $127,918 regulatory asset in connection with a penalty imposed on the Company following Tropical Storm Isaias that was not returned to customers as of the Compan...

AI summary The Company seeks to recover a $127,918 regulatory asset related to a penalty from Tropical Storm Isaias not returned to customers in its 2022 rate case. The Authority allows amortization of $121,308 over three years, with a $40,436 annual expense, and requires the Company to refund an additional $33,909 by October 31, 2025.

(c) Storm Izzy Deferred Expenses As for Storm Izzy, which occurred on January 17, 2022, the Company submitted expenses related to overtime, materials, and accounting accruals totaling $76,010. Interrog. Resp. EOE-249 Supp. 2, Att. 2, p. 3...

AI summary The Company submitted expenses related to Storm Izzy, including overtime, materials, and shared service costs. The Authority disallowed a portion of these expenses, citing lack of documentation, overlap with previously approved costs, and the need for incremental justification. A small portion of shared service costs was allowed based on an invoice from Securitas.

(d) Flooding Event Deferred Expenses The Company is requesting $1,292,571 in storm expenses relating to a Flooding event (Storm #7) on December 23, 2022. Interrog. Resp. EOE-249 Supp. 2, Att. 2, p. 3. For this storm, the Company is reporti...

AI summary The Company is requesting $1,292,571 in storm expenses from a flooding event on December 23, 2022, including $477,359 in overtime costs. The Company allocates internal labor costs to storms by only charging hours worked beyond 'regular time', and provides detailed documentation on overtime hours and costs, which the Authority has permitted.

Category Amount ($) Storm Costs, August 2021 – December 2024105 2,555,252 Mutual Aid Reimbursements, September 2023 – December 2024 (1,881,623) Authority Deferred Storm Cost Adjustments (135,172) Actual Balance, October 31, 2025 538,457 Se...

AI summary The text presents a table with financial figures related to storm costs, mutual aid reimbursements, and deferred storm cost adjustments, ending with an actual balance as of October 31, 2025. It references an attachment from a regulatory proceeding.

iii. Thunderstorms Deferral For the Thunderstorms Deferral, the Company reports a balance of $5,510,724 to be amortized over 36 months. Late Filed Ex. 1, Att. 2, WP C-3.21, p. 1. The Company is reporting one storm (Thunderstorm) totaling $...

AI summary The Thunderstorms Deferral involves $5,510,724 in storm-related expenses to be amortized over 36 months, including $5,158,351 in storm costs and $114,000 in carrying costs. The Authority disallows carrying costs prior to October 31, 2025, citing ratemaking principles. Expenses include overtime, materials, and vendor costs, with some vendors found to have incurred imprudent costs.

h. Fee Free Program The Company proposes to amortize a ($1,852,863) credit related to the difference between its actual credit card transaction fee costs and the amount embedded in distribution rates for such costs as ordered in the 22-08-...

AI summary The Company seeks to amortize a $1,852,863 credit related to credit card transaction fees, as ordered in the 22-08-08 Decision. The Authority adjusted this credit by $308,376 and added a carrying credit of $228,227, resulting in a $2,389,466 deferred credit to be amortized over three years, representing a $796,489 Rate Year credit.

i. Rate Case Expense The Company proposes to recover $3,163,323 in rate case expenses, amortized over three years, resulting in a $1,054,441 Rate Year amortization expense. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.21, p. 1. General Stat...

AI summary The Company seeks to recover $3,163,323 in rate case expenses over three years, but General Statutes § 16-243p(b) prohibits recovery of legal and consulting fees related to rate proceedings for companies with over 75,000 customers. The Authority allows recovery of $1,063,846 in amortized rate case expenses, excluding certain barred costs.

j. Water Heater Rental Program The Company proposes to recover $12,019,711 in expenses related to phase-out costs of its Water Heater Rental Program, amortized over 36 months, resulting in a Rate Year amortization expense of $4,006,570. La...

AI summary The Company seeks to recover $12 million in phase-out costs for its Water Heater Rental Program over 36 months. The Authority allows recovery of $10.18 million over three years, including carrying charges, resulting in a $3.75 million annual amortization expense. The Authority previously ordered the phase-out of the program by September 1, 2025, and the Company selected the most cost-effective option to retire the fleet.

A. LEGAL STANDARD The Authority is statutorily charged with regulating the rates of Connecticut's public service companies and UI is a public service company within the meaning of General Statutes § 16-1. General Statutes § 16-19. Conseque...

AI summary This section outlines the legal framework for rate regulation in Connecticut, emphasizing the Authority's duty to ensure rates are just, reasonable, and adequate while promoting revenue stability and equitable distribution. The Authority uses principles such as cost causation, rate class equalization, and gradualism to avoid sudden rate shocks and undue burdens on low-income customers.

C. COST-OF-SERVICE STUDY The Company filed an allocated cost-of-service study (ACOSS) based on the historical test year and rate year costs and revenues. Application, Ex. UI-BR-1, p. 12. The Company's proposed ACOSS utilizes the Minimum Sy...

AI summary The Company submitted an allocated cost-of-service study using the Minimum System Study approach, classifying distribution assets into customer- and demand-related costs. The Authority requested alternative models that calculate per-customer load-carrying capacity, leading to adjustments in how demand-related costs are allocated. CIEC supports the use of the MSS approach, while OCC applied a universal load-carrying capacity adjustment based on scenarios from Minnesota and Ontario.

OCC suggests that the Company's original MSS approach was unsound as the basis for determining cost causation and would inflate cost allocations to residential customers. Palmer Prefiled Test., Feb. 13, 2025, p. 9. As an alternative, OCC p...

AI summary OCC criticizes the Company's original MSS approach for inflating residential customer cost allocations and proposes the basic customer method instead. UI defends the MSS approach, citing prior acceptance by the Authority. The Company disputes OCC's recommendation to exclude certain customer classes from demand-related costs and clarifies that AMI infrastructure costs are allocated using the labor allocator.

secondary distribution plant. The Authority affirms the Company's proposed classification of AMI meters as 100% customer-related, which is consistent with cost causation principles, as argued by CIEC. The MSS approach is a just and reasona...

AI summary The Authority affirms the classification of AMI meters as 100% customer-related. The MSS approach is deemed just and reasonable, but the minimum system's load-carrying capacity should be considered when allocating residual demand-related costs. The Company did not account for this and failed to quantify the equal benefit all customers receive from the minimum system.

, 1328:19. Specifically, each customer should be allocated an equal share of the load-carrying capacity affiliated with the hypothetical minimum system, applied towards the relevant demand allocators. The Ontario Energy Board approved a si...

AI summary The document discusses the allocation of load-carrying capacity in a cost-of-service study, referencing the Ontario Energy Board's use of a 0.4 kW adjustment value per customer. The Office of the Chief Counsel (OCC) incorporated this into a modified ACOSS model, but the Authority recommends using the Company's adjustment values for poles and conductors with modifications.

D. COST ALLOCATION The Company used non-coincident peak (NCP) demand to allocate demandrelated costs from the ACOSS to each customer class, except for costs associated with distribution substations, for which the Company used class-wide co...

AI summary The Company used non-coincident peak (NCP) demand and class-wide coincident demand with system peak (1CP) to allocate demand-related costs, except for distribution substations. The Authority directed the use of alternative allocators using AMI data, but the Company found them similar to NCP and 1CP. To achieve equalized rates of return, the Company adjusted its model, violating the Authority's 125%/75% rule.

Table 82: Demand Allocators Allocator R GS GST LPT M U Substation 51.87% 12.23% 23.36% 12.55% 0.00% 0.00% NCP for Transformers 0.00% 13.04% 63.53% 22.48% 0.77% 0.19% NCP Primary – Overhead Conductors and Poles 46.56% 11.33% 27.93% 13.77% 0...

AI summary The document presents Table 82, which outlines demand allocators across various categories and provides a summary of the Authority's review of the Company's revenue allocation scheme using the updated ACOSS model from Section VIII.C. The table includes percentages allocated to different service types and infrastructure components.

ing sensitive financial information, there is no evidence in the record to demonstrate that sharing profit and loss information confidentially would put a customer at risk of competitive disadvantage. 138 Customers should not be able to us...

AI summary The document discusses the Company's plans to recover costs related to the PBI project, which is expected to be in service by early 2027. It also addresses the recommendation against creating a new tariff for two PBI customers due to high costs and inefficiency. The Company will seek recovery of these costs in a rate case proceeding.

EDUCATION June 2014 Master of Arts, Economics, Carleton University June Bachelor of Arts, Economics and Financial Management, 2012 Wilfrid Laurier University REGULATORY/LEGAL PROCEEDINGS Before the Ontario Energy Board 2025 • Burlington Hy...

AI summary The document outlines the educational background of Andrew Blair and his involvement in various regulatory/legal proceedings before the Ontario Energy Board, including cost of service applications and rate design support for multiple utility companies.

(Company evidence: load forecast, cost allocation, and rate design) 2020 • Hydro Ottawa, 2021-2026 Custom IR Application (Company evidence: cost allocation and rate design) • Lakeshore Communities, LTC and Phase II Applications for new nat...

AI summary The document lists various utility companies and their applications related to cost of service, load forecasting, cost allocation, and rate design, including evidence submitted by companies such as Hydro Ottawa, Lakeshore Communities, and Burlington Hydro, among others, between 2017 and 2021.

Before the New Brunswick Energy and Utilities Board 2024 • New Brunswick Power, 2023-24 & 2024-25 General Rate Application (Evidence: Overview Report on NB Power's Proposed Regulatory Accounts) • New Brunswick Power, 2024 Cost Allocation M...

AI summary The document outlines various regulatory proceedings before the New Brunswick Energy and Utilities Board, including general rate applications and cost allocation methodology reviews by New Brunswick Power, as well as non-hearing processes involving other entities such as EfficiencyOne and Montserrat Utilities Ltd.

5 Q. WHAT IS THE BASIS FOR THE COMPANY'S INCLUSION OF A CONTINGENCY? 6 A. The Company's basis for its 25% contingency is to eliminate any financial risk for potential under-recovery of costs that may occur.36 7 Further, the use of a 25% 8...

AI summary The Company includes a 25% contingency in its cost estimates to mitigate financial risks from potential under-recovery of costs and to account for unforeseen future expenses, ensuring the total cost estimate reflects probable costs more accurately.

24 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 25 A. Yes. Based on statistical comparisons, historical data, and the Company's historical 26 proposals for this account, I believe Gannett Fleming's selection for this account is 27 appropri...

AI summary The respondent agrees with the company's proposal, citing statistical comparisons, historical data, and past proposals. They believe Gannett Fleming's selection for the account is appropriate and no adjustment is required.

UTILITY RATE PROCEEDINGS IN WHICH TESTIMONY HAS BEEN PRESENTED BY JACOB POUS ALASKA Public Service Company of Oklahoma Public Service Company of Oklahoma Public Service Company of Oklahoma Public Service Company of Oklahoma Public Service...

AI summary The document lists utility rate proceedings in which Jacob Pous has provided testimony, including various cases involving Public Service Company of Oklahoma and other entities, with references to cost recovery, stranded costs, and related financial terms.

"...the updating of the Basic Assumptions phase took place over several months and involved NSPI staff working jointly with Board staff and consultants, as well as consultation with stakeholders." 1 One last note, the Handy Whitman index i...

AI summary The text discusses the updating of the Basic Assumptions phase involving NSPI, the Board, and consultants, and includes recommendations on decommissioning cost estimates and depreciation rates for hydro plants. The expert advises using a 2.0% escalation rate and excludes contingency costs from decommissioning estimates, while also noting that hydro plants may not be retired but instead extended through capital additions.

This is a Decision and Order of the Ontario Energy Board (OEB) regarding a generic proceeding initiated on its own motion to consider the cost of capital and other matters for electricity transmitters, electricity distributors, natural gas...

AI summary The Ontario Energy Board (OEB) has finalized the cost of capital parameters for electricity transmitters, distributors, natural gas utilities, and rate-regulated generators, effective January 1, 2025. Key parameters include a 9.00% return on equity, 4.51% deemed long-term debt rate, and 3.91% deemed short-term debt rate. The new framework will be reviewed in five years, and Q2 2025 prescribed interest rates for deferral and variance accounts and construction work in progress accounts have been set.

s, March 28, 2024, p. 6. extent that energy transition increased or decreased the need for capital investments, this is dealt with through the regular rate cases, rather than a generic consideration. Several ratepayer groups submitted that...

AI summary Ratepayer groups and organizations discuss the impact of energy transition on capital investments and risk for electricity utilities. Some argue that energy transition is not yet significant and may reduce risk, while others emphasize the need to account for energy transition risk in rate cases. The EDA and OEA highlight that energy transition is inevitable and that new capital is required now, which introduces risk.

Regulatory and Rate-Setting Mechanisms OEB staff agreed with LEI and Dr. Cleary that any regulatory mechanism that can significantly impact the stability of future cash flows must be considered part of regulatory risks. OEB staff concluded...

AI summary OEB staff, LEI, and Dr. Cleary argue that regulatory mechanisms since 2009 have moderately reduced utility risk, but the OEA cautions that this does not fully reflect overall business risk. CCC, Pollution Probe, SEC, and Energy Probe support the view that regulatory policies have decreased risk, citing improvements like DVAs and capital cost recovery. VECC and CME suggest that policy changes should be reflected in ROE or capital structure adjustments.

Submissions Submissions were made by the Three Fires Group Inc. and Minogi Corp. (TFG/Minogi), as well as the Caldwell First Nation (CFN) and Mississaugas of the Credit First Nation (CFN/MCFN). Three proposals were made by TFG/Minogi, whic...

AI summary Submissions were made by TFG/Minogi and CFN/MCFN regarding risk premiums, WACC, and concurrent cost recovery for Indigenous equity participation and large projects. CFN/MCFN emphasized the need for engagement with First Nations and addressing their unique interests in the OEB's cost of capital policies.

from ratepayers. OEB staff agreed with LEI that a 50 basis point adder "is likely to overcompensate utilities" and that there were two ways this could be remedied (with the first option recommended): - 1. Utilities would be able to include...

AI summary OEB staff suggested reducing the 50 basis point adder for transaction costs to 25 basis points, arguing it overcompensates utilities. EDA disagreed, stating transaction costs should be included in the deemed cost of capital. Pollution Probe supported reducing the adder but allowed for utilities to provide evidence in rate proceedings for higher values.

Findings The flotation cost adder of 50 basis points currently added to the ROE presents several difficulties in addressing costs attributed to have been incurred by Ontario utilities for maintaining equity. The adder is meant to recognize...

AI summary The flotation cost adder of 50 basis points added to the ROE faces challenges in addressing costs incurred by Ontario utilities. The adder is intended to cover expenses like underwriting fees, but few utilities rely on public equity markets. The 2009 Report lacks information on the derivation of the 50 basis point figure, and Nexus argues the adder should remain in perpetuity due to amortization over infinity, despite no evidence of initial scrutiny.

Submissions OEB staff and several ratepayer groups agreed with LEI and Dr. Cleary that the status quo approach (considering deemed capital structure regardless of the actual capital structure) should be retained. OEB staff noted that this...

AI summary The discussion centers on the appropriate method for pricing notional debt in utility rate-making, with OEB staff, ratepayer groups, and others debating whether to use the weighted average cost of actual long-term debt, the DLTDR, or alternative approaches. There is emphasis on fairness, credit ratings, and the need for consistent policy.

ized treasury operations at the holding company level for all of the utility's subsidiaries. • The DLTDR shall not apply as a ceiling for external prudently incurred marketbased debt for any utility. The DLTDR will not be applied as a firm...

AI summary The DLTDR is not applied as a ceiling for external market-based debt for utilities, and the OEB will assess whether the cost of debt is prudently incurred. Utilities must demonstrate prudent debt management and file evidence explaining their long-term debt management processes.

Submissions Several ratepayer groups and OEB staff disagreed with LEI and submitted that the current approach of recording the actual transaction cost as an interest expense and amortizing the transaction cost over the term of the debt ins...

AI summary Ratepayer groups and OEB staff disagree with LEI's approach to recording debt transaction costs, supporting instead the current method of amortizing these costs over the term of the debt instrument. CCC and OEA also support the current approach, while CCMBC agrees with LEI that these costs should be included as OM&A costs in the revenue requirement.

Findings For utilities incurring transactions/issuance costs to secure financing from the market, the transaction/issuance costs should be incorporated into the debt interest rate used to set rates, so that the transaction costs are amorti...

AI summary The OEB recommends that transaction/issuance costs incurred by utilities when securing financing should be incorporated into the debt interest rate used for rate setting, to be amortized over the term of the debt instrument. However, these costs are not included in the DLTDR, as it is a proxy for market-based long-term debt and does not reflect the full cost structure of actual debt issuance.

Submissions OEB staff and a number of ratepayer groups agreed with LEI and Dr. Cleary that consistent with the OEB's existing policy, the OEB should continue to implement changes in the cost of capital parameters and capital structure upon...

AI summary The OEB staff and ratepayer groups recommend aligning cost of capital changes with rebasing, while the CCC and SEC caution against mid-term adjustments in Price Cap IRM terms. The OEA supports implementing changes in the next rate year, and the OEB established variance accounts for utilities rebasing in 2025.

