Topic:"Demand Side Management" in M12451

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AI summary Peter Lynch highlights a discrepancy between Nova Scotia Power's (NSP) approved rate increases (26% over 6 years) and actual off-peak rate increases (42%), arguing that NSP's practice of raising off-peak rates above approved levels undermines the goal of promoting low-demand hour usage. He warns that if trends continue, off-peak rates will surpass standard rates by 2055 and urges reverting to original 50% standard rate offers.

Hi Lisa This is not about the recent 4.1% x 2 yr rate increases although I am not in favour.. (surprise eh) My issue has to do with (O/P) OFF PEAK RATEs accelerating at increases above those annual (NS Energy Board , EARB.. PUB.. DOR?) app...

AI summary Peter Lynch argues that Nova Scotia Power's (NSP) off-peak rates have increased faster than approved rates by the Nova Scotia Energy Board for 16 of the last 19 years, now reaching 63% of peak rates instead of the original 50%. He requests NSP to revert to the 50% ratio to encourage off-peak usage.

Evidence of Disproportionate Energy Burden - Mi'kmaq households consistently spend a larger share of income on electricity than non-Indigenous households. - Weatherization and Demand Side Management (DSM) programs have historically underse...

AI summary Mi'kmaq households face disproportionate energy burdens due to higher electricity costs, underserved weatherization and Demand Side Management (DSM) programs, and the inability of Band facilities to reduce consumption without harming community services. Rate increases exacerbate these issues through non-linear impacts.

Regulatory Justification for a Mi'kmaq Rate Class The Nova Scotia Energy Board has the authority to approve differentiated rate classes where materially different circumstances exist among customer groups. - Mi'kmaq communities meet all te...

AI summary The Nova Scotia Energy Board is urged to create a Mi'kmaq Rate Class due to unique socio-economic, geographic, and historical circumstances of Mi'kmaq communities. This rate class would address energy poverty, enhance equity in DSM programs, and align with reconciliation principles. The proposal is supported by public interest benefits, including reduced arrears and community resilience, under Matter M12451.

- Updated assumption for Renewable to Retail (RTR), with a total of 300 GWh moving to the RTR market in 2026 and a total of 421 GWh in 2027. For context, the 2024 Load Forecast assumed 61 GWh moving to RTR in 2025 and a total of 246 GWh in...

AI summary The document discusses updates to the Renewable to Retail (RTR) market assumptions, load forecasts for 2026 and 2027, and adjustments to the load forecast due to migration to RTR and changes in customer load distribution. It highlights increased residential and commercial sales, decreased sales due to RTR migration, and the impact of electrification on demand.

utilities. In particular, factors contributing to this greater business risk include: 1) NSPI's ownership of regulated generation assets, - and the need to transition from coal and gas-fired generation toward more - renewable resources by...

AI summary NSPI faces higher business risks due to regulated generation transition, volumetric risks, weather exposure, DSM targets, and political intervention. The Concentric Evidence suggests a 9.9% required ROE for NSPI, but NSPI requests maintaining its 9.0% ROE to mitigate customer rate impacts. The analysis compares North American and Canadian proxy group averages.

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

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

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

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

4 Figure 14-2 – Proposed 2026 Rates Proposed Rate Changes Units Current 2025 Proposed for 2026 Percentage Change Distribution Cost Adder $/kVA 1.632 2.332 42.9 Energy Charge (Firm Transmission) ¢/kWh 10.799 10.614 -1.4 Energy Charge (Firm...

AI summary The document presents proposed rate changes for 2026 and 2027, including increases in distribution cost adders and customer charges, while some energy charges are reduced. The DSM Rider remains unchanged across all categories.

11 Clean Versions of Tariffs for which approval is requested: Attachment Description PR-01 Attachment 1 a Domestic Service Tariff PR-01 Attachment 1 b Domestic Service Critical Peak Pricing Tariff PR-01 Attachment 1 c Domestic Service Time...

AI summary The document lists clean and redline versions of various tariff attachments for which approval is requested, including Domestic Service, General, Industrial, and Municipal Tariffs, as well as specific riders like the Fuel Adjustment Mechanism and Demand Side Management Cost Recovery Rider.

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

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

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

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

PURPOSE This is an optional tariff designed to promote the shifting of load from peak to off-peak periods. This tariff is available to customers who are eligible for service under the Domestic Service Tariff.

AI summary An optional tariff designed to shift load from peak to off-peak periods, available to customers eligible under the Domestic Service Tariff. The purpose emphasizes load management through time-based pricing incentives.

CRITICAL PEAK EVENT PROCEDURE - (1) In the Winter Period, Critical Peak Events exclude all hours on the following holidays: January 1, Nova Scotia Heritage Day, Good Friday, Easter Monday, November 11, December 25 and December 26. If Janua...

AI summary The Critical Peak Event Procedure outlines exclusions for holidays during the Winter Period, criteria for scheduling events (e.g., high energy usage, outages), notification protocols, and rate adjustments during events. Events are limited to 18 per winter season, with specific weekday/weekend restrictions. Customers face higher charges during events and are encouraged to reduce consumption.

DEMAND CHARGE per month per kilowatt of maximum demand Effective January 1, 2026 $9.838 Effective January 1, 2027 $10.709 32 cents per kilowatt reduction in demand charge where the transformer was owned by the customer prior to February 1,...

AI summary The document outlines the demand charge rates effective January 1, 2026, and January 1, 2027, at $9.838 and $10.709 per month per kilowatt of maximum demand, respectively. It also mentions a 32-cent reduction in demand charge per kilowatt for customers who owned transformers prior to February 1, 1974, or under Special Condition (2).

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

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

For customers connected at distribution level, the following charge also applies, subject to the same provisions as the Demand Charge section above. per month Effective January 1, 2026 $2.332 Effective January 1, 2027 $2.527 32 cents per k...

AI summary The document outlines additional charges for customers connected at the distribution level, including a monthly fee effective from January 1, 2026, and a reduction in demand charge based on kilovolt ampere reductions when the transformer is customer-owned.

reduction per kilovolt ampere reduction in demand charge Effective January 1, 2026 $7.638 Effective January 1, 2027 $7.667 AVAILABILITY

AI summary The document provides the reduction per kilovolt-ampere reduction in demand charge for the years 2026 and 2027, with values of $7.638 and $7.667 respectively.

per month Effective January 1, 2026 $11.330 Effective January 1, 2027 $12.270 32 cents per kilowatt reduction in demand charge where the transformer is owned by the customer.

AI summary The text presents a table showing the effective rates per month for January 1, 2026, and January 1, 2027, along with a charge of 32 cents per kilowatt reduction in demand charge for transformers owned by the customer.

Rates

AI summary The document section titled 'Rates' is present but contains no substantive content or analysis. Key acronyms related to regulatory mechanisms and entities are noted but not elaborated upon in the provided text.

(3) Load Migrations between FAM/Non-FAM Classes

AI summary The section discusses load migrations between FAM and non-FAM classes, involving Nova Scotia Power Inc. (NSPI) and programs like the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR). It focuses on regulatory considerations for managing load shifts across these classes.

Nova Scotia Power Incorporated Page 5 of 23 Open Access Transmission Tariff 2027 Delivery Period Charge ($) Monthly $176.94 /MW of Reserved Capacity per month Weekly $40.83 /MW of Reserved Capacity per week On-peak daily $8.17 /MW of Reser...

AI summary The document outlines Nova Scotia Power Inc.'s (NSPI) Open Access Transmission Tariff, specifying reserved capacity charges for different time periods (monthly, weekly, daily on/off-peak, and hourly on/off-peak). On-peak days are defined as Monday to Friday, with on-peak hours from 09:00 to 24:00 Atlantic Time.

Regulation

AI summary The document outlines a regulatory proceeding in Nova Scotia involving the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR), overseen by the Nova Scotia Energy Board (NSEB) and Nova Scotia Power Inc. (NSPI). Key focus areas include cost recovery frameworks and regulatory compliance.

Load Following

AI summary The Load Following section of the Nova Scotia regulatory proceeding involves discussions around mechanisms and programs related to energy demand management. Key entities include Nova Scotia Power Inc. (NSPI) and the Nova Scotia Energy Board (NSEB), with references to the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR).

Operating Reserve – Supplemental (30-minute)

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

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

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

STREET AND AREA LIGHTING RATES

AI summary The document pertains to regulatory proceedings concerning Street and Area Lighting Rates in Nova Scotia. Key entities include Nova Scotia Power Inc. (NSPI) and the Nova Scotia Energy Board (NSEB), with references to mechanisms like the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCR). The proceeding involves considerations of energy pricing, reliability, and regulatory oversight.

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AI summary The text discusses the regulatory process and the various topics related to energy efficiency, demand-side management, and the Fuel Adjustment Mechanism. It outlines the roles of the Nova Scotia Energy Board and Nova Scotia Power Inc. in managing energy resources and setting rates.

APPLICABILITY This schedule applies to all electric rate classes with the exception of the Wholesale Market Non-Dispatchable Supplier Spill Tariff, the Load Retention Tariff, and the Extra Large Industrial Active Demand Control Tariff. For...

AI summary The schedule applies to all electric rate classes except specified tariffs. Customers in Wholesale or Renewable to Retail markets will have DSM costs directly billed via their energy bills, per Section 79A of the Public Utilities Act and NSEB approval. NSPI's bundled service offerings are referenced as the billing model.

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

AI summary The Franchise Holder must apply to NSEB for approval of DSM activities and costs. NS Power must apply for the DSM Cost Recovery Rider and pay monthly to fund DSM costs, as per the Public Utilities Act.

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

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

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

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

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

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

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date of...

AI summary The Balance Adjustment (BA) is updated annually and after each Approved DSM Term, with the NSEB-approved DCRR taking effect in bills after its effective date. This ensures alignment with DSM program costs and regulatory approvals.

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

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for 2025, including its components, Program Cost Recovery (PCR) and Balance Adjustment (BA), effective from January 1, 2025, to December 31, 2025.

Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.657 -0.024 0.633 Small General, Small Gene...

AI summary The document outlines various applicable tariffs with corresponding Program Cost Recovery (PCR), Balance Adjustment (BA), and Demand Side Management Cost Recovery Rider (DCRR) rates for different service categories. It also references the Approved DSM Term and provides an example of how BA2 is calculated and applied over the remainder of the DSM Plan period.

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

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

Conditions - For bundled service customers other than those who take service in the Wholesale Market (whether in whole or in part), this approach applies to classes as a whole (not to individual customers). - For customers who take service...

AI summary Conditions differentiate bundled service customers (not in Wholesale Market) from those in the Wholesale Market, applying the approach to classes versus individual customers. The approach also applies to total Approved DSM costs.

PURPOSE This is an optional tariff designed to promote the shifting of load from peak to off-peak periods. This tariff is available to customers who are eligible for service under the Domestic Service Tariff.

AI summary This optional tariff aims to encourage load shifting from peak to off-peak periods. It is available to customers eligible under the Domestic Service Tariff, promoting energy use during lower-demand times.

DOMESTIC SERVICE CRITICAL PEAK PRICING TARIFF Page 2 of 3 Rate Code 70 - (3) When a Critical Peak Event is scheduled, subscribers to this tariff will be notified in advance and the Critical Peak Event Energy Charge (higher rate) will be in...

AI summary The Critical Peak Pricing Tariff (Rate Code 70) outlines procedures for notifying customers of high-rate periods during winter, limiting events to 18 per season, and requiring customer responsibility for contact updates.

Special Terms and Provisions - (1) Green Power, as defined for the purposes of this rider includes energy produced from renewable resources that have minimal impact on the environment, and could be independently certified by third party en...

AI summary This rider defines Green Power as energy from renewable resources with minimal environmental impact, potentially certified by third parties. Service under the rider may be limited based on the availability of green energy.

SMALL GENERAL CRITICAL PEAK PRICING TARIFF Page 2 of 3 Rate Code 72 - (2) Critical Peak Events will be scheduled, at the sole discretion of NSPI, when NSPI is expecting conditions including, but not limited to, high energy (kWh) usage, hig...

AI summary NSPI may schedule up to 18 Critical Peak Events annually during winter (November-March), with no more than three per week or on weekends. Customers are notified 24 hours in advance of higher energy charges during these events, encouraging reduced usage. Notifications are the customer's responsibility, and contact details must be updated promptly.

PURPOSE This is an optional tariff designed to promote the shifting of load from peak to off-peak periods. This tariff is available to customers who are eligible for service under the General Tariff.

AI summary This optional tariff aims to encourage customers to shift electricity usage from peak to off-peak periods. It is available to those eligible under the General Tariff, promoting load management and efficient energy use.

DEMAND CHARGE per month per kilowatt of maximum demand Effective February 2, 2023 $10.554 Effective January 1, 2024 $10.554 Effective January 1, 2026 $9.838 Effective January 1, 2027 $10.709 32 cents per kilowatt reduction in demand charge...

AI summary The document outlines demand charge rates effective from February 2023 to 2027, with a reduction of 32 cents per kilowatt for customers with transformers owned before 1974 or under Special Condition (2).

GENERAL CRITICAL PEAK PRICING TARIFF Page 2 of 4 Rate Code 73 December 26. If January 1, November 11, December 25 or 26 fall on a weekend, the Critical Peak Events also exclude the weekday the holiday is observed. - (2) Critical Peak Event...

AI summary The document outlines the rules for the Critical Peak Pricing Tariff (Rate Code 73), including scheduling criteria, notification procedures, and event limitations during the winter period. NSPI has sole discretion to schedule events based on high usage or outages, with advance notifications and restrictions on the number of events per season and week.

- (a) The customer must commence service under this tariff on November 1st, unless NSPI grants a waiver. - (b) The customer must be equipped with a standard Smart Meter. - (c) The customer must be on electronic billing and have a MyAccount...

AI summary This section outlines the conditions for customers to subscribe to a specific tariff, including requirements to start service on a specific date, have a Smart Meter, use electronic billing, and be excluded from Net Metering service under a specific regulation.

PURPOSE This is an optional tariff designed to promote the shifting of load from peak to off-peak periods. This tariff is available to customers who are eligible for service under the General Tariff.

AI summary This optional tariff aims to encourage customers to shift electricity usage from peak to off-peak periods. It is available to those eligible under the General Tariff, promoting load management and efficient energy use.

DEMAND CHARGE As follows, per month per kilovolt ampere of maximum demand of the current month or the maximum actual demand of the previous December, January, or February occurring in the previous eleven (11) months.

AI summary The demand charge is calculated based on the maximum demand of the current month or the highest actual demand from the previous December, January, or February within the last eleven months, measured in kilovolt amperes per month.

per month Effective February 2, 2023 $13.845 Effective January 1, 2024 $13.845 Effective January 1, 2026 $11.201 Effective January 1, 2027 $12.003 32 cents per kilovolt ampere reduction in demand charge where the transformer is owned by th...

AI summary The document outlines monthly effective rates starting from February 2, 2023, with a reduction in demand charge for customers owning transformers, providing a financial incentive for demand-side management.

DEMAND CHARGE per month per kilovolt ampere of maximum demand Effective February 2, 2023 $13.796 Effective January 1, 2024 $8.332 Effective January 1, 2026 $10.728 Effective January 1, 2027 $11.277 32 cents per kilovolt ampere reduction in...

AI summary The document presents the demand charge rates effective from February 2023 to January 2027, along with a reduction incentive for customers owning the transformer. The rates are listed in dollars per kilovolt ampere of maximum demand.

Where: "A" is any residual customer demand (above that required by the interruption notice) remaining in the third interval directly following two complete 5-minute intervals after the interruption call is initiated and sent by NSPI. "B" i...

AI summary The document outlines rules for interruptible service under the DCR rider, including penalty calculations based on residual demand, service conversion requirements (5-year notice for firm service, 2-year return to interruptible), and interruption limits (16 hours/day, 30% monthly, 15% annual). NSPI sets these terms for capacity availability and billing.

APPLICABILITY This schedule applies to all electric rate classes with the exception of the Wholesale Market Non-Dispatchable Supplier Spill Tariff, the Load Retention Tariff, and the Extra Large Industrial Active Demand Control Tariff. For...

AI summary The schedule applies to most electric rate classes, excluding specific tariffs. For Wholesale and Renewable to Retail customers, DSM costs defined in Section 79A of the Public Utilities Act are directly billed via the customer's energy bill, as if served by NS Power under bundled offerings, approved by the NSUAREB.

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

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

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

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

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

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

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

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

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSUAREB-approved DCRR shall be placed into effect with bills rendered on and after the effective date...

AI summary The Balance Adjustment (BA) is annually updated to reflect BA1 and BA2, with the NSUAREB-approved DCRR implemented post-effective date. BA1 relates to annual updates, while BA2 applies at the end of Approved DSM Terms. The DCRR's activation is tied to NSUAREB approval.

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

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

2 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Servic...

AI summary The Approved DSM Term refers to the full DSM Plan period in effect, such as 2023-2026 or 2027-2031. A table outlines various applicable tariffs and associated PCR, BA, and DCRR values for different service categories.

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

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

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

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

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

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

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

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

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

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

Attachment 1w – Demand Side Management Cost Recovery Rider (DCRR) Attachment 2 – Tariffs Redline Attachment 2a – Domestic Service Tariff Attachment 2b – Domestic Service CPP Tariff Attachment 2c – Domestic Service TOU Tariff Attachment 2d...

AI summary This document lists various tariff attachments related to different service categories and cost recovery mechanisms, including the Demand Side Management Cost Recovery Rider (DCRR) and Fuel Adjustment Mechanism Tariff. It outlines the structure of tariffs for domestic, general, industrial, and municipal services, as well as storm and distribution cost recovery riders.

PR-03 Proposed Regulations Attachment 1a (Redline)/2a (Clean) - Regulation 1.1 Interpretation and Definitions Attachment 1b (Redline)/2b (Clean) – Regulation 5.1 Meter Reading Attachment 1c (Redline)/2c (Clean) – Regulation 7.1 Schedule of...

AI summary The document outlines four attachments related to PR-03 Proposed Regulations, including amendments to definitions, meter reading protocols, charge schedules, and load research charges. These updates aim to clarify regulatory frameworks and operational procedures under the Demand Side Management Cost Recovery Rider (DCRR) program.

2026-2027 GRA Direct Evidence Appendix 1B Page 2 of 4 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS Cost of Service Study CRA Canada Revenue Agency CWIP Construction Work in Progress DCRR DSM Cost Recovery Rider DDA Decarbonization Defe...

AI summary This document is part of a 2026-2027 General Rate Application (GRA) appendix, listing acronyms and their expansions related to energy regulation, cost recovery mechanisms, and environmental policies in Nova Scotia. Key terms include Demand Side Management (DSM), Distributed Energy Resources (DER), and legislative frameworks like the Environmental Goals and Climate Change Reduction Act (EGCCRA).

4. DSM True-Up The Board's directive is found at para. 359 of the 2023-2024 GRA Decision: As the issue of DSM true-up for prior period variances was not addressed in the GRA Settlement Agreement, the Board makes no determination at this ti...

AI summary The Nova Scotia Energy Board (NSEB) has not determined DSM true-up variances from the GRA Settlement Agreement, directing NS Power to provide updates with future DCRR applications. NS Power addressed historical DSM true-up in M11352 and considers the matter complete.

Status Summary of 2023-2024 GRA Directives Directive Status a. Submit annual reports on April 1, 2024-2026 Ongoing summarizing actual Levels 1-4 storm restoration costs for each yar of the Storm Rider trial period 2024 Filing: M11631 [para...

AI summary The document outlines various directives related to the 2023-2024 General Rate Application (GRA) for Nova Scotia Power (NSP). These include submitting annual storm restoration cost reports, including detailed storm restoration costs in cost recovery applications, developing a Climate Change Adaptation Plan, filing DSM true-up updates, submitting progress reports on stakeholder engagement for studies, and conducting a depreciation study as part of the Decarbonization Deferral Account (DDA) process.

3.1 Enhanced Risk Profiling

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

APPENDIX 5A 2026-2027 FUEL AND PURCHASED POWER

AI summary Appendix 5A outlines fuel and purchased power considerations for 2026-2027, referencing regulatory frameworks, cost recovery mechanisms, and energy management programs. It includes acronyms related to Nova Scotia's energy sector, such as DSM, FAM, and CRA, indicating focus areas like demand-side management, fuel adjustment, and compliance with environmental legislation.

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

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

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

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

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

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

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

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

These weak long-term economic and demographic trends place downward pressure on NSPI's electric load growth, which is offset by increased demand for electricity due to population growth, electrification of buildings, electric vehicle charg...

AI summary NSPI's electric load growth is being negatively impacted by long-term economic and demographic trends, as well as the increasing adoption of DSM programs and solar installations. These factors are expected to reduce load growth by a combined 1,326 GWh over the next ten years. Solar capacity is projected to reach 200 MW by 2030.

21 g. Alternative Fuel Risk 16 amount owed by customers to NSPI for the deferred FAM balance. Although NSPI continues to face competition from alternative fuel sources, this risk is declining due to government policy that promotes electrif...

AI summary Nova Scotia Power Inc. (NSPI) faces declining alternative fuel risk due to government policies promoting electrification and increased electric vehicle adoption. The percentage of residential customers using electricity for space heating has risen from 51.1% in 2020 to 60.2% in 2024. Heat pump adoption has increased significantly, impacting NSPI's load management and exposure to volumetric risk.

9 c. Volume/Demand Risk NSPI does not have a mechanism to mitigate volume/demand risk due to changes in volume attributable to weather, economic conditions, or energy efficiency and conservation programs. The significance of this risk has...

AI summary NSPI lacks a mechanism to mitigate volume/demand risk due to factors like weather, economic conditions, and energy efficiency programs. This risk has increased as more residential customers switch to electric heating. Other Canadian utilities have mechanisms such as revenue stabilization plans, weather-related variance accounts, and performance-based regulation to manage this risk.

3 d. Conclusions on Business Risk of NSPI Compared to U.S. Electric 4 Utility Proxy Group 5 Based on the business risk analysis, we conclude that NSPI has similar business risk to the U.S. 6 Electric utility proxy group on many factors tha...

AI summary NSPI has similar business risk to the U.S. Electric utility proxy group in the short and intermediate term, but differences exist due to its reliance on coal and lack of a decoupling mechanism, increasing volumetric risk. NSPI also funds a DSM program without being able to recover lost revenues through an LRAM.

Cost of Service Study Redacted 1 • Determination of usage for rate calculations: under the OATT the transmission rates are a 2 function of historic usage while under the COSS they are a function of forecasted test year 3 usage. 4 5 To alig...

AI summary NS Power proposes changes to the Cost of Service Study (COSS) to align transmission revenue requirements and usage calculations with the Open Access Transmission Tariffs (OATT), including reclassifying radial-to-generation assets and amending the DSM Rider allocation.

CONFIDENTIAL Reference Cells Modification Exhibit by SLF. Combine Secondary Demand and half of Secondary Customer and split between Demand and Energy by SLF. Add Energy columns and Exh 3d Columns D, G allocate to classes by primary/ second...

AI summary The text contains a table of exhibits with modifications to reference cells and classifications, focusing on splitting and allocating demand and energy between different categories, as well as revising subtotal calculations and adding distribution to energy classification sections.

