Topic:"Cost Recovery" in M12551

Application for Annually Adjusted Rates for 2026 Redacted 1 5.0 SHORE POWER TARIFF 2 3 Service under the Shore Power (SP) Tariff is a seasonal priority interruptible service, which 4 starting in 2026 is proposed to be differentiated by two...

AI summary The document outlines the proposed changes to the Shore Power (SP) Tariff for 2026, including voltage level differentiation and a decrease in rates due to changes in marginal fuel cost and non-fuel cost components, as detailed in the 2026-2027 General Rate Application (GRA) under matter M12451.

Application for Annually Adjusted Rates for 2026 Redacted 1 against unforeseen schedule delays and so the request to extend the deadline for selling renewable 2 low-impact electricity to March 31, 2027 was approved.39 3 4 From a project ex...

AI summary Nova Scotia Power has completed most of the setup work for a renewable energy project, with remaining tasks expected to be completed within seven months prior to retail sales. The company has calculated the RTR Tariff Administration Charges based on near-term forecasted costs and anticipates future recovery starting in 2027. The Energy Balancing Service Tariff is a mandatory requirement for LRS customers.

7 7.2 Standby Service Tariff 8 6 9 The Standy Service (SS) Tariff is a mandatory tariff applicable to LRSs for supplemental standby 10 generation capacity service provided in combination with EBS under the EBS Tariff. The SS Tariff 11 has...

AI summary The Standby Service (SS) Tariff includes an Administration Charge and a Demand Charge. The Administration Charge is set annually and is aligned with the EBS Tariff. The Demand Charge is based on the 2026 Cost of Service Study, proposing a rate of $5.452 per month per kilowatt of monthly standby contract demand.

Application for Annually Adjusted Rates for 2026 Redacted • If CBL Cost ≤ $56.75/MWh : CBLA = 75% × (61.75 – CBL Cost)[49](#page-40-1) 1 2 3 • If CBL Cost > $56.75/MWh and < $61.75/MWh : CBLA = [75% × (61.75 – CBL Cost)] + [FCR – (75% × (6...

AI summary The document outlines the calculation of the Customer Baseline Adder (CBLA) for 2026, based on the Customer Baseline (CBL) Cost and Fixed Cost Recovery (FCR). The CBLA is set at $5.00/MWh for 2026, reflecting the full recovery of the minimum FCR under the revised tariff, an increase from $1.00/MWh in 2025.

ONE PART TRANSMISSION REAL TIME PRICING TARIFF Page 2 of 3 will be required to make a capital contribution equal to the additional capital cost of primary metering as opposed to the cost of secondary metering. - (3) The cost of any special...

AI summary The ONE PART TRANSMISSION REAL TIME PRICING TARIFF outlines requirements for customers, including capital contributions for metering, transformer loss adjustments, service terms, and power factor maintenance. Customers must maintain a minimum power factor or face billing adjustments.

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): 10.008 ¢/kWh Off-peak (11:00 pm – 7:00am, non-holiday weekday...

AI summary NSPI's energy charge includes on-peak and off-peak fixed cost adders, with weekend and holiday rates set at the off-peak price. These adders are determined annually and submitted for approval to the Nova Scotia Energy Board. A credit is also applied for customer-owned transformers based on peak demand.

REDACTED 2026 AAR Application Appendix B2 Page 1 of 19 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1P-RTP ADDER CALCULATION O&M Capital ROE Distribution Costs $0.00241 $0.00241 $0.00917 $0.00917 $0.00310 $0.00310 $0.01468 $0.01468 $0.00561...

AI summary The document presents a detailed cost breakdown and calculation for the 1P-RTP Adder in the 2026 AAR Application Appendix B2. It includes various cost components such as O&M, capital, distribution costs, fixed costs, avoided costs, and customer costs, along with percentages and proposed figures for 2025 and 2026.

36 The Fixed Cost Adders 37 38 The fixed cost rate components are designed to recover fully embedded fixed Generation cost of 39 services. 1 Currently there are three One Part RTP Tariffs in effect: (a) two transmission-based tariffs: 1P-R...

AI summary The text discusses fixed cost rate components designed to recover embedded generation costs, referencing the current One Part RTP Tariffs and the 2026-2027 GRA (M12451) Cost of Service Study, which no longer breaks down transmission costs by EHV and HV components.

22 Cost of Service Fixed Cost Riders 23 24 (a) Generation Cost Fixed Cost. 25 26 (i) The generation total cost of $426.9 million broken down into expense type 27 (operating, capital, and Return) in the 2026 Cost of service is apportioned t...