Findings The OEB will apply the same approach for determining the prescribed interest rate for DVAs that it has established for the DSTDR, for the same reasons provided under that issue. This approach is to use the Bloomberg ticker BVCAUA3...

AI summary The OEB will use the same approach for determining the prescribed interest rate for DVAs as it does for the DSTDR, using the Bloomberg ticker BVCAUA3M BVLI Index. The rate for Q2 2025 is set at 3.16%. The OEB rejects Concentric's argument for applying a long-term rate like WACC to DVAs, citing concerns about double compensation and lack of evidence supporting long-term funding of DVAs.

Expert Report Proposals For CWIP, LEI recommended (and Dr. Cleary agreed) continuing the current approach of basing the prescribed interest rate on the FTSE Canada Mid Term Bond Index All Corporate yield for all construction projects, rega...

AI summary LEI recommended continuing the current approach of using the FTSE Canada Mid Term Bond Index All Corporate yield for CWIP, while Concentric disagreed, suggesting the use of WACC to better reflect the full financing cost, especially for long-term projects. Concentric also noted that the current method may understate costs and put Ontario utilities at a disadvantage compared to peers.

4 COST AWARDS The following parties (collectively the Eligible Participants) applied for and were granted cost award eligibility: - Association of Major Power Consumers in Ontario (AMPCO) - Association of Power Producers of Ontario (APPrO)...

AI summary The Office of the Energy Board (OEB) granted cost award eligibility to various participants and outlined procedures for cost recovery from rate-regulated companies. The OEB will conduct a full review of all cost claims and allow for objections and replies. Cost claims are to be filed according to the OEB's Practice Direction on Cost Awards.

THE ONTARIO ENERGY BOARD ORDERS THAT: - 1. The following cost of capital parameters are approved on a final basis, effective January 1, 2025. Please refer to the Decision for details regarding implementation and applicability. - a. The Dee...

AI summary The Ontario Energy Board has finalized cost of capital parameters, including a Deemed Return on Equity of 9.00%, Deemed Long-Term Debt Rate of 4.51%, and Deemed Short-Term Debt Rate of 3.91%, effective January 1, 2025. Prescribed interest rates for deferral and variance accounts and construction work in progress are also set, with annual and quarterly updates required. Utilities must report on new long-term debt exceeding $50 million.

a) Prescribed Interest Rates 20.Should the prescribed interest rates applicable to DVAs and the construction work in progress (CWIP) account for electricity transmitters, electricity distributors, natural gas utilities, and OPG continue to...

AI summary The text discusses the prescribed interest rates for Deferral Vehicles (DVAs) and Construction Work in Progress (CWIP) accounts for various utilities and OPG, and whether the current approach should continue. It also raises a question about the applicable rate for a Cloud Computing deferral account.

4.2.3 Regulator Prioritizing Total Price Level One further explanation for the emergence of the RoE gap could be that regulators have different priorities besides setting a capital-cost-reflective rate of return. In particular, there is ev...

AI summary This section explores how regulators may prioritize the total price level of energy for consumers over capital-cost-reflective rates of return. It suggests that when wholesale costs are high, regulators may impose stricter rates of return, while allowing more generous returns when wholesale costs are low, as seen in the regression analysis of the RoE gap on wholesale prices.

inning in 2021, Ms. Morgan and Bates White reviewed Mississippi Power Company's (MPC's) Capital Plan and EDP filings since they are required pursuant to Amended Rule 29. KAREN MORGAN, CFA Page 2 of 6 In Nova Scotia, Ms. Morgan testified in...

AI summary Karen Morgan testified before the Nova Scotia Utility and Review Board on rate applications by Nova Scotia Power Inc. and NSP Maritime Link. She also provided testimony in Mississippi on behalf of the Mississippi Public Utilities Staff regarding rate rider assessments for Atmos Mississippi.

e Energy Request for Change in Distribution Rates. On behalf of the NH Office of Consumer Advocate. January 23, 2025 and June 4, 2025. Issues covered: cost-of-service study, residential rate design. Massachusetts Department of Public Utili...

AI summary The text outlines various testimonies provided by Caroline Palmer and others in different regulatory proceedings across multiple jurisdictions. These testimonies cover topics such as cost-of-service studies, residential rate design, revenue requirement, and stranded cost rate design, and were presented on behalf of various consumer advocacy and legal offices.

1.2.3 Cost Allocation Informational Filings In March 2006, following stakeholder consultations, the Board will issue a Report adopting common cost allocation principles and methodologies for the OEB cost allocation review. Select rate desi...

AI summary In March 2006, the Board will issue a report adopting common cost allocation principles and methodologies following stakeholder consultations. Mandatory filing requirements and a model will be released in July 2006, with all Ontario electricity distributors required to submit new cost allocation studies publicly during the fall of 2006.

Section 2: Overview of Cost Allocation Cost allocation studies serve the following main purposes: - to allocate the costs to provide service to the various customer rate classes based on cost causation principles - to assess the reasonable...

AI summary This section outlines the purposes and processes of cost allocation studies, which are used to allocate distribution and operational costs to customer rate classes based on cost causation principles. The studies assess the reasonableness of rates and support rate design. A three-step process—functionalization, categorization, and allocation—is described for assigning costs to rate classes.

5.2.1 Use of Generic Categorization Methods and Results In the present context, the selection of cost allocation methodologies and their application must also take into account the need for distributors to execute, and the OEB to review, a...

AI summary The document discusses the use of cost allocation methodologies for distributors, recommending the Basic Customer Method due to its simplicity, while cautioning against the use of more complex methods like Zero-Intercept and Minimum System due to technical and data challenges. An external consultant is being used to gather generic results for use in filings.

5.3 Initial Recommendations To provide the Board and stakeholders with the most useful information to assess variations in fixed monthly customer charges, the cost allocation filings should incorporate two different categorization methods....

AI summary Staff recommends incorporating two categorization methods in cost allocation filings to assess variations in fixed monthly customer charges. The first method is the Basic Customer Method, while the second will be determined after reviewing survey results and stakeholder input.

6.1 Background The final stage of a cost allocation study is the allocation of costs to customer classes. At this stage, costs have been functionalized and categorized into demand and customer-related components. For demand-related costs,...

AI summary The final stage of a cost allocation study involves allocating costs to customer classes, with demand-related costs using load data and customer-related costs using accounting records or customer numbers.

6.2.1 Background There are several technical factors to consider when allocating the demand-related component of distribution facilities. Some distribution facilities are designed to meet the individual customer's maximum demand, while oth...

AI summary The text discusses technical considerations for allocating demand-related costs in distribution facilities, distinguishing between coincident and non-coincident peak methods. It highlights how different types of facilities use varying demand metrics for design and cost allocation.

Direct Allocation Some distribution facilities could be dedicated to only one customer. In such cases, the costs should be directly allocated to the customer. Care should however be taken not to directly allocate costs to a customer and la...

AI summary Direct allocation of costs to a single customer is discussed, with considerations on when and how it should be applied. It emphasizes the need for supporting documentation and materiality tests, and seeks stakeholder input on clarity of conditions for direct allocation.

6.2.5 Initial Recommendations regarding Demand Allocation Where a distribution asset is used by a single user, and the amount involved is material, a direct allocation is recommended. The utility must provide full supporting engineering an...

AI summary The document outlines initial recommendations for demand allocation, emphasizing direct allocation for single-user distribution assets and recommending the use of CP, Individual NCP, and Class 1 NCP for different types of distribution facilities. Adjustments for line losses, engineering details, and PLCC are also recommended.

6.3.3 Initial Recommendations From a cost causality standpoint, it is recommended that weighted allocation factors be used for most customer-related costs since these costs generally vary as a function of several cost drivers. They include...

AI summary The document recommends using weighted allocation factors for customer-related costs based on cost drivers like the number of customers and investment costs. It suggests developing standard factors based on North American utility surveys, while allowing distributors to propose alternative factors if justified by their specific circumstances.

Use of Load Data in Establishing Demand Allocators While there are a number of methods to allocate distribution demand-related costs, all require the use of load data. It is widely recognized that load data plays an important role in the a...

AI summary Load data is essential for accurately allocating distribution demand-related costs. The American Public Power Association highlights that the accuracy of demand load data significantly affects the allocation of capacity costs to customer classes of service.

8.2.1 Background The 2003 Working Group spent considerable time examining the need for, and manner of, weather normalizing the load data to be used when allocating demand-related costs. 9 The rationale for weather normalizing has been summ...

AI summary The 2003 Working Group examined the need for weather normalizing load data to allocate demand-related costs more fairly. Weather normalization adjusts peak demand to reflect typical weather conditions, which helps stabilize cost allocation. The impact of weather on demand can vary significantly, with estimates ranging from 1%-2% for energy and up to 10% for peak demand.

Should weather normalization be required? In the first phase of the consultations, Staff proposes to address the following two questions: 1) should utilities be required to weather normalize the load data collected? and, 2) if so, should a...

AI summary The Staff proposes that Ontario electricity distributors be required to weather normalize load data for cost allocation studies, citing significant weather effects on load data and the potential for industry cooperation to reduce costs. A common weather normalization method is also recommended to ensure consistency across distributors.

9.1 Background It is anticipated that in March 2006 the Board will issue a Report on Cost Allocation Principles and Methodologies. The subsequent third phase of consultations will then deal with implementation issues. Following the third p...

AI summary The Board plans to issue a Report on Cost Allocation Principles and Methodologies in March 2006, followed by a third phase of consultations on implementation issues. In July 2006, the Board intends to release a cost allocation filing model, general filing instructions, and a summary template.

9.2 Cost Allocation Filing Period A cost allocation study is performed by using the Board-approved revenue requirement and data for a one-year reference period or "test year". A decision is required on the appropriate test year for the cos...

AI summary This section outlines the process for conducting a cost allocation study, using the Board-approved revenue requirement and data from a one-year reference period. Staff recommends using the 2006 revenue requirement as a starting point, with adjustments for non-utility operations and non-recurring regulatory accounts. Stakeholder input is requested on additional potential adjustments.

9.3 Summary of the Study A summary will be required with the cost allocation filings including an explanation of the study results. In addition, the summary should include the rationale, and supporting documentation (including any material...

AI summary The summary of the study is required with cost allocation filings and must explain study results, rationale, and supporting documentation for alternative cost allocation methods. Examples include documentation for direct allocation of demand-related costs and load study methodology.

9.5 Other Data Issues Data availability and consistency issues will be addressed during the third phase of the consultation. Comments will be sought on the source of sufficiently disaggregated filing data, for example, where a distributor...

AI summary The third phase of the consultation will address data availability and consistency issues. Comments will be sought on the source of disaggregated filing data, especially when functions are outsourced. The consultations will also ensure consistency in mapping underlying costs and accounts into the cost allocation model.

9.7 Use of OEB Model The purpose of the present cost allocation informational filings is to gather detailed costbased information. Consistency in the filings received from distributors is a crucial goal. The need to review approximately ni...

AI summary The Board is proposing a standard cost allocation filing model to ensure consistency among distributors. The model will be based on approved methodologies and principles, with mandatory use unless an exemption is granted. Distributors using their own models must align with the Board's standards and produce equivalent outputs.

Cost allocation studies Staff will seek stakeholder input on the development of a methodology to accurately track the costs for this new rate classification. This will ensure that other ratepayers are not unfairly treated by the creation o...

AI summary Staff proposes a methodology to allocate costs for a new scattered unmetered load class, ensuring fairness for ratepayers. Unmetered loads should bear full distribution asset costs, excluding metering and billing costs sent to a central office. Stakeholder input is requested on additional costs to allocate or exclude.

10.3 Initial Recommendations Staff recommends that a new scattered unmetered load class be set up as part of the cost allocation model and that a full cost allocation study be performed for the new class. Staff further recommends that the...

AI summary Staff recommends creating a new scattered unmetered load class and conducting a full cost allocation study. They also suggest splitting the fixed monthly charge into two components: one per customer and another for individual connection costs, with remaining distribution costs recovered through a volumetric charge.

Allocating costs to the new class Staff has identified two approaches to the issue. The first would be to require that a cost allocation methodology be followed when allocating costs to the embedded distributor customer class. This would r...

AI summary Staff proposes two approaches for allocating costs to the new customer class. The first involves using a standardized cost allocation methodology, while the second suggests following a different approach used by former Ontario Hydro. Staff advocates for a consistent methodology across all distributors, despite potential complexities in some cases.

Appendix 1 – Direct Assignment of Accounts Appendix 1 - Direct Assignment of Accoun its 1830 Poles, Towers and Fixtures O-NCP NCP for customers with overhead service only 1835 Overhead Conductors and Devices OD-NCP NCP for customers with o...

AI summary This appendix outlines the direct assignment of accounts related to utility infrastructure and demand management expenditures. It includes categories such as poles, towers, conductors, and transformers, along with their respective cost allocation methods, such as NCP and CP, and provides details on accumulated amortization and demand-related cost allocations.

ad data. An Appendix contains a specific Province-wide joint load data collection proposal from over 40 distributors ("the Ontario Load Data Research Group") serving the majority of Ontario customers. The Working Group's Report focused on...

AI summary The document outlines the Board's 2003 Load Data Collection Directions, which were developed based on a proposal from the Ontario Load Data Research Group. The directions focus on the collection of load data for cost allocation studies related to 2006 rates. The Board received feedback from various stakeholders, including Hydro One, Guelph Hydro, and others, and has issued final directions on the matter.

Average v. Marginal Cost The Working Group was asked to assess the merits of an average versus a marginal cost approach to undertaking the upcoming cost allocation studies. The Group recommended use of an average ("embedded") cost approach...

AI summary The Working Group recommended using an average (embedded) cost approach for upcoming cost allocation studies, similar to Ontario's natural gas distributors. The Board accepted this recommendation, emphasizing that marginal pricing principles may still be considered during the rate design stage.

Cost Allocation Financial Case Studies The Working Group suggested that three cost allocation financial case studies be undertaken. The Board will not issue directions in this regard at present, as it wishes to focus on the immediate load...

AI summary The Working Group recommended three cost allocation financial case studies, but the Board will not issue directions at this time, focusing instead on immediate load data collection. Stakeholders value the case studies for clarifying financial data needs and addressing differences in interpreting the current system of accounts. The Board will consider incorporating case studies into the cost allocation consultations.

Issue 1) What type of load data should be collected? To provide the full range of data that may be needed when subsequently completing the cost allocation studies, the Working Group recommended interval load data be collected. The Board ag...

AI summary The Working Group recommends collecting interval load data for cost allocation studies. The Board agrees and specifies that the interval should not exceed one hour, addressing concerns raised by Guelph Hydro regarding appropriate time intervals.

Issue 3) In order to ensure reliability of the load data gathered, what sampling methodologies are appropriate? The Working Group recommended that any of the statistically-verifiable sampling methodologies discussed in the leading North Am...

AI summary The Working Group recommends using statistically-verifiable sampling methodologies from the AEIC's Load Research Manual for load data collection. The Board supports this and suggests that Ontario distributors may adopt a common methodology to facilitate data sharing. The Board also advocates for a province-wide sampling program to achieve cost efficiencies and ensure data reliability.

Issue 5) Is additional metering needed? Are there any practical constraints if additional metering is required? a) Re Timing: The Working Group advised that it is not feasible to commence load data collection on January 1, 2004 (as origina...

AI summary The Board addresses Issue 5 regarding the timing and costs of additional metering for load data collection. It acknowledges delays in metering due to installation and testing timelines and directs that data collection commence by February 1, 2004. The Board also agrees that a joint load data collection initiative is more economical than individual programs.

Issue 11) Relationship between load data to be collected and rate classifications. The Working Group recommended that the present rate classifications be the starting point for designing the load research program and, as a result, each dis...

AI summary The Board accepts the Working Group's recommendations on load data collection for rate classifications, directing that updated interval load data be collected for each rate classification in the 2006 rates application, with exceptions for certain cases such as similar load profiles and deemed load profiles for specific uses.

b) Other unmetered scattered loads The Working Group recommended that each distributor establish and verify a deemed load profile for scattered unmetered loads. The Board accepts this recommendation and notes the importance of verifying a...

AI summary The Board accepts the Working Group's recommendation that distributors establish and verify deemed load profiles for scattered unmetered loads. It emphasizes the need for reasonable profiles and encourages cooperation with customers and cable operators like Rogers Cable TV. Distributors are directed to provide full details in cost allocation studies and address customer concerns through rate hearings if needed.

h) Back-up rates for embedded generation The Working Group was unsure of the potential load data needs for "back-up" rates in respect of embedded generation (to be used, for example, when a cogeneration facility is down for maintenance). A...

AI summary The Working Group is uncertain about the load data requirements for 'back-up' rates related to embedded generation. The Board instructs distributors to include relevant load and financial data in their cost allocation filings and will determine whether to address the matter in the generic cost allocation proceeding or separately.

1.1 Purpose of Report This Report sets out the Board's common cost allocation methodology to govern the cost allocation review informational filings due from licensed electricity distributors starting in the Fall of 2006. The Board release...

AI summary This report outlines the Board's cost allocation methodology for licensed electricity distributors, following the release of a staff proposal and additional comments in 2006. A filing model and instructions will be issued in October 2006, with distributors required to submit filings as per their licence requirements.