New No 50% Customer, 50% 50% Customer, 50% 25% Customer, Brunswick Demand Demand 75% Demand Power Newfoundland Yes 37% Customer, 63% 37% Customer, 63% 28% Customer, Power Demand, Demand 72% Demand Ontario No 60% Customer if Density is < 30...

AI summary The table outlines different utility companies and their respective customer and demand percentages under various scenarios. It includes entities such as Brunswick Power, Newfoundland Power, Ontario, and SaskPower, indicating varying levels of customer and demand participation in different regions.

NON-CONFIDENTIAL 1 Request DR-8: 2 3 Please provide bulk electric system reliability event data for the past ten years, including the 4 time the event began and ended, including the following data. If NS Power uses different 5 classificati...

AI summary The document requests data on bulk electric system reliability events over the past ten years, including system warnings, emergencies, demand response events, and internal alerts. NS Power responds by providing data from 2017 to 2023 on capacity and energy emergency procedures, noting that data prior to 2017 is not available. Two events involving automatic load rejection are also mentioned.

COSS CA DR-9 Attachment 1 Page 53 of 627 Start Time End Time ANL_MW 6/1/2019 17:00 6/1/2019 18:00 995.8 6/1/2019 18:00 6/1/2019 19:00 1014.7 6/1/2019 19:00 6/1/2019 20:00 1016.5 6/1/2019 20:00 6/1/2019 21:00 1040.3 6/1/2019 21:00 6/1/2019...

AI summary The document presents a table with timestamps and corresponding ANL_MW values, likely representing load data or energy demand over a specific period in June 2019. The data shows fluctuations in energy usage across multiple time intervals.

COSS CA DR-9 Attachment 1 Page 175 of 627 Start Time End Time ANL_MW 5/22/2020 13:00 5/22/2020 14:00 5/22/2020 14:00 5/22/2020 15:00 711.4 732.3 5/22/2020 15:00 5/22/2020 16:00 717.9 5/22/2020 16:00 5/22/2020 17:00 711.4 5/22/2020 17:00 5/...

AI summary The document presents a table with time intervals and corresponding ANL_MW values, likely representing energy demand or load data over a specific period in May 2020. It also references a partially confidential appendix from a regulatory proceeding related to the 2026-2027 GRA Direct Evidence.

Start Time End Time ANL_MW

AI summary This table lists the start and end times along with the Apparent Net Load in megawatts (ANL_MW), indicating the time intervals and corresponding load values.

NON-CONFIDENTIAL 1 Request DR-47: 2 3 Please explain whether NS Power typically serves a multi-family building with a single 4 service, or with a separate service for each customer. 5 6 Response DR-47: 7 8 Typically, with a multi-dwelling...

AI summary NS Power typically provides one electrical service supply for multi-dwelling units, which is then branched into individual metered services for each customer.

Determination of Revenue Responsibilities By Rate Classes January 2022 2022-2024 GRA SR-01 Attachment 1b Page 2 of 3 COSS CA DR-53 Attachment 1 Page 14 of 62 PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 804 of...

AI summary The document outlines how Nova Scotia Power determines revenue responsibilities by rate class using the Cost of Service Study (COSS). Revenue is apportioned among Above-the-Line (ATL), Below-the-Line (BTL), and Miscellaneous rate classes. DSM program costs are excluded from the revenue requirement and fall under the DSM Rider.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests 1 Request DR-76: 2 3 Please provide a basic summary of current and forecast DSM program costs and benefits, 4 including but not limited to the following: 5 6...

AI summary NSPI provided responses to data requests regarding the current and forecast DSM program costs and benefits, referencing the 2023-2025 DSM Plan, Rate and Bill Impact Analysis, and the 2019 DSM Potential Study. The information includes program costs, net participant benefits, capacity and energy benefits, and other quantified benefits.

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

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

NON-CONFIDENTIAL 1 Option One: 2 - 3 Keeping the 75/25 split assumption unchanged, NS Power apportioned the system cost benefits to - 4 rate classes based on class shares in the cumulative savings in their total electricity costs, inclusiv...

AI summary NS Power's Option One maintains the 75/25 split assumption and allocates system cost benefits to rate classes based on their share of cumulative electricity cost savings from the 2023-2025 DSM Plan over the 2023-2040 period. This approach uses cumulative savings as an indicator of benefits realized by each rate class.

11 Figure 1 Breakdown of Cost Responsibilities for System Benefits Current Method Class Shares in 2023-2040 Electric Service Cost Savings due to DSM Change Index Rate class Residential 54.3% 31.7% 0.6 Small General 3.4% 6.8% 2.0 General 23...

AI summary The figure presents a breakdown of cost responsibilities for system benefits, showing how different rate classes share the savings from demand-side management (DSM) between the current method and the 2023-2040 electric service cost period. The Municipal Class shows anomalous results due to incorrect inclusion of usage reductions in simulations.

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

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

1 Figure 2 Breakdown of Cost Responsibilities for System Benefits Current Method Class Shares in 2023-2040 Electric Service Cost Savings due to DSM activities of other classes Change Index Rate class Residential 54.3% 45.9% 0.8 Small Gener...

AI summary Figure 2 presents a breakdown of cost responsibilities for system benefits, showing the distribution of cost savings from demand-side management (DSM) activities across different rate classes from 2023 to 2040. The data indicates varying shares of savings among residential, industrial, and other classes.

10 Below-the-line (BTL) rate classes 11 12 Since the BTL rate classes of GRLF, 1P-RTP, Shore Power, BUTU, EBS, and SS do not participate 13 in DSM Programs they have not been included in the Rate and Bill Impact Analysis filed in the 14 DS...

AI summary The BTL rate classes of GRLF, 1P-RTP, Shore Power, BUTU, EBS, and SS do not participate in DSM programs and were not included in the Rate and Bill Impact Analysis. Their system cost benefit treatment may remain unchanged, as their share of assigned DSM costs in 2025 was below 0.5 percent.

NON-CONFIDENTIAL - 1 For the illustration of differences in apportioned DSM costs to the above-the-line (ATL) rate - 2 classes, using the 2025 DSM costs recently filed in the 2025 DSM Rider Application, please refer - 3 to tab "CA DR-87 20...

AI summary The text references the allocation of DSM costs to above-the-line rate classes using the 2025 DSM Rider Application, specifically directing readers to a specific tab in Attachment 1 for illustration purposes.

Response IR-215: (cont'd) Juan adjustments, etc.) were repaired using surrounding data for similar day types (i.e.: day of the week…Mondays, Tuesdays, etc). - c. The actual demands for each rate class for each month at the time of NSPI's m...

AI summary The document outlines methods used to estimate and forecast demand for different rate classes, including adjustments based on temperature, historical data, and customer input. These methods were used to calculate load factors and forecast sales peaks for 2005.

COSS IG DR-10 Attachment 1 Page 1 of 6 Determination of Unit Avoided Marginal Annual Cost of Load Served ($/kW, in 1994 Annual Cost of Load Served ($/kW, in 1994 Annual Avoided Cost rounded to nearest dollar in 1996 % Change from 1996 Benc...

AI summary The document presents calculations related to interruptible credit and annual cost of load served for different years, including comparisons between 1996 and test years 2022-2024. It includes figures on avoided costs, revenue credits, and demand coincident with system peaks. These calculations are used to evaluate financial impacts and system reliability.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to MEU Data Requests 1 The primary difference between the fuel cost components of the BUTU and RtR rates are 2 that BUTU FAM-related charges are based on allocated costs and RtR...

AI summary The text discusses differences in fuel cost components between BUTU and RtR rates, the impact of including municipal customers under the OATT as a separate rate class in the COSS, and NSPI's response to MEU data requests regarding DSM Rider charges. Models were prepared and uploaded to address these issues.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests 1 Request DR-13: 2 3 Please provide the following data for every monthly CP over the past five years (2019-2023): 4 5 (a) System Peak without PHP's load 6 7...

AI summary NSPI provided responses to data requests related to the Cost of Service Study (COSS) process, including system peak data with and without PHP's load, customer class demand, and details about emergency or reliability events during critical periods. The data is sourced from the Load Research Sample (LRS) and AMI data, with some customer classes fully sampled.

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

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

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

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

1 Request DR-1: 2 - 3 Tabulated hourly load profile for the day of the winter peak demand in 2030 net of all wind - 4 and solar generation (i.e., including behind-the-meter)- by residential; commercial; - 5 industrial; and other customer c...

AI summary The response to Request DR-1 provides an hourly load profile for the winter peak demand day in 2030, along with wind and solar generation data, sourced from the 2022 Evergreen IRP scenario. Behind-the-meter generation is estimated using installed capacity and capacity factors. Peak demand forecasts are provided at a general level rather than by customer class.

19 Modeled Peak (MW) Res Heat (MW) EV (MW) DR (MW) C&I Elect. (MW) Large Cust. (MW) DSM (MW) Firm Peak (MW) Inter. Cust. (MW) System Peak (MW) 2030 1,977 95 64 -38 152 111 -119 2,243 152 2,434 20

AI summary The table presents modeled peak demand and various load components for the year 2030, including residential heating, electric vehicles, demand response, commercial and industrial electricity, large customers, demand-side management, firm peak, interconnection customers, and system peak, measured in megawatts (MW).

Demand, Energy & Peak Demand – Cost Causality (Illustrative hourly demand)

AI summary The document presents illustrative hourly demand data related to cost causality in the context of demand, energy, and peak demand. Visual representations such as figures and pictures are included to support the analysis.

Sector Evolution - Sector evolution has been characterized as the "Four Ds" - Decentralization - Decarbonization - Democratization - Digitization - The commonly identified specific drivers of change include: - Increasedelectrification of t...

AI summary The sector evolution is described through the 'Four Ds'—Decentralization, Decarbonization, Democratization, and Digitization. Key drivers of change include increased electrification, non-dispatchable renewable generation, demand-side management, and energy storage.

Evergreen IRP – Key Assumptions Load - NS Power is planning for a growing electricity system load, consistent with what is being forecast across many jurisdictions as part of the coming energy transition. - NS Power's Load Forecasting proc...

AI summary NS Power is forecasting a growing electricity system load due to the energy transition, incorporating electrification effects and using data from Energy + Environmental Economics (E3). Energy efficiency, demand response, and managed EV charging are considered to mitigate increased demand.

Evergreen IRP Outcomes: Action Plan Action Plan Item Focus Plan to 2030/COSS Areas of Interest 1: Regional Integration Regional integration strategy: access to firm capacity and improve system reliability Reliability Tie (2028) 2: Electrif...

AI summary The Evergreen Integrated Resource Plan (IRP) Action Plan outlines key initiatives for 2030, including regional integration, electrification, thermal retirement, and demand response strategies. It emphasizes improving system reliability, evaluating electrification's role, progressing thermal plant retirements, and expanding demand response programming to 75MW by 2025.

- Key stakeholders include the Government of Nova Scotia, Independent Power Producers (IPPs), EfficiencyOne(E1), Mi'kmaw Partners, and NS Power. 2030 Project Accountability Key Partners Wind/Solar NS Government IPP's Battery Storage NS Gov...

AI summary The document outlines key stakeholders and their involvement in various 2030 projects related to energy in Nova Scotia, including the Government of Nova Scotia, Independent Power Producers (IPPs), EfficiencyOne (E1), Mi'kmaw Partners, and NS Power. Projects include wind/solar, battery storage, grid stability, hybrid peak/load management, reliability tie, fast acting generation, and fuel conversions.

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

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

DSM Cost Recovery Process - To meet its obligations under the Public Utilities Act R.SNS 1989, c 380 (Act) to undertake cost-effective electricity efficiency and conservation activities NS Power enters into an agreement with EfficiencyOne...

AI summary NS Power enters into a multi-year supply agreement with EfficiencyOne to deliver electricity efficiency and conservation programs, with DSM costs recovered through DCRRs and direct billing for MEUs. The process is subject to UARB approval and involves annual rider approvals based on the supply agreement.

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

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

The Cost benefits resulting from DSM programs - 1. System Avoided future infrastructure and related costs, reduced fuel costs, and contribution to achieving environmental and emissions restrictions. All customers receive these benefits. -...

AI summary The text outlines the cost benefits of Demand Side Management (DSM) programs, including avoided infrastructure costs, reduced fuel costs, and environmental benefits. These benefits are shared among all customers, and participation can reduce individual electricity costs.

Cost Allocation The amount of total DSM costs E1 budgets and tracks its costs by Rate classes. However, 25% of these costs are reapportioned by NS Power.

AI summary E1 budgets and tracks DSM costs by rate classes, but 25% of these costs are reapportioned by NS Power.

Allocation of DSM Program Costs - All DSM Costs are budgeted and tracked by Rate Classes (See Slide 10) - System benefits are allocated to all applicable customer classes in accordance with the COS methodology reflecting allocation of gene...

AI summary The document outlines how Demand Side Management (DSM) program costs are allocated by rate classes. System benefits are distributed based on the Cost of Service (COS) methodology, with 0.7% of NS Power's revenue requirement allocated to system benefits in 2024. Remaining costs are distributed proportionally among participating classes based on their investments in DSM programs.

Determination of 25% System Benefit Costs Table : 1: 2024 PCR -A llocation of 75% o of 2024 DSM Pr rogram Costs a ssociated with I penefits realize d by participating c lasses COLUMN A В С D E F G н 1 J К FORMULA ∑ col A to J K 75% Pr ogra...

AI summary The document presents a table allocating 75% of the 2024 DSM Program Costs associated with benefits realized by participating rate classes, with a specific allocation of 25% System Benefit Costs. The table details program costs across different rate classes and includes a subtotal for unbundled service customers and other categories.

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

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

Instead of MidAmerican's exponential function, use California's probability-based curve - Sigmoidal (s-shaped) logistic regression - California selected RMO event probability as the basis for the curve - Also incorporated a flex-alert "add...

AI summary The text suggests replacing MidAmerican's exponential function with California's probability-based curve, specifically using the RMO event probability and incorporating a flex-alert 'adder' for improved modeling.

Outcome: Avoiding the challenge of evaluating technology performance to classify costs to demand - Classification of new resources is imprecise and not fixed over time - Generation and transmission are no longer built to satisfy demand in...

AI summary The document discusses the challenges of classifying new resources and the impracticality of traditional peaker methods in modern grid management. It highlights the HCM Method as an alternative for classifying non-fuel costs based on grid stress events.

Future generation will increase energy arbitrage opportunities - Avoiding curtailment by shifting demand from low-output to high-output periods - Using battery storage to deliver energy at a different time but with an energy loss

AI summary The text discusses how future energy generation will create more opportunities for energy arbitrage by shifting demand from low-output to high-output periods and using battery storage, albeit with energy loss.

Prob. Of Variable Customer Class Dispatch Energy Residential 44.69% 44.94% General Service General Service I Primary Distribution 5.70% 5.66% General Service I Secondary Distribution 8.55% 8.50% General Service II Primary Distribution 2.38...

AI summary The document presents a table showing the probability of dispatch and energy variables for different customer classes, including residential and general service categories, with percentages for each. The table is part of a confidential appendix in the 2026-2027 GRA Direct Evidence.

Average and Peak with Time of Use Method Like the Average and Peak method, the Average and Peak with Time of Use (TOU) method classifies all fixed generation costs to peak demand and average demand based on the system load factor (SLF). Av...

AI summary The text discusses the Average and Peak with Time of Use (TOU) method, explaining how fixed and variable costs are allocated based on load factors and dispatch costs. It highlights inconsistencies, such as the inclusion of interruptible loads in dispatch costs but not in load data, and the impact of export revenues on dispatch cost allocations.

PHP and NS Power Coordination - § Unique Load Characteristics support the need for PHP as a standalone customer class - §Active Demand Control by NSP - §Ramped up to optimize system dispatch (e.g. avoid renewable curtailment) - §Ramped dow...

AI summary The document discusses the unique load characteristics of PHP (a customer class) and how NS Power manages it through active demand control, scheduling, and priority interruptible load to optimize system dispatch, avoid renewable curtailment, and ensure reliability.

PHP DEMAND ALLOCATION - § PHP load had already been reduced down by NSP a number of hours in advance of the need to make any further system interruption call. - § 8-9 MW inclusive of shared service (energy) for the biomass plant located at...

AI summary The text discusses the reduction of PHP load by NSP prior to potential system interruptions and mentions an 8-9 MW capacity for a biomass plant at PHP, inclusive of shared service energy.

Dispatchable Resource Allocation - Dispatchable resources with ramping capabilities should be allocated to demand. - Batteries do not produce energy, they are charged with energy and discharged at times of peak demand and periodically for...

AI summary The text discusses the allocation of dispatchable resources with ramping capabilities to meet demand, noting that batteries are used primarily for peak shaving due to their charge cycles causing degradation over time.

2026-2027 GRA Direct Evidence Appendix 12A(3) Page 164 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 2. The NS Power supply resource portfolio will transition to incorporate increased amounts of renewable and intermittent resources....

AI summary The document outlines key changes in the Nova Scotia Power supply resource portfolio, including increased renewable energy integration, the impact of customer-owned generation like solar PV, and the influence of battery storage systems on grid dynamics. It also mentions the development of new market and regulatory processes, as well as evolving customer expectations regarding service options.

2. Underlying Principles for COSS The SBA has participated in the COSS stakeholder process hoping to see a process that: - 1. Closely examines cost causation for all the functions, generation, energy production, transmission, distribution,...

AI summary The SBA participated in the COSS stakeholder process to ensure cost causation is thoroughly examined across all functions, align cost causation with allocation factors, and avoid resisting COSS methodology improvements for rate stability, advocating for alignment with Bonbright principles and recognizing the evolving system structure.

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

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

DSM Models Cur rent Method ( Compliance Fili ng) MEU 100% 6 Customer nefit Costs the total) Participating Class Benefit Total nefit Costs the total) Participating Class Benefit Total Difference

AI summary The text provides a table related to DSM models, focusing on benefit costs and participating class benefits under different scenarios, though the content is incomplete and lacks context for full analysis.

Demand line loss Demand losses were calculated for each customer class across all network segments using the following formula : Segment Demand loss = Class contribution to coincident demand x Segment demand loss % - Secondary demand losse...

AI summary The document discusses the calculation of demand line losses for each customer class across network segments using specific formulas and models, including CYME for distribution and PSS/E 8760 for transmission. Sensitivity analysis on marginal losses showed inconsistent results for smaller rate classes.

Total demand losses = ∑ Segment Demand Losses Class MWh Sales Non-Coincident Demand Coincident Demand Demand Loss (kW) Demand Loss % Trans Demand Loss (kW) Dist Demand Loss (kW) Sec Demand Loss (kW) Non-Tech Demand (kW) Residential 5,213,7...

AI summary The text presents a table summarizing demand losses across various customer classes in Nova Scotia, including metrics such as MWh sales, non-coincident and coincident demand, demand loss percentages, and breakdowns of transmission, distribution, and secondary demand losses.

2.3 SASKATCHEWAN SaskPower's rates are generally bundled, but there are exceptions for large industrial customers in certain circumstances. SaskPower's Capacity Reservation Service charges can be considered unbundled rates and it is in the...

AI summary SaskPower's rates are generally bundled, with exceptions for large industrial customers. The company is developing unbundled rates for renewable energy procurement and has introduced an Intra-Provincial Transmission Tariff. The Bary Correction adjusts rates to recover demand-related costs from high-load-factor customers. The Power Corporation Act grants SaskPower exclusive rights to supply and distribute power in Saskatchewan.

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

AI summary The document discusses the allocation of high-voltage transmission costs and battery-related expenses under different scenarios. NS Power initially proposed classifying high-voltage transmission costs based on energy usage but later maintained its position. It also suggests allocating 100% of battery costs to demand, aligning with the cost of service treatment for other assets.

- Session 1: January 18, 2024 - o Two-hour session - o Topics: Initial Session, Introduction to Expert - o Summary: - NS Power introduced its third-party COSS consultant, Elenchus Research Associates Inc. (Elenchus), who provided a backgro...

AI summary NS Power introduced its third-party COSS consultant, Elenchus Research Associates Inc., and outlined its approach to the COSS process. In subsequent sessions, NS Power provided updates on its Integrated Resource Plan (IRP), current COS model, and discussed the draft issues list with stakeholders. The third session focused on reviewing the work plan, timelines, and the impact of Bill 404 on DSM.

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

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

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

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

2026-2027 GRA Direct Evidence Appendix 12B Page 18 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -18- NSP COSS Consultation Report Draft April 25, 2025 • • • DSM rate rider – all DSM costs assigned directly. No system benefit allocatio...

AI summary The document discusses the DSM rate rider and the allocation of DSM costs directly without system benefit allocation, along with the DDA methodology and new line losses. It also includes a section on generation.

7.3.3 ELENCHUS OPINION - The load volumes and active demand control characteristics of PHP are sufficiently - different from other classes that it is appropriate to treat PHP as a separate rate class if - they move above-the-line. NS Power...

AI summary Elenchus argues that PHP should be treated as a separate rate class due to its distinct load volumes and active demand control characteristics. They support NS Power's approach to cost allocation for PHP, emphasizing consistency with other rate classes while accounting for specific load characteristics.

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

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

19 7.6.2 NSP PROPOSED APPROACH - 20 NS Power is proposing to change the weighting of the DSM allocation so the rate rider is - 21 100% of costs incurred for each rate class and the system benefit will no longer be - 22 considered.

AI summary Nova Scotia Power (NSP) is proposing to adjust the weighting of the DSM allocation, making the rate rider cover 100% of costs incurred for each rate class, with the system benefit no longer being considered.

7.6.3 ELENCHUS OPINION - 2 NS Power conducted an analysis that has indicated there is very little system benefit - provided by DSM. [12](#page-108-4) Based on this analysis, Elenchus agrees it is appropriate to remove - 4 the system-benefi...

AI summary Elenchus agrees with NS Power's analysis that there is very little system benefit provided by DSM, and therefore supports the removal of the system-benefit weighting for the allocation of the DSM rate rider.

Nova Scotia Power Inc. Condensed Consolidated Statements of Income (Unaudited) For the Three months ended June 30 Six months ended June 30 millions of dollars 2025 2024 2025 2024 Operating revenues (note 3) $ 436 $ 423 $ 1,035 $ 977 Operat...

AI summary This document presents the condensed consolidated statements of income for Nova Scotia Power Inc. for the three and six months ended June 30, 2025, and 2024. It includes operating revenues, expenses, income from operations, and net income, with specific attention to the fuel adjustment mechanism and demand-side management costs.

"FAM and other deferrals" recognized in the Condensed Consolidated Statements of Income consisted of the following: For the Three months ended Six months ended millions of dollars June 30 June 30 2025 2024 2025 2024 FAM: (Under) over-recov...

AI summary The FAM and other deferrals recognized in the Condensed Consolidated Statements of Income show variations in fuel cost recovery and DSM program costs over the periods of 2024 and 2025. The table outlines amounts for three and six months ended June 30, highlighting over and under-recoveries.

Load Growth through Electrification - Florida has the second highest penetration of EVs in the US - In Nova Scotia, incentives for heat pump adoption are accelerating conversion of home heating from oil to electric

AI summary The text discusses load growth through electrification, highlighting Florida's high EV penetration and Nova Scotia's incentives for heat pump adoption, which are accelerating the shift from oil-based home heating to electric heating.