AI summary The document discusses the allocation of generation costs in the 2026 Cost of Service Study, including the apportionment of costs based on coincident peaks and the derivation of fixed cost rates by service level. The methodology involves dividing generation costs by on-peak sales in kWh and references Appendix B for detailed rider calculations.

- (i) The Transmission total cost of $139.2 Million broken down by expense type; operating, capital and Return in the 2026 Cost of service also in Appendix D provided with the application is apportion to Transmission, Distribution service...

AI summary The text outlines the methodology for apportioning transmission costs across different service levels and customer types using the 2026 relative share of 3CPS, segregating costs by on and off-peak sales, and calculating fixed cost rate components based on service level and sales data.

27 Fuel Cost Adjustment 28 32 29 There is no longer avoided fuel cost adjustment from the difference between these values result to 30 partially offset the fixed cost. Refer to Section 4.1 of 2026 AAR Application for the rationale 31 behin...

AI summary The text discusses the removal of the Avoided Fuel Cost Adjustment, noting that it no longer results in a difference that partially offsets fixed costs, and refers to Section 4.1 of the 2026 AAR Application for the rationale behind this change.

2026 AAR Application Appendix B3 Page 6 of 11 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026 On peak rates in Cents/ kWh Fig 3 rates in Cents/ kWh Variance Transmission 196,618,713 211,929,809 408,548,522 48% 52% 0% 145.32 2.11% $9,004 $...

AI summary The document presents a cost breakdown for 2026 on-peak and off-peak rates in cents per kWh, including transmission, distribution, and customer classes. It includes figures for variance, costing determinants, and apportioned amounts. The data highlights the distribution of costs across different customer classes and service levels.

2026 AAR Application Appendix B3 Page 10 of 11 REDACTED (CONFIDENTIAL INFORMATION REMOVED) A B C D E F G H I J K L Formular A/C B/C D H E H I/A 100 I/A 100 Costing Determinants F G 12 Off On Adders Cents/ kWh Average Cost per Cost per Cust...

AI summary The document presents financial and cost data related to transmission and distribution for different customer classes, including sales, cost determinants, and allocation percentages. It includes tables with figures for total generation, transmission, and distribution costs, as well as percentages of on and off-peak sales.

2026 AAR Application Appendix C1 Page 3 of 4 REDACTED (CONFIDENTIAL INFORMATION REMOVED) SHORE POWER TARIFF Page 3 of 4 - metering transformers supplied by NSPI. NSPI owns and is responsible for the maintenance of meters and metering trans...

AI summary The Shore Power Tariff outlines responsibilities and requirements for the Port Authority and NSPI regarding metering, operational procedures, and billing adjustments. The Port Authority must provide trained staff and submit vessel schedules, while NSPI manages metering equipment. Customers may be required to cover additional capital costs for primary metering and special systems. Adjustments for transformer losses and power factor requirements are also specified.

Proposed Annual Inflation Rate 3.25% 2025 2026 Variance COLUMN A B C D E F G H I J K L M N O P Cost Allocation Factors 3 CP Demands Energy Requirement Purchased Power- Biomass Maritime Link Purchased Po Relative Shares Relative Shares of I...

AI summary The document outlines a proposed annual inflation rate of 3.25% and presents a detailed table with cost allocation factors for various rate classes and energy-related metrics for the years 2025 and 2026, including energy requirements, fuel costs, and purchased power details.

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, income tax, and OM&G, and are recovered through Bundled Service. Deferred costs are those approved by the Nova Scotia Energy Board for future recovery.

Minimum Payment The ELIADC Tariff requires that a minimum payment shall be made by PHP in respect of each tariff year, which shall not be less than the sum of: - (a) NS Power's actual total incremental cost of serving PHP during the year (...

AI summary The ELIADC Tariff mandates a minimum payment by PHP, calculated as the sum of NS Power's actual incremental costs and a fixed cost recovery component based on MWh supplied. Adjustments to meet this minimum are determined and charged after the year ends.

INTRA-YEAR MODIFICATIONS TO THE CBL ENERGY CHARGE NS Power will utilize its established forecasting methodology to determine the CBL Energy Charge. PHP will undertake commercially reasonable efforts to accurately forecast its energy usage....

AI summary NS Power will determine the CBL Energy Charge using its forecasting methodology. If significant changes occur, such as delays in NS Block energy import deliveries, NS Power may request the Board's approval to revise the CBL Energy Charge on a prospective basis.

Minimum Payment The ELIADC Tariff requires that a minimum payment shall be made by PHP in respect of each tariff year, which shall not be less than the sum of: - (a) NS Power's actual total incremental cost of serving PHP during the year (...