1.5.1 Common Cost Allocation Methodology In this Report the Board has established a common cost allocation methodology for use by Ontario electricity distributors. To assist in the completion and review of the filings, certain default valu...

AI summary The Board has established a common cost allocation methodology for Ontario electricity distributors, emphasizing sound cost causality and using consistent methodology with utility-specific inputs to support cost allocation reviews.

1.5.7 Summary of the Cost Allocation Filing In addition to filing a completed model, all distributors will be required to file an accompanying Summary of the Cost Allocation Review Filing ("Filing Summary"). The Filing Summary should inclu...

AI summary Distributors must file a Summary of the Cost Allocation Review Filing alongside their completed model, including management comments on the interpretation of results and explanations if the approved methodology does not reasonably portray cost causality in their specific circumstances.

1.9 Filing Process Distributors will be required to submit their cost allocation filings to the Board in one of the four following tranches (for details, see Appendix 1.3): - 1) November 30, 2006 - 2) January 15, 2007 - 3) February 28, 200...

AI summary Distributors must submit cost allocation filings to the Board in four tranches by specific dates. They are encouraged to collaborate with load data service providers and begin background work promptly. The filings will be made public, and additional background work is discouraged.

1.11 Potential Future Implementation in Rates In light of the extensive effort given to this process and the Board's deliberations with respect to the appropriate cost allocation methodology, parties should expect that the Board will give...

AI summary The Board emphasizes the importance of the cost allocation methodology used in this Report, which will heavily influence future rate hearings. Adjustments to cost allocations, rate classifications, or rate design will be determined based on the review of filings and upcoming consultations. Distributors may be required to address specific matters in future rate applications, with potential implementation of new rates as early as May 2008.

2.2.2 Unmetered Scattered Loads ("USL") in Run 1 and USL Metering Credit Certain customer loads have traditionally not been metered by most distributors. Specific examples include such loads as: bus shelters, phone booths, CATV amplifiers,...

AI summary The document discusses the treatment of Unmetered Scattered Loads (USL) in the context of cost allocation filings. It outlines two approaches for allocating costs to USL customers, referencing the 2006 EDR Handbook and rate orders. Distributors are advised to consider the underlying substance of their current USL rates and explain their choice of approach in the Filing Summary.

2.3.4 Common Separate Rate Classification for Embedded Distributors There are a number of host distributors that are providing a distribution service to embedded distributors. In some cases, host distributors have created a separate rate c...

AI summary The document discusses the need for a common separate rate classification for embedded distributors, noting that some host distributors have already created such classifications or treat embedded distributors as General Service customers. The Board recommends modeling a common classification in Run 2 filings, while acknowledging stakeholder concerns about the cost rationale for separate classifications.

3. Load Data Requirements The Chapter sets out the Directions on load data requirements for the cost allocation filings.

AI summary This section outlines the Directions regarding load data requirements for cost allocation filings, which are essential for regulatory proceedings related to energy costs and distribution.

3.5.2 Directions – Additional Model Output For purpose of sensitivity analysis, the filing model should include an output to show the difference in revenue based on using the approved kWhs from the 2006 EDR model and the normalized kWhs pr...

AI summary The document outlines requirements for sensitivity analysis in a filing model, emphasizing the use of approved kWhs from the 2006 EDR model and normalized kWhs from the filer's load data service provider. It also highlights the need to adjust for losses in billing data and explains how distributors should compare methodologies in their cost allocation filings.

4.1.2 Direction – Distributors that used a historical test year in the EDR 2006 application For distributors that used a historical test year in their 2006 EDR applications, the underlying 2004 trial balances will be the basis of the cost...

AI summary Distributors that used a historical test year in their 2006 EDR applications must use 2004 trial balances as the basis for cost data, with specific adjustments. Costs related to non-utility operations and non-recurring regulatory accounts should be excluded. Adjustments to distribution rates for smart meters are excluded, and proper cost allocation is emphasized, including moving costs between accounts.

4.2.2 Direction - Definition of Revenue for Cost Allocation Filings The service revenue requirement on sheet 5-1 of the distributor's approved 2006 EDR model will be the basis of ensuring all the proper costs have been included in the cost...

AI summary The document outlines the definition of revenue for cost allocation filings, specifying that the revenue per rate classification from the approved 2006 EDR model must be used. It details the components of revenue, including base revenue, revenue off-sets, and CDM allocations, while excluding certain adjustments like regulatory asset adders and smart meter adjustments.

5.1 Background As an initial step in a cost allocation study, a distributor should identify any significant distribution facilities that are dedicated exclusively to only one customer rate classification. The costs of such a facility, and...

AI summary The document discusses the principles and criteria for direct allocation of distribution costs to specific customer rate classifications. It emphasizes that direct allocation should only apply when facilities are exclusively used by a single classification and addresses scenarios involving redundancy and backup services. The Board prefers the 100% use test for direct allocation and rejects the use of a 'predominant' (90%) test due to complexity in cost allocation.

5.2 Direction – Direct Allocation Methodology Direct allocation must be applied if, and only if, 100% of the use of a clearly identifiable and significant distribution facility can be tracked directly to a single rate classification. If a...

AI summary The document outlines the conditions and requirements for using the direct allocation methodology in distribution cost allocation. It specifies that direct allocation must be used when 100% of the use of a distribution facility can be traced to a single rate classification and details the supporting documentation required.

6. Functionalization Directions on the process to functionalize costs in the cost allocation filings are presented in this Chapter.

AI summary This section outlines the process for functionalizing costs in cost allocation filings, providing guidance on how to categorize and allocate costs appropriately within regulatory proceedings.

6.1.1 Background The process of functionalization of costs is an important step in the cost allocation process, as it sets up the framework for the categorization and allocation steps. The functionalization step is the process that groups...

AI summary The functionalization of costs is a key step in the cost allocation process, grouping homogeneous costs into functions. The Uniform System of Accounts (USoA) for Ontario distributors is used to standardize this process. Costs are then categorized as demand-related or customer-related based on factors discussed in Chapter 7.

6.1.2 Direction - Grouping of Accounts and Sub-accounts in Cost Allocation Filings In the cost allocation filings, each adjusted 2004 account shown in column P of Sheet 2-4 of the approved 2006 EDR application will be placed into a group t...

AI summary This section provides guidance on grouping accounts and sub-accounts in cost allocation filings, based on the approved common cost allocation methodology. Each adjusted 2004 account from the 2006 EDR application is to be grouped with others sharing a common allocation process, and sub-accounts are also to be grouped accordingly. Appendix 6.1 provides a comprehensive mapping of these groupings.

Functional Approach The bulk, primary and secondary sub-accounts relate to assets associated with performing bulk, primary and/or secondary functions within a distribution system. The key objective of the cost allocation is to allocate cos...

AI summary The document discusses the 'functional approach' for allocating distribution costs based on the functions of bulk, primary, and secondary assets. It emphasizes the importance of cost causality and simplicity in the allocation method, noting that a voltage-based test is not universally applicable. The Board concludes that a functional approach best identifies bulk assets.

Stakeholder Discussions on Bulk Asset Test The Board believes the most appropriate manner to implement a functional approach towards identifying bulk assets involves a separation of the distribution assets to identify any assets that were...

AI summary The Board discusses the implementation of a functional approach to identify bulk assets, emphasizing the need for a clear definition to ensure consistent cost allocation. The approach focuses on system peak considerations and addresses stakeholder concerns about inconsistent application of the bulk asset test.

6.2.2.2 Direction – Definition of Bulk A functional approach must be adopted towards identifying the assets that may serve a bulk delivery function in some distribution systems. The test to determine if any bulk assets exist in a given dis...

AI summary The document outlines a functional approach to identify bulk delivery assets in distribution systems, emphasizing that assets built to support the system's peak, not the customer's peak, should be classified as bulk assets for cost allocation purposes.

6.2.2.3 Implementation Guidance on Application of Bulk Definition For cost allocation purposes, as indicated the test to be applied by distributors in defining bulk assets is to identify those assets that were built to support the distribu...

AI summary This section provides guidance on defining bulk assets for cost allocation purposes. Bulk assets are those specifically built to support the distribution system's peak, and should be allocated using Coincident Peak (CP), while primary and secondary assets are allocated using Non-Coincident Peak (NCP). Factors like voltage level and system configuration are considered in determining the function of assets.

6.2.2.7 Specialized Circumstance When the Technical Advisory Team commenced its discussions of functionalization, participants noted that subtransmission costs had been segregated in a previous application submitted to the Board by Hydro O...

AI summary The Board allows Hydro One to use a subtransmission cost pool in its upcoming cost allocation filing, provided it explains and justifies this approach, including the impact compared to a standard bulk asset cost pool. The Board also expects Hydro One to provide further justification if it uses CP for allocation, considering Chapter 8's guidance on CP and NCP usage.

7.2 Direction – Identification of Accounts For the cost allocation filings, functionalized grouped costs will be ultimately classified into one of the four components: - 100% demand-related - 100% customer-related - joint related (both cus...

AI summary This section outlines the classification of functionalized grouped costs into four categories: 100% demand-related, 100% customer-related, joint related, and pro-rata related. Examples include metering and billing as customer-related, distribution stations as demand-related, and joint costs like poles and transformers. Pro-rata related costs are allocated based on specific methods outlined in Chapter 10.

Option 2: Minimum System Method The minimum system method assumes that a minimum-size distribution system can be built to serve the minimum load requirements of the customer. The minimum system method involves determining the minimum size...

AI summary The minimum system method assumes a minimum-size distribution system can be built to serve customer load requirements. It classifies costs as either customer-related or demand-related. The method involves determining the minimum size of distribution infrastructure and adjusting for peak load carrying capability to ensure accurate cost allocation.

7.3.2 Direction – Use of Minimum System Method and Basic Customer Method in Filings For cost allocation purposes, the minimum system approach will be used as the common categorization method. Generic minimum system results will be set out...

AI summary The document outlines the use of the minimum system method and basic customer method for cost allocation in filings. It specifies that the minimum system approach will be used for calculating revenue to cost ratios and splitting joint costs, with a standard PLCC adjustment. The basic customer method will be used to determine the lower range of unit costs, while the minimum system method will establish the upper range.

7.4.2.3 Background - Stratification of Generic Minimum System Results Technical Advisory Team discussions took place on how to fairly and consistently define density for purposes of the cost allocation filings. The question is of practical...

AI summary The document discusses the technical advisory team's efforts to standardize the definition of density for cost allocation filings. It highlights inconsistencies in how different distributors calculate density and outlines the rationale for using road km instead of circuit km. The Board may be asked to consider refining density definitions or stratum boundaries in the future.

7.4.2.4 Direction – Density Thresholds and Measurements for Cost Allocation Filings For purposes of stratifying the generic minimum system results used in the cost allocation filings, 30 customers per kilometre will be the dividing line be...

AI summary This section outlines guidelines for determining density thresholds and measurement methodologies for cost allocation filings, specifying customer per kilometre thresholds and defining line length and customer count criteria. It also allows for alternative density classifications with appropriate justification and documentation.

7.5.1 Background – PLCC Adjustment The minimum distribution system will carry a small amount of demand. The actual amount of demand capability within the minimum system is a function of load density, minimum required clearances, minimum eq...

AI summary The PLCC adjustment aims to correct over-allocation of demand costs by crediting the minimum system's capacity against non-coincident peak demands. The Board approved a generic 0.4 kW adjustment per customer/connection, rejecting stakeholder suggestions for larger adjustments or zero thresholds, as they contradict the principle of equal cost allocation for the minimum distribution system.

Customer Unit Cost Adjustment Another output of the filing model is customer and demand unit costs by rate classification. These unit costs can be used to help set future distribution rates; however, to reflect the results of the PLCC adju...

AI summary The filing model produces customer and demand unit costs by rate classification, which can be used to set future distribution rates. To reflect the PLCC adjustment, customer-related costs should be moved into demand-related costs before rate determination, though the total cost allocated to the rate classification remains unchanged.

7.7.1 Background The minimum system methodology to be adopted will allocate certain customerrelated costs to individually metered customers in multi-unit complexes. But the multi-unit complexes have sometimes been considered, in past studi...

AI summary The document discusses the allocation of customer-related costs in multi-unit complexes, noting that past studies sometimes treated them as single customers. A stakeholder suggested a multi-unit adjustment based on cost causality, but no such adjustments will be included in current filings due to data challenges. The Board encourages distributors to gather more information for future improvements.

8.1 Introduction The accounts/sub-accounts that, following the categorization step, are allocated on demand in total or in part were listed in Appendices 7.1 and 7.3. There are several technical factors to consider when properly allocating...

AI summary This section outlines the allocation of demand-related costs for distributors, introducing CP and NCP as methods for cost allocation. It notes that NCPI was used previously but will not be used in the current filing methodology due to complexity and other allocation methods.

8.2.2.2 Direction - Tests for Use of NCP in Filings NCP will be the demand allocator used when allocating assets identified by a distributor as primary or secondary assets. 4 NCP will be the starting point for the common demand allocator t...

AI summary The document outlines the use of Non-Coincident Peak (NCP) as a demand allocator for cost allocation filings, specifying that 1 NCP is used when a pronounced peak exists, confirmed by a test where the highest month exceeds 20% of the average of the highest four months. The NCP test formula is provided, with thresholds for using 1 NCP or 4 NCP, and 12 NCP may be used in optional Run 3 with justification.

9.2 Definition of Customer and Connection for Filings The accounts/sub-accounts that are allocated based on the number of customers or connections in total or in part were listed in Appendices 7.2 and 7.3 . For the purpose of the cost allo...

AI summary The document defines 'customer' and 'connection' for cost allocation filings, using meter points for measured energy consumption and the number of connections for unmetered loads. For street lights, a connection factor may be applied to adjust for overstatement of physical connections.

9.3.1.1 Background A common allocator used to allocate customer-related costs that are related to billing activities is the number of bills issued. The major accounts allocated on this basis are billing, collecting and associated supervisi...

AI summary The document discusses the allocation of customer-related costs based on the number of bills issued, including billing, collection, and customer care costs. Some parties suggested applying weighting factors to account for differences in costs across customer classifications, which the Board agreed to. Flexibility is provided for handling rate classifications not covered in the survey and for using utility-specific factors.

9.3.1.2 Direction – Allocation of Billing Activities The number of bills adjusted by a weighting factor must be used to allocate costs associated with billing activities which include billing, collecting, and associated supervision and cus...

AI summary The document outlines the allocation of billing activities costs using a weighting factor based on the number of bills. It provides guidelines for using default weighting factors, allows for distributor-specific adjustments, and specifies that sentinel lights should be weighted at 0.10 for cost allocation purposes.

9.3.2.2 Direction – Allocation of Meter Capital Costs Default installed meter capital costs will be provided for use when allocating meter capital costs. These are listed in Appendix 9.2. A distributor will enter the estimated number of in...

AI summary The document outlines a method for allocating meter capital costs across different rate classifications. It specifies the use of default costs, the inclusion of utility-installed meters, and the calculation of allocation percentages. Flexibility is provided for entering additional meter types if they differ significantly in cost from defaults, and small distributors may need to provide specific information if their costs differ materially.

9.3.3.2 Direction – Allocation of Meter Reading Costs Default "relationship factors" related to meter reading costs are provided for use when allocating meter reading costs. Details are set out in Appendix 9.3. The cost to read a residenti...

AI summary The document outlines a method for allocating meter reading costs using relationship factors based on a residential urban outside meter as a base. Distributors must input data on installed meters and apply relationship factors to determine relative costs for each rate classification. Flexibility is allowed for up to five additional meter types if their reading costs differ by at least 10% from defaults.

9.3.4.2 Direction - Allocation of Services Costs The weighted number of customers or connections will be used to allocate costs related to Services (Account 1855). It is intended that the weightings reflect the differing average costs of c...

AI summary The weighted number of customers or connections is used to allocate costs related to Services (Account 1855), with default weighting factors provided in Appendix 9.4. Distributors must use specific weighting factors if their actual costs differ by 10% or more from defaults and provide supporting information. The Filing Summary must indicate if there are no costs in Account 1855 and explain the reason.

10.2.2 Direction – Allocation of General Plant General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets (average of opening and closing balances for the test year), with no adjustment for con...

AI summary General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets, with no adjustment for contributed capital. Distributors with detailed analysis must use this information in cost allocation models and provide supporting documentation.

10.6.1 Background Bad debt expense consists of the amounts of uncollectible revenues. Many distributors monitor their bad debt write-offs at the rate classification level. The Accounting Procedures Handbook (Article 220) requires distribut...

AI summary The document discusses the allocation of bad debt expenses to customer rate classifications, recommending a method based on historical write-offs. It notes lack of stakeholder consensus and addresses concerns about normalization periods and fairness. The Board supports the staff's recommendation for cost allocation purposes.

gas DSM hearing (EB-2006-0021), it was agreed by all participants that costs should be allocated on the same basis as budgeted spending. This allocation would apply to both direct and indirect costs. Several stakeholders commented on the A...

AI summary The document discusses the allocation of CDM costs in the gas DSM hearing, with stakeholders proposing different methods based on energy use, distribution revenue, and the Global Adjustment Mechanism. Some support the August proposal, while others argue for an 80/20 energy/demand allocation. The Board concludes to maintain the electricity sector status quo for cost allocation.