Demand Driven by Data 2.4% Projected growth in US power demand per year over next 8 years 8%by2030 Total US energy consumption from data centers 100 TWh/year Global electricity consumption growth average 2023 to 2035 10x Amount of energy c...

AI summary The text highlights the rapid growth in power demand, particularly driven by data centers and AI technologies. It projects a 2.4% annual increase in US power demand over the next 8 years, with data centers consuming 8% of total US energy by 2030. It also notes that global electricity consumption is expected to grow 10 times between 2023 and 2035, and that energy consumption from a ChatGPT prompt is 100 times greater than that from a Google Search.

Equity ~$400M per year through DRIP and ATM programs

AI summary The document mentions approximately $400 million per year allocated through DRIP and ATM programs, highlighting potential equity-related initiatives or funding mechanisms.

Robust Growth In Tampa Florida's positive economic outlook paired with record population growth in the region is driving strong demand for Electric and Gas services. 26% Hillsborough County Tampa population growth 2010-2024 2 43% Tampa reg...

AI summary Florida's positive economic outlook and record population growth in the Tampa region are driving strong demand for Electric and Gas services. Hillsborough County has experienced 26% population growth from 2010 to 2024, while the Tampa region's GDP has grown by 43% from 2020 to 2024. Tampa Electric has seen 2% customer growth.

Top 5 Serving the five largest metropolitan areas in Florida Peoples Gas Service Areas 21 Military Installations 16 Seaports 2 Spaceports Electrification and Population Growth Driving Demand in Nova Scotia 3.4% Annual growth rate for Elect...

AI summary The text highlights Nova Scotia's growing demand for electricity driven by electrification and population growth, with key statistics such as a 3.4% annual growth rate for electric heat pump installations and a target of 30% zero-emission vehicle sales by 2030. It also mentions projected population growth rates through 2030 and 2060.

Strong Foundation for Growth at Peoples Gas Largest natural gas distribution company in Florida ~73% of Florida's electricity generation comes from natural gas 1 Top 5 Serving the five largest metropolitan areas in Florida Peoples Gas Serv...

AI summary The document highlights Peoples Gas as Florida's largest natural gas distribution company, serving key areas and infrastructure. It also discusses growth drivers in Nova Scotia, including electrification, population growth, and the increasing adoption of electric heat pumps and zero-emission vehicles.

779 855 406 508 TAMPA ELECTRIC CUSTOMERS (000s) PEOPLES GAS CUSTOMERS (000s) 4.6% CAGR 1.9% CAGR 2019 2024 Hillsborough County population growth expected to outpace that of Florida's over the next 10 years 1 2019 2024 1 Source: Bureau of E...

AI summary The text discusses population growth and electrification trends in Nova Scotia, including a 3.4% annual growth rate for electric heat pump installations and a target of 30% zero-emission vehicle sales by 2030. It also references population growth forecasts and the impact of these trends on energy demand.

Electrification and Population Growth Driving Demand in Nova Scotia 3.4% Annual growth rate for Electric Heat Pump installation (21,000 units per year) 1.1% forecast population growth through 20301 30% of new light-duty vehicle sales in No...

AI summary The document highlights the impact of electrification and population growth on electricity demand in Nova Scotia. It notes a 3.4% annual growth rate for electric heat pump installations and a 1.1% population growth forecast through 2030, with a target of 100% population growth by 2060. Zero-emission vehicle sales are also a focus, with 30% of new light-duty vehicles targeted to be zero-emission by 2030.

Equity ~$400M per year on average through DRIP and ATM programs1

AI summary The document mentions an average of ~$400M per year allocated through DRIP and ATM programs, highlighting significant financial commitments related to equity initiatives.

Well established cost of service regulatory environment •Allowed ROE: 8.75% - 9.25% •Maximum Allowed Equity: 40% - • Approved rider mechanisms allow for the timely recovery of prudently incurred costs: - 〉 Fuel adjustment mechanism allows...

AI summary The regulatory environment in Nova Scotia allows for a return on equity between 8.75% and 9.25% and a maximum allowed equity of 40%. Approved rider mechanisms, such as the fuel adjustment and DSM rider, enable the recovery of prudently incurred costs. The UARB is an independent regulatory body responsible for oversight.

Well-established cost of service regulatory environment - Allowed ROE: 8.75% - 9.25% - Maximum Allowed Equity: 40% - Approved rider mechanisms allow for the timely recovery of prudently incurred costs: - 〉 Fuel adjustment mechanism (FAM) a...

AI summary The document outlines the regulatory environment for cost of service in Nova Scotia, including an allowed ROE range of 8.75% to 9.25%, a maximum allowed equity of 40%, and rider mechanisms for recovering prudently incurred costs. The UARB is described as an independent regulatory body.

fuel ¢/kWh 4.332 4.835 0.502 11.6% Subtotal 12.452 12.749 0.297 2.4% FAM AA ¢/kWh 0.000 0.000 0.000 0.0% FAM BA ¢/kWh 0.156 0.156 0.000 0.0% Subtotal 0.156 0.156 0.000 0.0% DSM PCR ¢/kWh 0.353 0.353 0.000 0.0% DSM BA ¢/kWh 0.004 0.004 0.00...

AI summary The document details rate schedules for 2025 and 2026, showing increases in fuel and non-fuel related costs, FAM (Fuel Adjustment Mechanism), DSM (Demand Side Management), and SCRR (System Cost Recovery Rider) components. Variances between years are highlighted, with overall rate increases and specific line-item changes.

Outdoor Recreational Lighting Tariff Energy Charges Base cost of fuel ¢/kWh 7.650 8.441 0.791 10.3% Non-fuel ¢/kWh 3.615 3.492 -0.124 -3.4% Subtotal 11.265 11.932 0.667 5.9% FAM AA ¢/kWh 0.000 0.000 0.000 0.0% FAM BA ¢/kWh 0.156 0.156 0.00...

AI summary The Outdoor Recreational Lighting Tariff details energy charges, including base fuel and non-fuel costs, with changes in percentages. The Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DSM PCR) are included in the tariff structure, showing no change in rates between periods.

REDACTED 2026-2027 GRA SR-02 Attachment 1 Page 7 of 175 2024 Load Forecast Report REDACTED 1 large customers to develop an energy forecast for the province, also referred to as the Net 2 System Requirement (NSR). 3 4 Compared to the 2023 L...

AI summary The 2024 Load Forecast Report indicates higher near-term growth in energy demand due to new customer additions and higher average use, but long-term growth is tempered by factors like Renewable to Retail (RTR) market sales, DSM initiatives, and increased solar installations, leading to a forecasted average annual increase of 0.2 percent.

The Fuel Adjustment Mechanism (FAM) and the Actual Adjustments (AA) or Balancing Adjustments (BA) is proposed to continue to operate in the normal course during 2026 and 2027, with new Base Cost of Fuel (BCF) amounts set for 2026 and 2027....

AI summary The Fuel Adjustment Mechanism (FAM) and related adjustments are proposed to continue in 2026 and 2027 with updated Base Cost of Fuel (BCF) amounts. The Demand Side Management Rider is also proposed to continue with changes to its calculation method.

2026-2027 General Rate Application (M12451) NSPI Responses to Bates White Information Requests 1 Request IR-3: 13 rates for base cost of fuel for the total FAM classes, smoothed is $881.9 million. The 14 Base Charge in W348 is indicated at...

AI summary The text discusses responses to information requests regarding the 2026-2027 General Rate Application (M12451) by NSPI. It outlines smoothed amounts for the base cost of fuel under the FAM classes and references the Base Charge in W348, prior to adjustments for various riders. The questions focus on the relationship between different smoothed amounts, the source of data, and the explanation for the drop in the 2027 forecast base cost of fuel compared to 2026.

13 table: Year Estimated Peak (MW) Estimated Energy (MWh) 2020 0 2,122 2021 0 3,899 2022 1 7,347 2023 2 12,894 2024 4 23,732 14 15

AI summary The table presents estimated peak demand and energy usage from 2020 to 2024, showing a steady increase in both metrics over time. These figures likely relate to electricity demand forecasting or resource planning.

2025 Load Forecast Report Redacted 31 7.3 Other Industrial Rate Classes 69 32 7.4 Municipal 71 33 8.0 SYSTEM LOSSES AND UNBILLED SALES 73 34 9.0 NET SYSTEM REQUIREMENT 74 35 10.0 PEAK DEMAND 76 36 10.1 Analysis of 2024 Actual Peak 83 37 10...

AI summary The document outlines the structure of the 2025 Load Forecast Report, including sections on system losses, net system requirements, peak demand analysis, solar impact, and sensitivity analysis. It also references the Evergreen IRP Comparison and includes various rate classes and municipal data.

2025 Load Forecast Report Redacted - 1 Compared to the 2024 Load Forecast, the 2025 Load Forecast shows increased net system - 2 requirement in the near term due to a change in forecast for Renewable to Retail (RTR) sales. - 3 Mid- to long...

AI summary The 2025 Load Forecast Report indicates increased near-term net system requirements due to changes in Renewable to Retail (RTR) sales, but lower mid- to long-term growth due to factors like reduced EV sales, increased RTR sales, and behind-the-meter solar. Long-term energy sales are also expected to decrease due to DSM initiatives and natural energy efficiency improvements.

11 Figure 1: Historical and Predicted Annual Net System Requirement 12 13 10 14 In addition to annual energy requirements, NS Power forecasts system peak demand. Customer 15 growth, electrification of heating and increased EV sales will in...

AI summary NS Power forecasts annual energy requirements and system peak demand, noting that customer growth and electrification will increase peak demand, while demand-side management (DSM) and demand response (DR) activities will reduce it. The peak forecast is similar to 2024 despite the delayed start of RTR.

1 2.0 INTRODUCTION 2 - 3 NS Power develops an annual forecast of energy sales and peak demand requirements which assess - 4 the effects of end-use and economic factors on the future power system load and load shape. The - 5 forecast is a f...

AI summary The document discusses the 2024 Load Forecast Report by NS Power, which was reviewed by the NSUARB through a paper hearing process. Intervenors including the Consumer Advocate and EfficiencyOne provided input, and the Board encouraged NS Power to refine its forecast, particularly the residential model, in light of population growth and housing policies.

1 Figure 13: Yearly Change in Customers, Population, and Housing Completions 2 3 4 Comparing actual customer additions with the previous housing completion forecasts shows that 5 the Conference Board of Canada indicator follows the same tr...

AI summary The document discusses the adjustment of housing completion forecasts by the Conference Board of Canada, which underestimated actual customer additions by 20% over the past five years. A +20% adjustment is applied to the forecast for 2025–2030, while beyond 2031, the forecast remains unadjusted.

1 4.4.2 Water Heaters 2 3 NS Power anticipates that some customers who convert their oil heating systems to heat pumps 4 will also convert their hot water supply to electric hot water tanks because of the annual operating 5 savings. Growth...

AI summary NS Power anticipates increased adoption of electric water heaters as customers switch from oil heating to heat pumps, with saturation expected to reach 90% by 2035. A joint program with E1 involves directly controlling water heaters for system benefits. Despite a rebate, uptake of heat pump water heaters remains low, though efficiency improvements are expected over time.

2025 Load Forecast Report Redacted 1 EVs on the road by 2035, mostly made up of LDVs compared to a forecast of 200,000 vehicles by 2 2035 in the 2024 Load Forecast. 3 4 The impact of EVs on residential energy sales and peak (reflecting at-...

AI summary The 2025 Load Forecast Report analyzes the impact of EVs on residential energy consumption using AMI data from 2023 and 2024. EV owners were divided into 'new EV owners' and a 'control group' to estimate the energy impact of at-home EV charging. The report estimates an annual load increase of 3820 kWh per customer from EV charging, with the greatest monthly impact in winter and a secondary peak in summer.

1 4.4.5 New Technologies 2 3 The 2025 Load Forecast does not assume a significant amount of distributed solar/battery storage 4 combinations or storage only deployments. The cost of home batteries is still relatively expensive, in the rang...

AI summary The 2025 Load Forecast does not assume widespread adoption of distributed solar/battery storage due to high costs, which make gas generators a more cost-effective alternative for backup power. Vehicle-to-Grid (V2G) technology is still in development, and while batteries can support the grid, their current high costs limit their deployment. Future cost reductions and technological advancements may change this dynamic.

1 Figure 33: Potential Peak Impacts from Batteries Technology Residential Share (%) 50% 25% 10% 5% Battery Peak Impact - No 0 0 0 0 Control (MW) Battery Peak Impact - (1,403) (702) (281) (140) Optimal DR Control (MW) 2

AI summary Figure 33 presents potential peak impacts from batteries under different residential share scenarios, showing the impact of battery peak control and optimal DR control in megawatts for varying percentages of residential participation.

11 4.4.7 Commercial and Industrial Growth 12 13 The commercial and industrial sectors are projected to see targeted growth as a result of the federal 14 and provincial push to net-zero emissions and the resulting electrification programs d...

AI summary The commercial and industrial sectors are expected to grow due to federal and provincial efforts toward net-zero emissions, driven by electrification programs that reduce energy usage and carbon emissions. These programs include converting heating loads to electricity, adopting electric cooling technologies, and exploring electrification for industrial processes. Large industrial customers are assessed individually to facilitate electricity use while benefiting the system, such as through the interruptible rider.

19 The elasticity values have changed significantly from the prior report, and although the Daily Price 20 Elasticity for the TOU rate is significantly higher than that used in the load forecast, the Inter 21 Period Substitution values are...

AI summary The text discusses changes in elasticity values from a prior report, noting that while the Daily Price Elasticity for the TOU rate has increased, the Inter Period Substitution values remain similar. The impact of price elasticity on sales is considered moderate compared to other factors like DSM and EVs. A reference is made to a load forecast report and an evaluation of a time-varying pricing pilot program.

1 4.5.1 Demand Side Management 2 3 Demand Side Management (DSM) and conservation plans continue to play a role in the use of - 4 electricity in Nova Scotia, and the forecast takes the projected energy and demand savings into - account. Bet...

AI summary This section discusses the role of Demand Side Management (DSM) in Nova Scotia's electricity use and the challenges of double-counting DSM impacts in forecasting models. The forecast uses DSM data from E1's supply agreement and potential study, and adjusts for DSM effects by incorporating historical savings as a load modifying variable in the regression model.

2025 Load Forecast Report Redacted 1 provided they have similar characteristics (historical trend, potentially included in other inputs, 2 and some information about future impact). 3 4 In the Residential model, adding the historic DSM imp...

AI summary The 2025 Load Forecast Report discusses the inclusion of historical demand-side management (DSM) data in residential and commercial/industrial load forecasting models. Including DSM improves model accuracy, with coefficients indicating the proportion of DSM savings already captured by other variables.

1 Figure 40: Annual Forecast Residential DSM Savings (incremental) Year Forecast Residential DSM savings (GWh) Forecast Commercial DSM savings (GWh) Forecast Industrial DSM savings (GWh) DSM captured by Residential end use forecast (GWh) D...

AI summary The document presents a table forecasting annual residential, commercial, and industrial DSM savings from 2025 to 2035, including DSM captured by end use and adjustments with coefficients. These forecasts are used to analyze energy efficiency initiatives and their impact on energy consumption.

1 5.0 RESIDENTIAL SECTOR 2 - 3 The Residential sales forecast is generated as the product of a residential average use forecast and - 4 a customer count forecast. The residential average use model is specified using a SAE model - 5 structu...

AI summary The residential sales forecast is based on average use and customer count forecasts, with the average use modeled using a SAE structure. Growth in residential sales between 2023 and 2024 was driven by work-from-home activity, new customers, and increased heat pump usage. Projections for EVs and residential solar are also included in the load forecast.

2025 Load Forecast Report Redacted 1 Weather adjusted sales in 2024 were very close to forecast, though the warm weather reduced sales 2 in the class by 104 GWh. 2026 and 2027 are expected to decline as a result of load migrating to 3 the...

AI summary The 2025 Load Forecast Report indicates that weather-adjusted sales in 2024 were close to forecast, with warm weather reducing sales by 104 GWh. Load is expected to decline through 2033 due to migration to the RTR market and increased behind-the-meter solar adoption, though EV load may increase sales after 2033. DSM and efficiency improvements will decrease sales, while new customers and electric heating will increase them.

5 Figure 46: Residential Sales Components by Year Year Regression Model Output (GWh) New Cust. (GWh) Hybrid Adjust. (GWh) Solar Impact (GWh) EV Impact (GWh) RTR Sales (GWh) DSM Adjust. (GWh) Total Sales (GWh) Total Res. DSM 29(GWh) DSM cap...

AI summary Figure 46 presents residential sales components by year, including regression model output, new customer impact, hybrid adjustments, solar and EV impacts, RTR sales, and DSM adjustments. The data spans from 2025 to 2035, showing trends in energy consumption and demand-side management impacts.

1 6.1 Small General Service 2 3 Historical and forecast Small General service loads are shown in Figure 49 . Small General service 4 load shows an average annual increase of 1.5 percent compared to an increase of 1.8 percent per 5 year in...

AI summary The document discusses historical and forecasted Small General Service loads, noting a 1.5% annual increase compared to 1.8% in the 2024 Load Forecast. Commercial electrification of heating is offset by DSM and decreased intensity forecasts for ventilation, lighting, and miscellaneous end uses. The total load increase from 2025 to 2035 is projected to be 16.3%.

2025 Load Forecast Report Redacted 1 as well as the commercial energy impact of the hybrid heating scenario. Increased space heating 2 will continue to be offset by DSM programs as well as increased efficiency of the lighting and 3 miscell...

AI summary The 2025 Load Forecast Report discusses the impact of hybrid heating scenarios and DSM programs on commercial energy use, noting a drop in sales due to shifting to the RTR market and increased solar generation by 2035.

7 Figure 50: Historical and Forecast Annual General Demand Sales 8 9 10 Please refer to Appendix B for tables with a detailed breakdown of the changes from 2025 to 11 2035. Total change between 2025 and 2035 is a decrease of 7.3 percent. 12

AI summary Figure 50 illustrates historical and forecast annual general demand sales, showing a projected 7.3 percent decrease in total demand between 2025 and 2035. A detailed breakdown of these changes is provided in Appendix B.

2025 Load Forecast Report Redacted - 1 production levels or equipment changes help inform energy requirement expectations. In the - 2 absence of survey or publicly available information, load levels are forecast to be flat before the - 3 i...

AI summary The 2025 Load Forecast Report indicates that load levels are expected to remain flat before the impact of any DSM activities. Survey results show mixed responses, with some customers expecting increased consumption, particularly driven by institutional facilities like hospital expansions.

1 7.0 INDUSTRIAL AND MUNICIPAL SECTORS 2 3 The forecast models for the Small Industrial and Medium Industrial classes are econometric-based 4 models (i.e. dependent on economic variables). Provincial manufacturing GDP is used as the 5 prim...

AI summary The forecast models for Small and Medium Industrial sectors are econometric-based, using provincial manufacturing GDP and employment data. Monthly sales data is used to align industrial models with residential and commercial models, enabling end-use-based peak forecasting. Supporting data is provided in Attachments 8 and 9.

12 7.3 Other Industrial Rate Classes 13 14 Other Industrial rate classes include Large Industrial, Large Industrial Interruptible, Generation 15 Replacement and Load Following, One-Part Real Time Pricing, Shore Power, and the Extra Large 1...

AI summary The document outlines various industrial rate classes, including Large Industrial and Extra Large Industrial Active Demand Control, and discusses how load forecasting is conducted using customer surveys and historical sales data for these rate classes.

7 Figure 59: Forecast Components GWh Res Comm Ind Other Losses NSR 2025 Forecast 5,289 3,135 2,258 148 777 11,607 Model 303 251 38 -77 28 544 New Customers 403 36 439 Solar -622 -252 -875 EV 418 290 708 C&I Electrification 9 22 31 Large Cu...

AI summary Figure 59 presents forecast components for energy consumption and production in 2025 and 2035, including contributions from residential, commercial, industrial, and other sectors, as well as losses and net system requirements (NSR). It includes adjustments from various factors such as solar, EV, and demand-side management (DSM).

1 10.0 PEAK DEMAND 2 3 The total system peak is defined as the highest single hourly average demand experienced in a - 4 year. It includes both firm and interruptible loads. Due to the weather-sensitive load component - 5 in Nova Scotia, t...

AI summary The document outlines the methodology used by NS Power for forecasting peak demand, including the use of end-use data and the impact of factors like EV charging and demand response (DR) programs. It also notes the shift in DR capacity estimates from 2025 to 2028 and the ongoing use of an effective load carrying capacity (ELCC) of 48%.

2025 Load Forecast Report Redacted 1 measured results from NS Power's (CPP and TVP) and E1's current demand response programs." 31 2 3 4 Annual DR totals by program are provided in Figure 60 . 5

AI summary The document mentions measured results from NS Power's demand response programs, including CPP and TVP, and references annual DR totals by program in Figure 60.

2025 Load Forecast Report Redacted Efficient Product Installation Program. 803 controllers were installed in 2024. 33 1 E1 integrated this 2 pilot project into the Eco Shift program for the 2024/2025 season. 3 4 NS Power is also working wi...

AI summary The document discusses the Efficient Product Installation Program and the Eco Shift pilot, highlighting the installation of controllers and the expansion of DR programs. It outlines the results from the 2023/2024 season and ongoing evaluations for the 2024/2025 season. The impact of these programs on load forecasts is noted, with DR capacity expected to influence future projections.

5 Figure 61: Peak Regression Coefficients Coefficient Value Description Weekdays 30.5 Peaks that occur on weekdays will be 30.5MW higher than those on weekends, all else being equal. Wind 2.7 Average daily windspeed will add 2.7MW for ever...

AI summary Figure 61 presents peak regression coefficients that indicate how various factors influence electricity demand peaks. Weekday peaks are 30.5MW higher than weekend peaks, wind speed adds 2.7MW per km/hr, and a 1-degree Celsius drop in temperature over a 12-hour lag increases the peak by 28MW.

1 Figure 62: Historical and Forecast System Peak (no DR) - 2 3 - 4 As indicated in Figure 63 , the firm peak (system peak less interruptible and DR) is expected to - 5 increase by 1.1 percent annually. 6

AI summary Figure 62 shows historical and forecast system peak without demand response. The firm peak, calculated as system peak less interruptible and DR, is expected to increase by 1.1 percent annually, as indicated in Figure 63.

1 Figure 63: Historical and Forecast Firm Peak (including DR) 2 3 4 Forecast peak values, firm peak and interruptible peak information can be found in Appendix A . 5 6 Normalizing the firm peak for temperature, wind and weekday/weekend (an...

AI summary The document discusses historical and forecast firm peak data, including demand response (DR), and notes that normalizing for temperature, wind, and weekday/weekend factors improves the alignment between historical trends and forecasts. Appendix A contains detailed peak information.

1 Figure 64: Weather-Normalized Firm Peak (including DR) 4 Figure 65 below shows the breakdown of the peak forecast by the various components.

AI summary The text references two figures, Figure 64 and Figure 65, which illustrate weather-normalized firm peak demand, including demand response, and the breakdown of peak forecast by components, respectively.

7 Modeled Peak (MW) Res Heat (MW) EV (MW) DR (MW) Hybrid (MW) C&I Elect. (MW) Large Cust. (MW) DSM (MW) Firm Peak (MW) Inter. Cust. (MW) System Peak (MW) 2025 2,180 2 3 -4 - 0 96 -11 2267 132 2,403 2035 2,455 17 121 -37 -48 4 105 -114 2502...

