Topic:"Cost Considerations" in M12551

1 4.0 ONE PART REAL-TIME PRICING TARIFFS 2 3 Consistent with its October 15, 2025 memorandum to AAR Stakeholders (Appendix J) on NS 4 Power's Proposal for Methodological Changes to 1P-RTP Tariff, the Company proposes that 5 starting in 202...

AI summary The document discusses NS Power's proposal to implement two One Part Real-Time Pricing (1P-RTP) Tariffs starting in 2026, eliminating the avoided fuel cost adjustment. The proposal includes a Transmission RTP Tariff and a Distribution Voltage RTP Tariff, with fixed cost adders designed to recover non-fuel-related costs. The change is driven by the new Cost of Service Study (COSS) filed in the 2026-2027 GRA, which no longer separates environmental and non-environmental costs.

& lt;sup>26 With the proposed simplification in classification of the non-fuel generation costs to be done entirely based on the system load factor, there is no longer a need, for tracking the environmental costs in the COSS, were determin...

AI summary The text discusses a proposed simplification in the classification of non-fuel generation costs based on the system load factor, eliminating the need to track environmental costs in the COSS, which were previously determined by the Company's bookkeeping records.

Application for Annually Adjusted Rates for 2026 Redacted - 1 due to change in the COSS methodology which is proposed to classify 100 percent of transmission - 2 costs to demand. Since Shore Power, as a priority interruptible service, is o...

AI summary The document discusses changes to the Cost of Service Study (COSS) methodology, proposing to classify 100% of transmission costs as demand-related. Shore Power, as a priority interruptible service, is only responsible for energy-related costs, not transmission costs. The proposed energy charge components for 2026 are compared to 2027 rates in Figure 4.

Application for Annually Adjusted Rates for 2026 Redacted 1 As approved by the Board in the original proceeding to set these rates,32 the BUTU Tariff and the 2 Spill Tariff were each assigned 50 percent of the associated administration cos...

AI summary The document discusses the application for annually adjusted rates for 2026, including the use of an inflation rate to adjust administration costs and the proposed increase in customer charges. It references past Board decisions and the methodology used to calculate energy charges.

3 Figure 14: Variable Capital Cost Calculation Item 2026 PHP VC Cost $787,508 PHP Load Est. (MWh) 774.46 Proposed PHP VC / MWh $1.02 4

AI summary Figure 14 presents a calculation of variable capital costs for 2026, including total cost, load estimate, and the proposed cost per megawatt-hour.

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, and weekend and holiday rates use the off-peak price. Fixed cost adders are updated annually and submitted for approval. A credit is 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 Avoided Costs less: MC Revenue Fuel Cost Adj $0.18982 $0.02395 $0.16130 $0.02036 $0.02852 $0.00360 -100.0% -100.0%...

AI summary The document presents a table outlining various cost components and percentages related to the 1P-RTP Adder calculation, including avoided costs, customer costs, distribution voltage, O&M, capital, ROE, and transmission costs. The percentages indicate changes or adjustments to these costs.

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.

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.

NON-CONFIDENTIAL Α В С D E F G Н I J K L M Formular A/C B/C G/G11 H I ı J-I J/A K/B Costir ng Deter minants i Catego amount in Adders i n$/kWh Customer Class Sa les On Off 3 C PS Amount in Millions On Off Off Line Relative % Apportion to S...

AI summary The table presents cost breakdowns for transmission and distribution, including on-peak and off-peak figures, percentages, and monetary values. It also includes a section for non-eligible customers and total costs. The text mentions 'Transmission Cost Fixed Cost' as a subheading, indicating a focus on fixed costs related to transmission.

- (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.

A B C D E F G H I J K L M Formular A/C B/C G/G11 H I I J-I J/A K/B Categorized amount in Costing Determinants Millions Adders in $ / kWh Customer Class Sales On Off 3 CPS Amount in On Off On Off Line Relative % Millions Apportion On Off On...