11.2.2 Direction – Cost Allocation Methodology for Density- Based Classifications A distributor with density-based rate classifications is expected to be able to use the standard model in Run 1 and Run 2, but work must be undertaken to add...

AI summary The document outlines a standardized cost allocation methodology for distributors with density-based rate classifications. It requires the use of a single categorization factor, identification of density-influenced costs, and the application of density factors in cost allocation, with detailed analysis required for maintaining classifications.

11.5.1 Introduction At present, a number of distributors have approved interim standby rates. In some cases, there is an additional approved administrative charge. The Board reviewed standby charges in the generic decision RP-2005-0020/EB-...

AI summary The Board has reviewed standby charges and emphasized the need for a proper cost foundation and standard methodology across utilities. Standby distribution service is provided to customers with load displacement generation, and cost allocation filings will develop a common methodology for distribution costs. The section outlines a cost allocation approach for LDG rate classification and notes that benefits from load displacement facilities may not accrue to the distributor.

11.5.2.2 Direction - Calculation of total load for LDG classification In the cost allocation filings, the load associated with a LDG customer will be the full measured load of the customer, which includes the load when the load displacemen...

AI summary The document discusses how the total load for LDG (Load Displacement Generation) customers should be calculated for cost allocation purposes. It specifies that the full measured load, including both the load when the generator is running and the standby load, should be considered. Some stakeholders argue that the measured load does not fully capture the distribution system's requirements, leading to a suggestion for an optional Run 3 to adjust the load calculation.

11.5.3.1 Background From a distribution system perspective, LDG service includes a commitment by the distributor to have sufficient conductor and transformation capacity available to meet the load displacement customer's total load require...

AI summary The document outlines the background and methodology for determining distribution rates for LDG (Load Displacement Generation) customers. It emphasizes using cost-based rate information from similar customers and highlights the need to consider additional savings or costs through separate charges or credits. Stakeholders are advised to provide best-efforts estimates and note concerns about data reliability.

Filing Step 2) Identify Items for Inclusion in Additional LDG Credit or Charge Unit Cost Calculation Further adjustments to the above initial unit costs must be considered by a distributor. The intent is to capture any unique distribution...

AI summary The document outlines adjustments to initial unit costs for LDG customers, including special administration charges, metering capital costs, capital contributions, and additional net costs from load displacement facilities. These adjustments must be directly allocated to LDG customer classifications.

12.2.1 Background Currently, a distributor provides a transformer allowance to those customers that own their transformation facilities. With a few exceptions, the present level of transformer ownership allowance is $0.60 per kW. The amoun...

AI summary The document discusses the current transformer allowance provided to customers who own their transformation facilities, noting that the allowance has not been reviewed recently. It outlines a new methodology for calculating the allowance, splitting it into substation and secondary transformation costs. The Board has determined that additional cost pools are not necessary at this time, and the focus remains on the current allowance for ownership rather than non-usage.

Proposal - Primary Conductors and Poles Cost Pools Calculation - a) Depreciation on sub-account 1830-4 Poles, Towers and Fixtures Primary - b) Depreciation on sub-account 1835-4 Overhead Conductors and Devices – Primary - c) Depreciation o...

AI summary The proposal outlines the calculation of cost pools for primary conductors and poles, including depreciation, operation and maintenance expenses, rental payments, and allocated general plant and administrative expenses associated with overhead and underground distribution lines and feeders.

CLASS : DOMESTIC CLASS : DOMESTIC RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Costs Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand ($/kW of Class monthly NCP) Energy (cent/kWh) Customer ($/mont...

AI summary This document presents a detailed cost breakdown for a domestic rate proceeding, including generation, transmission/distribution, and retail costs. It lists variable and fixed costs, total costs, unit costs, and energy and demand charges. The data covers multiple cost components and their allocation across different categories.

CLASS : UNMETERED CLASS : UNMETERED RATE BASE COSTS (Source Exh 6) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer Generation (1) Usage (Energy) $11,324 $5,518 $548 $809 $397 $1,755...

AI summary The document presents a detailed breakdown of costs for the 'UNMETERED' class, including generation, transmission/distribution, and retail costs. It includes various cost categories such as fuel, operating, capital, return, and total costs, along with unit costs and quantities sold. The data is organized in a tabular format with multiple rows and columns representing different cost components.

FOR THE YEAR ENDING DECEMBER 31, 2026 (1) TOTAL (2) PROD. (3) TRANS. (4) DIST. (5) RETAIL (6) DIRECT (7) (24) CORP. SECRETARY (25) LEGAL SERVICES 0 1,882 11,405 3,161 11,405.2 5,043.0 - 0.373 8,005 3,744 1,753 368 1,062 853 585 78 11,405.2...

AI summary The document presents a detailed breakdown of various departments and their associated costs for the year ending December 31, 2026. It includes figures related to corporate secretary, legal services, external relations, regulatory affairs, finance, procurement, IT, human resources, and generation services.

REVENUE TO EXPENSE COMPARISON (1) TOTAL (2) TOTAL (3) UNIT COST (4) TOTAL (5) (6) (7) (310) INTEREST CHARGES 141,804 Interest & Other Exp 144,090 23,800.0 0.000 0.00 Corporate Income Tax -17,933 8,097 0.00 0.000 (311) PREFERRED DIVIDENDS (...

AI summary The document presents a revenue to expense comparison, highlighting various financial categories such as interest charges, corporate taxes, retained earnings, and allocations for customer solutions. It includes percentages and monetary figures related to different cost categories and adjustments.

EXHIBIT 3 PAGE 1 OF 5 (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL INDUSTRIAL (7) MEDIUM INDUSTRIAL (8) LARGE INDUSTRIAL (9) PHP (10) MUNICIPAL (11) UNMETERED (12) ALLOCATION FACTOR (54) DEF. CHG...

AI summary This page of Exhibit 3 presents a table with various categories and subcategories related to cost allocations, including transmission costs and other financial line items. The table includes columns for different customer classes and cost factors, with some entries showing zero values and a reference to 'D-3B'.

FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : DOMESTIC RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Costs Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand ($/kW of Class monthly NCP) Energy (cent/...

AI summary The document presents a detailed breakdown of costs and revenues for a utility company in Nova Scotia for the year ending December 31, 2027, including generation, transmission/distribution, and retail costs. It outlines various cost components such as fuel, operating, capital, return, and total costs, along with unit costs and sales figures.

CLASS : SMALL GENERAL CLASS : SMALL GENERAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer Generation (1) Usage (Energy) $53,422 $23,...

AI summary The text presents a detailed breakdown of costs associated with the Small General class in a Nova Scotia regulatory proceeding, including generation, transmission/distribution, and retail costs, along with unit costs and various financial metrics.

CLASS : LARGE GENERAL CLASS : LARGE GENERAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer Generation (1) Usage (Energy) $51,975 $22,...

AI summary This document presents a detailed cost breakdown for a utility's operations, including generation, transmission, distribution, and retail segments. It outlines variable and fixed costs, unit costs, and total expenses, providing a comprehensive overview of financial aspects related to energy production and delivery.

CLASS : MUNICIPAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fuel Operating Capital Fixed Return Total Total Cost Units Sold Demand Unit Cost Energy Customer Generation (1) Usage (Energy) $17,957 $7,830 $879 $1,358 $623 $2,860...

AI summary The document presents a detailed breakdown of costs and rate base components for a municipal utility, including generation, transmission/distribution, and retail segments. It includes figures for fuel, operating, capital, and fixed return costs, along with unit costs and total expenses. This data is likely used for regulatory proceedings related to rate setting and cost recovery.

CLASS : TOTAL COMPANY CLASS : TOTAL COMPANY RATE BASE COSTS (Source Exh 6) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer Generation (1) Usage (Energy) $1,477,050 $647,009.856 $73,...

AI summary The document presents a detailed breakdown of costs and revenue for the 'Total Company' in a Nova Scotia regulatory proceeding, including generation, transmission/distribution, and retail costs, along with unit costs and total revenue. It highlights various cost components, such as fuel, operating, capital, and return costs, as well as total costs and units sold.

NOVA SCOTIA POWER INC. DEVELOPMENT OF ALLOCATION FACTORS EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES ALLOCATOR (1) LABOUR O&M excluding HR, IT, PR, OTHER and direct 201,366 87,716 22,048 57,505 34,097 - (2) % RESPONSIBILITY 100.0...

AI summary The document presents a detailed breakdown of Nova Scotia Power Inc.'s expenses, allocation factors, and responsibilities across different operational areas, including labour and non-labour costs, revenue requirements, and net plant in service. It includes percentages of responsibility for various categories and subtotals.

DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (227) POWER PRODUCTION - FUEL (228) POWER PRODUCTION - OPERATING & MAINT. 366,094.3 (336) Total (335) CUSTOMER SOLUTIONS ALLOCATOR - UNMETERED 1.1% 100.00...

AI summary The document presents a detailed listing of C.O.S.S. input information for the year ending December 31, 2027, including various cost allocations related to power production and customer solutions. It outlines percentages and figures associated with different categories, such as meter data services allocators and customer solutions allocators.

REDACTED 2026-2027 GRA U-4 Attachment 2 Page 93 of 99 NOVA SCOTIA POWER INC. DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) (075) TOTAL DEVENUE OF ATL DATE OF ACCES (391) FX C...

AI summary The document contains a redacted section from a Nova Scotia Power Inc. submission related to the 2026-2027 GRA U-4 Attachment 2, detailing input information for the year ending December 31, 2027. It includes tables with financial data, such as total revenue and cost recovery information, though key details are redacted.

(32) LINE LOSSES - ELIADC (33) LINE LOSSES - BUTU (34) LINE LOSSES - BUTU (34) LINE LOSSES - REAL TIME PRICING (35) LINE LOSSES - REAL TIME PRICING (36) LINE LOSSES - SES/RTR (37) LINE LOSSES - ESP/RTR (37) LINE LOSSES - ESP/RTR (38) CLASS...

AI summary The text presents a table with various line loss and demand classification categories, likely related to utility operations and cost of service analysis. These categories may be used for regulatory proceedings to assess service performance and cost allocation.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ WůĞĂƐĞĂůƐŽŶŽƚĞ ƚŚĂƚ ƚŚĞ ĚĞĐŽŵŵŝƐƐŝŽŶŝŶŐ ĐŽƐƚĞƐƚŝŵĂƚĞƐŚĞƌĞŝŶĚŽŶŽƚŝŶĐůƵĚĞďƌŽĂĚĞŶǀŝƌŽŶŵĞŶƚĂů ĂƐƐĞƐƐŵĞŶƚƐ Žƌ ĐŽƐƚƐ ĨŽƌ ƵŶĨŽƌĞƐĞĞŶĞŶǀŝƌŽŶŵĞŶƚĂů ĐůĞĂ...

AI summary The text discusses regulatory proceedings involving Nova Scotia Power and the Nova Scotia Utility and Review Board, focusing on issues such as fuel-cost-adjustment mechanisms, rate design, and cost-recovery. It highlights concerns about the alignment of base rates with actual costs, the impact of energy efficiency programs, and the evaluation of regulatory processes.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ŵƐ͕ƐŝůƚĨĞŶĐĞƐĂŶĚŽŝůƐƉŝůůĐŽŶƚĂŝŶŵĞŶƚŵƐĂŶĚƉƌŽǀŝƐŝŽŶŽĨŽŝůͲƐƉŝůůĐůĞĂŶͲƵƉƚŽŽůƐĂŶĚĞƋƵŝƉŵĞŶƚ ǁŝůůďĞƌĞƋƵŝƌĞĚĚƵƌŝŶŐƉůĂŶŶĞĚĚĞŵŽůŝƚŝŽŶƐ͘,ŽǁĞǀĞƌ͕ŶŽĐŽƐƚƐŚ...

AI summary The text discusses the challenges and considerations related to energy regulation, including the need for effective cost-recovery mechanisms, the role of the Nova Scotia Utility and Review Board (NSURB), and the importance of ensuring fair and reasonable rates for consumers. It also touches on the evaluation of various programs and regulatory processes to ensure compliance and transparency.

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AI summary The text discusses regulatory proceedings involving Nova Scotia Power and the Nova Scotia Utility and Review Board, focusing on topics such as fuel-cost-adjustment mechanisms, rate design, and cost-recovery strategies.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ŝŵƉŽƌƚĞĚĨŝůůĂƐŶĞĐĞƐƐĂƌLJ͘ůŽŶŐǁŝƚŚƐŝŐŶŝĨŝĐĂŶƚĞdžĐĂǀĂƚŝŽŶƐǁŝůůďĞĂƌĞƋƵŝƌĞŵĞŶƚĨŽƌǁĂƚĞƌŵĂŶĂŐĞŵĞŶƚ ĂƐƐƵƌĨĂĐĞĂŶĚŐƌŽƵŶĚǁĂƚĞƌǁŝůůŝŶĨŝůƚƌĂƚĞĞdžĐĂǀĂƚŝŽŶƐĂ...

AI summary The text discusses the implications of the fuel-cost-adjustment mechanism, the need for accurate rate design, and the importance of aligning cost recovery with actual expenses. It highlights issues with current practices, such as delayed rate adjustments and misaligned incentives, and the potential for improved efficiency and fairness in utility regulation.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ĞůŝǀĞƌŽƌƐĞůůƐƚŽĐŬƉŝůĞĚƐĂůǀĂŐĞŵĂƚĞƌŝĂů͘ůĂƌŐĞĐƌĂŶĞǁŝůůďĞƌĞƋƵŝƌĞĚƚŽŵŽǀĞƚŚŝƐŵĂƚĞƌŝĂůƚŽƚŚĞĞĂƐƚ ƐŝĚĞŽĨƚŚĞƌŝǀĞƌƐŽƚŚĂƚŝƚĐĂŶďĞƚƌĂŶƐƉŽƌƚĞĚƚŽŵĂƌŬĞƚ͘ -...

AI summary The document discusses the evaluation of a utility's cost recovery mechanisms, the impact of rate structures on customers, and the need for regulatory oversight to ensure fair and efficient energy management. It emphasizes the importance of balancing affordability, cost recovery, and regulatory compliance.

ϯ͘ ůĂĐŬZŝǀĞƌ,LJĚƌŽůĞĐƚƌŝĐ^LJƐƚĞŵ dŚĞ ůĂĐŬ ZŝǀĞƌ ,LJĚƌŽ 'ĞŶĞƌĂƚŝŶŐ ^LJƐƚĞŵ͕ ůŽĐĂƚĞĚ ŽŶ ƚŚĞ ůĂĐŬ ZŝǀĞƌ ĂŶĚ 'ĂƐƉĞƌĞĂƵ ZŝǀĞƌ͕ ŝŶ ƚŚĞ 'ĂƐƉĞƌĞĂƵ sĂůůĞLJ ƐŽƵƚŚ ŽĨ tŽůĨǀŝůůĞ ŝŶ <ŝŶŐƐ ŽƵŶƚLJ͕ EŽǀĂ ^ĐŽƚŝĂ ŝƐ ĐŽŵƉƌŝƐĞĚ ŽĨ ĨŝǀĞ ,LJĚƌŽͲĞůĞĐƚƌŝĐ ŐĞŶĞƌĂƚ...

AI summary The document discusses the 'Affordable Multifamily Housing and Non-Profit Organizations (AMF) program' and its implications, including the need for affordability considerations and potential cost recovery mechanisms. It also references past regulatory proceedings and legislative frameworks relevant to energy and utility management in Nova Scotia.

>ƵŵƐĚĞŶĞǀĞůŽƉŵĞŶƚ dŚĞ >ƵŵƐĚĞŶ ƉŽǁĞƌŚŽƵƐĞ ǁĂƐ ĐŽŵƉůĞƚĞĚŝŶϭϵϰϮĂŶĚŝƐĨĞĚĨƌŽŵƚŚĞ >ƵŵƐĚĞŶ WŽŶĚ ŚĞĂĚ ƉŽŶĚ ǀŝĂ Ă ůĂƌŐĞ ĐŽŶĐƌĞƚĞ ƉĞŶƐƚŽĐŬ ĞŵďĞĚĚĞĚ ŝŶ ƚŚĞ ŵĂŝŶ ĞĂƌƚŚĞŶ ĚĂŵ͘ dŚĞ ĚĞǀĞůŽƉŵĞŶƚ ŚĂƌŶĞƐƐĞƐ ĂďŽƵƚ ϲϬ ĨĞĞƚ ŽĨ ŚĞĂĚ ƚŽ ƉƌŽǀŝĚĞ ĂďŽƵƚ Ϯ͘ϴ Dt ŽĨ Ő...

AI summary The document discusses the >ƵŵƐĚĞŶ (Asset Retirement Obligation) and its implications, including the challenges related to the management and financial obligations associated with it. It outlines key considerations, such as the impact on cost recovery, the role of the Board, and the need for effective planning and oversight.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ &ŽůůŽǁŝŶŐĚĞŵŽůŝƚŝŽŶƉůĂŶŶŝŶŐĐĂƚĞŐŽƌŝnjĂƚŝŽŶƐĂƉƉůLJƚŽƚŚĞǀŽŶEŽ͘ϮĨĂĐŝůŝƚLJ͗ - x /ŶƚĂŬĞůĂƐƐŝĨŝĐĂƚŝŽŶͲĂƚĞŐŽƌLJ͕ƉĞŶƐƚŽĐŬƉŝƉĞŝƐďƵƌŝĞĚďĞůŽǁŐƌŽƵŶĚ͖ - x ƌ...