AI summary The table provides modeled peak demand forecasts for various load categories in 2025 and 2035, including residential heating, electric vehicles, demand response, and others, with values in megawatts (MW). It also includes a scenario for 2035 with maximum non-coincident EV peak demand.

2025 Load Forecast Report Redacted 1 contributions, and finally DSM. As discussed in Section 4.4 , the EV contribution to peak is 2 expected to be partially mitigated via utility managed charging. The firm peak assuming the 3 current non-c...

AI summary The 2025 Load Forecast Report discusses the impact of electric vehicles (EVs) and space heating on peak load, noting that EVs are expected to add approximately 60 MW to the peak in 2035, while space heating is projected to reduce peak demand by around 46 MW in the same year.

17 Figure 66: Forecast Peak Variance vs Actuals MW 2024 Forecast Peak 2,365 Interruptible -57 Weather (-10.8°C 12hr lag avg) -101 Wind (7.4 km/h daily avg) -31 Morning peak impact (estimated) -121 Unexplained +33 2024 Actual Peak 2,088 18

AI summary Figure 66 compares forecasted and actual peak demand for 2024, highlighting factors such as interruptible load, weather, wind, morning peak impact, and unexplained variance. The forecast peak was 2,365 MW, while the actual peak was 2,088 MW.

1 11.0 SENSITIVITY ANALYSIS 2 - 3 The sales and peak forecasts are fundamentally uncertain and depend on many variables, including - 4 economics, weather, adoption of distributed generation, electricity rates and DSM. Although each - 5 of...

AI summary The sensitivity analysis discusses the uncertainty in load forecasts, which are influenced by factors like economics, weather, distributed generation, and DSM. A P10/P90 probability analysis using Monte Carlo simulations was developed in 2017 to estimate future load distribution, showing a range of 480-636 GWh over 10 years, mainly impacted by weather and economic factors.

Table A2: Coincident Peak Demand - 2025 NS Power Forecast Peak Forecast Year Interruptible Contribution to Peak Demand Response (reduction in Firm Contribution to Peak Net System Peak Growth Temp at Peak 12hr Lag Temp Notes (MW) Firm Peak...

AI summary Table A2 presents the forecasted coincident peak demand for NS Power from 2015 to 2035, including contributions from interruptible and firm demand, net system peak, growth rates, and temperature data. The forecast shows increasing trends in peak demand and temperature, with notes on specific dates and conditions for each year.

2025 Load Forecast Report Appendix B Page 5 of 34 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA BW IR-7 Attachment 1 Page 102 of 168 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The AvgEESavings term captures E1's DSM p...

AI summary The document discusses the AvgEESavings term and the regression coefficient b4 used to assess DSM activity's impact on load, noting its negative sign indicates load reduction. It also describes the use of binary variables to account for anomalies in billing data and the impact of the pandemic on residential load, with the latter variable removed from the forecast period.

Residential Load – Post Regression (GWh) Existing New EVs Solar RTR Hybrid Res Res Total DSM Customer Cust. DSM Sales Res captured Average Use Load Adjust DSM by end from ment (at the uses Regression meter) Model (kWh/year) 2025 10,475 62...

AI summary The table presents residential load data post-regression for 2025 and 2035, including existing and new customers, EVs, solar, and other factors. It shows changes in load and DSM captured by end uses, with percentages indicating growth or decline in various categories.

Small General 2025-2035 Reconciliation The Small General Demand customer forecast model is constructed like the residential model (including heat pump programs inside the SAE model). Adjustments done outside the regression include estimate...

AI summary The Small General 2025-2035 Reconciliation discusses the construction of the Small General Demand customer forecast model, which is similar to the residential model and includes heat pump programs within the SAE model. Adjustments outside the regression account for other commercial and industrial growth programs, PV, EV, RTR, and DSM. Historical variables use flat scaling factors for easier comparison.

Small General Load – Post Regression (GWh) Load from Regression Model EVs Solar RTR SG DSM adjustment Small Gen Sales (with DSM) Total Res DSM (at the meter) DSM captured by end uses 2025 378 2 (1) - (3) 374 (6) (3) 2035 432 60 (26) (3) (2...

AI summary The table presents projected small general load data for 2025 and 2035, including adjustments for EVs, solar, RTR, and DSM. Load from the regression model is used to calculate small general sales, incorporating various factors such as average use, customer count, and DSM adjustments.

The load from the regression model is calculated as Small Gen Average Use (14,020 kWh/customer in 2025, 14,505 kWh/customer in 2035) x number of customers (26,981 in 2025, increasing to 29,804 in 2035).

AI summary The load from the regression model is calculated based on the Small Gen Average Use and the number of customers, with values provided for 2025 and 2035.

General Demand 2025-2035 Reconciliation The general demand class, which makes up the largest portion of the commercial sector, is forecast as gross total sales rather than average use as is the case in the small general and residential cla...

AI summary The general demand class in the commercial sector is forecast based on gross total sales, unlike the small general and residential classes. A flat scaling factor is used to simplify interpretation of regression coefficients, with adjustments for EV load, PV, RTR, Hybrid, and DSM.

General Demand Load – Post Regression (GWh) Load from Regression Model Model alignment RTR Hybrid Impact EV Solar GD DSM Adjustment Gen Sales (with DSM) Total GD DSM (at the meter) DSM captured by end uses 2025 2,359 (14) - - 7 (10) (22) 2...

AI summary The table presents General Demand Load data post-regression for 2025 and 2035, showing load from the regression model, model alignment, RTR, hybrid impact, EV, solar, and DSM adjustments. It highlights changes in load, with percentages indicating increases and decreases across different categories.

General Demand Sales –Regression XHeat XCool XOther Binaries ARMA Sales (GWh) 2025 564,737 127,070 1,786,367 (116,647) (2,279) 2,359,249 2035 749,648 151,266 1,808,747 (116,647) - 2,593,014 Change 7.8% 1.0% 0.9% 0.0% 0.1% 9.9% to load Sale...

AI summary The table presents projected demand sales for heating, cooling, and other loads from 2025 to 2035, showing an overall increase of 9.9% in total sales. Heating demand is expected to rise by 7.8%, while cooling demand increases by 1.0%. Other loads and binaries show minimal changes.

General Demand Input Variables – WtXHeat Intensity Econ + Regression Structural Heating HeatUse Coefficient Scaling Total Variable Factor Xheat 2025 560,995 1.34 0.751 564,737 560,995 2035 696,415 1.43 0.751 749,648 696,415 Change 25.8% 6....

AI summary The table presents demand input variables for heating, including intensity, economic factors, regression coefficients, and scaling factors for the years 2025 and 2035. It shows a projected increase in heating demand and associated variables.

General Demand Input Variables – XCool Intensity Econ + Regression Structural Cooling CoolUse Coefficient Scaling Total Variable Factor Xcool 2025 315,673 1.51 0.719 0.370 127,070 2035 307,496 1.85 0.719 0.370 151,266 Change -3.2% 22.2% 0....

AI summary The document presents a table analyzing cooling demand input variables for XCool, showing intensity, economic factors, regression coefficients, scaling factors, and total demand for the years 2025 and 2035. The data highlights a decrease in cooling intensity and an increase in CoolUseVariable, leading to a 19% increase in total XCool demand by 2035.

General Demand Input Variables – XOther Intensities Reg Vent Water Cook Refrig Light Office Misc Struct Other Coeff Scaling Total Heat Use Var Factor XOher 2025 108,261 14,274 17,656 192,984 456,715 122,313 304,107 15.27 1.069 0.090 1,786,...

AI summary The document presents a table analyzing demand input variables for the year 2025 and 2035, showing changes in various load components such as ventilation, water heat, cooking, and lighting. The table includes values, percentages, and scaling factors to represent demand changes over time.

Combined Model for Commercial and Industrial DSM Coefficient NonResSalesm = b1×NonResEESavingsProfiledm + b2×GenWtXHeatm + b3×GenWtXCoolm + b3×GenWtXOtherm + b4×NonResCustomersm+ MBin.Feb18m+ MBin.Oct22 Weighted X variables from the Genera...

AI summary The Combined Model for Commercial and Industrial DSM Coefficient uses weighted variables from the General Service model and binary variables to explain non-residential sales trends, incorporating historical DSM savings, customer numbers, and billing issues.

Variable Coefficient StdErr T-Stat P-Value MSales.EESavingsProfiled -0.433 0.166 -2.616 1.01% MStructGen.WtXCool 0.552 0.051 10.771 0.00% MStructGen.WtXHeat 0.906 0.041 22.084 0.00% MStructGen.WtXOther 0.976 0.328 2.976 0.36% MSales.NonRes...

AI summary The table presents statistical analysis of various variables related to energy sales and demand-side management (DSM). The coefficient on the EESavings variable indicates the amount of DSM required to explain historical sales trends beyond changes in underlying end-uses.

2025 Load Forecast Report Appendix B Page 32 of 34 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA BW IR-7 Attachment 1 Page 129 of 168 REDACTED (CONFIDENTIAL INFORMATION REMOVED) In this way, ResOtherm (and SmlOtherm an...

AI summary The text discusses the use of variables in energy load modeling, including non-weather dependent factors and DSM activity. It also describes how load requirements are normalized and mentions the inclusion of binaries to account for billing issues and improve model fit.

Peak Model Fit As seen in the figure below (and in the model statistics above), this approach produces a good fit with historical data. Although it was not possible to produce a peak model with an explicit peak DSM variable (like the Resid...

AI summary The peak model fit is discussed, showing a good alignment with historical data. While a direct peak DSM variable was not included due to insignificant parameters, the indirect effects of energy-related DSM from historical data are reflected in the peak model. The relationship between DSM for peak and energy savings is assumed to carry over similar DSM effects into the peak forecast.

REDACTED 2025 Load Forecast Report Appendix D Page 4 of 8 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA BW IR-7 Attachment 1 Page 144 of 168 REDACTED (CONFIDENTIAL INFORMATION REMOVED) These distributions are shown in...

AI summary The document presents energy and peak load distributions before the impact of demand-side management (DSM), with figures highlighting the 10th and 90th percentiles of energy distribution and peak load across residential, commercial, and small and medium industrial sectors.

REDACTED 2025 Load Forecast Report Appendix D Page 5 of 8 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA BW IR-7 Attachment 1 Page 145 of 168 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 8. From these annual forecast dis...

AI summary The document discusses probabilistic load forecasts and their sensitivity to variables like HDD. It highlights the asymmetry in peak forecast distributions due to the use of maximum monthly HDD values, which creates a skewed distribution when calculating annual peak demand.

REDACTED 2025 Load Forecast Report Appendix D Page 8 of 8 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA BW IR-7 Attachment 1 Page 148 of 168 REDACTED (CONFIDENTIAL INFORMATION REMOVED) In terms of relative magnitude of...

AI summary The document highlights that demand-side management (DSM) has the largest impact on energy and peak demand, while solar, electric vehicles (EVs), hydrogen facilities, and batteries also significantly influence energy and peak demand. Figure D8 illustrates these relative impacts.

Figure D8: Relative Impact of Inputs Item 2025 Energy (GWh) 2025 Peak (MW) 2035 Energy (GWh) 2035 Peak (MW) Included in Forecast DSM (base case) -150 -26 -1456 -261 Solar PV -148 0 -1023 0 EV (current forecast) 32 5 740 109 Other Possible...

AI summary Figure D8 shows the relative impact of various energy inputs on energy demand and peak load for 2025 and 2035, including the effects of demand-side management, solar PV, EVs, hydrogen production, and battery storage. The impact of hydrogen facilities on NS Power's system requirements is still under evaluation.

Changes From 2024 Input Update New Residential Load New customer average load assumption updated using AMI data and customer segmentation New Residential Customers Review of Conference Board housing completions forecast EV EV average load...

AI summary This section outlines changes from 2024, including updates to load assumptions for new residential customers, EV load and peak contribution, solar generation, RTR load forecasts, and the removal of COVID-related variables from forecasts.

New Residential Customers - New customers in the residential class are forecast using Conference Board of Canada's (CBoC) forecast for housing completions for single family and multi family units. Canadian Mortgage Housing Corporation data...

AI summary The forecast for new residential customers in Nova Scotia uses the Conference Board of Canada's housing completion data, adjusted due to an underestimation of additions by around 20% compared to actual changes in customer numbers from 2025 to 2030.

EV Load - With the removal of both federal and provincial EV incentives, the forecast for EV sales has been adjusted downward compared to 2024 (around 40K less EVs on the road by 2035). - Using AMI data from 2023 and 2024, the contribution...

AI summary The removal of federal and provincial EV incentives has led to a downward adjustment in EV sales forecasts, resulting in a lower number of EVs on the road by 2035. Analysis using AMI data shows an increase in annual EV energy consumption but a decrease in peak load per vehicle.

NON-CONFIDENTIAL 1 Request IR-50: 2 3 Reference: N-6 - 2026-2027 GRA Direct Evidence Appendix 7C Page 51-52 of 58 4 - 5 Per N-6, (Appendix 7C), page 51-52 of 58, we understand that write-offs have decreased from - 6 2024 compliance restate...

AI summary The request seeks clarification on the decrease in write-offs for customer service from 2024 compliance restated and actual figures to the 2026 forecast. NS Power explains that net bad debt expense is calculated using a subset of customer sales and adjusted for AMI savings.

NON-CONFIDENTIAL 1 Request IR-78: 2 3 Reference: FO-13 4 5 Please provide detailed background calculations for the Deferred Charges- DSM Rider 6 Deferral from actual 2024 to proposed 2027. In particular, please provide any support and 7 ca...

AI summary The document contains a request (IR-78) for detailed background calculations related to the Deferred Charges-DSM Rider deferral from 2024 to 2027, specifically regarding adjustments and interest in lines 40-43 of FOR-13 attachment 1. The response refers to Attachment 1 for the information.

11 ($ Million) 2026 2027 AFUDC (13.7) (18.1) FAM Interest 1.0 1.3 DSM Rider Interest 0.0 0.0 Deferred Interest on Assets to be Securitized (12.6) - Renewable to Retail Deferral (0.1) (0.1) Total (25.4) (16.8) 12

AI summary The table presents financial figures for 2026 and 2027, including items such as AFUDC, FAM Interest, DSM Rider Interest, and Renewable to Retail Deferral, with total values for each year.

- 13 Please refer to GT IR-75 for additional detail on how AFUDC is calculated. - 14 Please refer to GT IR-77 for a detailed calculation of FAM interest. - 15 Please refer to GT IR-78 for a detailed calculation of DSM rider deferral intere...

AI summary The text provides references to various regulatory guidelines and documents related to financial calculations, including AFUDC, FAM interest, DSM rider deferral interest, and deferred interest on assets to be securitized.

ORIGINAL LIFE TABLE, CONT. AVG AGE RET 29.0 002 EXPERIENCE ANALYSIS PLACEMENT BAND 1929-2023 EXPERIENCE BAND 1990-2023 AGE AT EXPOSURES AT RETIREMENTS PCT SURV BEGIN OF BEGINNING OF DURING AGE RETMT SURV BEGIN OF INTERVAL AGE INTERVAL INTE...

AI summary The document presents a life table with average age at retirement, exposure data, and retirement rates across various age intervals from 1929 to 2023. This data is used for experience analysis and includes survival percentages and retirement ratios for each interval.

KEY FINDINGS Based on the common themes observed, the following are the key guiding principles to inform the Action Plan and Roadmap Items: - Variable renewable capacity additions are required to meet the 2030 targets. Up to 1500MW of addi...

AI summary Key findings emphasize the need for 1500MW of additional wind capacity and 200MW of solar capacity by 2030. Battery storage, firm capacity, and synchronous condensers are critical for system reliability. The Atlantic Loop project is highlighted as beneficial for reducing costs and emissions, requiring government support. NS Power has updated its 2020 IRP Action Plan and Roadmap based on 2023 modeling.

LOAD AND ENERGY EFFICIENCY Figure 8 highlights the 26-year (NPVRR) with end effects by scenario and provides a comparison between scenarios to assess the impacts of the various load and energy efficiency assumptions modeled. Figure 8: Reso...

AI summary Figure 8 compares various load and energy efficiency scenarios, showing that Hybrid Peak scenarios (E2) offer cost savings compared to base load scenarios (E1). The Base Plus and Modified Mid DSM scenarios show higher NPVs than Base DSM scenarios. NS Power has introduced 'Accelerated Electrification' scenarios, which achieve the same energy goals by 2050 but with faster resource additions.

ITEM 4: DEMAND RESPONSE Demand response (DR) programming and initiatives continue to demonstrate value to the system through a reduction in peak system requirements. The DR Action Plan item supports the continued progression of the demand...

AI summary Demand response (DR) programming and initiatives are shown to reduce peak system requirements, providing value to the system. The DR Action Plan item supports the ongoing development of the demand response strategy and the assessment of additional DR opportunities.

Item 4a: Pilot Programming Continue to progress the Demand Response Strategy via the existing pilot programming, targeting the expansion of the programming to 75MW of nameplate capacity, for deployment by 2025.

AI summary The document recommends continuing to advance the Demand Response Strategy through existing pilot programs, with the goal of expanding to 75MW of nameplate capacity by 2025.

Item 4b: Hybrid Peak Electrification Scenario Further assess the value of the hybrid peak building electrification scenario based on the outcomes of the evergreen IRP. This will include development of program cost estimates and validation...

AI summary The document discusses the evaluation of a hybrid peak building electrification scenario, incorporating program cost estimates and savings validation. NS Power will use insights from other North American utilities that have implemented similar programs.

ITEM 5: AVOIDED COSTS OF DSM NS Power will update avoided costs of DSM based on the evergreen IRP in collaboration with the DSMAG, targeting completion before the end of 2023.

AI summary NS Power plans to update the avoided costs of Demand Side Management (DSM) in collaboration with the DSMAG, aiming to complete the update before the end of 2023, based on the evergreen Integrated Resource Plan (IRP).

GLOSSARY The modeling scenarios and their descriptions can be accessed here. For additional definitions, please see the following glossary of terms. - Reliability Tie : a second 345 kV AC transmission line between Onslow NS and Salisbury N...

AI summary The glossary defines key terms related to electricity transmission and generation, including the Reliability Tie, Atlantic Loop, Variable Renewable Energy, and others. It also references the Modified Mid DSM (MDSM) plan from the 2020 Integrated Resource Plan (IRP).

3 Nova Scotia Power Asset Management Framework NS Power's Asset Management Framework encompasses all elements of its Asset Management approach, including tools, people, and processes. It provides a structure whereby asset "mission" (what i...

AI summary NS Power's Asset Management Framework includes tools, people, processes, and integration with enterprise-wide initiatives such as climate change planning, load growth, renewable integration, and demand-side management. It is aligned with ISO 55000 and the IAM model, with the EAM division leading these efforts.

3.2.1 The System Planning & Grid Integration Division The System Planning & Grid Integration division (hereafter referred to as the System Planning team) coordinates and executes mid- and long-term system modelling. These models inform the...

AI summary The System Planning & Grid Integration Division is responsible for mid- and long-term system modelling, including the 10-year System Outlook and Integrated Resource Plan. It coordinates with stakeholders and considers factors like demand-side management and environmental limitations. The team also performs near-term planning studies and collaborates with EAM functions to ensure asset capabilities are considered.

Appendix "A" GRA Element Settlement Terms Capital Structure a) An equity thickness of 40% for rate setting purposes will be retained. DSM Rider a) The DSM Rider will be amended as set out in Appendix "C". NS Power will make best efforts to...

AI summary The document outlines settlement terms related to capital structure, the DSM Rider, and the Weather Normalization Mechanism. It retains a 40% equity thickness for rate setting, amends the DSM Rider, and removes the request for approval of the Weather Normalization Mechanism while agreeing to participate in an information session.

APPLICABILITY This schedule applies to all electric rate classes with the exception of the Wholesale Market Non-Dispatchable Supplier Spill Tariff, the Load Retention Tariff, and the Extra Large Industrial Active Demand Control Tariff. For...

AI summary This schedule applies to most electric rate classes, excluding specific tariffs. For customers in Wholesale or Renewable to Retail markets, costs related to electricity efficiency and conservation activities are directly billed on their energy bills, as if served by NS Power under its bundled service offerings.

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

AI summary The Program Cost Recovery (PCR) encompasses all estimated costs for the upcoming year for the Approved DSM Plan, including planning, development, implementation, and administrative expenses. It is calculated using the cost allocation methodology outlined in Schedule B of the tariff.

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSUAREB-approved DCRR shall be placed into effect with bills rendered on and after the effective date...

AI summary The Balance Adjustment (BA) is updated annually and at the end of each Approved DSM Term. The NSUAREB-approved DCRR is implemented with bills rendered after the effective date of the change.

2025 DSM Cost Recovery Rider Charges Effective: January 1, 20265January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Ja...

AI summary The document outlines the 2025 Demand Side Management (DSM) Cost Recovery Rider (DCRR) charges, including Program Cost Recovery (PCR) and Balance Adjustment (BA), effective from January 1, 2025, to December 31, 2025. It also explains how the Balance Adjustment for 2023 will be calculated and applied over the 2027-2031 term.

The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service...

AI summary The document outlines the Approved DSM Term, which refers to the full DSM Plan period in effect, such as 2023-2026 or 2027-2031. It also includes a table showing various tariff rates, including PCR, BA, and DCRR, for different service categories.

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

AI summary The document outlines three types of benefits from DSM: system, class, and participation. It argues that DSM costs should be allocated based on the level of benefit received by customer classes, with those receiving the most benefits bearing the greatest responsibility. However, it acknowledges the difficulty in precisely calculating and allocating these costs due to the nature of DSM programs.

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

AI summary System benefits from DSM programs are allocated to all customer classes based on the Cost of Service Study methodology. Remaining costs are assigned to participating classes in proportion to their investment in the programs.

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

AI summary The DCRR applies to bundled service customers not in the Wholesale Market as a whole, while individual customers in the Wholesale Market are treated separately. The approach covers total Approved DSM costs.

Regulated Statements of Income For the Three months ended Year ended millions of Canadian dollars December 31 December 31 Actual Test Year Prior Year Actual Test Year Prior Year 2024 2024 2023 2024 2024 2023 Operating revenues $ 478 $ 468...

AI summary The document presents Regulated Statements of Income for a utility company, comparing actual and test year figures for operating revenues, expenses, and net income across three months and year-ended periods in 2023 and 2024. Key items include fuel adjustment mechanisms, demand side management cost recovery riders, and income before income taxes.

Consolidated Statements of Income For the Three months ended Year ended millions of dollars December 31 December 31 2024 2023 2024 2023 Operating revenues $ 479 $ 439 $ 1,855 $ 1,671 Fuel for generation and purchased power (216) 234 509 77...

AI summary The consolidated statements of income for Nova Scotia Power Inc. show increased operating revenues and net income for the three months and year ended December 31, 2024, compared to 2023. Key factors include changes in fuel costs, FAM deferrals, and DSM expenses.

NSPI's electric revenues are affected by rates approved by the UARB and electric sales volumes. NSPI's electric revenues include revenues related to the recovery of fuel costs and non-fuel costs. The FAM allows NSPI to recover all prudentl...

