Topic:"Rate Base" in M12551

- 5 In addition, in the 2019 AARs proceeding NS Power committed to providing a comparison of values - 6 associated with each assumption from the current and previous year's application and PLEXOS - output reports. 16 The PLEXOS model used...

AI summary The document discusses NS Power's use of the PLEXOS model in the 2026 AARs proceeding, including modeling assumptions and sensitivity analyses on fuel prices. It references the 2019 AARs proceeding and a 2025 Q3 Fuel and Purchased Power model.

14 Figure 13: CBL Adder 2026 ($/MWh) CBL Cost 73.60 Minus FCR 3.75 CBL Energy Charge 69.85 Constant (CBLA) 1.25 Plus FCR transferred from CBL Cost 3.75 Total CBLA 5.00 8.1.3 Variable Capital Charge 2 The ELIADC Energy Charge includes a Var...

AI summary This section discusses the CBL Adder and Variable Capital Charge (VCC) in the context of NS Power's 2021 AAR application. The CBL Adder is calculated by subtracting FCR from CBL Cost and adding back FCR transferred from CBL Cost, resulting in a total CBLA. The VCC is part of the ELIADC Energy Charge and is used to account for the incremental generation and delivery costs of electricity for PHP.

REDACTED 2026 AAR Application Appendix B2 Page 1 of 19 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1P-RTP ADDER CALCULATION Transmission-connected O&M Capital ROE Generation Costs $0.01496 $0.02561 $0.01125 $0.05182 $0.01538 $0.02086 $0.00...

AI summary This document presents a table with various cost calculations, including transmission-connected costs, fixed costs, and customer costs. It includes percentages and monetary values related to operations, capital, return on equity, and fuel cost adjustments.

REDACTED 2026 AAR Application Appendix B2 Page 6 of 19 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Approved Year 2025 Proposed Year 2026 Exclude the GRLF, LRT and Shore Power rate classes. Exclude the following rate classes: the GRLF, OATT...

AI summary The table compares average hourly KW requirements across different voltage classes for 2025 and 2026, highlighting significant variance percentages, including a 95.9% increase in EHV and a -100.0% change in HV. The GRLF, LRT, and OATT rate classes are excluded in 2026, affecting the data representation.

NON-CONFIDENTIAL 1 NS Power utilizes the Partially Confidential electronic Excel file, Appendix B2, to calculate the 2 1P-RTP rates by using the following method. 3 4 • The costing determinants such as Monthly Energy requirement, Monthly s...

AI summary NS Power uses a Partially Confidential Excel file to calculate 1P-RTP rates by inputting costing determinants, fixed costs from the 2026 Cost of Service Study, and breaking down fixed costs by expense type and customer service level. The company no longer includes fuel cost adjustments in the Adders, as per its October 2025 memorandum.

NON-CONFIDENTIAL 1 Adding the Generation, Transmission, distribution, customer costs and fuel cost adjustment rates 2 by Service level in the tables above produces the 2026 1P-RTP components as shown below that 3 reconcile to those in Figu...

AI summary The text discusses the addition of generation, transmission, distribution, customer costs, and fuel cost adjustment rates by service level to produce the 2026 1P-RTP components, which align with those in Figure 3 from NS Power's evidence.

- (2) A fixed cost adder adjusted concurrent with changes in base cost rates coming into effect as a result of a General Rate Case application. Base Energy Charge Components Transmission Voltage of 69 kV or Higher (cents per kWh) Distribut...

AI summary The text describes a fixed cost adder that is adjusted in tandem with changes in base cost rates resulting from a General Rate Case application. A table provides details on base energy charge components, including fuel cost and fixed cost adder for different voltage levels.

SALES, GENERATION AND DEMAND ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2026 ( 1) DOMESTIC ( 2) SMALL GENERAL ( 3) GENERAL ( 4) GENERAL LARGE (1) MWH SALES 5,286,337,241 376,992,742 2,308,034,614 363,766,784 (2) ENERGY LINE 8.2% 8.2% 7.9% 5...

AI summary The document presents a sales, generation, and demand analysis for the year ending December 31, 2026, including data on energy sales, losses, demand factors, and contributions by different classes and sources. It outlines key metrics such as MWH sales, energy losses, system demand, and coincident factors.