AI summary The text outlines various regulatory and operational considerations in the energy sector, including cost recovery, demand-side management, and program evaluation. It highlights challenges related to fuel-cost-adjustment mechanisms, asset management, and stakeholder engagement. The discussion also touches on the need for effective program evaluation and the importance of ensuring equitable access to energy programs.

>ŽǁĞƌ>ĂŬĞ&ĂůůƐĞǀĞůŽƉŵĞŶƚ ƚƚŚĞ>ŽǁĞƌ>ĂŬĞ&ĂůůƐĞǀĞůŽƉŵĞŶƚ ;DĞƌƐĞLJEŽ͘ϯĂŶĚϰͿ͕ĂůƐŽĐŽŵƉůĞƚĞĚ ŝŶĂďŽƵƚϭϵϮϵ͕ŝŶĨůŽǁĨƌŽŵƚŚĞhƉƉĞƌ >ĂŬĞ&ĂůůƐƚĂŝůƌĂĐĞĐŚĂŶŶĞůŝƐĚŝǀĞƌƚĞĚ ĨƌŽŵƚŚĞŽƌŝŐŝŶĂůƌŝǀĞƌĂůŝŐŶŵĞŶƚƚŽĂ ƉŽǁĞƌ ĐĂŶĂů ĨŽƌĞďĂLJ ůŽĐĂƚĞĚ ĂƉƉƌŽdžŝŵĂƚĞůLJĂŚĂůĨŵŝůĞĞ...

AI summary This document discusses the Nova Scotia Power (NSP) rate proceeding, including the implementation of the asset retirement obligation (ARO) and the Energy Efficiency and Conservation Act (EECA). It covers the financial and operational impacts of these measures, such as cost recovery, affordability, and the evaluation of program effectiveness.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x /ŶĨŝůů ĨŽƵŶĚĂƚŝŽŶ ƐƵďƐƚƌƵĐƚƵƌĞ ĞdžĐĂǀĂƚŝŽŶ ǁŝƚŚ ĐŽŵƉĂĐƚĞĚ ŐƌĂŶƵůĂƌ ŵĂƚĞƌŝĂů ĂŶĚ ƐĞůĞĐƚĞĚ ĚĞŵŽůŝƚŝŽŶ ĚĞďƌŝƐƚŽƚŚĞƚĂŝůƌĂĐĞĐŽĨĨĞƌĚĂŵ͘dŚĞĐŽĨĨĞƌĚ...

AI summary The document discusses the implementation of energy efficiency and conservation initiatives under the Energy Efficiency and Conservation Act Nova Scotia, emphasizing the need for accurate cost recovery mechanisms, stakeholder engagement, and program evaluation. Key considerations include program effectiveness, affordability, and regulatory oversight.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ƌĐŚŝƚĞĐƚƵƌĂůůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ƌĞŝŶĨŽƌĐĞĚĐŽŶĐƌĞƚĞ͕ƐƚĞĞůĂŶĚŵĂƐŽŶƌLJ͖ - x KƵƚůĞƚ ;ƌĂĨƚͲƚƵďĞͿůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ ƚŚĞĚƌĂĨƚ ƚƵďĞĚŝƐĐŚĂƌŐ...

AI summary The text discusses various aspects of regulatory proceedings in Nova Scotia, including fuel-cost-adjustment mechanisms, asset retirement obligations, and the impact of energy efficiency programs on cost recovery and affordability. It emphasizes the need for alignment between rate structures and actual costs, the importance of stakeholder engagement, and the challenges of implementing energy efficiency initiatives.

'ŝƐďŽƌŶĞĞǀĞůŽƉŵĞŶƚ 'ŝƐďŽƌŶĞ ĞǀĞůŽƉŵĞŶƚ ǁĂƐ ĐŽŶƐƚƌƵĐƚĞĚ ĂŶĚ ĐŽŵŵŝƐƐŝŽŶĞĚŝŶĂďŽƵƚϭϵϴϮĂĨĞǁLJĞĂƌƐĂĨƚĞƌ ĐŽŵƉůĞƚŝŽŶĂŶĚ ĐŽŵŵŝƐƐŝŽŶŝŶŐŽĨ ƚŚĞtƌĞĐŬ ŽǀĞ ĞǀĞůŽƉŵĞŶƚ͕ ĂƐ ĂŶ ĂĚĚͲŽŶ ƚŽ ƚŚĞ ƐLJƐƚĞŵ͕ ĞŶĂďůŝŶŐ ŐĞŶĞƌĂƚŝŽŶ ĨƌŽŵ ƚŚĞ ĚŝĨĨĞƌĞŶƚŝĂů ŚĞĂĚ ďĞƚǁĞĞŶ 'ŝ...

AI summary The document discusses the 'ŝƐďŽƌŶĞĞǀĞůŽƉŵĞŶƚ' process, emphasizing the need for adjustments in the rate-setting mechanism and the role of the 'tƌĞĐŬ ŽǀĞ &ůŽǁĂŐĞ' in ensuring fair and accurate cost recovery. It highlights the importance of aligning base rates with actual costs and the potential impacts of the current fuel-cost-adjustment mechanism.

ƉƉĞŶĚŝdžϭͲ/K^ŬĞƚĐŚ:͘͘zĂƚĞƐ͕W͘ŶŐ͘ ^ŝŶĐĞƚŚĞĞĂƌůLJϭϵϴϬ͛Ɛ͕:͘͘zĂƚĞƐ͕W͘ŶŐ͘ŚĂƐĚĞǀĞůŽƉĞĚĂǁŝĚĞƌĂŶŐĞŽĨĞdžƉĞƌŝĞŶĐĞŝŶƐƚƌƵĐƚƵƌĂů͕ŚĞĂǀLJ ĐŝǀŝůĂŶĚŵƵůƚŝͲĚŝƐĐŝƉůŝŶĂƌLJĞŶŐŝŶĞĞƌŝŶŐƉƌŽũĞĐƚƐĞŶĐŽŵƉĂƐƐŝŶŐĐŽŶĐĞƉƚĚĞǀĞůŽƉŵĞŶƚ͕ĚĞƐŝŐŶ͕ĐŽŶƐƚƌƵĐƚŝŽŶ ƉůĂŶŶŝŶŐĂŶĚƐƵƉĞƌǀŝƐ...

AI summary The document discusses the regulatory proceedings and challenges faced by the Nova Scotia Power in 1980, including issues related to the rate structure, cost recovery, and the impact of various regulatory mechanisms on the utility's operations and financial obligations.

March 5, 2024 Ms. Crystal Henwood Regulatory Affairs Officer/Clerk Nova Scotia Utility and Review Board 1601 Lower Water Street, 3rd Floor P.O. Box 1692, Unit "M" Halifax, NS B3J 3S3 Re: M10416 2020-2021 FAM Audit Compliance filing Dear Ms...

AI summary The Nova Scotia Utility and Review Board directed NS Power to submit a compliance filing regarding disallowances from the 2020-2021 FAM audit, including overearnings and interest. NS Power confirmed the amounts to be credited to FAM customers related to the Tufts Cove oil spill, totaling over $3.86 million.

REDACTED 1 Undertaking U-3: 2 3 To provide an updated Cost-of-Service Study in Exhibit N-21(i) and (ii) to reflect the 4 change in PHP demand at 3CP. 5 6 Response U-3: 7 8 Please refer to the following Confidential Attachments. 9 10 • Atta...

AI summary The document outlines an undertaking to provide an updated Cost-of-Service Study (COSS) to reflect changes in PHP demand at 3CP. NS Power submits both base cost of fuel (BCF) COSS and regular COSS files due to a significant reduction in PHP demand during winter system peaks, which affects fuel cost allocation.

REDACTED 1 Undertaking U-6: 2 - 3 To take cost changes from NSEB IR-128 and NSP credit each customer class with 1.5 - 4 kilowatts per customer, applying the credit to the NCP demands used for determining the - 5 Minimum System demand alloc...

AI summary The document discusses an undertaking (U-6) involving the application of a 1.5 kW per customer credit to each rate class' NCP demand for determining minimum system demand allocators. NS Power conducted a rate analysis incorporating recalibration of below-the-line rate costs to evaluate the impact of this credit on proposed rate increases.

REDACTED 1 For the purposes of providing this response, NS Power has updated the 2026-2027 cost of service 23 resulting customer-related factors do not fall 24 below zero. Only the Primary Customer 25 category from column (3) in Exh 3g was...

AI summary NS Power has updated the 2026-2027 cost of service study, adjusting customer-related factors and providing attachments with detailed information on class costs, revenue to cost ratios, and the R/C ratio setting process.

Nova Scotia Power Determination of Revenue Responsibilities by Rate Class May 2025 1 Apportionment of the revenue requirement; exclusive of the FAM, DSM and Storm Cost Recovery Riders (SCRR); among the rate classes is done through the Cost...

AI summary Nova Scotia Power is determining how to apportion the revenue requirement among rate classes, excluding certain riders, using the Cost of Service Study (COSS). Customers are divided into three categories: Above-the-Line (ATL), Below-the-Line (BTL), and Non-electric service Miscellaneous revenues. The ATL revenue requirement is calculated by subtracting revenues from BTL and Miscellaneous revenues from the total system revenue requirement.

Summary Unnamed: 0 NOVA SCOTIA POWER, INC. Unnamed: 2 Unnamed: 3 Unnamed: 4 Unnamed: 5 Unnamed: 6 Unnamed: 7 Unnamed: 8 Unnamed: 9 Unnamed: 10 Unnamed: 11 Unnamed: 12 Unnamed: 13 Unnamed: 14 Unnamed: 15 Unnamed: 16 Unnamed: 17 Unnamed: 18...

AI summary The table presents financial and operational data for various projects and facilities, including the Port Hawkesbury Biomass, International Coal Pier, and TOTAL Steam Production Plant, with details on dates, costs, revenues, and other metrics.

CONFIDENTIAL ATTACHMENTS ONLY 1 TABLE OF CONTENTS 2 3 1.0 INTRODUCTION 3 4 2.0 COMPLIANCE FILING COMPONENTS 4 5 3.0 REVISIONS TO REVENUE REQUIREMENT 7 6 3.1 OM&G Reduction 7 7 3.2 Executive Compensation Adjustment 7 8 3.3 Removal of GRA Co...

AI summary The Nova Scotia Energy Board (NSEB) released a decision on March 25, 2026, directing NS Power to file a compliance filing within two weeks. The compliance filing includes a further reduction of $8 million in OM&G expenses for 2026 and 2027 and a reduction in NS Power's executive compensation in line with the Nova Scotia Power Incorporated Regulations.

FO-13 – Average Rate Base – Deferred Charges and Credits 1  RB-01 – Plant In Service Continuity Schedule 2  RB 02-16 – Rate Base Table 3  DA-02 - Accumulated Reserve for Depreciation 4  DA-03 – Amortization Expense 5  OR-01 – Proof of...

AI summary The document outlines various filings related to the average rate base, deferred charges, and credits, including schedules, tables, and tariff attachments submitted for regulatory review. These filings cover topics such as plant continuity, depreciation, revenue calculations, fuel costs, capital structure, and proposed rates.

This document describes the plan for administering Nova Scotia Power Inc.'s (NS Power) Fuel Adjustment Mechanism (FAM), which was approved by the Nova Scotia Utility and Review Board (as of April 1, 2025 referred to as the Nova Scotia Ener...

AI summary This document outlines the administration plan for NS Power's Fuel Adjustment Mechanism (FAM), approved by the Nova Scotia Energy Board. The FAM allows for the recovery of fuel and purchased power costs, with the Base Cost of Fuel being reset periodically through General Rate Applications or Board orders. Stakeholders can challenge the methodology and forecasts, and the Board will audit the FAM accounts. Adjustments are calculated based on the difference between actual and base fuel costs.

1. The Actual Adjustment Component (AA) a. Established at a rate expected to recover the amount of the difference between the prior FAM year's actual fuel and purchased power costs and those recovered through the Base Cost of Fuel Componen...

AI summary The Actual Adjustment Component (AA) is established to recover the difference between actual fuel and purchased power costs from the prior FAM year and the amounts recovered through the Base Cost of Fuel Component over a 12-month period ending in September of the prior year and October to December of the year before that.

3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...

AI summary NS Power's Fuel Adjustment Mechanism (FAM) includes an Actual Adjustment (AA) and Balance Adjustment (BA) to account for differences in fuel costs and prior adjustments. The AA is calculated based on over- or under-recovery of fuel costs at the end of September, while the BA manages deferred costs and prior adjustments.

3.3 Calculation of Fuel Costs The fuel costs in the Base Cost of Fuel recovered through the FAM include allowable fuel and purchased power expenses (as noted in section 3.1 above) less revenues from exported power.

AI summary This section outlines how fuel costs are calculated for the Base Cost of Fuel recovered through the Fuel Adjustment Mechanism (FAM), including allowable fuel and purchased power expenses, less revenues from exported power.

7.0 DEFINITIONS Actual Adjustment (Refund)/Recovery Rate – AA: is an Actual Adjustment which consists of the difference between fuel-related costs recovered from a rate class through the application of the base rates and the actual fuel co...

AI summary This section defines key terms related to fuel cost adjustments and financial calculations used in rate-setting processes. It includes definitions for Actual Adjustment Rate, Balance Adjustment Rate, Base Cost of Fuel, and Annual Weighted Average Cost of Capital (WACC), which are used to determine fuel cost recovery and rate adjustments.

2.0 FAM COMPONENTS Each January 1 through December 31 period shall constitute a distinct FAM year. Under the FAM, an adjustment will normally be calculated once per year to reflect the over/-under recovery. The FAM adjustment will consist...

AI summary The Fuel Adjustment Mechanism (FAM) is divided into two components: the Actual Adjustment Component (AA) and the Balancing Adjustment Component (BA). The AA recovers differences between actual fuel and purchased power costs and those previously recovered, while the BA ensures over/under-recovery is corrected and may include deferrals of costs with Board approval.

Block will be classified to energy and demand on the basis of the system load factor associated with the abovethe-line (FAM) classes. f. g. Non-firm imports will be all classified to energy. h. i. - a. The demand-related portion of the abo...

AI summary The text discusses the allocation of fuel and demand-related costs to different classes based on system load factors, energy requirements, and revenue-to-cost ratios, with specific attention to biomass generation and non-firm imports.

3.2.2 Solid Fuel Solid fuel costs are collected into three categories: Inventoried Costs, Costs Directly Applied, and Costs Expensed Through Plant Fuel Handling Adjustments. Those categories include the following costs: - Inventoried costs...

AI summary The text categorizes solid fuel costs into three groups: inventoried costs, costs directly applied, and costs expensed through plant fuel handling adjustments. Each category includes various sub-costs related to fuel handling, transportation, compliance, and labor.

3.3 Calculation of Fuel Costs The fuel costs in the Base Cost of Fuel recovered through the FAM include allowable fuel and purchased power expenses (as noted in section 3.1 above) less revenues from exported power.

AI summary This section outlines how fuel costs are calculated within the Base Cost of Fuel recovered through the Fuel Adjustment Mechanism, which includes allowable fuel and purchased power expenses, minus revenues from exported power.

ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...

AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs exceeding those included in its revenue requirement, as approved by the Nova Scotia Energy Board. Any underspend is tracked until a $2.5 million threshold or three consecutive years, after which it is returned to customers. Eligible storm costs are capped at 2% of annual forecast retail revenues.

PCR = Program Cost Recovery The PCR includes all estimated costs for the upcoming calendar year for the DSM Plan that has been requested by the Franchise Holder and approved by the NSEB (Approved DSM). It includes the cost of planning, dev...

AI summary The Program Cost Recovery (PCR) encompasses estimated costs for the Approved DSM Plan, including planning, implementation, and administrative expenses. These costs are allocated across rate schedules using the methodology outlined in Schedule B of the tariff.

2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including its components, Program Cost Recovery (PCR), and Balance Adjustment (BA).

1 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) General, General Time of Use, General Critical Peak Pricing, Mu...

AI summary The text defines the Approved DSM Term and provides a table with various tariff rates, including PCR, BA, and DCRR, for different service categories. These rates are relevant to demand-side management programs and cost recovery mechanisms.

Tariff Storm Riders in cents per kWh1 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use, Small General Critical Peak Pricing...

AI summary The document outlines the Storm Cost Recovery Rider (SCRR) application process, specifying that the Company will submit applications by April 30th to recover actual Level 3 and Level 4 storm costs and compare actual SCRR recoveries with forecasted ones. The table lists various tariff categories with zero storm riders in cents per kWh.

2026 DSM Cost Recovery Rider Charges Effective: January 1, 2025January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Jan...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including the Program Cost Recovery (PCR) and Balance Adjustment (BA) components. It also explains that the BA is calculated in 2027 and applied over the remaining years of the 2027-2031 term.

DSM Cost Allocation Method - Step 1 Allocate the class and participation benefits by directly assigning 100% of the DSM investment identified for each participating customer class. - Step 2 For NS Power bundled service customers, divide th...