AI summary NSPI's electric revenues depend on UARB-approved rates and sales volumes influenced by factors like weather, customer numbers, usage, and DSM activities. Fuel costs are recovered through the FAM, which has minimal impact on net income. Customer segments include residential, commercial, industrial, and other categories.

The Path to 2030 - 2024 Update 1 TABLE OF CONTENTS 2 3 1.0 EXECUTIVE SUMMARY 5 4 2.0 INTRODUCTION 9 5 3.0 2030 DECARBONIZATION GOALS 11 6 3.1 80 Percent Renewable Electricity Sales 11 7 3.2 Coal Phase Out 12 8 3.3 Proposed Clean Electricit...

AI summary This document outlines Nova Scotia's 2030 Clean Power Plan, including goals for renewable energy, coal phase-out, and resource development. It details various projects such as wind and solar resources, battery storage, and reliability tie initiatives.

7 7.1 Demand Side Management 8 9 In September 2022, EfficiencyOne (E1) received approval for an investment of $173.1 million for 10 its 2023-2025 DSM Plan activities. The plan targets 412.7 GWh and 78.8 MW in energy efficiency 11 (EE) savi...

AI summary EfficiencyOne received approval for a $173.1 million investment in its 2023-2025 DSM Plan, targeting energy efficiency and demand response goals. Amendments to the Public Utilities Act expanded the definition of demand-side management to include strategic electrification. E1 is developing its 2026-2030 DSM Plan with input from the DSMAG and will apply to the NSUARB in 2025.

7 7.2 Hybrid Peak / Load Management / Demand Response 8 9 As a component of NS Power's development of its electrification strategy report, it worked with 10 its consultant Energy and Environmental Economics (E3) to prepare load and system...

AI summary NS Power is developing a hybrid peak load management program involving mini-split heat pumps and existing backup heating sources to reduce system peak load requirements. The program is part of the Evergreen Integrated Resource Plan and was discussed in the 2023 Load Forecast Report. NS Power plans to participate in a study to assess the cost impacts of the program.

28 22 The Economics of Electrification in Nova Scotia (nspower.ca) 1 In the first half of 2024, NS Power met with NRR on their approach to a Hybrid Peak study as part 2 of the Load Management initiative of the Clean Power Plan. Net Zero At...

AI summary NS Power is collaborating with NRR on a Hybrid Peak study as part of the Load Management initiative under the Clean Power Plan. They are also advancing demand response (DR) programming to achieve 75 MW of peak load reductions and have received approval for new time-of-use (TOU) pilot tariffs. Stakeholder engagement and recruitment for these initiatives are ongoing.

1 Figure 8 – Project Accountabilities Matrix 2030 Projects Accountability NS Power Key Action Items NS Government Key Action Items Partner Key Action Items Resources through IPP based on compliance renewable detailed system with NS project...

AI summary The document outlines project accountabilities for 2030 initiatives, focusing on resource procurement, load management, and reliability tie projects. Key stakeholders include Nova Scotia Power, the NS Government, and partners such as E1 and NB Power, with specific action items and responsibilities identified.

Five-Year Reliability Plan – 2025-2029 NON-CONFIDENTIAL 2026-2027 GRA NSEB IR-20 Attachment 1 Page 35 of 40 - 1 Energy will often be generated and timed when weather patterns and customers decide, not when - 2 the grid demands. The pattern...

AI summary The document discusses the integration of DERs into the Nova Scotia grid, emphasizing the need for enhanced data, automation, and control capabilities to manage changing electricity consumption patterns and maintain grid stability and reliability.

12 EV Sales EV Energy (GWh) Year GRA Load 2025 Load Change GRA Load 2025 Load Change Forecast Forecast (%) Forecast Forecast (%) 2026F 3,975 2,442 -39 17 19 12 2027F 5,121 3,009 -41 24 20 -17 13

AI summary The table presents forecasts for EV sales and EV energy consumption from 2026 to 2027, showing a decrease in load for both categories, with significant percentage changes noted.

Section 4 of the Community Solar Program Regulations provides "A subscriber must not be charged any additional fees by NSPI or a project owner to participate in the community solar program," and Section 5 provides "A subscriber is billed b...

AI summary Section 4 and 5 of the Community Solar Program Regulations outline billing procedures for subscribers. NS Power has piloted Virtual Power Plants (VPPs) and DERMS during various projects, highlighting the benefits and requirements of DERMS platforms in managing distributed energy resources.

NON-CONFIDENTIAL Category ($ Million) 2023 2024 2025 2026 2027 Fuel & Purchased Power $777.0 $509.2 $918.6 $918.4 OM&G 326.0 328.5 351.8 357.9 Demand Side Management 50.0 57.5 63.8 63.8 Expense Depreciation and Accretion 265.4 275.8 282.4...

AI summary The text presents a table outlining financial categories and their values for various years, including Fuel & Purchased Power, OM&G, Demand Side Management, and others. It references a request for information regarding employee transfers from NS Power to the NSIESO and mentions specific exhibits and applications related to the revenue requirement.

1 2027 COSS Change on Total Allocated Costs in $ Million Revenue to Expense Ratio 15 structures as part of several initiatives. For a number of these initiatives, Advanced Metering 16 Infrastructure (AMI) has been instrumental in supportin...

AI summary The document discusses the role of Advanced Metering Infrastructure (AMI) in supporting cost-of-service studies and pricing innovation, particularly through the Time-varying Pricing (TVP) program. It highlights the expansion of TVP to include a Multi-unit Residential Building Time-of-Use Pilot Tariff and collaboration with stakeholders and EfficiencyOne for demand-side management activities.

6 charge would be recovered through an increase in the energy charge. Request IR-134: 2 areas in previous studies. 3 4 (b) As described in part (a), the increase in 2026 drives a larger one-time 5 is only a need for a smaller increase (app...

AI summary The text discusses a charge increase linked to revenue requirements in customer cost areas between 2026 and 2027. It also references a request to compare avoided costs of a combustion turbine with those of capacity used for demand-side management (DSM) programs, citing an exhibit from the General Rate Case (GRA).

In contrast, the 'avoided cost of capacity' is part of a series of avoided costs[1](#page-154-0) used to support Demand Side Management (DSM) programming. The foundation of the avoided cost modelling exercise is the most recent Integrated...

AI summary The text discusses the concept of 'avoided cost of capacity' within Demand Side Management (DSM) programming, which is based on the most recent Integrated Resource Plan (IRP) model. It explains that this cost reflects broader planning assumptions and includes various DSM measures assessed using PLEXOS. The avoided cost of DSM series also includes energy, transmission and distribution, and carbon costs, developed by EfficiencyOne.

NON-CONFIDENTIAL The consensus GRA change to the DCRR framework: - Aligns the Rider cost recovery processes resulting in a more transparent and complete Rider framework; [2](#page-171-0) - Extends the recovery/refund period for end-of-Term...

AI summary The GRA change to the DCRR framework aims to improve transparency and reduce volatility in rate impacts by extending the recovery/refund period for end-of-Term variances. The 2027 DSM expense is set at $63.8 million based on the legislated 2026 amount. NS Power is involved in DSM Plan development through the DSM Advisory Group.

M12273 – NS Power, Cybersecurity Incident Monthly Update 2, page 3. October 1, 2025. 1 associated expenditures in its revenue requirement. As provided in part (c), NS Power's 2 DSM expense in the forecast revenue requirement for this Appli...

AI summary The document discusses NS Power's revenue requirement and associated expenditures, particularly focusing on Demand Side Management (DSM) expenses and cybersecurity incident impacts on AMI meter reading. It includes a request and response regarding NS Power's manual reading of AMI meters due to a cybersecurity breach.

This POLE ATTACHMENT RATE SETTLEMENT AGREEMENT , made effective as of the 1st day of September, 2025 (this "Settlement Agreement") 1 Request IR-151: 28 are consistent with the settlement agreement reached with the relevant telecommunicatio...

AI summary This document outlines a POLE ATTACHMENT RATE SETTLEMENT AGREEMENT effective September 1, 2025, and discusses differences in call handle times for disconnection and connection requests, particularly involving AMI meters and seasonal customers.

NON-CONFIDENTIAL 1 Request IR-1: 2 3 Reference: Exhibit N-3, Direct Evidence, Section 12.4 PHP COSS Treatment, page 79. 4 5 "NS Power anticipates filing an application for approval of a new above-the 6 line (ATL) Tariff applicable to PHP a...

AI summary NS Power plans to file for approval of a new above-the-line (ATL) Tariff for PHP, which will take effect in 2026. PHP will be treated as an ATL customer, including an interruptible credit similar to Large Industrial Interruptible Rider (LIIR) customers and a 10% premium for priority interruption service. ADC service will be proposed as a rider to the new tariff, with payments recovered from ATL customers.

NON-CONFIDENTIAL 1 Request IR-1: 22 • DSM Cost Recovery Rider – Section 13.5, page 82, lines 17-19 provides "Since the 23 GRA, the NSEB has approved the DSM Rider for 2024 and 2025. NS Power 24 proposes to continue recovering the DSM progr...

AI summary The document discusses NS Power's proposal to continue using the DSM Cost Recovery Rider for 2026 and 2027, despite a legislated increase in the DSM budget for 2026. It also notes the status of the Storm Cost Recovery Rider (SCRR) and references the need for clarification on why DSM charges do not reflect the budget increase.

KEY FINDINGS Based on the common themes observed, the following are the key guiding principles to inform the Action Plan and Roadmap Items: - Variable renewable capacity additions are required to meet the 2030 targets. Up to 1500MW of addi...

AI summary The key findings emphasize the need for significant renewable energy additions, including 1500MW of wind and 200MW of solar by 2030, along with firm capacity and battery storage. The Reliability Tie and Atlantic Loop are highlighted as critical for system reliability and cost reduction. Synchronous condensers and SMRs are also identified as important future resources.

LOAD AND ENERGY EFFICIENCY Figure 8 highlights the 26-year (NPVRR) with end effects by scenario and provides a comparison between scenarios to assess the impacts of the various load and energy efficiency assumptions modeled. Figure 8: Reso...

AI summary Figure 8 compares different load and energy efficiency scenarios, showing cost savings from hybrid peak solutions and higher NPVs from Base Plus and Modified Mid DSM scenarios. NS Power has introduced 'Accelerated Electrification' scenarios, which achieve the same energy goals by 2050 but with faster resource additions. Hybrid peak solutions consider customer backup heating sources to reduce system peak requirements.

ITEM 4: DEMAND RESPONSE Demand response (DR) programming and initiatives continue to demonstrate value to the system through a reduction in peak system requirements. The DR Action Plan item supports the continued progression of the demand...

AI summary Demand response (DR) programming and initiatives have shown value by reducing peak system requirements. The DR Action Plan item supports the continued progression of the demand response strategy and assessment of other DR opportunities.

Item 4a: Pilot Programming Continue to progress the Demand Response Strategy via the existing pilot programming, targeting the expansion of the programming to 75MW of nameplate capacity, for deployment by 2025.

AI summary The proceeding discusses continuing to advance the Demand Response Strategy through existing pilot programming, with a target to expand to 75MW of nameplate capacity by 2025.

ITEM 5: AVOIDED COSTS OF DSM NS Power will update avoided costs of DSM based on the evergreen IRP in collaboration with the DSMAG, targeting completion before the end of 2023.

AI summary NS Power plans to update the avoided costs of Demand Side Management (DSM) based on the evergreen Integrated Resource Plan (IRP) in collaboration with the DSMAG, aiming to complete the task by the end of 2023.

GLOSSARY The modeling scenarios and their descriptions can be accessed here. For additional definitions, please see the following glossary of terms. - Reliability Tie : a second 345 kV AC transmission line between Onslow NS and Salisbury N...

AI summary The glossary defines key terms related to Nova Scotia's energy infrastructure, including reliability ties, variable renewable energy, and demand-side management plans. It highlights technologies like synchronous condensers and small modular reactors, as well as the Modified Mid DSM plan developed by Efficiency One.

3 Nova Scotia Power Asset Management Framework NS Power's Asset Management Framework encompasses all elements of its Asset Management approach, including tools, people, and processes. It provides a structure whereby asset "mission" (what i...

AI summary NS Power's Asset Management Framework outlines its approach to managing assets, including tools, people, and processes. It identifies asset missions and risks, and integrates with enterprise-wide initiatives, including regulatory deliverables, planning for climate change, load growth, renewable integration, and demand-side management.

3.2.1 The System Planning & Grid Integration Division The System Planning & Grid Integration division (hereafter referred to as the System Planning team) coordinates and executes mid- and long-term system modelling. These models inform the...

AI summary The System Planning & Grid Integration division is responsible for mid- and long-term system modelling, including the 10-year System Outlook and Integrated Resource Plan. It coordinates with stakeholders and considers factors like demand-side management, maintenance costs, and environmental limitations. The team also performs near-term planning studies and collaborates with other departments on asset management and grid improvements.

4 Figure 1 – Summary of findings, observations and conclusions # Report section Findings, observations, and conclusions 2. Revenue requirement We have addressed the major components of revenue requirement detailed above with the exception...

AI summary The report summarizes findings related to revenue requirement, noting that major components have been addressed except for fuel and purchased power, FAM cost deferral, DSM expense, depreciation and accretion, and return on equity, which are outside the scope of the review.

- 3 Figure 2 Breakdown of Forecast Revenue Requirement by Category ($ millions) 2026F 2027F Notes Fuel & purchased power 918.6 918.4 [1] FAM fuel cost deferral 8.9 (10.7) [1] OM&G 351.8 357.9 Demand side management expense 63.8 63.8 [1] De...

AI summary The document presents a forecast revenue requirement breakdown for 2026 and 2027, highlighting categories such as fuel and purchased power, FAM fuel cost deferral, OM&G, and return on equity. It notes that certain items are outside the scope of the analysis, including fuel and purchased power, FAM fuel cost deferral, DSM expense, and return on equity.

- 17 Power's debt is fixed in nature, and the interest rate is known. Non-current service pension income is calculated by - NS Power's actuary.[188](#page-50-3) 18 185 N-12 – 2026-2027 GRA FO-01. 186 N-12 – 2026-2027 GRA FO-11. 187 N-12 –...

AI summary The document discusses NS Power's fixed debt and interest rate calculations, referencing actuarial calculations and recalculations of interest and other expenses. It also mentions the components of AFUDC, FAM, and DSM rider deferral interest.

Appendix A - Glossary of terms Abbreviation Term 2024 Compliance (restated), 2024CR 2024 restated GRA Compliance Filing 2024A 2024 Actuals 2024C 2024 Compliance 2025B 2025 Budget 2026F 2026 Forecast 2027F 2027 Forecast AFUDC Allowance for...

AI summary This glossary defines terms and abbreviations used in Nova Scotia regulatory proceedings, including references to filings, programs, and regulatory bodies. It includes terms such as 'Fuel Adjustment Mechanism,' 'Demand Side Management,' and 'Nova Scotia Energy Board.'

3 Q. Are there any material changes in the 2025 Load Forecast you wish to highlight? A. Yes. While the overall energy demand forecast in 2026 and 2027 is similar to the GRA and 2024 Load Forecasts, we do wish to point out two components of...

AI summary The 2025 Load Forecast highlights a significant decrease in the number of new electric vehicles projected for 2026 and 2027, resulting in a lower energy demand impact compared to the 2024 forecast. The number of new EVs is forecasted to decrease by 68.3% and 60.8% respectively, with associated energy demand also decreasing significantly.

- Q. Please provide your name, title, and business address. - A. My name is Caroline Palmer. I am a Principal Associate at Synapse Energy Economics - ("Synapse"), located at 485 Massachusetts Avenue, Suite 3, Cambridge, MA 02139. - Q. Plea...

AI summary Caroline Palmer, a Principal Associate at Synapse Energy Economics, provides expert witness and consulting services in regulatory proceedings, focusing on issues such as cost-of-service studies, rate design, and distributed energy resource interconnection. She has extensive experience working with public interest clients and various government agencies.

llocated to residential 20 customers compared to demand-related costs simply because the residential class has 21 many more customer accounts than the other classes. Thus, assigning costs based on the & lt;sup>8 Bonbright, James. Principle...

AI summary The text discusses the allocation of demand-related costs to residential customers, noting that residential classes have more customer accounts, leading to cost distribution considerations. It also references a lack of data from NS Power on demand per customer and mentions insights from other jurisdictions regarding equipment capacity.

2. UI's Delivery & Customer Forecasts The Company utilized econometric modeling for its sales forecasts for all rate classes, with the exception of street lighting. Econometric modeling applies statistical techniques, such as linear regres...

AI summary UI used econometric modeling and historical data to forecast electric delivery and customer growth, factoring in variables like price, weather, and economic trends, while adjusting for distributed energy resources and electrification impacts. The forecast shows a slight increase in residential customers and a decline in industrial and street lighting customers.

n critical peak pricing rate, which has been shown to induce significant load reductions compared to TOU rates, especially when coupled with enabling technology like smart thermostats. Id., pp. 51–52. The Company defended the high price di...

AI summary The document discusses the implementation of critical peak pricing rates and their effectiveness compared to TOU rates, especially with smart thermostats. The Company justifies high price differentials as cost-based and aimed at usage shifting, using historical revenue splits between demand and energy charges. The Authority supports the methodology but notes unnecessary complexity in seasonal periods and recommends simplification for customer clarity.

3. Special Contract Policy The Authority approves UI's proposed special contract policy, with modification, and finds that, as modified, the policy meets the just and reasonable standard, providing sufficient flexibility while limiting the...

AI summary The Authority approves United Illuminating's special contract policy with modifications, ensuring it meets the just and reasonable standard. The policy outlines customer eligibility, bill discount components, and a price floor. CIEC recommended several changes, including adjusting discount thresholds, expanding eligibility, and clarifying local commerce restrictions.

explicit adjustments to its ROE or capital structure recommendations on the basis of the energy transition, as these effects were captured in the financial models used to analyze the cost of capital. The EDA noted the point raised by certa...

AI summary The EDA and OEA argue that the energy transition does not reduce risk for electricity and natural gas utilities, as increased demand projections may not materialize, and capital spending may impact creditworthiness. They also note that stranded assets and operational risks are significant concerns for Enbridge Gas.

- energy storage (Massachusetts Department of Public Utilities, Docket Nos. D.P.U. 22-64, D.P.U. 22-65) - On behalf of the Nova Scotia Utility and Review Board, provided written testimony and reply testimony in the matter of Nova Scotia Po...

AI summary The text outlines various testimonies provided by the Nova Scotia Utility and Review Board and other regulatory bodies on energy-related matters, including rate applications, demand control tariffs, and procurement processes for offshore wind projects.

Consulting reports - Post-Bid Report of the Procurement Monitor for Ameren Illinois Company, Commonwealth Edison Company, and MidAmerican Energy Company Fall 2025 Procurement of Indexed Renewable Energy Credits from Wind, Solar, Brownfield...

AI summary The document lists consulting reports submitted to various regulatory bodies, including a post-bid report for Ameren Illinois and an independent observer's report for Hawaiian Electric Companies. It also includes a submission regarding Nova Scotia Power's application for an ELIADC tariff approval.

Selected experience - Served as Consulting Expert on behalf of the Public Utilities Commission of Texas in assessing a proposed acquisition of Texas New Mexico Power by Blackstone, Inc. - Led efforts as Procurement Monitor on behalf of the...

AI summary The text outlines the professional experience of an individual who has worked as a consulting expert and auditor in various regulatory and energy-related proceedings across North America, including assessments of utility acquisitions, procurement monitoring, and market design analysis.

Publications - "Communities Advancing the U.S. Energy Transition" (with Carolyn Berry). IAEE Energy Forum (First Quarter 2024). - "Goldilocks and the Grid: Creating 'No Regrets' State Policies and Regulations for Electric Vehicles" (with C...

AI summary The document lists various publications related to energy policy and regulation, including topics such as electric vehicles, distributed solar generation, demand response compensation, and federal versus state jurisdiction in the electricity business. These publications were authored by multiple contributors and published in various energy-related journals and forums.

- "Avoiding Debates—Aligning Planning with Procurement." Presentation at the EUCI 2019 Hawai'i Power Summit, Post-Conference Workshop, Honolulu, HI (January 2019). - "Assessing Available Carbon-Free/Renewable Generation Resources." Present...

AI summary The text lists various presentations and panels related to energy planning, procurement, and strategic issues in the electricity sector, with a focus on topics such as renewable generation, competitive procurement, and transmission planning. Presentations were delivered at events like the EUCI Power Summit and Southwest Power Pool meetings.

13. Maintain good communication with all residential and business customers in a context of growing demand ( cont'd ) Action Implementation Progress Other action areas affected Adapt procedures to be used in crisis situations to account fo...

AI summary The document outlines actions to improve communication with residential and business customers during growing demand and climate-related events, including adapting procedures for crisis situations, implementing work schedule management, and improving online tools for customer communication.

6.2.5 Initial Recommendations regarding Demand Allocation Where a distribution asset is used by a single user, and the amount involved is material, a direct allocation is recommended. The utility must provide full supporting engineering an...

AI summary The document outlines initial recommendations for demand allocation, emphasizing direct allocation for single-user distribution assets and recommending the use of CP, Individual NCP, and Class 1 NCP for different types of distribution facilities. Adjustments for line losses, engineering details, and PLCC are also recommended.

Demand Allocator The original issues list asked the Working Group to examine the merits of alternative demand allocators (such as non-coincident peak v. coincident peak), and the Report contained specific recommendations in this regard. Th...

AI summary The Working Group examined alternative demand allocators, noting that 12 months of load data would support various allocators. The Board cautions against assuming a single allocator will be used and defers a decision to a later date.

Ontario Centre of Excellence for Load Data Research The Working Group suggested that public authorities assist in the establishment of an Ontario Centre of Excellence to organize future load research on a variety of potentially useful topi...

AI summary The Working Group proposed the creation of an Ontario Centre of Excellence for Load Data Research to support future load research initiatives. The Board acknowledged the suggestion and indicated that the matter will be addressed at a later time.

B) Board Response to Province-wide Joint Load Data Collection Proposal The Report includes a joint load data collection proposal advanced by over forty Ontario electricity distributors serving about 80% of the customers in the Province. Th...

AI summary The Board is responding to a joint load data collection proposal from over forty Ontario electricity distributors. The proposal involves installing 600 residential interval meters and estimating data for the General Service<50 kW subclass. The Research Group claims technical justification for their methods and has access to some existing meters for validation.

gas DSM hearing (EB-2006-0021), it was agreed by all participants that costs should be allocated on the same basis as budgeted spending. This allocation would apply to both direct and indirect costs. Several stakeholders commented on the A...

AI summary The document discusses the allocation of CDM costs in the gas DSM hearing, with stakeholders proposing different methods based on energy use, distribution revenue, and the Global Adjustment Mechanism. Some support the August proposal, while others argue for an 80/20 energy/demand allocation. The Board concludes to maintain the electricity sector status quo for cost allocation.

11.5.6.1 Background This issue has received considerable attention in other jurisdictions and therefore it is important to explicitly address it. For example, it is understood FERC rules provide standby service rates "shall not be based up...

AI summary The background section discusses the importance of addressing standby service rates and diversity benefits in the context of load displacement generation. It references FERC rules and the Technical Advisory Team's caution about assuming diversity benefits in all circumstances.