AI summary The ELIADC Tariff mandates a minimum payment from PHP, calculated as the sum of NS Power's actual incremental serving costs and a fixed cost recovery component based on MWh supplied. Adjustments are applied after year-end to ensure the minimum payment is met.

Customer Baseline Energy Charge, Customer Baseline Energy Cost, and Contribution to Utility Costs In advance of each tariff year, PHP shall advise NS Power of its forecast annual and monthly energy requirements for the subsequent calendar...

AI summary PHP is required to provide NS Power with its forecast energy requirements and maintenance schedules to calculate the Customer Baseline Load (CBL) Cost, which includes fuel, purchased power, line losses, and variable operating costs. The CBL Adder (CBLA) is calculated based on the CBL Cost and includes the Fixed Cost Recovery (FCR) when the CBL Cost is below a certain threshold.

ACTIVE DEMAND CONTROL AND SCHEDULE VARIANCE NS Power shall be entitled to actively manage PHP's load in accordance with the terms and conditions set out in the Active Demand Control – Energy Supply Protocol attached as Schedule 1 to this T...

AI summary NS Power is permitted to manage PHP's load under the Active Demand Control – Energy Supply Protocol. NS Power must annually report system savings and load shifting benefits to the Board, including impacts of schedule variances. PHP is entitled to a 25% credit based on the cost differential between the Customer Baseline Load and actual annual costs to serve PHP.

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 1 (i) In your response, please specifically address the hypothesis that the marginal 2 system capacity for 2026 would be shifting Lingan 2 from cold reserve to full 3 retirement status. 4 5 (ii) If your response to subpart...

AI summary The text outlines a series of questions regarding the marginal system capacity for 2026, the impact of removing load served under the 1P-RTP Tariff, and the inclusion of avoided costs in the proposed tariff design. It also requests an alternate version of Appendix B2 and a summary of total cost recovery under the proposed and alternate 1P-RTP rates.

NON-CONFIDENTIAL 1 Request IR-3: 2 3 Reference: Page 20, lines 16-19. 4 5 6 7 8 9 10 In view of the foregoing, NS Power has, in this Application, eliminated the adjustment for the projected imbalance in the recovery of the avoided fuel. En...

AI summary NSPI has eliminated the adjustment for projected imbalance in the recovery of avoided fuel costs in its rate application. Energy charges are based on hourly marginal costs, and fixed cost adders include only non-fuel costs. The response indicates that no other rates or methodologies are impacted by the volatility in avoided fuel cost calculations.

Minimum Payment The ELIADC Tariff requires that a minimum payment shall be made by PHP in respect of each tariff year, which shall not be less than the sum of: - (a) NS Power's actual total incremental cost of serving PHP during the year (...

AI summary The ELIADC Tariff requires PHP to make a minimum payment each year, calculated as the sum of NS Power's incremental serving costs and a fixed cost recovery amount of $5.00 per MWh supplied. Adjustments to meet this minimum are determined and charged after year-end.

Customer Baseline Energy Charge, Customer Baseline Energy Cost, and Contribution to Utility Costs In advance of each tariff year, PHP shall advise NS Power of its forecast annual and monthly energy requirements for the subsequent calendar...

AI summary The document outlines the process for calculating the Customer Baseline Energy Charge (CBL Cost) and its relationship with the CBL Adder (CBLA) and Fixed Cost Recovery (FCR). NS Power uses PHP's forecast energy requirements to determine the CBL Cost, which includes fuel, purchased power, line losses, and variable operating costs. The CBLA is calculated based on the forecast CBL Cost and interacts with the FCR.

EXTRA LARGE INDUSTRIAL ACTIVE DEMAND CONTROL TARIFF Page 4 of 8 - (a) It becomes apparent that the CBL Energy Charge plus the CBLA plus the Variable Capital Charge will not result in the recovery of the actual incremental cost to serve plu...

AI summary The document outlines conditions under which adjustments to the CBL Energy Charge may be necessary, including changes in generation costs, unexpected consumption shifts, and capital expenditures. If NS Power and PHP cannot agree, the issue can be referred to the Board for expedited adjudication, with the Minimum Payment remaining unchanged.

Metering will normally be at the low voltage side of the transformer and, for measurement and, where applicable, billing purposes, meter readings will be increased by 1.1%. Should the Mill's requirements make it necessary for NS Power to p...

AI summary The document outlines metering requirements and cost responsibilities for NS Power and PHP under the tariff. Metering is typically at the low voltage side, with a 1.1% increase in readings. If primary metering is required, PHP must cover the additional cost. Special metering or communication systems costs are also borne by PHP as a capital contribution.