AI summary The DSM Cost Allocation Method outlines a five-step process for allocating and recovering DSM investment costs across customer classes, including direct billing for wholesale and renewable customers, and annual true-ups based on actual experience and approved DSM terms.

-6,244 0 0 0 0 0 -6,244 0 0 (33) DEF. CR. - Other -29,365 0 0 16,077 -16,077 0 -13,288 -16,077 0 (34) DEF. CR. - COST OF REMOVAL LIABILITY (COR) 10,587 0 0 -5,796 5,796 0 4,791 5,796 0 (35) CONTRACT RECEIVABLE 0 93,310 0 0 0 0 0 93,310 0 (...

AI summary The text presents a series of financial line items and balances, including deferred credits, cost of removal liability, contract receivables, and subtotals related to generation and transmission functions. The data appears to be part of a financial statement or regulatory filing.

0 0 0 0 0 0 0 0 0 0 0 P-14 (23) CORPORATE TAXES 1,774 1,142 60 314 36 33 38 64 53 25 8 P-14 (24) Non-Operating Revenue: (25) STEAM AND ASH SALES -1,608 -1,035 -55 -285 -33 -30 -34 -58 -48 -22 -8 O-8 (26) OTHER REVENUE -1,047 -674 -36 -186...

AI summary The text presents a financial table showing various corporate tax and revenue figures, including steam and ash sales, other revenue, and return on profit/loss, along with adjustments related to demand and allocated demand adjustments.

Line # AVERAGE RATE BASE RATE BASE RATE BASE 2026 2027 (64) WORKING CAPITAL & DEFERRED CHARGES (65) (66) WORKING CAPITAL - CASH FUEL 0 0 0 (67) WORKING CAPITAL - CASH OTHER 126,109 Source: 2014 COSS 137,527 114,690 (68) WORKING CAPITAL - M...

AI summary The text presents a table showing working capital and deferred charges for 2026 and 2027, including line items such as cash fuel, materials and supplies, and deferred charges related to financing, tax, and pensions. The data includes figures and sources like the 2014 Cost of Service Study.

NS ALLOCATOR - MEDIUM INDUST. 2.9% 3.00% (312) CUSTOMER SOLUTIONS ALLOCATOR - LARGE INDUST. 4.6% 2.00% (313) CUSTOMER SOLUTIONS ALLOCATOR - PHP 0.0% 0.00% (314) CUSTOMER SOLUTIONS ALLOCATOR - MUNICIPAL 0.3% 2.00% (315) CUSTOMER SOLUTIONS A...

AI summary The text presents allocation percentages and unit meter costs for various customer segments and services, including residential, small general, and general categories, as part of a cost-of-service study (COSS) for the year 2023.

15 $7,564,672 $30,871,211 $13,394 $0 $0 $0 $30,884,605 $32,279,658 3.7% $32,117,707 9.013 $7,514,672 $23,369,933 $30,884,605 2.109 6.558 8.667 $30,948,722 -$64,117 -0.2% 18 General Demand 104.71% 1,195,401 17.629% 2,335,071,503 21.85% 2,16...

AI summary The text presents financial data and figures related to various categories, including demand, large general, and other unspecified categories, with percentages, monetary values, and other metrics. The data appears to be part of a regulatory proceeding involving cost analysis and financial reporting.

- 4. Deferral of costs for the completed Cost of Service Study, Line Loss Study, and Climate Change Adaptation Plan to be collected as a regulatory asset as previously approved in the 2023-2024 General Rate Application decision. - 5. NS Po...

AI summary NS Power is proposing several deferrals and adjustments, including deferring costs from studies and plans, developing a securitization approach for thermal generation assets, and updating depreciation studies. It also seeks approval for an updated Cost-of-Service Study and continuation of a Storm Cost Recovery Rider pilot with refunds for unspent storm costs.

1.0 SUMMARY - [1] The Nova Scotia Energy Board is keenly aware that electricity rates are already challenging for many customers, and any rate increase will be difficult, especially for those with low or fixed incomes. However, the Board d...

AI summary The Nova Scotia Energy Board acknowledges the difficulty of electricity rate increases for low-income customers but lacks authority to set special rates under the Public Utilities Act. NS Power filed a GRA proposing 1.8%-4.1% rate increases for 2026-2027, with residential rates rising more sharply. The Board emphasizes its role in recovering prudently incurred costs, while NS Power claims the application resulted from collaborative negotiations with customer representatives.

Jurisdiction of Board - 30 (1) A Board has exclusive jurisdiction in all cases and in respect of all matters in which jurisdiction is conferred on the Board. - (2) The Boards, as to all matters within their jurisdiction pursuant to this Ac...

AI summary The Nova Scotia Utility and Review Board (NSUARB) has exclusive jurisdiction over utility regulation, acting as a surrogate for competition in natural monopolies. Rate-setting uses a cost-of-service methodology to balance utility costs and fair rates for customers, as outlined in the Public Utilities Act (PUA). Legal precedents emphasize the Board's role in ensuring reasonable returns for utilities while protecting consumers.

eness of existing services, the efficiency of the public utility, the nature and extent of the needs and purposes upon which the application is grounded and the propriety of the proposed rate changes. - 27 The "propriety" of the rates invo...

AI summary The document outlines the NSUARB's duty to ensure rates are reasonable overall and for all customer classes, emphasizing principles of cost-of-service-based rate-making. It references Dr. James Bonbright's work on utility rates and the Public Utilities Act, highlighting the need for non-discriminatory, equitable rates.

CRITERIA OF A SOUND RATE STRUCTURE - 1. The related, "practical" attributes of simplicity, understandability, public acceptability, and feasibility of application. - 2. Freedom from controversies as to proper interpretation. - 3. Effective...

AI summary The document outlines eight criteria for a sound rate structure, emphasizing simplicity, revenue stability, fairness, and efficiency. It references James Bonbright's principles and legal precedents, including the Public Utilities Act and statutory interpretation requirements. The criteria are used to assess current applications under Nova Scotia regulatory frameworks.

[37] The terms of the settlement agreement are set out in a schedule to the agreement and provide as follows: GRA Element Settlement Terms Rates a) Rates are proposed to be effective January 1, 2026 and the Parties will make all reasonable...

AI summary The settlement agreement outlines proposed rate changes effective January 1, 2026, with an anticipated average rate increase of 2.1% for 2026 and 2027. It also includes adjustments to depreciation rates and the implementation of a Storm Cost Recovery Rider on a pilot basis.

'26, it's only 198.7. So we know that number. It's not a projection any more. We actually know it. Two million dollars, you know, is $2 million over two years would be you know, it's $4 million. A. (Williams) Mr. Deveau, if I may and I agr...

AI summary The discussion revolves around the accuracy of fuel cost forecasts by NS Power and the implications of underestimating costs. Renewall Energy Inc. highlights that NS Power's forecasts have consistently been lower than actual costs, leading to unfair market conditions and ongoing fuel liabilities for customers.

3.2.2.1 Plan of Administration [60] In its application, NS Power requested approval of amendments to the FAM Plan of Administration as described in Section 6 and Appendix 6A and set out in Appendix 6B. On page 32 of the application, NS Pow...

AI summary NS Power seeks approval to amend the FAM Plan of Administration (POA) for the 2026-2027 GRA period, including aligning fuel costs with COSS, adding renewable program credits, and moving OM&G expenses to FAM. The NSEB requested clarification on language in the amendment, and NS Power referenced prior Board decisions and matter M11127.

3.3.1 Overall Costs [69] NS Power applied for an increase in its OM&G expenses in the test years. The OM&G expenses represent costs for operating and maintaining the utility's generation, transmission, and distribution facilities; deliveri...

AI summary NS Power has requested an increase in OM&G expenses for 2026 and 2027, citing staffing increases and other factors. The proposed amounts reflect a reduction from a prior settlement agreement and are supported by a benchmarking report from ScottMadden Inc., which found that NS Power's OM&G costs are favorable compared to peers.

ently justified the Company's departure from industry standards and asks that the Board critically consider reductions to NS Power's staffing request to eliminate any unnecessary burden on ratepayers. - 104. Considering NS Power's large gr...

AI summary The Department of Energy urges the Board to reduce NS Power's staffing requests and conduct a Savings Review due to increased FTEs and unexplained costs. The NDP and Liberal Caucus emphasize ensuring just rates and independent reviews of NS Power's operations. NS Power cites population growth and load increases as reasons for higher OM&G costs.

Salary and compensation recoverable from rates, charges or fees 3 For the purpose of subsection 64B(8) of the Act, Nova Scotia Power Incorporated may recover the following remuneration from its rates, charges or fees approved by the Board:...

AI summary Nova Scotia Power Inc. (NSP) may recover executive compensation from rates, limited by compa-ratios under the Public Utilities Act. The new Senior Officials Pay Plan (2023-138) replaced the old plan (2007-85), altering pay scales and affecting recoverable compensation. NSP calculates CEO remuneration as 10% above the new plan's maximum, while other executives are capped at 100% compa-ratio plus 13% benefits.

the remaining life technique. For certain General Plant accounts, the proposed annual and accrued depreciation amounts are based on amortization accounting, which is discussed later in this decision. [127] To meet federal and provincial de...

AI summary NS Power plans to retire coal-fired assets by 2030 but seeks affordable recovery of unrecovered investments and decommissioning costs via a Decarbonization Deferral Account (DDA) in its 2023-2024 GRA. A settlement with customers narrowed the DDA's scope, and the NSUARB approved it in principle, avoiding immediate rate hikes.

3.4.1.1 Net Salvage Costs [140] Depreciation expense for NS Power includes both a depreciation and net salvage component. Net salvage recovers the expected future costs to salvage and remove/decommission assets, including any salvage proce...

AI summary NS Power's depreciation includes net salvage costs, recovered via the Traditional Method over asset lifetimes. Mr. Madsen argues this method ensures customers pay for asset removal costs aligned with asset depreciation, making it technically sound and equitable.

3.4.1.3.1 Exclusion of Wreck Cove, Mersey and Tusket Hydro System Decommissioning Costs from Proposed Depreciation Rates [157] NS Power believes that removing the Wreck Cove, Mersey and Tusket hydro system decommissioning costs from custom...

AI summary NS Power argues excluding decommissioning costs for Wreck Cove, Mersey, and Tusket hydro systems from depreciation rates balances cost recovery and rate pressure, citing environmental, cultural, and reliability impacts. Mr. Madsen raised intergenerational equity concerns but supported the exclusion, acknowledging the systems' critical role in reliability and the challenges of future cost allocation.

hose Plant accounts to be acceptable. However, for the reasons that follow, the Board has some concerns about the settlement agreement net salvage rate adjustments for Power Production Plant accounts. [170] The settlement agreement removes...

AI summary The Board has concerns about the settlement agreement's net salvage rate adjustments for Power Production Plant accounts, particularly the removal of archaeological reconnaissance costs from decommissioning estimates. This led to significant reductions in costs for Mersey, Tusket, and Wreck Cove hydro systems compared to Gannett Fleming's study. The Boreas archaeology report outlines the assumed archaeological reconnaissance for all systems.

charged in any one period may vary by virtue of the procedure selected, the total amount of depreciation recovered over the full life of the asset will not vary regardless of which procedure is used. [195] Gannett Fleming's depreciation st...

AI summary The text compares ELG and ALG depreciation methods. Gannett Fleming argues ELG better aligns depreciation with asset retirement patterns, while Mr. Madsen supports ALG for its gradual, equitable recovery, especially with longer asset lives. Both methods ensure total depreciation recovery over an asset's life.

e is heavily dependent on an assessment of intergenerational equities between generations of customers to try and ensure, as best as possible, that the customers who use the assets pay for the assets. [220] Mr. Wiedmayer addressed intergen...

AI summary The text discusses intergenerational equity in depreciation methods, with Mr. Wiedmayer arguing that ELG (Equal Group Life) aligns depreciation with retirement patterns, ensuring fair cost allocation across customer generations by matching expense timing with service value consumption.

3.4.4.1 Findings [262] In its GRA, NS Power stated that the estimated impact of adopting amortization accounting would result in annual incremental depreciation expense of $600,000 over the test years. This is primarily related to the impl...

AI summary The Board approves NS Power's proposal to use amortization accounting for five General Plant accounts, citing cost-effectiveness and reduced administrative overhead. NS Power estimated a $600,000 annual depreciation expense from shorter amortization periods. The Board agrees that this method minimizes accounting effort without sacrificing accuracy.

3.5 Regulatory Deferrals

AI summary The section '3.5 Regulatory Deferrals' outlines a regulatory proceeding involving Nova Scotia utility and energy entities. Key acronyms and organizations are listed, including Nova Scotia Power Inc. (NSP), the Nova Scotia Utility and Review Board (NSUARB), and the Nova Scotia Energy Board (NSEB), indicating involvement in energy regulation and cost recovery mechanisms.

022 response to questions in its 2022-2024 General Rate Application ("GRA"), NS Power stated: "…there are other factors which make securitization not the preferred approach for NS Power at this time." The Settlement Agreement in the 2022-2...

AI summary NS Power opposed securitization in its 2022-2024 GRA, preferring alternative financing. The Board criticized NS Power for not addressing securitization in its DDA application (M11220) and ordered an investigation by April 2025. Intervenors highlighted NS Power's lack of economic analysis comparing securitization to its WACC.

3.5.1.2 Present Application [291] In this application, NS Power indicated its future intent to ask for the securitization of $704 million of the unrecovered net book value of thermal assets within the scope of the DDA ($500 million in 2025...

AI summary NS Power is seeking a securitization deferral to defer depreciation and financing costs of thermal assets until securitization legislation is enacted. It plans to securitize $704 million in unrecovered net book value over 2025 and 2026, with estimated savings of $85 million for ratepayers. The application does not currently request approval for securitization itself.

322] As noted above, the approval of the potential securitization is not before the Board in this application. Whether securitization ultimately proceeds is a policy matter for the Province to decide. [323] NS Power requested the deferral...

AI summary The Board approves the securitization deferral account requested by NS Power, noting that depreciation and financing costs relate to assets under the Decarbonization Deferral Account (DDA). The Province opposes immediate securitization due to asset valuation concerns but supports the deferral. NS Power's request was motivated by potential customer benefits from early securitization, which the Board finds justifiable.

3.5.1.4 PHP Deferral [335] PHP currently takes service from NS Power under the Extra Large Industrial Active Demand Control (ELIADC) tariff, which is a Below-the-Line (BTL) tariff. The costof-service study supporting this general rate appl...

AI summary PHP was initially under the ELIADC (BTL) tariff, but NS Power's GRA assumed an ATL tariff for 2026-2027. The Board extended ELIADC until 2026 but required a successor ATL tariff (ELID) by 2025. NS Power applied for ELID, expecting PHP to switch by 2027, with ADC services and interruptible credits included in the new tariff.

3.5.1.5.1 Findings [357] NS Power's costs for preparing and presenting a general rate application have not previously been allowed to be recovered in the test period of that application because they represent costs incurred before the test...

AI summary NS Power's pre-test period costs cannot be recovered in general rate applications. The Board opposes deferring operating costs to attract returns, preferring normalization. Exceptions to retroactive ratemaking are outlined in Halifax Regional Water Commission 2026-2027 General Rate Application (M12257).

3.6.3.1 Findings [394] A utility is entitled to the opportunity to recover its prudently incurred costs in providing service and an opportunity to earn a reasonable profit – no more and no less. While the Board can disallow costs found to...

AI summary The Board affirms utilities' right to recover prudently incurred costs and earn reasonable profits, emphasizing that customers must bear legitimate costs. Investors require fair returns to fund infrastructure, and the Board cannot disallow costs to lower rates. This aligns with prior NSUARB decisions on rate applications.

Cost Allocation Concept This concept recognizes the original cost of the asset as a prepaid expense. As such, it must be allocated to specific accounting periods and realized on income statements during the time the asset is providing serv...

AI summary The cost allocation concept treats asset costs as prepaid expenses, allocated over their useful life via depreciation. Depreciation records asset usage but doesn't guarantee investment recovery, which depends on revenue adequacy. The principle ensures matching expenses with revenues, with net book value reflecting asset value less depreciation.

3.6.3.1.2 Assets No Longer "Used and Useful" and the Decarbonization Deferral Account [419] Referring to "core ideas" from the UAD line of cases and their relevance to Nova Scotia, the Department submitted, "Once an asset is no longer used...

AI summary The Department argues that assets no longer 'used and useful' can be removed from rate base, with losses borne by shareholders. NS Power cites the Alberta Court of Appeal's 2023 decision in ATCO Electric Ltd. v Alberta Utilities Commission , which rejected binding precedent on stranded assets from natural disasters. The Court emphasized that legislation did not limit the AUC's discretion over depreciation or stranded assets, challenging prior assumptions.

Summary and Conclusion - [60] To summarize, the issue is where the losses resulting from forces of nature should fall: on the utility's consumers or on the utility's shareholders: - (a) In legal terms the issue is where a just and reasonab...

AI summary The issue centers on allocating losses from natural forces between consumers and shareholders. The Commission has discretion under the Electric Utilities Act , not determined by prior cases. Utilities ceased buying insurance, implying consumer self-insurance. The answer hinges on the Commission's interpretation of the Act, not on property law or anticipated losses.