AI summary The document presents a detailed breakdown of transmission and distribution costs, including sales, peak and off-peak usage, line losses, and cost apportionment across different customer classes. It also includes notes on line losses and cost categorization.

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.

FOR THE YEAR ENDING DECEMBER 31, 2026 CLASS : TOTAL COMPANY RATE BASE Variable Fixed COSTS (Source Exh 6) Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer Generation Usage (Energy) $1,537,126 $741,...

AI summary The document presents a detailed cost breakdown for the year ending December 31, 2026, 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 energy sales data.

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.

BUTU Capacity Credit Calc. Approved Net Demand Installed Capacity Capacity Credit Contract Demands (kWs) FAM-related Demand Charge Gross Demand Payment payment bfr Credits Capacity Credit Ellershouse Imports 23,500 20.5% 0% 7,549 $6.252 $6...

AI summary This document presents a capacity credit calculation table related to Ellershouse Imports, including installed capacity, capacity credit, contract demands, and financial figures. The table includes a total capacity credit of -301,764, which may relate to a 2026 AAR Application Appendix E4.

2026 Energy Balancing Service Annual Avoided Fuel Cost Calculations Source Annual MWh Load at Transmission Level Generation non-fuel related costs Avoided Unit Cost (c/kWh) Before Fixed Cost Deferral Adj. Fixed Cost Deferral Adj. if applic...

AI summary The document outlines the 2026 Energy Balancing Service, focusing on annual avoided fuel cost calculations and the top-up energy rate calculation. It includes detailed cost breakdowns and energy-related fixed cost components, referencing exhibits and data from COSS (Cost of Service Study).

Source Category Demand-related Costs Cost in thousands of $'s 2026 COSS - Exhibit 5, page 1, column 2. $357,621.5 Less FUEL $0 PURCHASES - OTHER THAN BIOMASS AND WIND $8,334 PURCHASES - BIOMASS $5,365 MARITIME LINK $90,413 PURCHASES - WIND...

AI summary The document presents demand-related costs, including fuel purchases, capacity credits, and ancillary service costs, as well as standby demand charge calculations for various service types. It includes data from multiple exhibits and references specific regulatory filings.

VCC CALCULATION Description Units Value Variable capital cost impact $ $787,508 PHP load forecast-2026 GWh 774.46 VCC Rate $/MWh $1.02 2026 AAR Application Appendix H Page 1 of 37 REDACTED (CONFIDENTIAL INFORMATION REMOVED)

AI summary The document provides a table detailing the variable capital cost impact, PHP load forecast for 2026, and the VCC rate. These figures are part of an AAR application appendix, which includes confidential information that has been redacted.

NON-CONFIDENTIAL 1 GHG emissions regulations. When one of the annual air emissions limits is relaxed, one of 2 the remaining limits becomes a binding constraint. Another challenge is posed by the 3 growing share of the non-dispatchable mus...

AI summary The text discusses challenges related to GHG emissions regulations and the impact of renewable energy integration on compliance costs. It highlights how relaxing one emission limit can create a new binding constraint and how the interaction between RES and OBPS may lead to unfair cost distribution. The planning process for generation resources is also examined, with a focus on non-dispatchable renewables and their effect on system capacity and compliance costs.

NON-CONFIDENTIAL 1 Request IR-5: 2 3 In its 2018 AAR application, NS Power stated that the "the marginal hourly costs of the next 4 MWh are determined by the incremental costs of the source of generation on the margin in 5 each hour."1 In...

AI summary The document requests an explanation of how different 1P-RTP Tariff designs collect unit commitment costs from additional demand, referencing the 2024, 2025, and 2026 AAR decisions. The response explains that unit commitment costs are included in the decremental load methodology, with the 2025 AAR including a pro-rated SO2 limit.