Annual Peak of ATL 2,356,954 Annual Energy Requirement of ATL 11,303,785,142 System Coincident Load Factor 54.748044% Rate Base Average 2025 2026 Steam Plant $ 481,584 $ 543,265 $ 419,903 Steam Plant - CWIP $ 4,559 $ 4,744 $ 4,374 Steam En...

AI summary The text provides data on the annual peak and energy requirement of ATL, along with a detailed table outlining various plant components and their associated costs for different years, including Steam, Hydro, Wind, and Gas Turbine Plants, as well as their respective CWIP (Construction Work in Progress) and environmental and fuel conversion costs.

PURPOSE Pursuant to Section 3G(2) of the Electricity Act (Nova Scotia), this Renewable to Retail Market Transition Tariff (RTT) is designed to recover from Licenced Retail Suppliers (LRS) NS Power's embedded fixed costs and deferred costs,...

AI summary The Renewable to Retail Market Transition Tariff (RTT) is established under the Electricity Act to recover NS Power's embedded fixed and deferred costs from Licensed Retail Suppliers (LRS). These costs include depreciation, financing, and operational expenses, and are to be recovered through Bundled Service, not through other applicable tariffs.

NON-CONFIDENTIAL Request IR-4: Reference: Page 38, lines 22-23. NSPI confirms the possibility of the ELIADC Tariff being discontinued before the end of 2026. If that is the case: (a) Does the anticipated duration of service to be provided...

AI summary NSPI confirms the possibility of discontinuing the ELIADC Tariff before the end of 2026 and explains that the Energy Charge calculation will still be based on the forecast annual cost to serve PHP, even if the tariff is extended for less than a year. A full year forecast is required for operational constraints, but actual costs will be finalized at the end of the tariff term.

EXTRA LARGE INDUSTRIAL ACTIVE DEMAND CONTROL TARIFF Page 3 of 8 $61.75/MWh. The FCR transferred from the CBL Cost is then added to the calculated CBLA to equal $5/MWh FCR. x When the forecast CBL Cost is at or over $61.75/MWh, the FCR to b...

AI summary The ELIADC Energy Charge is calculated by summing the CBL Energy Charge, CBLA, and VCC. When the forecast CBL Cost exceeds $61.75/MWh, the FCR transferred is capped at $3.75/MWh, with the difference assigned a value of zero. These charges are submitted for Board approval annually as part of the Annual Adjusted Rates proceeding.

Annually Adjusted Rates for 2026 (NSEB M12551) NSPI Responses to NSEB Information Requests 1 Request IR-8: 2 3 Appendix E5 provides the calculation for the . Please explain how the 4 5 6 Response IR-8: 7 8 Appendix E5 provides the calculat...

AI summary The response to Request IR-8 explains that Appendix E5 calculates the marginal cost-based Demand Charge of $13.430 per kW, supporting a four-year phase-in of embedded cost-based charges under the BUTU Tariff. The calculation uses the annual levelized capacity cost, which was used to determine the interruptible credit of $7.638/kVA in the 2026-2027 GRA.

NON-CONFIDENTIAL 1 Request IR-11: 2 3 Appendix J refers to the 1P-RTP moving from an annually adjusted rate to one set through 4 a General Rate Application. However, toward the bottom of page 2 of 3 in the appendix NS 5 Power states that t...

AI summary The document raises questions about the transition of the 1P-RTP tariff from an annually adjusted rate to one set through a General Rate Application (GRA), including customer choices, alignment with other AARs, benefits to NS Power and customers, and customer impact.

NON-CONFIDENTIAL 1 Overall decrease of 9 percent in the non-fuel generation costs primarily due to the 2 reduction in generation rate base of over 8 percent. Date Filed: December 19, 2025 NSPI (REI) IR-13 Page 3 of 3

AI summary The text indicates a 9% overall decrease in non-fuel generation costs, mainly due to an 8% reduction in the generation rate base. The document was filed on December 19, 2025, by NSPI (REI) IR-13, page 3 of 3.

M12551, Exhibit N-1 NS Power's Application for the 2026 Annually Adjusted Rates (AARs) (the "Application"), page 25 of 45, at lines 8-20, and Appendix E2. 1 use the escalator factor is based on the 2019 Annually Adjusted Board letter decis...