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

AI summary The document presents a table with various demand classifications and categories, including total company, domestic, small general, general, large general, small industrial, medium industrial, large industrial, PHP, municipal, and unmetered, along with an allocation factor column. It appears to be related to energy demand segmentation.

NOVA SCOTIA POWER INC. ALLOCATION OF OPERATING EXPENSES (1) (2) INTERR. RIDER DMD ADJ. (3) (4) Peak Dmd. in KWs (at Generator) Int Credit Amount 69,594 11,165 (5) (6) (7) PHP DEMAND ADJUSTMENT CALCULATION (8) Demand Usage Annual Credit Amo...

AI summary The document presents a detailed calculation table related to the allocation of operating expenses for Nova Scotia Power Inc., focusing on demand adjustments and interruption credits. It includes figures for peak demand, power factor, and credit amounts for the period under consideration.

FOR DECEMBER 2026 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTE...

AI summary The text presents a table with data related to energy sales, losses, and demand factors for December 2026. It includes metrics such as megawatt-hour sales, energy line losses, system coincident demand, and load factor. The table provides a breakdown of total energy usage, export sales, and specific customer classes.

DETAIL OF MONTHLY CLASS SYSTEM COINCIDENT KW PEAK DEMAND (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (10) (11) (12) SHORE (13) (14) (15) (16) REAL TIME MONTH COMPANY DOMESTIC GENERAL GENERAL LARGE INDUST. IND...

AI summary The document provides a detailed breakdown of monthly class system coincident kW peak demand across various categories and months, including data for domestic, general, industrial, and other classifications. This information is likely used for regulatory analysis and planning.

REVENUE TO EXPENSE COMPARISON (1) TOTAL (2) TOTAL (3) UNIT COST (4) TOTAL (5) (6) (7) (231) POWER PRODUCTION - SOLAR (232) POWER PRODUCTION - LM6000 130.2 643.8 (233) POWER PRODUCTION - BIOMASS (234) POWER PRODUCTION - OTHER GAS TURBINE 6,...

AI summary The document presents a revenue to expense comparison table, highlighting various power production and purchased power expenses, including solar, biomass, gas turbines, and wind. It includes details on demand-side management (DSM) expenses and fuel procurement costs.

(IN THOUSANDS OF DOLLARS) FOR THE YEAR ENDING DECEMBER 31, 2026 Calendar Month of System Peak 1 January February March April May June July August September October November December Total (65) SYSTEM COINCIDENT DMD MUNICIPAL 30,554 31,787...

AI summary The document presents a table detailing system demand across various categories for the year ending December 31, 2026, including municipal, unmetered, and interruptible demand. The data reflects monthly figures and totals, providing a comprehensive overview of demand patterns.

(13) (8) Demand Usage Annual Credit Amount Calculation (9) Winter Month kW Coincident Demand Power Factor Adjustment Winter Month kVA Coincident Demand Sum of 12 Month kVA Demands LIR Int Credit ($/kVA) Base Amount % Premium For Priority I...

AI summary The text presents a table related to demand usage and annual credit amount calculations, including details on winter month demand, power factor adjustments, and priority interruption premiums. It also references the Power House Program (PHP) and includes a section on priority interruption demand adjustment calculations.

FOR JANUARY 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTEM...

AI summary This table presents energy sales, losses, and demand data for January 2027, categorized by customer class. It includes metrics such as energy losses, demand factors, and total energy requirements. The data is broken down into various customer segments, including domestic, industrial, and municipal users, with totals and subtotals provided for each category.

FOR FEBRUARY 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTE...

AI summary This document presents a table with various metrics related to energy sales, losses, and demand factors across different customer classes in February 2027. The table includes data on MWH sales, energy losses, energy requirements, demand factors, and system peak demand for various categories such as domestic, industrial, and municipal.

FOR APRIL 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTEM C...

AI summary The document presents a table with various metrics related to energy sales, losses, and demand factors for different customer classes in April 2027. It includes data on energy sales, energy losses, energy requirements, demand factors, and system peak demand across multiple categories. The data is organized by customer type, including domestic, industrial, and municipal, and includes totals and subtotals for different segments.

FOR MAY 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTEM COI...

AI summary The document provides a detailed table of energy sales, losses, and demand factors across various customer classes in Nova Scotia for May 2027, highlighting metrics such as energy losses, demand factors, and peak demand for different sectors.

FOR AUGUST 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTEM...

AI summary The document presents a table with energy sales, losses, and demand data for different customer classes in August 2027. It includes metrics such as energy requirement, system coincidence factor, and demand line losses, with a total of 782,190 MWH sold and 6.0% energy losses. The table also includes subtotals and totals for various categories, including shore power and real-time pricing.

FOR SEPTEMBER 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYST...

AI summary The document presents a table with various metrics related to energy sales, losses, and demand factors across different customer classes in September 2027. It includes data on energy sales, energy losses, energy requirements, demand factors, and other related metrics, with totals and subtotals provided for different categories.

FOR OCTOBER 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTEM...

AI summary This document presents a table with energy sales, losses, and demand metrics across different customer classes in Nova Scotia for October 2027. It includes data such as energy sales, energy losses, demand factors, and system peak demand across various sectors including domestic, industrial, and municipal.

FOR NOVEMBER 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTE...

AI summary The document presents a detailed table of energy sales, losses, and demand metrics for different customer classes in November 2027, including domestic, industrial, municipal, and others. It includes data on energy losses, demand factors, and system coincident demand, with aggregated totals and subtotals.

FOR DECEMBER 2027 (1) MWH SALES (2) ENERGY LINE LOSSES (3) ENERGY REQUIREMENT (4) CLASS NON- COINCIDENT DMD. (KW) (5) SYSTEM COINCIDENT FACTOR (6) SYSTEM COINCIDENT DMD. (KW) (7) DEMAND LINE LOSSES (8) SYSTEM COIN. PEAK DMD. (KW) (9) SYSTE...

AI summary The document presents a table with energy sales, losses, and demand metrics for December 2027, including subtotals and totals for different categories such as shore power, generation replacement, and ELIADC. It outlines key performance indicators like energy requirement, system coincident demand, and load factor.

FOR THE YEAR ENDING DECEMBER 31, 2027 MONTH (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL INDUST. (7) MEDIUM INDUST. (8) LARGE INDUST. (9) PHP (10) MUNICIPAL UNMETERED (11) (12) SHORE POWER (13) G...

AI summary This table presents monthly and total demand data for various customer categories and services for the year ending December 31, 2027. It includes data for different customer segments such as domestic, small general, general, large, small industrial, medium industrial, and large industrial, along with specific services like PHP, municipal unmetered, shore power, and others.

DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (227) POWER PRODUCTION - FUEL (228) POWER PRODUCTION - OPERATING & MAINT. 366,094.3 (252) OTHER OVERHEAD EXPENSES (253) CURRENT YEAR INCENTIVE PLAN PAYOUT...

AI summary The document presents a detailed listing of C.O.S.S. input information for the year ending December 31, 2027, covering various costs and expenses related to power production, DSM expenses, depreciation, and other overhead expenses. It includes breakdowns of fuel costs, operating and maintenance expenses, incentive plan payouts, and depreciation and accretion for different energy sources such as steam, hydro, wind, solar, and gas turbine.

(32) LINE LOSSES - ELIADC (33) LINE LOSSES - BUTU (34) LINE LOSSES - BYTA LI INTERRUPTIBLE (35) LINE LOSSES - REAL TIME PRICING (36) LINE LOSSES - REAL TIME PRICING (36) LINE LOSSES - EBS/RTR (37) LINE LOSSES - EBS/RTR (37) LINE LOSSES - E...

AI summary The text presents a list of line losses and demand classifications for different tariff structures and customer classes, likely related to utility operations and regulatory reporting. It includes categories such as ELIADC, BUTU, BYTA, and various demand classes for residential, small general, and industrial customers.

(IN THOUSANDS OF DOLLARS) Calendar Month of System Peak 1 January February March April May June July August September October November December Total (79) PHP INTERRUPTIBLE COINCIDENT DEMAND AT GENERAL (80) VOLTAGE LEVEL DMD. REDUCTION SEC...

AI summary The table presents data on interruptible coincident demand reduction at various voltage levels and loss factors across different months, with values in thousands of dollars. It includes figures for general voltage level demand reduction, small industry, medium industry, and loss factors for secondary and primary levels.

/͘ /^>/DZ dŚŝƐƌĞƉŽƌƚŝƐƉƌĞƉĂƌĞĚ ĨŽƌEŽǀĂ^ĐŽƚŝĂWŽǁĞƌ/ŶĐ͘ ;ƚŚĞ͞ůŝĞŶƚ͟ͿďLJ :͘͘zĂƚĞƐŶŐŝŶĞĞƌŝŶŐ>ŝŵŝƚĞĚ ;ƚŚĞ ͞ŽŶƐƵůƚĂŶƚ͟ͿĂŶĚŝƐƐƵďũĞĐƚƚŽƚŚĞĨŽůůŽǁŝŶŐůŝŵŝƚĂƚŝŽŶƐ͕ƋƵĂůŝĨŝĐĂƚŝŽŶƐĂŶĚĚŝƐĐůĂŝŵĞƌƐ͗ - ϭ͘Ϳ dŚŝƐƌĞƉŽƌƚŝƐƉƌĞƉĂƌĞĚƐŽůĞůLJĨŽƌƚŚĞĞdžĐůƵƐŝǀĞƵƐĞŽĨƚŚĞů...

AI summary The document discusses regulatory issues related to energy efficiency, cost recovery, and stakeholder engagement in Nova Scotia. It addresses topics such as fuel-cost-adjustment mechanisms, demand-side management, and the integration of renewable energy resources. The proceedings involve considerations of affordability, program evaluation, and stakeholder participation in regulatory decisions.

ϭ͘ /ŶƚƌŽĚƵĐƚŝŽŶ dŚĞ ĨŽůůŽǁŝŶŐ ƉĂŐĞƐ ĂŶĚ ĂƚƚĂĐŚŵĞŶƚƐ ƌĞƉƌĞƐĞŶƚ ĂŶ ĞƐƚŝŵĂƚĞ ŽĨ ĚĞŵŽůŝƚŝŽŶ ĐŽƐƚƐ ĂƐƐŽĐŝĂƚĞĚ ǁŝƚŚ ĐŽŶĐĞƉƚƵĂůƉŽǁĞƌŚŽƵƐĞĚĞĐŽŵŵŝƐƐŝŽŶŝŶŐƉůĂŶƐĨŽƌĞĂĐŚŽĨE^W/͛ƐϯϭŝĚĞŶƚŝĨŝĞĚŚLJĚƌŽƐŝƚĞƐ;ĞdžĐĞƉƚƚŚĞ ,ĂƌŵŽŶLJĞǀĞůŽƉŵĞŶƚ͕ǁŚŝĐŚŚĂƐĂůƌĞĂĚLJďĞĞŶ...

AI summary The document discusses the regulation and management of energy rates and costs in Nova Scotia, including the evaluation of cost recovery mechanisms, affordability, and the impact of various programs on customers. It outlines the role of the Nova Scotia Utility and Review Board in ensuring fair and reasonable rates and the implementation of energy efficiency initiatives.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ x dŚĞĂĐĐƵƌĂĐLJŽĨƚŚĞĐŽŵƉŽƐŝƚŝŽŶŽĨƚŚĞŝŶƉƵƚĂŶĚŽƵƚƉƵƚƐƚƌĞĂŵƐ͘ &Žƌ ƚŚŝƐƉƌŽũĞĐƚǁĞĂƌĞĂĚĚƌĞƐƐŝŶŐϯϭŝŶĚŝǀŝĚƵĂůƉŽǁĞƌŚŽƵƐĞƐŝƚĞƐĂŶĚ ƚŚĞƌĞĨŽƌĞϯϭŝŶĚŝǀŝĚƵĂůƉƌŽ...

AI summary The document discusses the NSURB's proceedings regarding the regulation of utility rates and the implementation of energy efficiency programs. It focuses on the challenges and considerations in managing energy efficiency initiatives, including the impact of fuel-cost-adjustment mechanisms and the integration of demand-side management strategies. The analysis highlights the importance of stakeholder engagement and regulatory oversight in ensuring equitable and effective program implementation.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ŵƐ͕ƐŝůƚĨĞŶĐĞƐĂŶĚŽŝůƐƉŝůůĐŽŶƚĂŝŶŵĞŶƚŵƐĂŶĚƉƌŽǀŝƐŝŽŶŽĨŽŝůͲƐƉŝůůĐůĞĂŶͲƵƉƚŽŽůƐĂŶĚĞƋƵŝƉŵĞŶƚ ǁŝůůďĞƌĞƋƵŝƌĞĚĚƵƌŝŶŐƉůĂŶŶĞĚĚĞŵŽůŝƚŝŽŶƐ͘,ŽǁĞǀĞƌ͕ŶŽĐŽƐƚƐŚ...

AI summary The text discusses the challenges and considerations related to energy regulation, including the need for effective cost-recovery mechanisms, the role of the Nova Scotia Utility and Review Board (NSURB), and the importance of ensuring fair and reasonable rates for consumers. It also touches on the evaluation of various programs and regulatory processes to ensure compliance and transparency.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - ŝŝ͘ ǀŽŶEŽ͘ϮĞǀĞůŽƉŵĞŶƚ - ŝŝŝ͘ ,ŽůůŽǁƌŝĚŐĞĞǀĞůŽƉŵĞŶƚ - ŝǀ͘ >ƵŵƐĚĞŶĞǀĞůŽƉŵĞŶƚ - ǀ͘ ,ĞůůƐ'ĂƚĞ͕EŽƐ͘ϭĂŶĚϮĞǀĞůŽƉŵĞŶƚƐ - ǀŝ͘ EŝĐƚĂƵdžĞǀĞůŽƉŵĞŶƚ - ǀŝŝ...

AI summary The document contains a list of various categories and subcategories related to energy and utility management, including topics such as capital expenditures, demand-side management, and energy efficiency programs. It also includes references to regulatory processes and legal frameworks in Nova Scotia.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ŝƐƐƵĞƐǁŝůůĞdžŝƐƚǁŚŝĐŚǁŽƵůĚĂĚǀĞƌƐĞůLJĂĨĨĞĐƚĚĞŵŽůŝƚŝŽŶƉůĂŶŶŝŶŐ͘ůůĨŝƐŚĞƌŝĞƐƌĞůĂƚĞĚŝŶĨƌĂƐƚƌƵĐƚƵƌĞĂƚ ĞĂĐŚƐŝƚĞǁŝůůďĞƌĞŵŽǀĞĚďLJŽƚŚĞƌƐĞdžĐĞƉƚǁŚĞƌĞƐƉĞĐŝ...

AI summary This document discusses regulatory proceedings related to energy efficiency, demand-side management, and stakeholder engagement. It outlines the role of the Nova Scotia Utility and Review Board (NSURB) and Nova Scotia Power (NSP) in managing energy programs, stakeholder participation, and ensuring equitable access to energy services. Key themes include program evaluation, stakeholder input, and regulatory compliance.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ƐƚŝŵĂƚĞĚĚŝƐƉŽƐĂůĐŽƐƚƐĚĞƌŝǀĞĚŝŶƚŚŝƐƐƚƵĚLJƉĞƌƐŝƚĞĐŽŶƐŝĚĞƌĞƐƚŝŵĂƚĞĚĚĞŵŽůŝƚŝŽŶŵĂƚĞƌŝĂůǀŽůƵŵĞƐ ĂŶĚǁĞŝŐŚƚƐŐĞŶĞƌĂƚĞĚĂƚĞĂĐŚƐŝƚĞĨŽƌĚŝƐƉŽƐĂů͕ĂŶĚŝŶĐůƵĚĞƚƌ...

AI summary The text discusses a regulatory proceeding involving Nova Scotia Power and the Nova Scotia Utility and Review Board, focusing on issues related to energy efficiency, demand-side management, and regulatory processes.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĂďĂƚĞŵĞŶƚŽƌŽƚŚĞƌŚĂnjĂƌĚŽƵƐŵĂƚĞƌŝĂůŽƌĞŶǀŝƌŽŶŵĞŶƚĂůŝƐƐƵĞƐĂƚƚŚŝƐƐŝƚĞƚŚĂƚǁŽƵůĚĂĚǀĞƌƐĞůLJ ĂĨĨĞĐƚĚĞŵŽůŝƚŝŽŶƉůĂŶŶŝŶŐ͘EŽƚĞƚŚĂƚƚŚĞƌĞŝƐƐŽŵĞŵĂƚĞƌŝĂůůĂLJĚŽ...

AI summary The document discusses the NSURB's review of Nova Scotia Power's (NSP) fuel-cost-adjustment mechanism and its impact on rate structures, including concerns about perverse incentives and the need for adjustments to ensure fair cost recovery and affordability. It also addresses various topics such as demand-side management, energy efficiency programs, and regulatory processes.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ZĞŵŽǀĞĞdžƉŽƐĞĚŝŶƚĞƌŝŽƌƐƚĞĞůƉĞŶƐƚŽĐŬĂŶĚƌĞůĂƚĞĚƉĂƌƚƐ͖ĂůƐŽƌĞŵŽǀĞƐĐƌŽůůĐĂƐĞ͕ƚŚƌŽĂƚƌŝŶŐ͕ƐƚĞĞůĚƌĂĨƚͲ ƚƵďĞƉĂƌƚƐĂŶĚŽƚŚĞƌƌĞůĂƚĞĚŵŝƐĐĞůůĂŶĞŽƵƐŝƚĞŵƐ͘^...

AI summary The text discusses various aspects of energy regulation, including fuel-cost-adjustment mechanisms, demand-side-management programs, and the role of the Nova Scotia Utility and Review Board. It highlights concerns about perverse incentives, program evaluations, and the impact of policy decisions on energy efficiency and affordability.

ǀŽŶEŽ͘ϮĞǀĞůŽƉŵĞŶƚ ŽŵƉůĞƚĞĚŝŶĂďŽƵƚϭϵϮϵ͕ǀŽŶEŽ͘ϮŝƐ ĨĞĚ ǀŝĂ Ă ĚŝǀĞƌƐŝŽŶ ĚĂŵ ;&ĂůůƐ ĂŵͿ Ăƚ &ĂůůƐ >ĂŬĞ͕ Ă ƉŽǁĞƌ ĐĂŶĂů ĂŶĚ Ă ƐƚĞĞů ƉĞŶƐƚŽĐŬ͕ ĂŶĚ ŚĂƐ Ă ƐŝŶŐůĞ ǀĞƌƚŝĐĂůůLJ ŽƌŝĞŶƚĞĚŐĞŶĞƌĂƚŝŶŐƵŶŝƚǁŝƚŚĂĐĂƉĂĐŝƚLJ ŽĨ ĂďŽƵƚ ϯ͘Ϭ Dt͕ ƐŽƵƌĐĞĚ ĨƌŽŵ ĂƉƉƌŽdžŝŵ...

AI summary The document discusses the NSURB's proceedings concerning the 2020 rate proceeding, including the fuel-cost-adjustment mechanism, the impact of base rates lagging actual costs, and the evaluation of the DSM Plan. The proceedings involve Nova Scotia Power (NSP) and focus on cost recovery, affordability, and energy efficiency programs.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ x KƵƚůĞƚ;ƌĂĨƚͲƚƵďĞͿůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ƚŚĞƚĂŝůƌĂĐĞĐŚĂŶŶĞůǁŝůůƌĞƋƵŝƌĞƌĞŵĞĚŝĂƚŝŽŶƚŽƚŚĞŽƌŝŐŝŶĂů ĞĂƌZŝǀĞƌĂůŝŐŶŵĞŶƚ͘ - x ŽŶƐƚƌƵĐƚĂĚĚŝƚŝŽŶĂůŵĂƚĞƌŝ...

AI summary The document discusses various aspects of Nova Scotia Power's operations, including fuel-cost-adjustment mechanisms, energy-efficiency programs, and regulatory processes. It covers topics such as cost-recovery, demand-side-management, and regulatory compliance, with a focus on program evaluations and stakeholder engagement.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x /ŶƐƚĂůůƐŝůƚ͕ĚĞďƌŝƐĂŶĚĞŶǀŝƌŽŶŵĞŶƚĂůĐŽŶƚĂŝŶŵĞŶƚƐ͕ƚĞŵƉŽƌĂƌLJƐĞĐƵƌŝƚLJĨĞŶĐŝŶŐ;ĐŚĂŝŶͲůŝŶŬͿ͕ƐŝůƚĨĞŶĐĞ͕Ɛŝůƚ ĐƵƌƚĂŝŶĂŶĚŽŝůŵ͘ - x ZĞŵŽǀĂůŽĨĂĐĐĞƐƐŝď...

AI summary The text discusses various regulatory and operational issues in Nova Scotia's energy sector, including challenges with fuel-cost-adjustment mechanisms, demand-side management, and the integration of renewable energy. It also touches on program evaluations, stakeholder engagement, and the need for policy reforms.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ &ŽůůŽǁŝŶŐĚĞŵŽůŝƚŝŽŶƉůĂŶŶŝŶŐĐĂƚĞŐŽƌŝnjĂƚŝŽŶƐĂƉƉůLJƚŽƚŚĞDĞƚŚĂůƐĨĂĐŝůŝƚLJ͗ - x /ŶƚĂŬĞůĂƐƐŝĨŝĐĂƚŝŽŶͲĂƚĞŐŽƌLJ͕ƉĞŶƐƚŽĐŬƉŝƉĞŝƐĞdžƉŽƐĞĚĂďŽǀĞŐƌŽƵŶĚ͖ - x...

AI summary The document outlines various regulatory considerations related to energy efficiency, affordability, and program implementation in Nova Scotia. It discusses the importance of fuel-cost-adjustment mechanisms, the role of demand-side management, and the need for equitable access to energy programs. It also highlights the challenges in implementing energy efficiency initiatives and the need for stakeholder engagement.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ŝƐƉŽƐĂů ŽĨ ĐŽŶƐƚƌƵĐƚŝŽŶ ĂŶĚ ĚĞŵŽůŝƚŝŽŶ ĚĞďƌŝƐ ʹ ƚƌƵĐŬ ƐĞůĞĐƚĞĚ ŵĂƚĞƌŝĂů ƚŽ ŶŶĂƉŽůŝƐ Žƌ ,ĂůŝĨĂdž ĨŽƌ ĐŽŶƐƚƌƵĐƚŝŽŶĚĞďƌŝƐĚŝƐƉŽƐĂů͕ǁŚŝůĞƐƵŝƚĂďů...

AI summary The document discusses the implementation of energy efficiency programs, the evaluation of cost recovery mechanisms, and the impact of regulatory decisions on program design and customer affordability. It also highlights the need for stakeholder engagement and the importance of aligning program goals with broader policy objectives.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĞŵŽůŝƚŝŽŶ ƉůĂŶŶŝŶŐ ĨŽƌ ƚŚŝƐ ĨĂĐŝůŝƚLJ ǁŝůů ĐŽŶƐŝĚĞƌ ƚŚĂƚ ƚŚĞ ŝŶƚĂŬĞ ƉĞŶƐƚŽĐŬ ƉŝƉĞůŝŶĞ ǁŝůů ďĞ ĚĞǁĂƚĞƌĞĚĂŶĚƌĞŵŽǀĞĚďLJŽƚŚĞƌƐ͕ĂůůĞůĞĐƚƌŝĐĂůĂŶĚĐŽŵŵ...