Power Factor Constant Power Factor Constant 90-100% 1.0000 65-70% 1.1255 80-90% 1.0230 60-65% 1.1785 75-80% 1.0500 55-60% 1.2455 70-75% 1.0835 50-55% 1.3335 METERING COSTS

AI summary The table outlines power factor constants for different ranges, which may be relevant to metering costs in the context of electricity regulation. The section 'Metering Costs' suggests the discussion will focus on the financial aspects related to metering in the regulatory proceeding.

Annually Adjusted Rates for 2026 (M12551) NSPI Responses to REI Information Requests 1 Request IR-9: 2 3 (a) Please explain what financial and operational risks or benefits NS Power faces if it 4 underestimates marginal costs in the AAR ca...

AI summary NS Power explains that earnings are not impacted by over- or under-forecasting of annual average marginal fuel costs used for AAR pricing. Imbalances between forecasted and actual costs are accounted for in the financial processes, but the response does not fully address the risks or benefits to different customer classes.

NOVA SCOTIA POWER INC. CLASSIFICATION OF OPERATING EXPENSES (1) INTERMEDIATE CLASSIFICATION (2) (3) THERMAL O&M $111,342 (4) HYDRO O&M $3,544 (5) WIND O&M $15,773 (6) BIOMASS O&M $12,703 (7) LM6000 O&M $1,214 (8) OTHER CT's O&M $2,999 (9)...

AI summary The document presents a detailed breakdown of Nova Scotia Power Inc.'s operating expenses across various classifications, including thermal, hydro, wind, biomass, and others. It includes figures for operating and maintenance costs, as well as allocation percentages for demand and energy across different segments of the power generation and distribution system.

ALLOCATION OF OPERATING EXPENSES (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL (7) MEDIUM INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) PHP (10) MUNICIPAL (11) UNMETERED (12) ALLOCATION FACTOR DE...

AI summary The document provides a detailed breakdown of operating expenses categorized by demand classification, including fuel purchases, biomass, wind, and imports. The data is segmented across various customer classes and includes references to specific files for further details.

DEMAND CLASSIFICATION (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (9) (10) (11) ALLOCATION (14) TOTAL - EHV 139,195 89,400 4,571 24,801 2,821 2,541 3,259 5,058 4,170 1,927 647 (15) (16) TOTAL TRANSMISSION 139...

AI summary The table presents a detailed breakdown of demand classification and associated costs, including operating and maintenance expenses, depreciation, interest, taxes, and revenue, categorized by different demand classes and allocation types.

FOR THE YEAR ENDING DECEMBER 31, 2026 (IN THOUSANDS OF DOLLARS) (21) PREFERRED DIVIDENDS (22) CORPORATE TAXES 0 -2,636 0 -1,316 0 -89 0 -558 0 -88 0 -64 0 -109 0 -168 0 -194 0 -30 0 -19 P-17 P-17 (23) Non-Operating Revenue: (24) EXPORT SAL...

AI summary The document provides a summary of financial figures for the year ending December 31, 2026, including preferred dividends, corporate taxes, non-operating revenue, return on profit/loss, total generation, and operating and maintenance expenses. Key figures are listed in thousands of dollars.

ALLOCATION OF OPERATING EXPENSES FOR THE YEAR ENDING DECEMBER 31, 2026 (IN THOUSANDS OF DOLLARS) (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL (7) MEDIUM INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE...

AI summary The document presents the allocation of operating expenses for the year ending December 31, 2026, across various customer categories and cost components. It includes figures for customer-related costs, distribution, retail, and other miscellaneous revenues and credits.

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 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.

Comments The SBA's review of this 2026 AAR Application is focused on risk transfer, cross-subsidization concerns, and administrative cost discipline, each of which are summarized below.

AI summary The SBA's review of the 2026 AAR Application focuses on risk transfer, cross-subsidization concerns, and administrative cost discipline, highlighting key areas of concern in the application.