AI summary NS Power's 2026 AAR application proposes a 3.25% escalation factor for administrative charges in the Spill Tariff, based on a supporting calculation in Appendix E2.1. The Board previously rejected a higher administrative cost in 2019 and directed the use of an adjusted 2018 amount. The response refers to NSEB IR-12 for justification, stating the same escalation applies to other 2026 AAR tariffs.

") submitted comments that do not challenge the appropriateness of the ELIADC Energy Charge as filed by NS Power. Rather, the comments appear to raise questions about the timing of the effective date. The CA's submission states that: "Give...

AI summary The Consumer Advocate (CA) and Industrial Group (IG) have submitted comments regarding the ELIADC Energy Charge and the timing of interim relief. The CA suggests delaying the effective date of interim relief to align with the 2026 Annually Adjusted Rates, while the IG argues against granting relief to PHP alone, as other rate classes also have rate changes and have not sought interim relief.

NS Power Response: - Under the established ATL and below-the-line (BTL) rate setting and true-up processes, variances - between forecast and actual marginal fuel costs flow through to ATL customers through the FAM. - BTL customers are not...

AI summary NS Power explains that under the ATL and BTL rate structures, variances in forecasted and actual fuel costs are passed through to ATL customers via the FAM. BTL customers are not affected by these true-ups but face risks of over or under-charging. The fuel cost transfer between rate classes can result in both upward and downward adjustments, with BTL classes facing greater risk exposure due to the proportion of their revenues affected by these transfers.

DATE FILED: January 27, 2026 Page 13 of 22 1 5.0 EVIDENCE OF RENEWALL ENERGY INC. 2 3 REI framed its evidence and submission around the use of the proposed Cost of Service Study 4 (COSS) methodology, RtR Tariff review and design, SS Tariff...

AI summary REI submitted evidence related to the proposed Cost of Service Study (COSS) methodology, RtR Tariff review, and SS Tariff calculations. REI requested the recalculation of 2026 AAR rates using the most recently approved COSS methodology or that the rates be interim. NS Power responded that the 2026 COSS was developed collaboratively with Customer Representatives and that the 2026-2027 GRA proposed methodology remains open for the Board's final determination.

M12551, Exhibit N-12, pages 7-8. 1 directed by the Board, and monthly marginal cost values underlying the annual average applied in 2 the tariffs. 3 4 NS Power does not support a requirement to provide historical reconstructions or narrati...

AI summary NS Power opposes the requirement to provide detailed historical reconstructions or explanations for monthly or hourly deviations between forecast and actual marginal costs, citing administrative burdens and limited incremental value. It emphasizes that forecasts are based on the best available information and are aligned with the FAM Plan of Administration forecasting methodology.

ENERGY CHARGE The energy charge is made up of the following two components: - (1) Annually adjusted energy-related purchased power and fuel cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism or General R...

AI summary The energy charge consists of two components, one of which is annually adjusted energy-related purchased power and fuel cost, influenced by factors such as Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

DEMAND CHARGE The demand charge for this service is made up of the following two components: - (1) Annually adjusted demand-related purchased power cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism, or...

AI summary The demand charge for the service is composed of two components, one being an annually adjusted demand-related purchased power cost, which is influenced by factors such as the Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

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) $1,528,710 $740,938 $74,223 $109,815 $53,749 $237,...

AI summary This document presents a detailed breakdown of costs and revenue for a utility company's total company class, including generation, transmission, distribution, and retail segments. It includes data on rate base, variable and fixed costs, unit costs, and total costs by category, providing a comprehensive financial overview.

Summarized Rate base from Schedule 2a in 2026 COSS INITIAL CLASSIFICATION AS PER 2026 GRA Application Filing DEMAND ENERGY CUSTOMER Relative Blended TOTAL RELATED RELATED RELATED Share of COMPANY PLANT PLANT (4) PLANT Energy Steam 383,306...

AI summary The document provides a summarized rate base from Schedule 2a in the 2026 COSS, detailing the classification of assets under the 2026 GRA Application Filing. It includes breakdowns for generation, transmission, distribution, and retail, along with associated costs and shares of the rate base.

CLASSIFICATION OF AVERAGE RATE BASE (1) (2) (3) (4) INITIAL CLASSIFICATION DEMAND ENERGY CUSTOMER TOTAL COMPANY RELATED PLANT RELATED PLANT RELATED PLANT (1) Transmission - EHV 820,016 820,016 0 0 (2) (3) (4) GENERAL PROPERTY PLANT TOTAL P...