ACTIVE DEMAND CONTROL AND SCHEDULE VARIANCE NS Power shall be entitled to actively manage PHP's load in accordance with the terms and conditions set out in the Active Demand Control – Energy Supply Protocol attached as Schedule 1 to this T...

AI summary NS Power is allowed to manage PHP's load under the Active Demand Control protocol, with annual reporting to the Board on system savings and schedule variances. PHP is entitled to a 25% credit based on the cost differential between the CBL Cost and the actual cost to serve them during the tariff year.

Metering will normally be at the low voltage side of the transformer and, for measurement and, where applicable, billing purposes, meter readings will be increased by 1.1%. Should the Mill's requirements make it necessary for NS Power to p...

AI summary The text outlines metering requirements under a tariff, specifying that metering is typically at the low voltage side of the transformer. If primary metering is required by the Mill, PHP must cover the additional cost as a capital contribution. Special metering or communication systems required by PHP must also be funded by PHP as a capital contribution.

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 FAM. To the extent these costs are over-forecast the FAM customers see a reduction in 2 their imbalance and the opposite happens if these costs are under forecasts. However, it's 3 important not to lose a perspective on...

AI summary The text discusses the Fuel and Purchased Power (FAM) mechanism and its impact on customers, noting that variations in forecasted costs have minimal materiality. It also references the lack of need for a true-up mechanism due to the low significance of fuel imbalance in the recovery of marginal fuel costs.

FOR THE YEAR ENDING DECEMBER 31, 2026 (IN THOUSANDS OF DOLLARS) (56) FCR DEFERRAL (57) OTHER REVENUE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 P-18B O-12B (58) RETURN (PROFIT/LOSS) 0 0 0 0 0 0 0 0 0 0 0 P-18B (59) TOTAL - EHV 0 0 0 0 0 0...

AI summary The document presents financial data for the year ending December 31, 2026, with a focus on energy-related figures, including total energy costs and various revenue and cost categories. The table includes entries such as FCR deferral, return, and total transmission, but most values are zero, with the exception of total energy, which is reported at approximately $980,912.547.

5 8 13 17 2 The double percent digit reduction in the fuel cost components are due to the overall lower 3 cost of energy generation as provided in Figure 1: Cost of Energy Generation in the 4 evidence of the Application. 6 The reduction of...

AI summary The text discusses a 33.66% reduction in the Fixed Cost Adder, attributed to changes in the Cost of Service (COS) methodology and increased energy requirements in the above-the-line rate classes. It references the 2023 and 2026 Cost of Service Studies (COSS) and refers to an application related to the Annually Adjusted Rates for 2026 (M12551).

NON-CONFIDENTIAL 1  The LI interruptible credit of $11.165 million is a product of the levelized annual 2 capacity cost of $160.44/kW-Yr and the coincident peak of the interruptible load 3 of the LI class of 69,593 kW. ($160.44/kW-Yr x 69...

AI summary The document discusses the calculation of the LI interruptible credit, which is based on the levelized annual capacity cost and the coincident peak of the LI class load. It references specific cells in the 2026 Cost of Service Study and provides a cross-reference to another document.

Annually Adjusted Rates for 2026 (M12551) NSPI Responses to REI Information Requests 1 Request IR-17: 2 3 (a) Under the current RTT framework, please confirm whether the Annual Energy Cost 4 Adjustment would require NS Power to provide a c...

AI summary The document outlines a series of questions regarding the Annual Energy Cost Adjustment under the current RTT framework, specifically focusing on whether credits would be provided to RtR customers when avoided costs exceed system fuel costs, and whether any caps or constraints apply to these credits. The questions also ask for references to specific tariff provisions and Board orders.

Annually Adjusted Rates for 2026 REI IR-18 Attachment 1 Page 7 of 41 REDACTED (CONFIDENTIAL INFORMATION REMOVED) technical standards and to communicate with and accept direction from the Nova Scotia Power System Operator (NSPSO) while supp...

AI summary The document outlines the design of generation-related tariffs for 2026, including Standby Service, Energy Balancing Services, and RtR Transition Tariffs. These tariffs are intended to ensure system reliability, manage surplus and deficit generation, and recover costs from Licensed Retail Suppliers (LRS). The charges are based on a Cost of Service analysis model and remain consistent with the OATT charges.

5.2 Cost Allocation Principles The Energy Balancing Service, Standby Service, and RtR Market Transition tariffs have been designed to incorporate the same fixed cost classification and allocation principles as in the Cost of Service analys...

AI summary The document outlines the cost allocation principles for the Energy Balancing Service, Standby Service, and RtR Market Transition tariffs, aligning them with the Bundled Service Cost of Service analysis. Fixed generation costs are classified and allocated based on demand and energy use, with aggregated rates applied for RtR customers.