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.

lly affect marginal costs, yet no historical accuracy assessment or sensitivity analyses are provided, then the resulting forecast cannot reasonably be relied upon as a stable basis for tariff design. REI's concerns with marginal cost fore...

AI summary The text highlights concerns raised by REI regarding the lack of historical validation and sensitivity analyses in marginal cost forecasts, particularly in the context of the Fuel Adjustment Mechanism (FAM). It notes significant discrepancies between forecasted and actual FAM balances, suggesting structural under-forecasting of energy costs. REI also references NSPI's receipt of various financial benefits and the inaccuracy of marginal cost assumptions.

NS Power Response: - NS Power notes the SBA's observation regarding the 3.25 percent escalation factor applied to - AAR administrative charges. As described in the Company's responses to NSEB and SBA - information requests,[15](#page-10-1)...

AI summary NS Power responds to the SBA's observation regarding the 3.25 percent escalation factor applied to AAR administrative charges, explaining that it reflects forecast salary cost increases for 2026 and includes considerations for market competitiveness, merit-based progression, and retention.

- (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 outlines 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 base energy charge components, including fuel cost and fixed cost adder at different voltage levels.

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.

(2) Removed Exports as this is a variable cost (3) This investment, deemed as made for environmental reasons, was identified as energy-related under the previous COS methodology. EXHIBIT 9A

AI summary The document removes exports as a variable cost and references an investment made for environmental reasons, identified as energy-related under the previous COS methodology. Exhibit 9A is included but no further details are provided.

CLASSIFICATION OF OPERATING EXPENSES (1) TOTAL COMPANY (2) DEMAND EXPENSES (3) ENERGY EXPENSES (4) CUSTOMER EXPENSES GENERATION FUNCTION (1) FUEL 434,033 $0 $434,033 - (2) PURCHASES - OTHER THAN BIOMASS AND WIND 18,420 $8,334 $10,086 - (3)...

AI summary This document presents a detailed breakdown of operating expenses categorized into demand, energy, and customer expenses for a utility company in Nova Scotia, including fuel costs, operations and maintenance, depreciation, and other financial details.

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.

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 the 2026 GRLF, SP, Spill, EBS, and RTT rates, which decreased by 24% due to changes in emissions limits and fuel pricing. The NSUARB requested a sensitivity analysis for no surplus energy delivery from Muskrat Falls, but NS Power requested its removal, which the Board denied. The Board instead suggested adjusting the scenario. The customer charge increased by 3.25%, which NS Power explained includes salary increases, but the SBA questioned the justification.

Renewall Energy Inc. REI's submission was concentrated on the use of the proposed Cost of Service Study methodology, the RtR tariff review and design, RTRSS tariff calculation and the forecasted marginal cost used in the application. Notab...

AI summary Renewall Energy Inc. (REI) raised concerns about the proposed Cost of Service Study methodology, RtR tariff design, and RTRSS tariff calculations, requesting recalculations and a Board order to revise tariffs by March 31, 2026. NS Power responded by suggesting that changes to tariffs may be premature due to ongoing regulatory proceedings and proposed a draft Terms of Reference for an interruptible service pilot with REI.

1 Request IR-3: - 2 Preamble: Based on the principles of economic dispatch, and recognizing the influence 3 of environmental legislation, REI expects that the highest variable cost generators would 4 generally be: diesel combustion turbine...

AI summary The document requests NS Power to confirm or refute REI's assertion that diesel combustion turbines, natural gas generation from Tufts Cove, and imports are the highest variable cost generators. It also asks for a comparison between PLEXOS model forecasts and actual data on marginal generator hours for 2024 and 2025.

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.

17 Request IR-9: - 18 (a) Please explain what financial and operational risks or benefits NS Power 19 faces if it underestimates marginal costs in the AAR calculation versus the 20 risks or benefits if it overestimates marginal costs. - 21...