AI summary The document presents a classification of the average rate base, including details on transmission and distribution plant assets, working capital, and deferred charges. The classification is divided into categories such as demand, energy, and customer-related plant, with specific figures provided for each category.

CLASSIFICATION OF RATE BASE INITIAL CLASSIFICATION DEMAND ENERGY CUSTOMER TOTAL RELATED RELATED RELATED COMPANY PLANT PLANT PLANT (1) RETAIL FUNCTION (2) (3) DISTRIBUTION PLANT: (4) SERVICES 0 0 0 0 (5) METERS 0 0 0 0 (6) TOTAL RETAIL PLAN...

AI summary The document presents a classification of the rate base, detailing the distribution plant, general property plant, and working capital. It includes initial classifications for demand, energy, and customer-related categories, along with totals for various components of the rate base.

Annual Peak of ATL 2,356,954 Annual Energy Requirement of ATL 11,303,785,142 O- 4 0-! 4 1 1 F4 51 /stem Coinc iaent Load Factor System Coincident Load Factor 54.748044% Rate Base Average 2025 2026 Steam Plant $ 481,584 $ 543,265 $ 419,903...

AI summary The text provides data on the annual peak and energy requirement of ATL, along with a table showing various plant and infrastructure-related financial figures for 2025 and 2026, including rate base, capital works in progress (CWIP), and environmental and fuel conversion costs.

- (2) A fixed cost adder adjusted concurrent with changes in base cost rates coming into effect as a result of a General Rate Case application. Base Energy Charge Components Transmission Voltage of 69 kV or Higher (cents per kWh) Distribut...

AI summary The text discusses a fixed cost adder that is adjusted in line with changes in base cost rates resulting from a General Rate Case application. It includes a table showing the breakdown of base energy charges, including fuel cost and fixed cost adder components for different voltage levels.

DEMAND CHARGE The demand charge for this service is made up of the following two components: - (1) Annually adjusted demand-related purchased power cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism, or...

AI summary The demand charge for the service consists of two components, one being an annually adjusted demand-related purchased power cost, which is influenced by factors such as the Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

ENERGY CHARGE The energy charge is made up of the following two components: - (1) Annually adjusted energy-related purchased power and fuel cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism or General R...

AI summary The energy charge consists of two components, one of which is annually adjusted energy-related purchased power and fuel cost, influenced by factors such as the Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

rginal costs are calculated in real time, it does not require Board approval. The fixed cost adders recover the non-fuel costs and adjustments for the difference in the recovery of avoided fuel costs. Under the RTP proposed changes, the EH...

AI summary NS Power proposes changes to the RTP and Shore Power Tariff (SP), including the elimination of the avoided fuel cost adjustment and differentiation of SP by voltage levels. The Board approves these changes, finding them reasonable and noting stakeholder engagement was completed.

ce to customers. NS Power reported that it proposed a draft Terms of Reference for an interruptible service pilot with REI in July 2025. NS Power remains amenable to discussing this service structure. When NS Power filed this AAR applicati...

AI summary NS Power proposed a draft Terms of Reference for an interruptible service pilot with Renewall Energy Inc. (REI). The Board is concerned about using a new COSS in the AAR application since it has not been approved. The current COSS is outdated and the Board agrees with NS Power that adjustments can be made through a compliance filing.

ENERGY CHARGE Energy charges will vary by voltage level of the point of delivery and will be made up of two components. - (1) Annually adjusted fuel cost component which shall be the Company's forecast average annual marginal energy cost a...

AI summary Energy charges are determined based on voltage levels and consist of two components. One is an annually adjusted fuel cost component, calculated as the company's forecast average annual marginal energy cost, approved for use with the GR&LF tariff and adjusted for line losses at the point of delivery voltage level.

- (2) A fixed cost adder adjusted concurrent with changes in base cost rates coming into effect as a result of a General Rate Case application. Energy Base Charge Components Transmission Voltage of Higher 69 kV or (cents per kWh) Distribut...

AI summary The text describes a fixed cost adder that is adjusted in conjunction with changes in base cost rates resulting from a General Rate Case application. The table provides specific values for fuel cost and fixed adder components across different voltage levels.