5.5.3 Allocated Cost Element In order to recover the appropriate allocation of fixed generation costs to the production for top-up, the selected tariff structure adds the fixed generation cost allocated to energy to the incremental top-up...

AI summary The allocated cost element in the tariff structure is designed to recover fixed generation costs by adding them to the incremental top-up rate, aligning with the energy-based charge used in the Bundled Service Cost of Service analysis.

5.7.2 Charge Determinant Details It is expected that customers can and will migrate between bundled service and RtR supply, and among LRSs, at any time of year. This presents a challenge in properly allocating costs for recovery from each...

AI summary The document discusses the allocation of costs among Local Resource Suppliers (LRS) and the challenge of accurately reflecting customer portfolios over time. A proposed method involves recalculating annual coincident demand based on monthly data to ensure fair billing for large industrial customers.

• Embedded Cost Recovery To the extent that an LRS was to be relieved of transmission charges for generation located in the same zone as load, and this loss of NS Power revenue could not be recovered from Bundled Service customers, this wo...

AI summary The text discusses the potential need to add a transmission cost element to the RtR Market Transition Tariff to recover embedded costs from LRS if they are relieved of transmission charges for generation in the same zone as load, which could negate benefits for LRS.

Annually Adjusted Rates for 2026 REI IR-18 Attachment 1 Page 32 of 41 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - The foregone amounts under the energy-based charge for fixed generation costs under the Bundled Service tariffs, less that...

AI summary The text discusses the calculation of stranded amounts related to energy-based charges and fuel cost recovery, focusing on the impact of load supplied by LRS and the nature of generation resources. It also explains how differences in fuel costs between bundled service tariffs and RtR supply affect the RTT energy charge.

8.2.1 Options Two potential recovery mechanisms were presented to stakeholders: - A Retail Access Adjustment based on the extent of the embedded cost recovery required in each year as a result of each LRS's activity, using rates that could...

AI summary Two potential recovery mechanisms were presented to stakeholders: a Retail Access Adjustment based on embedded cost recovery requirements and an exit fee associated with each exiting customer to recover estimated embedded costs.

8.2.2 Retail Access Adjustment Characteristics of the retail access adjustment as proposed in the RtR Market Transition Tariff are: - Charges per unit of stranded demand and energy set in advance and capable of annual adjustment; - Charge...

AI summary The retail access adjustment, as proposed in the RtR Market Transition Tariff, includes features such as adjustable charges per unit of stranded demand and energy, indifference to generation technology, and cost responsibility moving with customers during migration between LRSs. The adjustment aims to ensure stable cost recovery and can continue as long as embedded cost recovery is required.

8.2.5 Basis for selection The amount of embedded cost recovery depends in large part on the amounts of NS Power fixed costs recovered by other mechanisms. As noted in the discussion of the EBS and Standby Service tariffs, the amounts recov...

AI summary The selection of the RtR Market Transition Tariff over Exit Fees is based on its ability to achieve full and fair embedded cost recovery with less risk and uncertainty, considering the complexity and variability of Exit Fee estimates.

Annually Adjusted Rates for 2026 (M12551) NSPI Responses to REI Information Requests 1  Tariff Design: Interruptible service terms must be incorporated into tariffs and 2 aligned with regulatory requirements. 3  Compliance Obligations: N...

AI summary The document outlines challenges related to tariff design, compliance obligations, cost recovery, and mitigation steps for the Annually Adjusted Rates for 2026 proceeding. NSPI acknowledges these challenges and commits to addressing them proactively while providing updates to REI.

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.

M12551, Exhibit N-1, the Application, page. 9 of 45, at lines 26-31 through page. 10 of 45, at lines 1-22. 1 (a) Please confirm when NS Power plans to re-initiate stakeholder engagement with a 2 schedule for offering a TVP structure for AA...

AI summary The document discusses NS Power's plans to re-initiate stakeholder engagement for TVP structures in AARs following the 2025 AAR proceeding (M11989) and provides details on the calculation and recovery of RtR Tariff Administration Charges, including deferred costs and future recovery starting in 2027.

Cross Subsidization The SBA also notes the request for the deferral of Renewable-to-Retail (RtR) costs is being made without knowing the magnitude nor any explicit details regarding the timing of recovery of the deferred amount. 5 The SBA...

AI summary The SBA raises concerns about the deferral of Renewable-to-Retail (RtR) costs without a clear recovery mechanism, potentially leading to cross-subsidization across time periods and customer classes. While the AAR process is not the appropriate forum to define the recovery mechanism, the lack of clarity is acknowledged as a potential issue.