AI summary The request asks NS Power to explain the financial and operational risks or benefits of underestimating or overestimating marginal costs in the AAR calculation, quantify these impacts, identify affected customer classes, and address impediments to more frequent updates of marginal costs in the RtR market.

- 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.

1. NS Power has stated that higher SO2 emission limits have resulted in lower marginal costs. Please confirm the SO2 emissions associated with NS Power production in 2026, the applicable SO2 emission limits, and the remaining headroom unde...

AI summary The document presents a series of questions to NS Power regarding SO2 emissions, marginal costs, surplus energy delivery, and sensitivity analyses related to commodity price volatility, Muskrat Surplus Energy, and wind project delays. It also requests confirmation on the inclusion of the Goose Harbour Lake wind farm in the 2026 PHP CBL load and a comparison of marginal and average costs under different tariff scenarios.

ysis showing the impact on marginal and average costs if PHP continues to receive service under the ELIADC through 2026 versus taking service under a to-be-filed successor tariff which may be above-the-line. Please quantify the potential r...

AI summary The text consists of a series of questions directed at NS Power regarding the financial and operational implications of various scenarios, including the impact of ELIADC, accuracy of wind generation data, forecasting methods, risk management, and the potential for more frequent marginal cost updates in the RtR market.

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.

rison of the monthly forecast NB imports to actual NB imports dating back to at least 2023? If so, please provide such comparison. If not, please explain why not. Reference: Page 20, lines 16-19. In view of the foregoing, NS Power has, in...

AI summary The text raises questions about NSPI's handling of avoided fuel cost adjustments, the reliability of estimated avoided fuel costs, and the potential discontinuation of the ELIADC Tariff. It also references the impact of these adjustments on rate-setting methodologies and the implications for the ELIADC Tariff's annual calculations.

ed, including the year-end calculations of benefits. Reference: Section 8.0, ELIADC, pages 38-43, and Appendix G1. And Reference: M12184, Submissions of Bates White, dated November 26, 2025. Preamble: In response to NSPI’s ELIADC Third Ter...

AI summary Bates White submitted recommendations to remove fixed costs from the CBL Energy Charge in response to NSPI’s ELIADC Third Term Application. The proceeding asks whether these concerns impact the ELIADC Energy Charge and whether NSPI agrees with the recommended revision to the FCR definition.

Renewall Energy Inc. REI's submission was concentrated on the use of the proposed Cost of Service Study methodology, the RtR tariff review and design, RTRSS tariff calculation and the forecasted marginal cost used in the application. Notab...

AI summary Renewall Energy Inc. (REI) submitted concerns regarding the proposed Cost of Service Study methodology, RtR tariff design, and RTRSS tariff calculation, noting changes to the RTRSS formula. REI requested recalculations and regulatory action by March 31, 2026. NS Power responded by suggesting that addressing these issues may be premature and that changes should occur after the RtR begins service.

Conclusion The Board approves the AARs as filed, subject to retaining jurisdiction to make amendments if adjustments are required to them as a result of the GRA decision. The Board approves the ELIADC tariff, on an interim basis effective...

AI summary The Board approves the AARs with conditions, including interim approval of the ELIADC tariff. It issues several directives to NS Power, including revising sensitivity analyses, providing data on administration charges, and initiating stakeholder engagement. The final approval of AAR rates is pending the outcome of the COSS review.

May 15, 2026 Interested parties: M12551 – 2026 Annually Adjusted Rates – Compliance Filing The Nova Scotia Energy Board's decision dated March 9, 2026, approved the 2026 Annually Adjusted Rates (AARs) effective April 1, 2026. The Board ret...

AI summary The Nova Scotia Energy Board approved the 2026 Annually Adjusted Rates (AARs) effective April 1, 2026, and NS Power submitted a compliance filing with revisions to seven AARs following the Board's decision on the 2026-2027 GRA. Comments on the revised AARs are invited from interested parties by May 25, 2026.