DEMAND CHARGE The demand charge for this service is made up of the following two components: - (1) Annually adjusted demand-related purchased power cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism, or...

AI summary The demand charge for the service consists of two components, with the first being an annually adjusted demand-related purchased power cost, influenced by factors such as the Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

Where: - o "k" is the number of otherwise applicable bundled service rate classes to RtR customers of an LRS. - o "CMPFDi" is hourly kW Class Monthly Peak Firm Demand of the LRS firm load in each tariff class at the time of system coincide...

AI summary The text defines key terms related to bundled service rate classes and demand metrics for LRS customers. It outlines how CMPFDi and CMDAFi are calculated, with specific attention to unmetered customer classes and the use of research-based load profile data.

Multiple Moving Variables The ELIADC is a below-the-line ("BTL") rate. The ongoing General Rate Application ("GRA " ), Matter M12451, assumes PHP takes above-the-line ("ATL") service, as of January 1, 2026 – the same timeline in which PHP...

AI summary The document discusses the ELIADC rate and the GRA application, highlighting the uncertainty around PHP's transition to ATL service and the potential cost implications. NSPI seeks to defer risks through a deferral account, while concerns are raised about the fairness of granting PHP interim relief without similar measures for other customer classes.

f the ELIADC Tariff, it would appear that the first option is applicable, as PHP is the only customer within the ELIADC rate class and the change does appear to represent a reduction is costs for PHP. However, as noted, the section offers...

AI summary The text discusses the ELIADC Tariff and the interim approval process for PHP, noting that the Board's previous approval in M11989 set the rate effective from February 1, 2025, avoiding a true-up for January 2025. It suggests that applying the interim rate retroactively could lead to multiple readjustments and recommends setting the rate effective from February 1, 2026.

ENERGY CHARGE NSPI's actual hourly marginal energy costs, plus the following fixed cost adders for on-peak and offpeak usage: On-peak (7:00 am – 11:00 pm, non-holiday weekdays): 5.308 ¢/kWh Off-peak (11:00 pm – 7:00am, non-holiday weekdays...

AI summary NSPI's energy charge includes hourly marginal costs and fixed cost adders for on-peak and off-peak usage. On-peak adders are significantly higher than off-peak, with weekend and holiday rates aligned to off-peak. Annual approval from the Nova Scotia Energy Board is required, and a credit is applied for customer-owned transformers based on peak demand.

ENERGY CHARGE Energy charges will vary by voltage level of the point of delivery and will be made up of two components. - (1) Annually adjusted fuel cost component which shall be the Company's forecast average annual marginal energy cost a...

AI summary The energy charge consists of two components, with the first being an annually adjusted fuel cost component based on the Company's forecast average annual marginal energy cost, approved for use with the GR&LF tariff and adjusted for line losses at the voltage level of the point of delivery.

DEMAND CHARGE The demand charge for this service is made up of the following two components: - (1) Annually adjusted demand-related purchased power cost, coming into effect as a result of a Base Cost of Fuel, Fuel Adjustment Mechanism, or...

AI summary The demand charge for the service includes an annually adjusted demand-related purchased power cost, which is influenced by factors such as the Base Cost of Fuel, Fuel Adjustment Mechanism, or General Rate Application.

Where: - o "k" is the number of otherwise applicable bundled service rate classes to RtR customers of an LRS. - o "CMPFDi" is hourly kW Class Monthly Peak Firm Demand of the LRS firm load in each tariff class at the time of system coincide...

AI summary The text defines technical terms related to rate classes and demand calculations for LRS customers, including CMPFDi and CMDAFi, which are used in determining peak firm demand and adjustment factors for different customer classes.

(a) Renewable to Retail Implementation (M12588) With respect to RtR market implementation costs, NS Power is not proposing any changes to the existing cost recovery mechanisms within the RtR tariffs. Instead, the Company proposes to utiliz...

AI summary NS Power plans to recover implementation costs for the Renewable to Retail (RtR) market through existing administrative charge frameworks, including the Energy Balancing Service (EBS) and Standby Service (SS) tariffs. These costs will be amortized over 10 years, contingent on the recovery of financing costs at NS Power's weighted average cost of capital. Administrative costs incurred before the 2027 AAR Application decision will be deferred for future recovery.