2026 COSS Methodology Disproportionately impacts RtR Customers The RtR tariffs were developed and approved under a different cost allocation model and therefore do not reflect the substantial shifts in demand-related allocations now propos...

AI summary The 2026 COSS methodology disproportionately impacts RtR customers by shifting costs from energy to demand, increasing demand charges and misaligning cost allocation with the current framework. This could undermine competition in the RtR market and contradict legislative objectives, requiring a tariff review before Q4 2026.

The AAR Application is not the Forum to apply new Cost Allocation Methods The AAR process is designed to be streamlined and formula-driven. Introducing an unapproved COSS that incorporates significant methodological changes is inconsistent...

AI summary The AAR process is intended to be streamlined and formula-driven, and introducing an unapproved COSS with significant methodological changes is inconsistent with this framework. NSPI has not provided sufficient justification for applying the new methodology in the AAR context, risking incorrect cost allocations in customer rates.

No True-Up Mechanism Exists to Correct for any COSS Changes NSPI sets the AARs using forecasts that, with the exception of the ELIADC Tariff, are not subject to a true-up. While the Board has previously found that the absence of a true-up...

AI summary The document highlights the absence of a true-up mechanism to correct for changes in the Cost of Service Study (COSS) methodology, which could lead to regulatory asymmetry and risk. REI recommends using the currently approved COSS methodology for setting 2026 AAR rates to avoid methodological risk and ensure rates reflect Board-approved cost allocations.

Material Impact on RTT Rates The marginal cost calculation, combined with the COSS methodology changes, significantly impact the 2026 RTT charge. The RTT Total Energy Charge is proposed to increase from 0.802 cents/kWh (2025) to 4.363 cent...

AI summary The 2026 RTT charge is expected to increase significantly due to changes in the COSS methodology and the impact of the SO2 CoV. This increase has led to a 444.3% rise in the Energy Charge and a 60.5% increase in the Demand Charge, creating financial risks for REI and affecting market competition.

3. INCORRECT SS TARIFF VALUES AND METHODOLOGY NSPI has applied for approval of a Demand Charge under the SS Tariff of $5.452/kW, representing a variance of $2.055/kW from 2025.[30](#page-8-6) Appendix F3 provides the explanation for this C...

AI summary NSPI has applied for approval of a Demand Charge under the SS Tariff at $5.452/kW, but the calculation is based on incorrect values and a changed methodology involving an additional Interruptible Credit cost. Discrepancies are noted between Appendix F3 and the 2026-2027 GRA Application exhibits.

CONCLUSION REI respectfully requests that the Board direct NSPI to: 1. Recalculate the 2026 AAR rates using the most recently approved COSS methodology rather than the unapproved 2026 COSS, or alternatively, make the 2026 AAR rates interim...

AI summary REI requests the Board to direct NSPI to recalculate 2026 AAR rates using the approved COSS methodology, initiate a tariff amendment proceeding for RtR tariffs, address errors in SS Tariff Demand Charges, and provide forecast versus actual marginal cost data for 2021–2026.

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.

Company notes that the nature of utility pricing and tariffs is that these are subject to change within, and across, years as cost drivers and market conditions change. Concerning REI's fourth request, the Company's position is that these...

AI summary The Company argues that annual applications provide sufficient marginal cost information for the AAR process, as detailed in Section 2.0 and Appendices A2 through A7. The text references several exhibits and board decisions related to the 2026 AAR Application.

NS Power Response: 1. Treatment of Ancillary Service Costs Calculations in Appendix F3 reflect the correct amount of the "Load Following" cost of $21,166 in cell C23. The cost of $21,166 matches the amount displayed in cell E14 in tab "Anc...

AI summary NS Power has identified and corrected an error in the calculation of ancillary service costs in Appendix F3, adjusting the demand charge for firm service. Additionally, NS Power proposes an amendment to the firm service charge to account for interruptible service costs, ensuring fair cost recovery and preventing bundled service customers from subsidizing the RtR market.

the wholesale customer must provide: - 1. Documentation demonstrating that the import capacity will be supported by the external control area and afforded the same curtailment priority as the external control area's native load. - 2. Docum...

AI summary Special conditions outline requirements for wholesale customers regarding import capacity support, transmission assurance, reliability performance, and financial obligations in case of failure. These include documentation requirements, capacity procurement timelines, and procedures for cost recovery and CCF adjustments.

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 This 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, return on equity, income tax, and OM&G, and are approved for recovery by the Nova Scotia Energy Board.