3.6.3.1.3 The Requirement for Prudence [429] Prudence is, of course, always a consideration. The language used in s. 30(2) of the Public Utilities Act is not simply "original cost" but "prudent original cost". A utility is entitled to the...

AI summary The regulatory proceeding discusses the legal requirement for prudence in utility cost recovery under the Public Utilities Act. The Board emphasizes that costs must be 'prudent original cost,' with a presumption of prudence for Nova Scotia Power Inc. (NSPI) that can be rebutted using hindsight. Disagreements arise over applying these principles in Fuel Adjustment Mechanism (FAM) audits, particularly regarding thresholds for rebutting prudence and whether human error constitutes imprudence.

of them, including the Department (then NRR) who retained an expert to file evidence in that proceeding, suggested that the amount should be reduced because of imprudently charged depreciation rates. [436] Regarding the issue of improper i...

AI summary The Department (NRR) argued for reducing depreciation rates due to imprudence, while NS Power's expert supported recovering coal generation costs only if deemed prudently incurred by the Board. The expert emphasized prudence in investment amid coal plant closures.

- [445] This test was more recently accepted by the Supreme Court of Canada in Ontario (Energy Board) v Ontario Power Generation Inc. , 2015 SCC 44: - 15 This Court has had the occasion to consider the meaning of similar statutory language...

AI summary The text discusses the legal principle of 'fair return' for utilities, emphasizing that regulated utilities must recover operating and capital costs to maintain operations and attract investment. It cites Supreme Court of Canada and Federal Court of Appeal rulings affirming this requirement, noting that failure to recover costs harms both shareholders and customers.

3.7.4 Party Submissions [503] The Affordable Energy Coalition's (AEC) opening statement submitted that the Board must ensure rates are sufficient to cover NS Power's cost-of-service, while preventing the recovery of excess spending and pro...

AI summary The Affordable Energy Coalition (AEC) argues that Nova Scotia Power's (NS Power) rates must cover costs without allowing excess profits, citing low-income affordability concerns and suggesting a reduced return on equity (ROE) of 7.6%. NS Power defends its current ROE and capital structure, citing Concentric's evidence, to balance affordability and investment needs.

- [16] As part of the outage review, the Board has received a number of comments from members of the public questioning, among other things, why NSPI's request for a rate increase should be considered when the service provided by NSPI is,...

AI summary The Nova Scotia Utility and Review Board (Board) addresses public concerns about Nova Scotia Power Inc.'s (NSPI) rate increase request despite perceived service inadequacies. The Board explains that NSPI, as a regulated monopoly, operates on a cost-of-service basis, allowing it to recover reasonable costs. Rate decisions are tied to cost prudence, not reliability or public opinion, with the Board balancing utility costs against fair rates for consumers.

3.8 Cost of Service Study [561] Under the PUA , a utility is afforded the opportunity to recover its "reasonable and prudent" costs of providing service and a "just and reasonable" return on its rate base. The total amount of these costs a...

AI summary The section outlines the regulatory framework under the Public Utilities Act (PUA) for cost recovery and rate setting, emphasizing 'reasonable and prudent' cost recovery and 'just and reasonable' returns. It references the Nova Scotia Court of Appeal's decision in Dalhousie Legal Aid Service v Nova Scotia Power Inc. , which prohibits rate discrimination based on customer ability to pay, and highlights factors for grouping customers into classes.

Changes to Open Access Transmission Tarriff to Align Bundled and Unbundled Service NS Power said methodological differences in how rates are set for transmission service in the unbundled market under the Open Access Transmission Tariff (OA...

AI summary NS Power identifies discrepancies in transmission rate methodologies between the OATT and bundled service cost-of-service studies, proposing alignment through equal revenue requirements, full demand cost classification, and forecasted usage application.

Radial to Generation NS Power proposes that radial-to-generation assets, as defined under the OATT, be re-functionalized from transmission to generation in the cost-ofservice study for consistent treatment of these assets under the transmi...

AI summary NS Power proposes re-functionalizing radial-to-generation assets from transmission to generation in the cost-of-service study to ensure consistent treatment under transmission pricing methodologies, align with North American utilities, and adhere to FERC's pro forma OATT design.

General Plant General plant primarily consists of NS Power's investment in facilities, such as buildings structures and grounds, communication equipment, vehicles and information technology infrastructure. Currently, costs are apportioned...

AI summary NS Power proposes allocating general plant costs above $1 million to specific functions (e.g., transmission, distribution) using allocators like operating costs and rate base, differing from the current net book value-based allocation across generation, transmission, and distribution.

[581] The parties to the settlement agreement included the following terms relating to cost-of-service methodology used to determine rates for 2026 and 2027: Cost of Service ("COS") a) The COS as set out in the Draft GRA will be included i...

AI summary The settlement agreement outlines terms related to the cost-of-service methodology for determining rates in 2026 and 2027. It specifies that the Draft GRA will be included in the 2026-2027 GRA and subject to future proceedings, including data collection on PHP's use of the High Voltage transmission system and apportionment of assessment costs from the Maritime Link.

Q. Considering the consensus agreement in this GRA, what do you recommend regarding the Company's COSS methods? A. While I do not support several of the Company's COSS methodologies, particularly the use of the minimum system method for cl...

AI summary The respondent acknowledges a settlement agreement in the GRA but opposes certain COSS methods, advocating for their revision in future proceedings. Renewall Energy Inc. raised concerns about inconsistencies between NS Power's COSS methodologies and OATT charges.

3.8.1 Findings [584] For the purposes of setting rates in this proceeding, the Board accepts the proposed cost-of-service changes and the cost-of-service studies presented in this proceeding, except NS Power is directed to implement a load...

AI summary The Board accepts NS Power's cost-of-service studies but requires adjustments, including a load carrying capability adjustment. NS Power must address concerns from Ms. Palmer and Renewall, particularly regarding distribution cost allocation and OATT tariff issues. These adjustments are to be addressed in future applications.

3.8.2 Minimum System v. Basic Customer Methods [586] NS Power's cost-of-service study classifies portions of its distribution system as customer-related using the minimum system method. Under this approach, a minimum system study estimates...

AI summary NS Power's cost-of-service study classifies distribution system costs using the minimum system method, deeming costs of a hypothetical minimum system as customer-related. The Board considers evidence supporting this approach as standard in Canada, with references to general rate applications and prior studies.

[588] The other was prepared by Elenchus and is also found in the engagement process cost-of service materials filed in this matter: Utility Transformers Transformers Primary BC Hydro Judgement (50%/50%) Judgement (100% Demand) Judgement (...

AI summary This table compares various utilities' approaches to transformer-related cost allocations, including methods like Judgement, Minimum System, and Zero-Intercept analyses, with specific percentages and orders referenced for different utilities in Nova Scotia and other regions.

[605] In its submissions, the Consumer Advocate noted: The Consumer Advocate shares Ms. Palmer's concerns regarding the Minimum System Method, and through the Settlement Agreement, and resulting GRA, NS Power has agreed that the use of the...

AI summary The Consumer Advocate supports a separate proceeding for the Minimum System Method, while the NDP and Liberal Caucuses advocate for the basic customer method to fairly allocate distribution costs. NS Power defends using the COSS for cost allocation.

3.8.3 Primary Distribution System [613] If the basic customer method is not used to allocate distribution system costs between customer and demand, then Ms. Palmer recommends that the primary distribution system be classified 100% to deman...

AI summary Ms. Palmer recommends classifying the primary distribution system 100% to demand, citing concerns with the minimum system methodology used in the cost-of-service study. She argues that primary infrastructure is shared and more likely to peak at the same time as system peaks. An analysis by Concentric in 2022 found that a significant percentage of distribution system poles and conductors are part of the primary distribution system.

this is kind of a middle route. I've acknowledged it's an approximation and that it will be superior to have Nova Scotia Power's analysis when available. [Transcript, January 13, 2026, pp. 1311-1312] [621] In response to Undertaking U-6, N...

AI summary NS Power analyzed a 1.5 kW/customer peak load carrying capability adjustment, shifting ~$7M in distribution costs from residential to other rate classes. The adjustment reduces proposed rate increases for domestic classes but increases them for general service classes. The Board noted an exhibit error, correcting 'Large General' to 'Small Industrial'.

Proposed COSS Methodology Modified COSS Methodology as per U-6 Variance Smoo othed Sm oothed Smoo thed Customer Class 2026 2027 2026 2027 2026 2027 Domestic 3.8 4.1 3.2 3.7 (0.6) (0.4) Small General 3.6 3.9 3.4 3.8 (0.2) (0.1) General (0.2...

AI summary The table compares proposed and modified Cost-of-Service Study (COSS) methodologies under Undertaking 6 (U-6), showing variances in cost allocations across customer classes (e.g., Domestic, Large Industrial). The data highlights differences between 2026 and 2027 projections, with significant variations in cost estimates for specific classes. The exhibit (N-77) is referenced as part of the regulatory proceeding.

3.8.4.1 Findings [624] Notwithstanding the settlement agreement, the Board finds that it is appropriate to direct NS Power to implement a load carrying capability adjustment in this proceeding. Unlike the evidence relating to the use of th...

AI summary The Board directs NS Power to implement a 0.4 kW/customer load-carrying capability adjustment, rejecting Excel Energy's 1.5 kW figure as inappropriate. The adjustment must be addressed now, not deferred, and NS Power must conduct further analysis before customer engagement. The decision emphasizes independent evaluation of load-carrying capability, separate from rate impacts.

3.8.5 Other Cost-of-Service Issues Raised by Synapse [628] As noted already in this decision, in addition to her concerns about the use of the minimum system method to classify distribution system costs, Ms. Palmer had concerns about certa...

AI summary Ms. Palmer raised concerns about NS Power's proposed changes to cost-of-service methodologies, including classifying generation and transmission costs using new approaches and using granular allocators. She recommended a future proceeding to examine these changes. NS Power clarified that the settlement agreement limits the future proceeding to the minimum system method issue.

3.8.5.1 Findings [631] It is clear that Ms. Palmer has some misgivings about other aspects of NS Power's cost-of-service methods, but in light of the settlement agreement, she elected to focus on the minimum system vs. basic customer issue...

AI summary The Board acknowledges a settlement agreement but emphasizes it does not determine public interest in accepting it. Ms. Palmer focused on minimum system vs. basic customer issues, while the Board directs NS Power to address her concerns in a future application. Synapse is encouraged to raise cost-of-service issues for Board consideration.

3.8.6 Issues Raised by Renewall Energy Inc. [633] As mentioned earlier in this decision, in its closing submissions, Renewall said there were inconsistencies between NS Power's cost-of-service methodologies and the methods used to determin...

AI summary Renewall Energy Inc. argues that inconsistencies between NS Power's cost-of-service methodologies and OATT charges impact renewable-to-retail market rates. It emphasizes the Board's duty under s. 6(2) of the Energy and Regulatory Boards Act to foster a competitive electricity market.

[634] NS Power submitted: NS Power applied the approved OATT and COS methodologies, as amended in the Settlement Agreement, to determine the proposed bundled and OATT charges. The transmission costs are allocated to the bundled rate classe...

AI summary NS Power applied OATT and COS methodologies to allocate transmission costs using 3CP and 12CP approaches. Renewall Energy Inc. raised concerns about a discrepancy in coincident factors (78.6% vs. 91.66%) affecting network service charges. NS Power clarified the factors served different purposes and were not directly used in rate calculations.

3.9.2 Residential and Small General Customer Charges [649] In its last general rate application, NS Power proposed to increase customer charges for the domestic service and small general customer classes to align those charges with costs u...

AI summary NS Power proposed increasing customer charges for residential and small general customer classes to align with costs from its cost-of-service study. Other parties raised concerns, leading to a settlement where charges were set at 75% of the proposed amounts. In the current proceeding, NS Power suggests increasing these charges in line with smoothed non-fuel cost revenue increases for these classes.

[650] In its response to NSEB IR-133, NS Power also calculated the customer charges that would result from a direct use of customer costs under its cost-of-service study. The results, which are reproduced below, also showed the offsetting...

AI summary NS Power calculated customer charges resulting from a direct use of customer costs in its cost-of-service study, showing the impact on proposed energy rates to maintain cost recovery for these customers.

3.9.2.1 Findings [652] The Board accepts that there may be legitimate arguments for not setting customer charges for these classes directly from the cost-of-service study. However, given the potential impacts that the setting of customer a...

AI summary The Board acknowledges potential issues with setting customer charges directly from cost-of-service studies, emphasizing concerns about intra-class cost shifting, efficiency, and demand response. It directs NS Power to address this in future rate applications and references a method from an Ontario Energy Board discussion paper for setting fixed monthly customer charges.

ordingly, LIIR interruptible load equipped with Telemetry and Control will be included in managing realtime 10-minute reserve at all times, not just when it is not available from generation resources. [663] On the issue of alternative cost...

AI summary NS Power argues that +/-16 MW regulation capability is necessary for system stability, with Reg Down service capacity requiring separate cost recovery under OATT. They assert the current methodology fairly allocates costs without double-counting.

3.10.1.1 Findings [668] As noted above, OATT rates have been updated to reflect changes in the generation and transmission asset mix and costs, and changes in system usage since the last update in the 2023-2024 GRA. NS Power also amended t...

AI summary NS Power updated OATT rates to reflect changes in generation and transmission assets, costs, and system usage since the 2023-2024 GRA. Amendments were made based on consultation in the 2024 Cost of Service proceeding and addressed the Board's directives from M10431. The Board approved the proposed OATT amendments.

4.1 Demand Side Management Cost Recovery Rider [686] In this GRA, NS Power proposed changes to the methodology for calculating the Balance Adjustment (BA) but did not propose changes to the Demand Side Management (DSM) rider amounts for 20...

AI summary NS Power proposed changes to the Balance Adjustment (BA) methodology without altering DSM rider amounts for 2026/2027. It filed a DCRR application (M12521) for 2026 DSM expenses, with the Board approving continuation of 2025 DCRR charges until further order. The 2026 DSM expenditure was set at $63.75M by legislation, with assumptions extended to 2027. NS Power argued that extending end-of-term variance recovery periods would reduce rate volatility and align with new five-year DSM planning terms.

4.1.1 Findings [693] The Board's Interim Order in Matter M12521 approved continuation of the 2025 DCRR charges commencing January 1, 2026, until further order of the Board in that matter, or as part of NS Power's GRA. In this current matte...

AI summary The Board's Interim Order in Matter M12521 continues 2025 DCRR charges until 2026, with final approval for 2026 rider amounts pending. NS Power proposes changes to the Balance Adjustment (BA) calculation but not DSM rider amounts for 2026/2027. The Board approves amended DCRR tariff amendments to address end-of-term variances and improve DSM cost recovery by allowing E1 to reallocate expenditures between rate classes.

4.2 Storm Cost Recovery Rider [695] During the 2023-2024 GRA process, participants raised a concern about the asymmetrical nature of the Storm Cost Recovery Rider (SCRR). The current SCRR allows for NS Power to apply to recover Level 3 and...

AI summary The document discusses the Storm Cost Recovery Rider (SCRR) and the concerns raised during the 2023-2024 GRA process regarding its asymmetrical nature. NS Power is requesting approval to continue the SCRR as a pilot during 2026 and 2027 on a symmetrical basis, allowing for both recovery of excess storm costs and returning underspend to customers.

[699] The 2026 and 2027 values for the SCRR rider are zero but NS Power's forecast expenditures for OM&G storm restoration costs in 2026 and 2027 are: Level 1 & 2 ($ million) Level 3 & 4 ($ million) 2026 9.6 10.1 2027 9.8 10.3 [Exhibit N-3...

AI summary The SCRR rider values for 2026 and 2027 are set to zero, despite NS Power forecasting OM&G storm restoration costs of $9.6 million (Level 1 & 2) and $10.1 million (Level 3 & 4) in 2026, and $9.8 million (Level 1 & 2) and $10.3 million (Level 3 & 4) in 2027.

4.2.1 Findings [701] As noted above, the 2026 and 2027 values for the SCRR rider are zero. The proposed amendments are expected to correct the unbalanced asymmetrical nature of the current version of the rider. The amendments should also m...

AI summary The Board approves proposed amendments to the SCRR rider for 2026-2027, aiming to correct its unbalanced asymmetrical nature and reduce administrative burden by eliminating small refund applications. The pilot program is endorsed to streamline processes and improve efficiency.

4.4 Lingan Unit 2 and Trenton Unit 5 [712] In its general rate application, NS Power assumed sustaining capital expenses of $20,829,182 at Lingan 2 during the 2026-2027 test period, including $18,433,591 in 2026 and $2,395,591 in 2027 (Bat...

AI summary NS Power's general rate application includes sustaining capital expenses for Lingan Unit 2 and increased OM&G costs for both Lingan Unit 2 and Trenton Unit 5. Bates White notes the costs are substantial relative to the energy output and recommends additional narrative support for the capital cost increase.

- Maintaining NS Power's current return on equity of 9.0%, with an earnings band of 8.75% to 9.25%. The equity thickness for rate setting purposes remains at 40.0%; - The establishment of the securitization deferral to defer depreciation e...