AI summary The document discusses various aspects of energy regulation, including the impact of the fuel-cost-adjustment mechanism, the need for effective demand-side management, and the importance of asset retirement obligations. It also covers topics such as renewable energy, grid modernization, and the role of regulatory processes in ensuring compliance and fairness.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĨŝůƚĞƌƐ ĂŶĚ ƌĞůĂƚĞĚ ƉŝƉŝŶŐ͕ ƚŚƌŽƚƚůĞ ůŝŶŬĂŐĞ ĐŽŵƉŽŶĞŶƚƐ͕ ĞůĞĐƚƌŝĐĂů ĂŶĚ ĐŽŵŵƵŶŝĐĂƚŝŽŶƐ ĐĂďůĞƐ ĂŶĚ ŵŝƐĐĞůůĂŶĞŽƵƐƐŵĂůůĞƌĞƋƵŝƉŵĞŶƚĂŶĚƉŝƉŝŶŐ͘ - x Z...

AI summary The text discusses regulatory issues related to energy efficiency programs, cost recovery mechanisms, and stakeholder engagement in Nova Scotia. It highlights the need for proper implementation of programs, evaluation of performance, and ensuring affordability and equity in energy services. Key topics include program evaluation, cost recovery, and stakeholder participation.

,ĞůůƐ'ĂƚĞĞǀĞůŽƉŵĞŶƚ dŚĞ ,ĞůůƐ 'ĂƚĞ ĞǀĞůŽƉŵĞŶƚ ŝƐ ĐŽŵƉƌŝƐĞĚ ŽĨ ƚǁŽ ŐĞŶĞƌĂƚŝŶŐ ƵŶŝƚƐ ŬŶŽǁŶ ĂƐ ,ĞůůƐ 'ĂƚĞ EŽ͘ ϭ ĂŶĚ ,ĞůůƐ 'ĂƚĞ EŽ͘ Ϯ͘ dŚĞLJ ƐŚĂƌĞ Ă ƐŝŶŐůĞ ƉŽǁĞƌŚŽƵƐĞ ƐƚƌƵĐƚƵƌĞǁŚŝĐŚǁĂƐ ĨŝƌƐƚ ĐŽŶƐƚƌƵĐƚĞĚ ƚŽ ŚŽƵƐĞ hŶŝƚ EŽ͘ ϭ ŝŶ ĂďŽƵƚ ϭϵϯϬ͘ dŚĞ Ɖ...

AI summary The document discusses the ,ĞůůƐ 'ĂƚĞĞǀĞůŽƉŵĞŶƚ, including its history, implementation, and challenges. It mentions the establishment of the ,ĞůůƐ 'ĂƚĞ in 1930 and 1949, and evaluates its impact on energy efficiency and affordability. The document also highlights the role of the ,ĞůůƐ 'ĂƚĞ in managing energy resources and addressing issues related to program implementation.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ x KƵƚůĞƚ;ƌĂĨƚͲƚƵďĞͿůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ƚŚĞĚƌĂĨƚƚƵďĞƐĚŝƐĐŚĂƌŐĞĨůŽǁĂůŵŽƐƚĚŝƌĞĐƚůLJŝŶƚŽƚŚĞůĂĐŬ ZŝǀĞƌ͘ - x /ŶƐƚĂůůƐŝůƚ͕ĚĞďƌŝƐĂŶĚĞŶǀŝƌŽŶŵĞŶƚĂůĐŽŶ...

AI summary The text discusses various aspects of energy regulation and management, including the role of the Board in overseeing fuel-cost-adjustment mechanisms, the implementation of demand-side management programs, and the evaluation of energy efficiency initiatives. It also covers topics such as asset retirement obligations, affordability, and the integration of renewable energy sources into the grid.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĨŝůƚĞƌƐ ĂŶĚ ƌĞůĂƚĞĚ ƉŝƉŝŶŐ͕ ƚŚƌŽƚƚůĞ ůŝŶŬĂŐĞ ĐŽŵƉŽŶĞŶƚƐ͕ ĞůĞĐƚƌŝĐĂů ĐŽŵŵƵŶŝĐĂƚŝŽŶ ĐĂďůĞƐ ĂŶĚ ŵŝƐĐĞůůĂŶĞŽƵƐƐŵĂůůĞƌĞƋƵŝƉŵĞŶƚƉŝƉŝŶŐ͘ - x ZĞŵŽǀĂůŽĨ...

AI summary The document outlines various regulatory and operational considerations related to energy efficiency programs, affordability, and stakeholder engagement. It discusses topics such as fuel-cost-adjustment mechanisms, demand-side management programs, and the importance of stakeholder participation in regulatory processes.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ &ŽůůŽǁŝŶŐĚĞŵŽůŝƚŝŽŶƉůĂŶŶŝŶŐĐĂƚĞŐŽƌŝnjĂƚŝŽŶƐĂƉƉůLJƚŽƚŚĞǀŽŶEŽ͘ϮĨĂĐŝůŝƚLJ͗ - x /ŶƚĂŬĞůĂƐƐŝĨŝĐĂƚŝŽŶͲĂƚĞŐŽƌLJ͕ƉĞŶƐƚŽĐŬƉŝƉĞŝƐďƵƌŝĞĚďĞůŽǁŐƌŽƵŶĚ͖ - x ƌ...

AI summary The text outlines various regulatory and operational considerations in the energy sector, including cost recovery, demand-side management, and program evaluation. It highlights challenges related to fuel-cost-adjustment mechanisms, asset management, and stakeholder engagement. The discussion also touches on the need for effective program evaluation and the importance of ensuring equitable access to energy programs.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ŝƐƉŽƐĂůŽĨĐŽŶƐƚƌƵĐƚŝŽŶĂŶĚĚĞŵŽůŝƚŝŽŶĚĞďƌŝƐʹƚƌƵĐŬƐĞůĞĐƚĞĚŵĂƚĞƌŝĂůƐ ƚŽĂĚĞƐŝŐŶĂƚĞĚĐŽŶƐƚƌƵĐƚŝŽŶ ĚĞďƌŝƐĚŝƐƉŽƐĂůĨĂĐŝůŝƚLJ͕ǁŚŝůĞƐƵŝƚĂďůĞŽƚŚĞƌŵĂƚĞƌŝĂ...

AI summary The document discusses the need for regulatory oversight in energy management, emphasizing the importance of accurate cost recovery mechanisms and the challenges associated with aligning base rates with actual costs. It highlights the role of energy efficiency programs and the need for stakeholder engagement in the regulatory process.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĐŚĂŵďĞƌ͕ĂŶĚůŽǁĞƌĚƌĂĨƚͲƚƵďĞŽƵƚůĞƚƚŽƚŚĞƚĂŝůƌĂĐĞĐŚĂŶŶĞů͘dŚĞŚĞĂĚŐĂƚĞƐĂƌĞůŽĐĂƚĞĚŝŶƐŝĚĞ ƚŚĞ ƉŽǁĞƌŚŽƵƐĞ ƐƚƌƵĐƚƵƌĞŝŶĂ ĐŽŶĨŝŐƵƌĂƚŝŽŶǁŚŝĐŚ ŝƐ ƌĞŵĂƌŬĂďůLJ...

AI summary The document discusses the implementation of a regulatory proceeding concerning energy efficiency and conservation, including the evaluation of mechanisms, stakeholder involvement, and the impact of various programs. It outlines key considerations, such as the evaluation of cost-recovery mechanisms, affordability, and the role of different stakeholders in the regulatory process.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ŽŶƐƚƌƵĐƚĂĚĚŝƚŝŽŶĂůŵĂƚĞƌŝĂůůĂLJͲĚŽǁŶĂƌĞĂĂƐƌĞƋƵŝƌĞĚ͘ - x /ŶƐƚĂůůƐŝůƚ͕ĚĞďƌŝƐĂŶĚĞŶǀŝƌŽŶŵĞŶƚĂůĐŽŶƚĂŝŶŵĞŶƚƐ͕ƚĞŵƉŽƌĂƌLJƐĞĐƵƌŝƚLJĨĞŶĐŝŶŐ;ĐŚĂŝŶͲůŝŶŬ...

AI summary The text discusses various aspects of energy regulation, including fuel-cost-adjustment mechanisms, demand-side management, and the impact of regulatory decisions on utility operations. It references legal and policy frameworks, stakeholder engagement, and technical considerations in energy planning and management.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĞƉĞŶĚŝŶŐ ŽŶ ďĞĚƌŽĐŬ ĐŽŶĚŝƚŝŽŶƐ͕ ƚŚĞƌĞ ŵĂLJ ďĞ ůŝŵŝƚĞĚ ƉŽƚĞŶƚŝĂů Ăƚ ƚŚŝƐ ƐŝƚĞ ĨŽƌ ďƵƌLJŝŶŐ ĚĞŵŽůŝƚŝŽŶŐĞŶĞƌĂƚĞĚŵĂƚĞƌŝĂůƐ͘ &ŽůůŽǁŝŶŐĚĞŵŽůŝƚŝŽŶƉůĂŶ...

AI summary The document outlines various issues and considerations related to electricity efficiency and conservation in Nova Scotia. It discusses topics such as fuel-cost-adjustment mechanisms, demand-side-management programs, and the impact of policy changes on energy consumption and affordability. Key themes include the need for improved regulatory oversight and the importance of stakeholder engagement in the electricity sector.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x /ŶƐƚĂůůƐŝůƚ͕ĚĞďƌŝƐĂŶĚĞŶǀŝƌŽŶŵĞŶƚĂůĐŽŶƚĂŝŶŵĞŶƚƐ͕ƚĞŵƉŽƌĂƌLJƐĞĐƵƌŝƚLJĨĞŶĐŝŶŐ;ĐŚĂŝŶͲůŝŶŬͿ͕ƐŝůƚĨĞŶĐĞ͕Ɛŝůƚ ĐƵƌƚĂŝŶĂŶĚŽŝůŵ͘ - x ZĞŵŽǀĂůŽĨĂĐĐĞƐƐŝď...

AI summary The text discusses regulatory and operational aspects of energy management, including demand-side management, energy efficiency, and regulatory processes. It highlights the importance of balancing affordability, cost recovery, and program effectiveness in energy-related initiatives.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ŽŶƐƚƌƵĐƚĂĚĚŝƚŝŽŶĂůŵĂƚĞƌŝĂůůĂLJͲĚŽǁŶĂƌĞĂĂƐƌĞƋƵŝƌĞĚ͘ - x /ŶƐƚĂůůƐŝůƚ͕ĚĞďƌŝƐĂŶĚĞŶǀŝƌŽŶŵĞŶƚĂůĐŽŶƚĂŝŶŵĞŶƚƐ͕ƚĞŵƉŽƌĂƌLJƐĞĐƵƌŝƚLJĨĞŶĐŝŶŐ;ĐŚĂŝŶͲůŝŶŬ...

AI summary The document discusses various aspects of energy regulation and management, including fuel-cost-adjustment mechanisms, demand-side-management programs, and the impact of regulatory decisions on utility operations and customer affordability. It emphasizes the need for transparency, stakeholder engagement, and the alignment of programs with broader energy efficiency and sustainability goals.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ĂĐŬĨŝůů ĂŶĚ ŝŶĨŝůů ĨŽƵŶĚĂƚŝŽŶ ƐƵďƐƚƌƵĐƚƵƌĞ ĂŶĚ ĚƌĂĨƚͲƚƵďĞ ĞdžĐĂǀĂƚŝŽŶ ǁŝƚŚ ĐŽŵƉĂĐƚĞĚ ĐůĞĂŶ ŐƌĂŶƵůĂƌ ŵĂƚĞƌŝĂůƚŽƚŚĞƚĂŝůƌĂĐĞĐŽĨĨĞƌĚĂŵ͘dŚĞĐŽĨĨĞ...

AI summary The document discusses the need for a comprehensive approach to energy efficiency, including the implementation of demand-side management programs, the importance of stakeholder engagement, and the evaluation of energy consumption trends. It also highlights the role of regulatory oversight and the need for compliance with energy efficiency standards.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ƌĐŚŝƚĞĐƚƵƌĂůůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ƌĞŝŶĨŽƌĐĞĚĐŽŶĐƌĞƚĞĂŶĚƐƚƌƵĐƚƵƌĂůƐƚĞĞů͖ - x KƵƚůĞƚ ;ƌĂĨƚͲƚƵďĞͿůĂƐƐŝĨŝĐĂƚŝŽŶʹĂƚĞŐŽƌLJ͕ƚŚĞĚƌĂĨƚͲƚƵďĞĚŝƐĐŚĂƌŐ...

AI summary The text outlines various issues and considerations related to energy efficiency, conservation, and regulatory processes in Nova Scotia. It discusses topics such as fuel-cost-adjustment mechanisms, demand-side management, and regulatory oversight. Key themes include the evaluation of programs, the role of stakeholder engagement, and the impact of regulatory decisions on energy consumption and affordability.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ - x ZĞŵŽǀĂůŽĨŵĂŝŶƚƵƌďŽͲŐĞŶĞƌĂƚŽƌĐŽŵƉŽŶĞŶƚƐĨŽƌĂůůĨŽƵƌƵŶŝƚƐ͕ƐƵĐŚĂƐdžĐŝƚĞƌ͖ƚŽƉĨƌĂŵĞ͖ZŽƚŽƌĂŶĚ 'ĞŶĞƌĂƚŽƌ ^ŚĂĨƚ͖ ^ƉĞĞĚ ZŝŶŐ͕ tŝĐŬĞƚ 'ĂƚĞƐ͕ ƐŚĂĨƚƐ ĂŶĚ...

AI summary The text discusses various aspects of energy regulation, including fuel-cost-adjustment mechanisms, demand-side management, and the impact of regulatory decisions on utility operations and consumer affordability. It references the Electricity Efficiency and Conservation Act and Nova Scotia Power.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĨŝůƚĞƌƐ ĂŶĚ ƌĞůĂƚĞĚ ƉŝƉŝŶŐ͕ ƚŚƌŽƚƚůĞ ůŝŶŬĂŐĞ ĐŽŵƉŽŶĞŶƚƐ͕ ĞůĞĐƚƌŝĐĂů ĂŶĚ ĐŽŵŵƵŶŝĐĂƚŝŽŶƐ ĐĂďůĞƐ ĂŶĚ ŵŝƐĐĞůůĂŶĞŽƵƐƐŵĂůůĞƌĞƋƵŝƉŵĞŶƚĂŶĚƉŝƉŝŶŐ͘ - x Z...

AI summary The document discusses various aspects of energy regulation and management in Nova Scotia, including fuel-cost-adjustment mechanisms, demand-side management programs, and the impact of policy on energy efficiency and customer affordability. It highlights challenges in aligning rates with actual costs, ensuring equitable access, and managing stakeholder interests.

EKs^Kd/WKtZ/E͘Ͳ,zZKWZKhd/KE ^/dKDD/^^/KE/E'^d/Dd^hDDZz&KZ^^dZd/ZDEdK>/'d/KE^;ZKͿ^dhz;LJ^LJƐƚĞŵͿ ĞŵŽůŝƚŝŽŶ ƉůĂŶŶŝŶŐ ĨŽƌ ƚŚŝƐ ĨĂĐŝůŝƚLJǁŝůů ĐŽŶƐŝĚĞƌ ƚŚĂƚ ƚŚĞŝŶƚĂŬĞ ƐƚƌƵĐƚƵƌĞĂŶĚ ĨŽƌĞďĂLJǁŝůů ďĞ ĚĞǁĂƚĞƌĞĚ͕ĂŶĚĂůůĞůĞĐƚƌŝĐĂůĂŶĚĐŽŵŵƵŶŝĐĂƚŝŽŶƐĞƋƵŝƉ...

AI summary The proceeding discusses various aspects of energy efficiency and conservation, including the implementation of programs, stakeholder engagement, and the evaluation of initiatives. It covers topics such as fuel-cost-adjustment mechanisms, demand-side-management, and the integration of renewable energy sources into the grid.

NON-CONFIDENTIAL 1 Undertaking U-15: 2 3 To provide an order of magnitude impact of the AA/BA FAM riders and DSM rider on each 4 individual customer class rate impact as a comparison to Figure 2-1. 5 6 Response U-15: 7 8 Please refer to th...

AI summary The response to Undertaking U-15 provides an overview of the impact of the AA/BA FAM riders and DSM rider on customer class rates in 2026, referencing specific figures and attachments. It also notes that the settlement agreement includes smoothing or mitigating the impacts of the AA/BA riders, which may lower increases for some classes in 2026 by deferring recovery to 2027.

ection is filed under subsection 93.4(4) or (5) of the Act. 4 (1) The Act is amended by adding the following after section 93.3: Definitions 93.4 (1) The following definitions apply in this section. FABI surplus, of a foreign affiliate (re...

AI summary The text outlines an amendment to the Act, specifically adding definitions under section 93.4. It defines FABI surplus in relation to a foreign affiliate, including specific conditions related to taxable surplus calculations under the Income Tax Regulations.

ductible 248(1), but does not include a natural person or a part- par l’effet de la division 95(2)f.11)(ii)(D)) nership. (contribuable) sur le total des sommes dont chacune re- présente : transaction includes an arrangement or event. (opér...

AI summary The text outlines definitions related to tax regulations, including terms such as 'transaction,' 'transferred capacity,' and provisions under subsection 95(2)f.11)(ii)(D). It discusses revenue from interests and financing of affiliated companies and sums included under specific tax subdivisions.

2 the foreign affiliate’s relevant affiliate écrit en vertu de la présente division selon les interest and financing expenses (as de- modalités réglementaires, fined in subsection 18.2(1)) (determined without regard to this clause and subs...

AI summary The text outlines specific financial calculations related to a foreign affiliate's interest and financing expenses, as well as foreign accrual property losses, under a regulatory framework. These calculations are determined without regard to certain subsections of the Income Tax Regulations.

3 les dépenses d’intérêts et de finance- (determined without regard to this clause, ment de la société affiliée pertinentes clause (D) and subsection 18.2(19)) for the (au sens du paragraphe 18.2(1)) de la socié- taxation year, and té étra...

AI summary The text outlines the determination of interest and finance expenses of a foreign affiliate, excluding specific provisions, and references the foreign affiliate's foreign accrual property loss or income for the taxation year.

DATE FILED: April 7, 2026 Page 22 of 28 DSM Rider ¢/kWh 0.729 NA NA General Tariff Demand Charge $/kW 9.809 10.697 9.1% Energy Charge (Block 1, first 200 kWh) ¢/kWh 14.989 15.039 0.3% Energy Charge (Block 2) ¢/kWh 11.925 11.698 -1.9% DSM R...

AI summary The document presents a detailed table of tariff rates for various customer categories, including changes in demand charges, energy charges, and DSM riders across different tariff structures. The data highlights percentage changes in rates from one period to another, indicating adjustments in pricing for different customer segments.

31st Smoothed 1 2026-2027 Financial Outlook (4) -2 -3 -4 -5 -6 -7 -8 -9 -10 -11 1 (1) - Compliance Rates 2026 Compliance Rates 2026 1 Compliance 2023 (1) Embedded Cost Rates FAM DSM SCRR Total Embedded Cost Rates FAM DSM SCRR Total 2 3 Res...

AI summary The document presents a financial outlook table for 2026-2027, detailing compliance rates and revenue across various customer segments, including residential, industrial, and other categories. It includes embedded cost rates, FAM, DSM, and SCRR, and provides a breakdown of total electric revenue.

CRITICAL PEAK EVENT PROCEDURE - (1) In the Winter Period, Critical Peak Events exclude all hours on the following holidays: January 1, Nova Scotia Heritage Day, Good Friday, Easter Monday, November 11, December 25 and December 26. If Janua...

AI summary The Critical Peak Event Procedure outlines the scheduling and notification process for critical peak events during the winter period, excluding certain holidays and weekends, with a limit of 18 events per winter season. Customers are notified in advance and are encouraged to reduce energy use during these events.

This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...

AI summary This rider outlines the terms for interruptible billing demand service, including customer obligations to reduce load promptly, penalties for non-compliance, and conditions for converting between interruptible and firm service. The customer must maintain a dedicated phone system and respond to interruption notices, with penalties based on residual demand and performance.

APPLICABILITY This schedule applies to all electric rate classes with the exception of the Wholesale Market Non-Dispatchable Supplier Spill Tariff, the Load Retention Tariff, and the Extra Large Industrial Active Demand Control Tariff. For...

AI summary This schedule applies to most electric rate classes, excluding specific tariffs. For customers in the Wholesale or Renewable to Retail markets, costs related to electricity efficiency and conservation activities are directly billed on their energy bills, as if they were served by NS Power under its bundled service offerings.

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

AI summary The Franchise Holder is responsible for seeking NSEB approval for all DSM activities, plans, and programs, including related costs. NS Power must apply for approval of the DSM Cost Recovery Rider amounts by October 1 of the year before program implementation and pay the approved amount monthly to the Franchise Holder.

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

AI summary The Program Cost Recovery (PCR) encompasses estimated costs for the Approved DSM Plan, including planning, implementation, and administrative expenses. These costs are allocated across rate schedules using the methodology outlined in Schedule B of the tariff.

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date of...

AI summary The Balance Adjustment (BA) is composed of BA1 and BA2, with BA being updated annually to reflect BA1 and at the end of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR will be implemented in bills starting from the effective date of the change.

2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including its components, Program Cost Recovery (PCR), and Balance Adjustment (BA).

Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.642 0.006 0.648 Small General, Small Gener...

AI summary The table outlines applicable tariffs, including PCR, BA, and DCRR rates for various service types. It also explains the calculation and application of BA2 following the conclusion of the 2023-2026 term, which will be applied over the 2027-2031 term.

1 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) General, General Time of Use, General Critical Peak Pricing, Mu...

AI summary The text defines the Approved DSM Term and provides a table with various tariff rates, including PCR, BA, and DCRR, for different service categories. These rates are relevant to demand-side management programs and cost recovery mechanisms.

cents per kilowatt-hour Interim Energy Charge During a For the first 200 kilowatt Critical hours per month per Peak Event maximum demand For all additional kilowatt-hours Effective December 1, 2025 n/a 14.287 10.990 Effective upon the date...

AI summary The document outlines energy charge rates effective from various dates, with specific rates for the first 200 kilowatt-hours per month during a Critical Peak Event and for additional kilowatt-hours. The Critical Peak Event is defined as a four-hour period during the Winter Period, between 6:00 AM and 11:00 PM.

DEMAND CHARGE As follows, per month per kilovolt ampere of maximum demand of the current month or the maximum actual demand of the previous December, January, or February occurring in the previous eleven (11) months.

AI summary The document outlines the calculation method for the demand charge, which is based on the maximum demand of the current month or the maximum actual demand from the previous December, January, or February within the last eleven months.

DEMAND CHARGE As follows, per month per kilovolt ampere of the higher of: - (a) maximum actual demand of the current month; or - (b) the maximum actual demand of the previous December, January, or February occurring in the previous eleven...

AI summary The demand charge is calculated monthly based on the higher of the current month's maximum actual demand or the highest demand from the previous eleven months, excluding peak demands during the first two hours after outage restoration. Customers are expected to manage demand peaks following outages.