COLUMN A B C D E F G H I J K L M N O P Q R S T U V X Cost Allocation Fact tors Fuel-re lated Cos ts from COS 3 CP De mands Energy Requ uirement Purchased Powe r- Biomass Maritime Link Purchased Po wer other than B Wind Biomass and ı Purcha...

AI summary The text presents a table outlining cost allocation factors and energy requirements across various rate classes and embedded cost categories, including fuel-related costs, purchased power, and energy-related and demand-related costs. It includes columns for different types of energy sources and cost allocations.

- (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.

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 This 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, return on equity, income tax, and OM&G, and are approved for recovery by the Nova Scotia Energy Board.

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.

SPECIAL CONDITIONS - (1) Projections of the anticipated hourly energy price (week ahead and day ahead) will be provided to the customer according to the following schedule: - o By midnight each business day, hourly price forecasts for each...

AI summary The special conditions outline requirements for energy pricing forecasts, metering arrangements, service terms, and power factor maintenance under a specific tariff. Customers must provide capital contributions for primary metering, maintain a minimum service term, and adhere to power factor standards to avoid adjustments.

- (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. The table provides breakdowns of base energy charges, including fuel costs and fixed cost adders for different voltage levels.

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 This Renewable to Retail Market Transition Tariff (RTT) is established under Section 3G(2) of the Electricity Act (Nova Scotia) to recover NS Power's embedded fixed and deferred costs from Licensed Retail Suppliers (LRS). These costs include generation-related fixed costs and those approved by the Nova Scotia Energy Board for future recovery.

Minimum Payment Effective: April 1, 2026 The ELIADC Tariff requires that a minimum payment shall be made by PHP in respect of each tariff year, which shall not be less than the sum of: - (a) NS Power's actual total incremental cost of serv...

AI summary The ELIADC Tariff requires PHP to make a minimum payment each year, calculated as the sum of NS Power's incremental serving costs and a fixed cost recovery component based on MWh supplied. Adjustments to meet this minimum are determined and charged after year end.

INTRA-YEAR MODIFICATIONS TO THE CBL ENERGY CHARGE NS Power will utilize its established forecasting methodology to determine the CBL Energy Charge. PHP will undertake commercially reasonable efforts to accurately forecast its energy usage....

AI summary NS Power will adjust the CBL Energy Charge based on significant changes in circumstances, such as delays in energy imports or unexpected changes in generation costs or consumption. These adjustments require Board approval and do not affect the Minimum Payment by PHP.

SPECIAL CONDITIONS - (1) Projections of the anticipated hourly energy price (week ahead and day ahead) will be provided to the customer according to the following schedule: - O By midnight each business day, hourly price forecasts for each...

AI summary The document outlines special conditions for a tariff, including hourly energy price forecasts, metering requirements, capital contributions for primary metering, transformer loss adjustments, service terms, and power factor requirements. These conditions apply to customers taking service under this tariff.

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) aims to recover NS Power's embedded fixed and deferred costs from Licensed Retail Suppliers (LRS). These costs include depreciation, financing, return on equity, and OM&G, and are not otherwise recovered through other tariffs. The RTT is established under Section 3G(2) of the Electricity Act (Nova Scotia).

Request IR-4: Refer to M12551, Exhibit N-1, the Application, Section 7.0 Renewable to Retail Market (RtR) Tariffs and the proposed RtR Tariff Administration Charge , which states: The Company has calculated the RtR Tariff Administration Ch...

AI summary The document discusses NS Power's proposed RtR Tariff Administration Charge, including the deferral of costs incurred in 2026 and anticipated recovery starting in 2027. Questions are raised about current estimated costs, whether interest costs will be applied, and the expected interest rate.

ffering a TVP structure for AARs? Refer to M12551, Exhibit N-1, the Application, Section 7.0 Renewable to Retail Market (RtR) Tariffs and the proposed RtR Tariff Administration Charge , which states: The Company has calculated the RtR Tari...

AI summary The document discusses NS Power's proposed RtR Tariff Administration Charge and associated costs, including deferred costs and future recovery plans. It also references standby service tariff charges for 2025 and 2026 and asks about estimated costs, interest rates, and supporting documentation.

1 (b) Over the last three years, for each year, please provide: 2 3 (i) The forecast number of hours in which NB imports and ML imports (disaggregated) were expected to be the marginal 4 cost generator; and 5 (ii) The actual number of hour...

AI summary The document requests information on the accuracy of NS Power's monthly marginal cost forecasts, the operational and administrative impacts of transitioning from annual to monthly updates for AARs, and whether NS Power agrees that monthly marginal cost pricing would improve price signals and reduce cross-subsidization.