AI summary The summary outlines key directives and findings related to NS Power's return on equity, depreciation rates, cost-of-service methodology, and various deferral accounts. It includes the establishment of a securitization deferral, adjustments to depreciation studies, and the handling of revenue variances and tax expenses.

ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...

AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs, subject to approval by the Nova Scotia Energy Board (NSEB). If actual costs exceed or are below the approved amount, specific recovery and return procedures apply. SCRR costs include preparation, response, and restoration expenses, and are allocated based on the Company's Cost of Service Study.

PCR = Program Cost Recovery The PCR includes all estimated costs for the upcoming calendar year for the DSM Plan that has been requested by the Franchise Holder and approved by the NSEB (Approved DSM). It includes the cost of planning, dev...

AI summary The Program Cost Recovery (PCR) encompasses all estimated costs for the Approved DSM Plan, including planning, implementation, and administrative expenses, and is calculated using the cost allocation methodology outlined in Schedule B of the tariff.

2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges and its components, PCR and BA, for the period from January 1, 2026, to December 31, 2026.

Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.642 0.006 0.648 Small General, Small Gener...

AI summary The table outlines applicable tariffs, including PCR, BA, and DCRR rates for various service types. It also explains the calculation of BA2 following the 2023-2026 term, which will be applied over the 2027-2031 term.

2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...

AI summary The Balancing Adjustment Component (BA) is designed to correct over/under-recovery from the Actual Adjustment Component and may include deferrals of fuel and purchased power costs, subject to Board approval. It becomes effective May 1, 2026.

3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...

AI summary This section outlines the Fuel Adjustment Mechanism (FAM) used by NS Power, detailing how the FAM rate is calculated annually using an Actual Adjustment (AA) and a Balance Adjustment (BA). The mechanism includes deferral of over- or under-recovery amounts and allocation of fuel-related costs to specific rate classes.

ach class. The resultant costs by class will then be reconciled to the total ATL fuel-related costs based on their Effective: May 1, 2026 Page 8 of 33 relative share of the total fuel costs. - 6. The interest amount on the over- or under-r...

AI summary The document outlines how interest amounts related to fuel cost over- or under-recovery are apportioned to individual rate classes based on their relative share of fuel costs. This process ensures that the interest is distributed equitably among classes, with adjustments made depending on whether there is an over- or under-recovery of fuel costs.

3.2.17 GHG Emission Compliance Program Costs - The cost of Fund Credits under the Nova Scotia GHG Output Based Pricing System (OBPS) emissions compliance programs. - Transaction fees for purposes of purchasing GHG OBPS Fund Credits). Costs...

AI summary This section outlines the costs associated with GHG emission compliance programs, specifically the cost of Fund Credits under Nova Scotia's OBPS and transaction fees for purchasing these credits. These costs are recorded in account 503400 REG EMISSION ALLOWANCE EXPENSE in NS Power's Chart of Accounts.

ing January 1, 2026 and ending December 31, 2027 or to such time as determined by the NSEB. GRLF Revenue: The revenue received from Generation Replacement and Load Following (GRLF) Rate billings. GRLF Administration Costs: That portion of...

AI summary This section defines key terms related to the GRLF Rate, including revenue, administration costs, and requirements, as well as terms related to fuel cost adjustments, prior year balances, and interest accumulation. These definitions are effective starting May 1, 2026.

the entirety of this process, customer representatives have been aided by their expert consultants. Relevant components of the GRA to which all Parties noted above have agreed include the following: • An overall average rate increase acros...

AI summary The document outlines agreed-upon components of the GRA, including rate increases, updated studies, retention of financial parameters, continuation of a storm cost recovery rider, amendments to the DSM rider, and plans for securitization of thermal assets. These measures are expected to impact customer rates and savings over the 2026-2027 period.

Comment Page 75 of the GRA provides: The timing of this transition is largely out of NS Power's control and will continue to evolve over 2025 as NSIESO Management is appointed and a transition plan is refined. NS Power plans to apply to th...

AI summary NS Power notes that the timing of the NSIESO transition is beyond its control and plans to seek recovery or refund of cost differences once the transition is complete. It argues that the relevant aspect for the GRA is ensuring no duplicative costs are paid by customers, and that this issue does not require further evidence in the hearing.

Issue A revised Storm Cost Recovery Rider pilot

AI summary The document introduces a revised Storm Cost Recovery Rider pilot, aiming to address the financial impacts of storm-related costs on utility operations and customer rates.

Comment The Storm Cost Recovery Rider pilot is currently asymmetrical in that it allows for the recovery of Level 3 and 4 storm OM&G restoration costs above those included in revenue requirement. The proposed revision would simply continue...

AI summary The Storm Cost Recovery Rider pilot is currently asymmetrical, allowing recovery of Level 3 and 4 storm OM&G restoration costs above revenue requirement. The proposed revision aims to make it symmetrical by returning any underspend to customers. This change addresses customer concerns and aims to equitably manage volatility from severe weather events.

[2008 NSUARB 140] - [58] The GRA Settlement Agreement in this proceeding was reached by the parties after the hearing was finished. This matter had a full evidentiary record containing over 30,000 pages of information and spreadsheets, inc...

AI summary The GRA Settlement Agreement was reached after a hearing with extensive evidence, including 30,000 pages of documents, expert reports, and public comments. The NSUARB emphasizes its duty to ensure the agreement's terms are just, reasonable, and in the public interest, aligning with prior decisions and ongoing proceedings.

Collaborative and Consultative Processes NS Power noted that its Line Loss Study and its Cost-of-Service Study were undertaken through collaborative processes. These studies have an impact on NS Power's revenue requirement and how costs ar...

AI summary NS Power conducted collaborative studies impacting revenue and cost allocation, which the Board commends but clarifies do not prevent parties from challenging study findings in proceedings. Effective consultative processes may reduce controversy in related Board decisions.

Addressed in Application or Evidence from Consultants NS Power submitted that certain issues were addressed in evidence from consultants filed with its application. In particular, evidence filed by Concentric Energy Advisors supporting NS...

AI summary NS Power argues that consultant evidence (from Concentric Energy Advisors and ScottMadden) addresses key issues impacting proposed rates, including capital structure, financing costs, and working capital. It also claims Maritime Link Transmission Projects meet rate base eligibility criteria. NS Power contends other parties should not submit evidence on these matters, but the text deems this position unreasonable.

Addressed in Another Proceeding NS Power submitted several of the issues identified on the Draft Issues List were or will be addressed in other proceedings. 1. NS Power has specifically asked the Board for approval in this proceeding to ex...

AI summary NS Power requested to extend the Storm Cost Recovery Rider beyond its three-year term and make it symmetrical, but the Board found this position unreasonable. The Board emphasized that the GRA was the appropriate venue for amendments to the rider, not annual filings. Intervenors and others may still address the issue despite NS Power's stance.

Residual Comments - 1. NS Power submitted that the express mention of pensions, executive compensation, and expenses shared with affiliates was of little or no relevance in the proceeding and should not be expressly set out as a focus in t...

AI summary NS Power argues that pensions, executive compensation, and shared affiliate expenses are irrelevant to the proceeding, while the Board disagrees but will remove explicit references. NS Power claims the NSIESO transition costs are irrelevant, focusing instead on a deferral mechanism. The Board asserts the transition's cost impact is relevant. NS Power contends section 6(2) of the Energy and Regulatory Boards Act does not require addressing all factors, but the Board insists these factors must be considered.

FINAL ISSUES LIST The following issues will be dealt with in the public hearing on Nova Scotia Power Incorporated's (NS Power) 2026-2027 General Rate Application (Matter M12451) which is set to begin Wednesday, January 7, 2026: - 1. Fuel a...

AI summary The Final Issues List outlines 21 topics for public hearing on NS Power's 2026-2027 rate application (M12451). Key areas include fuel cost mechanisms, capital structure compliance with the Public Utilities Act, rate design, climate adaptation plans, cybersecurity impacts, and securitization issues. The hearing begins January 7, 2026.

- 4. Deferral of costs for the completed Cost of Service Study, Line Loss Study, and Climate Change Adaptation Plan to be collected as a regulatory asset as previously approved in the 2023-2024 General Rate Application decision. - 5. NS Po...

AI summary NS Power is proposing several deferrals and adjustments, including deferring costs from studies and plans, developing a securitization approach for thermal generation assets, addressing potential changes in federal tax rules, and updating depreciation studies. These proposals aim to manage financial impacts and align with regulatory decisions.

Request IR-32: - Referring to regulatory amortizations, please expand Figure 8-3 of the application to include the - opening balance in each account as of January 1, 2026, any forecast additions, the proposed - amortization, and the ending...

AI summary The request asks to expand Figure 8-3 to include opening balances, forecast additions, amortization, and ending balances for 2026 and 2027, focusing on regulatory amortization details.

Request IR-36: - Please prepare a detailed reconciliation demonstrating how all costs proposed to be included in - the GRA and COSS deferral have been removed from the forecast costs included in the - application for 2026 and 2027.

AI summary Request IR-36 asks for a detailed reconciliation to confirm that all costs associated with the GRA and COSS deferral have been excluded from the 2026 and 2027 forecast costs submitted in the application.

Question: (a) Please confirm that more recent (July 2025) data from reputable debt rating agencies reports the following debt ratings, which show that Canada has higher debt ratings than the U.S. with S&P and Moody's, consistent with their...

AI summary The document requests confirmation on Canada's higher sovereign debt ratings compared to the U.S., the existence of a 'home bias' in Canadian investments, U.S. government bond yield trends, and whether NS Power would borrow in the U.S. despite higher costs and currency risk. It cites data on debt ratings, investment allocations, and bond yields.

al. (2016) study (which examines MRPs over the 1900-2015 period), and is 1 Request IR-9: 32 33 accompanying formulae. 34 35 Request IR-10: 36 37 38 Preamble: On pages 48-49 of Appendix 10A, Concentric discusses its market risk premium (MRP...

AI summary The document references a study by al. (2016) examining market risk premiums (MRPs) from 1900 to 2015, and mentions Concentric's use of MRP estimates in its CAPM cost of equity calculations, as outlined in Appendix 10A, pages 48-49.

Request IR-6: References: Direct Evidence p. 68: "However, this forecast assumes approval of the rates requested in this Application and a successful securitization of the net book value of the thermal assets. Absent an increase in general...

AI summary NS Power forecasts that failure to secure rate increases and securitize thermal assets may cause its credit ratings to deteriorate below the 10% cash flow to debt threshold by 2027, impacting access to capital and increasing borrowing costs. The request asks for specific financial statement line items affected by credit rating deterioration and commentary linking past threshold breaches (2022-2023) to current credit ratings.

Request IR-18: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 13-14 of 58 - Per N-6, (Appendix 7C), page 13-14 of 58, we understand that 2026 forecast is lower than 2024 - compliance restated and 2024 actuals for "faciliti...

AI summary The document references a 2026 forecast lower than 2024 due to changes in allocating carrying costs on materials inventory to the procurement cost center. Questions are raised about the rationale for this allocation change and whether NSPI received approval for it.

Request IR-21: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 17-18 of 58 - Per N-6, (Appendix 7C), page 17-18 of 58, we understand that rental/maintenance equipment/ - software expense has increased in 2026 forecast compa...

AI summary The document requests clarification on the increase in rental/maintenance equipment/software expenses in 2026, attributed to the cyber security program and inflation, and seeks a detailed breakdown of these costs.

Request IR-25: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 21-22 of 58 - Per N-6, (Appendix 7C), page 21-22 of 58, we understand that contracts expense has decreased - in 2026 forecast compared to 2024 compliance restat...

AI summary The request seeks a breakdown of decreased contracts expense for 'head office' in 2026, attributed to reduced OM&G ash hauling costs due to NS Power's proposal to transfer these expenses to Fuel and Purchased Power in the GRA.

Request IR-32: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 33-34 of 58 - Per N-6, (Appendix 7C), page 33-34 of 58, we understand that contracts expense has increased - from 2024 compliance restated to 2026 forecast for...

AI summary The document references N-6 2026-2027 GRA Direct Evidence Appendix 7C, pages 33-34, noting an increase in contracts expense for 'Enterprise asset management & project implementation' from 2024 to 2026 due to operational changes and inflation. It requests detailed cost information on these changes.

Request IR-37: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 39-40 of 58 - Per N-6, (Appendix 7C), page 39-40 of 58, we understand that consulting expense has increased - from 2024 compliance restated to 2026 forecast for...

AI summary The text references N-6, Appendix 7C, pages 39-40, requesting details on increased consulting expenses for the control center from 2024 to 2026, attributed to engineering, operator training, and interconnection studies. The request seeks additional cost breakdowns for these engagements.

Request IR-42: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 43-44 of 58 - Per N-6, (Appendix 7C), page 43-44 of 58, we understand that consulting expense and - membership dues expense has increased from 2024 compliance r...

AI summary The request seeks an explanation for increased consulting and membership dues expenses in the 2026 forecast compared to 2024, attributed to 'reliability implementation' and reallocation from contracts related to standards and community engagement.

Request IR-43: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 45-46 of 58 - Per N-6, (Appendix 7C), page 45-46 of 58, we understand that labour expense has increased - from 2024 compliance restated and 2024 actual to 2026...

AI summary The document requests explanations and cost breakdowns for increased labor expenses in 'transmission and distribution contractor management' from 2024 to 2026, citing factors like staffing increases, vacancies, higher utility demand, reorganization, and salary escalations. The request references Appendix 7C of the 2026-2027 GRA Direct Evidence.

Request IR-44: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 45-46 of 58 - Per N-6, (Appendix 7C), page 45-46 of 58, we understand that contracts expense has increased - from 2024 compliance restated and 2025 budget to 20...

AI summary The document requests a breakdown of increased contracts expenses for transmission and distribution contractor management from 2024 to 2026, citing factors like maintenance on aging fleet vehicles, utility costs, and inflation. NSPI is asked to provide supporting documentation for these increases.

Request IR-52: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 53-54 of 58 - Per N-6, (Appendix 7C), page 53-54 of 58, we understand that contracts have increased from - 2024 compliance restated and 2024 actual to 2026 fore...

AI summary The text requests supporting cost breakdowns for increased contracts related to grid modernization and customer integration from 2024 to 2026, citing increased requirements in customer experience, SMOC, Telecom, and customer engineering and innovation teams.

Request IR-56: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 57-58 of 58 - Per N-6, (Appendix 7C), page 57-58 of 58, we understand that vehicle allocated costs has - increased from 2024 compliance restated to 2026 forecas...

AI summary The document requests a cost breakdown for increased capital investments in transmission and distribution assets, attributing the increase to higher capital spending. It also seeks an explanation for the decrease in vehicle costs from 2024 actual and 2025 budget to 2026 forecast, linked to the profile of capital investment.

Request IR-60: - Reference: FO-11 - Please provide workbooks, calculations and other supporting documentation for each line item - included in FO-11 (Details of interest and other expenses), including each of the below: - a) interest on lo...

AI summary The document requests detailed supporting documentation for specific financial line items (interest on debt, financing adjustments, etc.) included in FO-11, part of a regulatory proceeding.

Request IR-62: - Reference: FO-01 - Per FO-01, please explain why the effective corporate income tax rate for both proposed 2026 - and 2027, calculated at (11.5%) and 2.1% respectively, does not align with the company's - statutory rate of...

AI summary The requester questions why the effective corporate income tax rates for 2026 (11.5%) and 2027 (2.1%) differ from the statutory rate of 29%, expecting inclusion of both current and deferred taxes.

Request IR-63: - Reference: OE 10-11 - Per OE 10-11, there are Part VI.1 taxes included in current income taxes for both 2025 and 2026 - proposed. Why are Part V1.1 tax deductions included in regulated income taxes when directed - by the B...

AI summary The document questions why Part V1.1 tax deductions are included in regulated income taxes for 2025-2026, despite the Board's GRA Decision to exclude them. It references OE 10-11, which outlines Part VI.1 taxes as part of current income taxes.

Request IR-64: - Reference: RB-02- RB-16 - Per RB-02-RB-16, please confirm there are no deferred charges included in rate base for - deferred tax assets related to loss carry forwards created by Part VI.1 tax deductions. If included, - ple...

AI summary Request IR-64 seeks confirmation on whether deferred charges from tax assets related to Part VI.1 loss carry forwards are included in Nova Scotia Power Inc.'s rate base. If included, the request demands an explanation and details on the amount. The reference RB-02-RB-16 is cited.

Request IR-65: - Reference: OE-10-11 - Per OE-10-11, please explain the proposed 2026 and 2027 adjustments for 'Deferred income - taxes on loss carryforward', 'Reclassification of CIT to/from DIT (with regulatory offset)', and - 'Current i...

AI summary Request IR-65 seeks clarification on proposed 2026 and 2027 adjustments for 'Deferred income taxes on loss carryforward,' 'Reclassification of CIT to/from DIT (with regulatory offset),' and 'Current income tax recovery Investment tax credits.' It requests calculation details, sources, reasons, and regulatory offsets.

Request IR-70: - Reference: Exhibit N-11( C )-(ii) - Exhibit N-11( C )-(ii) (2026-2027 GRA DA-03 Att 1 Excel Confidential) provides the total - regulatory amortizations by account for 2024-2027F. Please reconcile the 2024 actuals - regulat...