2 Reference: Assumptions, page 11, Appendix A3 PCON; and Board-Directed Sensitivity 3 Analyses, pages 12-13 and Appendix A6 PCON. - 4 (a) NS Power has stated that higher SO2 emission limits have resulted in lower 5 marginal costs. Please c...

AI summary The document contains a series of questions directed to NS Power regarding SO2 emissions, marginal cost impacts, surplus energy delivery, and sensitivity analyses related to commodity price volatility, wind generation delays, and tariff assumptions. The questions seek clarification on assumptions, risk factors, and forecasting methodologies used in cost modeling.

- 30 (d) If a true-up mechanism were implemented to reconcile forecast versus 31 actual marginal costs, please explain how this would affect: 1 2 (i) the risks or benefits to NS Power identified in part (a) above; 3 (ii) the need for or be...

AI summary The document outlines requests related to implementing a true-up mechanism to reconcile forecast versus actual marginal costs, including its impact on risks and benefits to NS Power, the need for frequent updates, and forecast risk allocation. It also requests updated financial data and information on planned filings for a capital work order.

re implemented to reconcile forecast versus actual marginal costs, please explain how this would affect: 1. the risks or benefits to NS Power identified in part (a) above; 2. the need for or benefit of more frequent marginal cost updates;...

AI summary The text requests an explanation of how reconciling forecast versus actual marginal costs would affect NS Power's risks and benefits, the need for frequent updates, and risk allocation. It also asks for steps to implement an annual true-up mechanism and compares it to the ELIADC calculation. References to cost estimates and capital work orders are included.

es that the system resources mix that would be developed for a lower load case resulting from the load decrement analysis would not differ from the present system configuration. If not confirmed, please explain. 3. Please provide an altern...

AI summary The document requests clarification on system resource mix, an alternate version of Appendix B2 using the SO2 adjustment method, and a summary of total cost recovery under different 1P-RTP rates. NS Power eliminated the fuel cost imbalance adjustment due to the SO2 emissions limit and hourly marginal cost pricing, which can cause volatility in adders.

t used in deriving the 2026 GRLF, SP, Spill, EBS and RTT, is $67.36 per MWh. This is a 24% decrease from 2025 which is mostly due to changes in emissions limits and forecasted pricing for solid fuel. The NSUARB had directed NS Power to pro...

AI summary The document discusses a 24% decrease in the cost used for the 2026 GRLF, SP, Spill, EBS, and RTT, attributed to changes in emissions limits and solid fuel pricing. It also addresses the NSUARB's request for a sensitivity analysis on Muskrat Falls energy deliveries and NS Power's request to remove the scenario. The Board suggests adjusting the scenario instead. The customer charge increased by 3.25%, with NS Power explaining it includes salary increases, while the SBA questioned the justification.

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 Section 3G(2) of the Electricity Act (Nova Scotia) to recover NS Power's embedded fixed and deferred costs from Licensed Retail Suppliers (LRS). These costs include depreciation, financing costs, and OM&G, and are recovered through Bundled Service, not through other applicable tariffs.

Minimum Payment Effective: April 1, 2026 The ELIADC Tariff requires that a minimum payment shall be made by PHP in respect of each tariff year, which shall not be less than the sum of: - (a) NS Power's actual total incremental cost of serv...

AI summary The ELIADC Tariff requires PHP to make a minimum payment each year, calculated as the sum of NS Power's actual incremental costs and a fixed cost recovery component based on MWh supplied. Adjustments to meet this minimum will be applied after year-end.

INTRA-YEAR MODIFICATIONS TO THE CBL ENERGY CHARGE NS Power will utilize its established forecasting methodology to determine the CBL Energy Charge. PHP will undertake commercially reasonable efforts to accurately forecast its energy usage....

AI summary NS Power will adjust the CBL Energy Charge based on significant changes in circumstances, such as delays in energy imports or unexpected changes in generation costs or consumption. Adjustments require Board approval and do not affect the Minimum Payment by PHP.

- (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 line with changes in base cost rates resulting from a General Rate Case application. The table outlines energy base charge components, including fuel cost and fixed adder rates for different voltage levels.

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 This 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 costs, and operational expenses, and are not otherwise recovered through other applicable tariffs.

COMMENTS ON STATUS AND PATH FORWARD REI agrees with the Board's observation that a number of proceedings — including M11422 (Large Industrial Interruptible Rider (LIIR) Pilot), M12339 (Development of RtR Tariff Amendments), and M12588 (Ren...

AI summary REI agrees with the Board's observation that several ongoing proceedings impact the Renewable to Retail (RtR) framework and REI's market entry. REI is collaborating with NS Power on these matters and supports the need for a new process to establish a cost recovery mechanism for RtR implementation costs.

(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.