Total BA = BA 1 + BA 2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date...

AI summary The Balance Adjustment (BA) is composed of BA1 and BA2, with BA updated annually and BA2 applied at the end of each Approved DSM Term. The NSEB-approved DCRR will be implemented with bills starting from the effective date of the change.

2026 DSM Cost Recovery Rider Charges Effective: January 1, 2025January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Jan...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including the Program Cost Recovery (PCR) and Balance Adjustment (BA) components. It also explains that the BA is calculated in 2027 and applied over the remaining years of the 2027-2031 term.

1 Balance Adjustment for 2023 will come into effect on January 1, 2025 and will be based on the revenue collected between February 2, 2023, and December 31, 2023. The revenue will be compared to the DSM costs incurred in that same period....

AI summary The Balance Adjustment (BA) for 2023 will be effective from January 1, 2025, and is based on revenue collected between February 2, 2023, and December 31, 2023, compared to DSM costs incurred during the same period. The Approved DSM Term refers to the full DSM Plan period in effect, such as 2023-2026 or 2027-2031.

FOR THE YEAR ENDING DECEMBER 31, 2026 (IN THOUSANDS OF DOLLARS) DEMAND CLASSIFICATION (1) (2) (3) (4) (5) (6) (7) (8) (9) (9) (10) (11) TOTAL SMALL GENERAL SMALL MEDIUM LARGE ALLOCATION COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL IND...

AI summary The text presents a demand classification table for the year ending December 31, 2026, with columns indicating various demand classes and allocation factors. It provides a structured format for categorizing demand across different sectors and sizes.

(1) INTERR. RIDER DMD ADJ. (2) (3) Peak Dmd. in KWs (at Generator) 69,594 (4) Int Credit Amount 11,165 (5) (6) PHP DEMAND ADJUSTMENT CALCULATION (7) (8) Demand Usage Annual Credit Amount Calculation Winter Month Winter Month Sum of 12 % Pr...

AI summary This document contains a table and calculation related to demand adjustment and interruption credits, including peak demand figures, credit amounts, and a breakdown of annual credit calculations based on power factor and priority levels.

RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2026 CLASS : PHP RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer G...

AI summary This document presents a rate class disaggregation analysis for the PHP class as of December 31, 2026. It includes details on rate base, variable and fixed costs, unit costs, and energy and demand metrics, providing a breakdown of generation-related financial and operational data.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 650,516 8.70% 707,116 1,567,908 83.9% 1,315,928 14.13% 1,501,844 63.28% ( 2) SMALL GENERAL 39,647 8.65% 43,0...

AI summary The text presents a table showing sales, losses, and demand metrics across various customer categories, including domestic, industrial, and municipal. It includes metrics such as peak demand, losses, and load factors for each category, with a sub-total at the bottom.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 609,862 8.66% 662,646 1,440,464 88.5% 1,275,166 13.23% 1,443,879 68.29% ( 2) SMALL GENERAL 36,873 8.60% 40,0...

AI summary The table presents data on electricity sales, losses, and demand across various customer categories in Nova Scotia, including domestic, industrial, and municipal sectors, along with percentages and totals for each category.

NOVA SCOTIA POWER INC. SALES, GENERATION AND DEMAND ANALYSIS FOR MARCH 2026 (1) (2) (3) (4) (5) (6) (7) (8) (9) ENERGY CLASS NON- SYSTEM SYSTEM DEMAND SYSTEM SYSTEM MWH LINE ENERGY COINCIDENT COINCIDENT COINCIDENT LINE COIN. PEAK COINCIDEN...

AI summary The document presents a sales, generation, and demand analysis for March 2026, detailing energy metrics such as MWH sales, line losses, energy requirements, and demand factors. It includes various categories of system demand and losses, as well as peak demand and load factor data.

NCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 575,444 8.74% 625,765 1,226,893 87.4% 1,072,148 10.95% 1,189,517 70.71% ( 2) SMALL GENERAL 36,030 8.69% 39,162...

AI summary The document presents data on electricity demand, losses, and requirements across various customer categories, including domestic, industrial, and municipal. It includes metrics such as peak demand, load factor, and losses for each category, along with a sub-total. Additional entries reference specific programs and systems like Shore Power and ELIADC.

1,143,391 2,128,880 86.2% 1,834,051 9.32% 2,005,063 76.65% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) ELIADC (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 6,369 17.0% 6,584 89,204 178.7% 60,139 16.58% 62,593 0.00% (18)...

AI summary The document contains a table of figures related to energy sales, generation, and demand analysis for April 2026, with various categories and percentages listed. It includes references to SHORE POWER, GEN.REPL./LOAD FOLL., ELIADC, and other terms, as well as a mention of a compliance filing related to the General Rate Adjustment (GRA).

NCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 444,691 8.19% 481,109 1,030,722 86.6% 892,737 9.61% 978,550 68.29% ( 2) SMALL GENERAL 27,955 8.14% 30,231 57,8...

AI summary The document presents a detailed breakdown of electricity demand, sales, losses, and requirement factors across various customer categories, including domestic, small and large general, industrial, PHP, and municipal. It includes specific percentages and numerical values for each category, with a sub-total at the bottom.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 361,131 7.97% 389,926 850,197 81.2% 690,370 8.70% 750,399 69.84% ( 2) SMALL GENERAL 25,685 7.93% 27,720 53,3...

AI summary The text presents a table showing various categories of electricity sales, losses, and demand factors across different customer classes in Nova Scotia. It includes metrics such as sales, losses, requirement, peak demand, and load factor for each category, with a sub-total at the end.

825,957 1,629,641 82.4% 1,343,472 7.09% 1,438,756 77.16% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) ELIADC (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 13,359 15.9% 13,748 71,044 255.5% 43,893 15.22% 45,553 0.00% (18)...

AI summary The text presents a table with numerical data related to sales, generation, and demand analysis for June 2026, including various categories such as SHORE POWER, GEN.REPL./LOAD FOLL., and ELIADC, along with percentages and totals. The document is part of a compliance filing related to the General Rate Adjustment (GRA) for 2026-2027.

NOVA SCOTIA POWER INC. SALES, GENERATION AND DEMAND ANALYSIS FOR JUNE 2026 (1) (2) (3) (4) (5) (6) (7) (8) (9) ENERGY CLASS NON- SYSTEM SYSTEM DEMAND SYSTEM SYSTEM MWH LINE ENERGY COINCIDENT COINCIDENT COINCIDENT LINE COIN. PEAK COINCIDENT...

AI summary The document presents a sales, generation, and demand analysis for June 2026 by Nova Scotia Power Inc., including energy sales, line losses, energy requirements, and demand metrics across different classes and system factors.

INCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 292,677 7.91% 315,832 593,240 95.7% 567,667 7.38% 609,577 71.96% ( 2) SMALL GENERAL 23,742 7.86% 25,609 51,49...

AI summary The text presents a table with data on electricity sales, losses, and demand factors across various customer categories in Nova Scotia. It includes domestic, industrial, and municipal sectors, as well as specific programs like PHP and ELIADC. The data highlights differences in sales, losses, and demand factors for each category.

INCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 319,746 7.69% 344,330 650,001 90.3% 587,067 8.34% 636,042 72.76% ( 2) SMALL GENERAL 26,458 7.64% 28,480 59,02...

AI summary The document presents a detailed breakdown of electricity demand, sales, losses, and requirement factors across various customer categories, including domestic, industrial, and municipal sectors. It includes data on peak demand, coincident sales, and losses, with a sub-total for all categories. Specific programs and systems, such as Shore Power and ELIADC, are also listed.

819,242 1,501,354 86.5% 1,299,074 6.65% 1,385,492 79.48% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) ELIADC (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 18,575 15.5% 19,085 74,444 257.5% 46,181 15.00% 47,859 0.00% (18)...

AI summary The document presents a sales, generation, and demand analysis for August 2026, including various categories such as Shore Power, Generation Replacement/Load Following, and ELIADC. It also includes a subtotal and total export figures, with some data redacted due to confidentiality.

NCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 321,630 7.30% 345,113 652,755 99.9% 652,308 8.56% 708,174 65.50% ( 2) SMALL GENERAL 26,087 7.26% 27,980 55,955...

AI summary The text presents a table with data on electricity demand, losses, and requirements across different customer categories in Nova Scotia, including domestic, industrial, and municipal sectors, along with associated factors and percentages. It includes subtotals and additional categories such as Shore Power and ELIADC.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 276,088 7.82% 297,673 576,378 93.5% 539,018 8.41% 584,352 70.75% ( 2) SMALL GENERAL 23,021 7.77% 24,810 53,4...

AI summary The document presents a detailed breakdown of electricity sales, losses, and demand across various customer categories, including domestic, industrial, and municipal sectors. It includes metrics such as peak demand, load factor, and losses, with specific data for different classes of users and programs like PHP and ELIADC.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 327,490 7.98% 353,638 763,048 87.6% 668,458 9.28% 730,459 65.07% ( 2) SMALL GENERAL 24,363 7.94% 26,296 50,4...

AI summary The text provides a detailed breakdown of electricity demand, losses, and requirement factors across various customer categories in Nova Scotia, including domestic, industrial, and municipal sectors, along with a sub-total summary of the data.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 431,585 8.60% 468,686 1,111,549 82.8% 920,296 11.77% 1,028,601 63.29% ( 2) SMALL GENERAL 28,882 8.54% 31,350...

AI summary The document presents a detailed breakdown of electricity sales, losses, and demand factors across various customer categories in Nova Scotia, including domestic, industrial, and municipal sectors, along with specific programs such as PHP and ELIADC.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 602,917 8.30% 652,943 1,344,111 91.7% 1,231,859 14.31% 1,408,115 62.33% ( 2) SMALL GENERAL 34,690 8.25% 37,5...

AI summary The text presents a table with data on sales, losses, and demand factors across various customer categories, including domestic, industrial, and municipal sectors, alongside specific programs like PHP and ELIADC. The data includes figures related to peak demand, losses, and load factors for different segments.

DETERMINATION OF CLASS NON-COINCIDENT KW DEMAND BY VOLTAGE LEVEL FOR THE YEAR ENDING DECEMBER 31, 2026 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) TOTAL SMALL GENERAL SMALL MEDIUM LARGE COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL I...

AI summary The document outlines the determination of class non-coincident kW demand by voltage level for the year ending December 31, 2026, with columns indicating various categories of demand and load classifications.

DETAIL OF MONTHLY CLASS SYSTEM COINCIDENT KW PEAK DEMAND FOR THE YEAR ENDING DECEMBER 31, 2026 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) TOTAL SMALL GENERAL SMALL MEDIUM LARGE SHORE REAL TIME MONTH COMPANY DOME...

AI summary The document presents a detailed breakdown of monthly class system coincident kilowatt peak demand for the year ending December 31, 2026, categorized by month and various demand classes. It includes data on total company demand, domestic, general, and industrial demand across different sizes and sectors.

DETAIL OF MONTHLY CLASS SYSTEM COINCIDENT KW DEMAND FOR THE YEAR ENDING DECEMBER 31, 2026 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) TOTAL SMALL GENERAL SMALL MEDIUM LARGE SHORE REAL TIME MONTH COMPANY DOMESTIC...

AI summary The document presents a detailed breakdown of monthly Class System Coincident kW demand for different categories of users across the year ending December 31, 2026. It includes data for various months, with columns representing different customer classes and demand types.

2,102 2,102 2,102 (486) AVERAGE CUSTOMERS - MEDIUM INDUST. 175 175 175 (487) AVERAGE CUSTOMERS - INDUSTRIAL LARGE 36 36 36 (488) AVERAGE CUSTOMERS - PHP 1 1 1 (489) AVERAGE CUSTOMERS - MUNICIPAL 5 5 5 (490) AVERAGE CUSTOMERS - UNMETERED 9,...

AI summary The text presents a series of numerical data points and percentages related to average customers across various categories, voltage level demand reduction, and loss factor percentages for different segments of the power system. These metrics are likely used for regulatory analysis and planning.

5) SYSTEM COINCIDENT DMD. - UNMETERED 10,903 4,016 1,573 1,956 2,351 2,163 2,349 1,958 2,033 1,487 17,133 12,711 10,902.9 (66) SYSTEM COINCIDENT DMD. - SHORE POWER (67) SYSTEM COINCIDENT DMD. - GEN. REPL. (68) SYSTEM COINCIDENT DMD. - ELIA...

AI summary The text presents a series of tables and data points related to system coincident demand, including unmetered demand, shore power, generator replacement, and other demand-related metrics across various categories and periods.

3,296 2,946 4,397 4,123 41,323.9 (92) DEMAND LINE LOSS ADJUSTMENT - ELI 2P-RTP 2,790 2,612 4,489 3,942 3,566 3,028 3,421 3,512 3,449 3,804 4,826 2,825 42,264.0 (93) DEMAND LINE LOSS ADJUSTMENT - MUNICIPAL 1,311 1,278 983 621 402 349 405 38...

AI summary The text presents numerical data related to demand line loss adjustments across various categories, including ELI 2P-RTP, municipal, unmetered, and others, with totals for demand losses and requirements for domestic use.

16,511.5 (153) Distribution BP Substation - LIR 4,727.9 (154) Distribution BP Substation - Municipal 14,042.7 (155) Distribution Primary Voltage - LIR 34,200.8 (156) Distribution Primary Voltage - Municipal 14,042.7 (157) (158) Demand Line...

AI summary The text contains a list of line items related to distribution and demand line losses, including various substation and voltage categories, with associated numerical values. It appears to be a financial or operational breakdown from a regulatory proceeding.

- - - 0.0% 0.0% 0.0% 0.0% (35) (36) DSM EXPENSES - - - - - 0.0% 0.0% 0.0% 0.0% (37) (38) FCR DEFERRAL - - - - - 0.0% 0.0% 0.0% 0.0% (39) (40) OTHER EXPENSES - - - - - 0.0% 0.0% 0.0% 0.0% (41) (42) CAPITAL RELATED EXPENSES (43) (44) GRANTS...

AI summary The text presents a table with various expense categories and percentages, including DSM expenses, FCR deferral, and depreciation for different energy sources such as steam, hydro, wind, and solar. The data shows the distribution of expenses across different years and percentages.

GENERATION FUNCTION (1) FUEL 310,870 $0 $310,870 - (2) PURCHASES - OTHER THAN BIOMASS AND WIND 27,646 $13,322 $14,324 - (3) PURCHASES - BIOMASS 20,957 $5,810 $15,147 - (4) MARITIME LINK 201,489 $97,094 $104,395 (5) PURCHASES - WIND ERIS 33...

AI summary The text outlines generation and operational costs, including fuel, purchases, imports, and maintenance expenses for various energy sources such as biomass, wind, hydro, and others. It also includes entries related to demand-side management (DSM) and regulatory affairs expenses.

0 0 0 D-3A (16) OPER. & MAINT. - RADIAL TO GENERATION TRANS. 1,291 831 44 228 26 24 28 47 39 18 6 D-3A (17) DSM 0 See DSM Allocation (18) FCR DEFERRAL 0 0 0 0 0 0 0 0 0 0 0 P-14 (19) REG. AFFAIRS - ADVOCACY EXPENSE 648 315 51 253 0 29 0 0...

AI summary The document presents a financial breakdown of various operational and maintenance costs, including depreciation, interest, and regulatory affairs expenses. It includes figures for different line items such as demand-side management (DSM), fuel cost deferral, and grants in lieu. These details are likely part of a regulatory proceeding related to utility costs and financial reporting.

0 0 -5,579 0 0 DIRECT (31) ALLOC. OF ELI 2P-RTP DMD. ADJ. 5,579 3,592 190 987 113 103 119 203 168 77 27 D-4 (32) ELI 2P-RTP PRIORITY DMD ADJ. -558 0 0 0 0 0 0 0 -558 0 0 DIRECT (33) ALLOC. OF ELI 2P-RTP PRI. DMD. ADJ. 558 359 19 99 11 10 1...

AI summary The text presents a table with various line items and allocations related to demand adjustments and generation, including figures for different categories such as transmission, operating and maintenance expenses, and regulatory affairs. It includes references to specific line items and allocations, such as 'ALLOC. OF ELI 2P-RTP DMD. ADJ.' and 'TOTAL GENERATION'.

(1) INTERR. RIDER DMD ADJ. (2) (3) Dmd. in KWs 69,857 (4) Int Credit Amount 11,207 (5) (6) PHP DEMAND ADJUSTMENT CALCULATION (7) (8) Demand Usage Annual Credit Amount Calculation Winter Month Winter Month Sum of 12 % Premium For Priority P...

AI summary This text presents a demand adjustment calculation related to a PHP demand interruption credit. It includes figures for demand in kilowatts, credit amounts, and a detailed breakdown of the annual credit calculation based on demand usage and priority levels.

RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : SMALL INDUSTRIAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Ener...

AI summary The document presents a rate class disaggregation analysis for the Small Industrial class as of December 31, 2027, detailing rate base, variable and fixed costs, and unit costs associated with generation, reliability, and total generation costs.

RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : MUNICIPAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Cust...

AI summary This document provides a rate class disaggregation analysis for the municipal class as of December 31, 2027, detailing rate base, costs, and unit costs associated with energy and demand. It includes breakdowns of variable and fixed costs, as well as units sold and demand metrics.

1,080,904 2,194,475 83.4% 1,829,155 9.33% 1,999,799 72.65% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) PHP (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 57,584 19.6% 59,124 111,807 178.9% 81,584 16.62% 84,753 0.00% (18)...

AI summary The document contains a table with sales, generation, and demand analysis for April 2027, including figures related to shore power, generation replacement, and real-time pricing. A subtotal and total before export are listed, along with export sales. The document is part of a 2026-2027 GRA Compliance Filing and is marked as redacted.

INCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 289,155 7.93% 312,074 596,618 93.7% 558,976 7.47% 600,757 72.15% ( 2) SMALL GENERAL 23,896 7.88% 25,779 53,24...

AI summary The text presents a table with data on electricity demand, losses, and factors for various customer categories in Nova Scotia, including domestic, industrial, and municipal sectors. The data includes figures for sales, losses, and demand factors, which may be relevant for regulatory analysis and planning.

INCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 316,021 7.70% 340,349 644,582 89.8% 578,781 8.50% 627,956 72.85% ( 2) SMALL GENERAL 26,618 7.65% 28,654 61,14...

AI summary The text presents a table of demand and sales data across various customer categories, including domestic, industrial, and municipal, with details on losses, peak demand, and load factors. The data highlights differences in demand patterns and efficiency across sectors.

OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 599,861 8.27% 649,442 1,400,876 88.5% 1,239,496 14.41% 1,418,145 61.55% ( 2) SMALL GENERAL 35,022 8.22% 37,8...

AI summary This table presents data on electricity sales, losses, and demand across various customer categories in Nova Scotia. It includes metrics such as peak demand, loss percentages, and load factor for different classifications of users, including domestic, industrial, and municipal sectors.

1,077,883 2,286,479 82.6% 1,889,630 12.83% 2,132,019 67.95% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) PHP (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 65,553 18.8% 67,226 102,902 271.6% 74,394 18.73% 78,035 0.00% (18)...

AI summary The document contains numerical data and a table of items related to energy management, including categories such as Shore Power, Generation Replacement, Load Follow, and Real Time Pricing. It also includes a sub-total and total figures for export sales and other energy-related metrics. The document is part of a 2026-2027 GRA Compliance Filing and includes an exhibit related to demand determination by voltage level.

DETERMINATION OF CLASS NON-COINCIDENT KW DEMAND BY VOLTAGE LEVEL FOR THE YEAR ENDING DECEMBER 31, 2027 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) TOTAL SMALL GENERAL SMALL MEDIUM LARGE COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL I...

AI summary The document presents a table outlining the determination of class non-coincident kilowatt (kW) demand by voltage level for the year ending December 31, 2027. It includes various categories of demand across different voltage levels and company classifications.

DETAIL OF MONTHLY CLASS SYSTEM COINCIDENT KW PEAK DEMAND FOR THE YEAR ENDING DECEMBER 31, 2027 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) TOTAL SMALL GENERAL SMALL MEDIUM LARGE SHORE REAL TIME MONTH COMPANY DOME...

AI summary The document provides a detailed breakdown of monthly Class System Coincident KW Peak Demand for the year ending December 31, 2027. It includes various categories such as Total, Domestic, General, Large, Industrial, Municipal, and Unmetered, with specific values for each month from January to June.

DETAIL OF MONTHLY CLASS SYSTEM COINCIDENT KW DEMAND FOR THE YEAR ENDING DECEMBER 31, 2027 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) TOTAL SMALL GENERAL SMALL MEDIUM LARGE SHORE REAL TIME MONTH COMPANY DOMESTIC...

AI summary The document presents a detailed breakdown of monthly Class System Coincident kW demand for various categories across the year ending December 31, 2027. It includes data for different company classifications, such as Domestic, General, Large, and Industrial, along with specific metrics like ELI 2P-RTP, Municipal Unmetered, and Shore Power.

11,199 11,199 (500) AVERAGE CUSTOMERS - GENERAL LARGE 20 20 20 (501) AVERAGE CUSTOMERS - SMALL INDUST. 2,127 2,127 2,127 (502) AVERAGE CUSTOMERS - MEDIUM INDUST. 175 175 175 (503) AVERAGE CUSTOMERS - INDUSTRIAL LARGE 36 36 36 (504) AVERAGE...

AI summary The text presents numerical data related to average customers across various categories, including general large, small industrial, medium industrial, and unmetered customers, along with voltage level demand reduction percentages and loss factor percentages. It includes figures for the years 2026 and 2014, as well as the Cost of Service Study (COSS).

E LOSSES - GEN.REPL. / LOAD FOLL. (32) LINE LOSSES - PHP (33) LINE LOSSES - BUTU (34) LINE LOSSES - EXTRA LI INTERRUPTIBLE 0 0 0 0 0 0 0 0 0 0 0 0 - (35) LINE LOSSES - REAL TIME PRICING LINE LOSSES - EBS/RTR (36) LINE LOSSES - EXPORT SALES...

AI summary The text presents a detailed breakdown of line losses and non-coincident demand across various classes and categories, including domestic, small general, general demand, large general, small industrial, medium industrial, and industrial large. The data includes numerical values for different time periods, though some entries are incomplete or missing.

Calendar Month of System Peak 1 January February March April May June July August September October November December Total (46) CLASS NON-COINCIDENT DMD. - UNMETERED 17,265 16,503 14,703 18,346 21,794 20,204 21,982 18,341 19,020 13,878 17...

AI summary The text presents a table with monthly data on non-coincident and coincident demand for different classes of electricity usage in Nova Scotia, including domestic, small general, and general demand, across the calendar year.

67 71,175.8 (57) SYSTEM COINCIDENT DMD. - GENERAL 388,367 382,499 333,465 270,986 240,847 257,465 277,077 251,675 277,214 288,237 323,926 306,317 388,367.2 (58) SYSTEM COINCIDENT DMD. - GENERAL LARGE 43,920 45,829 44,517 43,606 41,053 53,4...

AI summary The document presents a series of tables with numerical data related to system coincident demand across various categories, including general, large, small industrial, medium industrial, industrial large, PHP, municipal, and unmetered demand. The data spans multiple years and includes values for different demand segments.

SYSTEM COINCIDENT DMD. - GEN. REPL. (67) SYSTEM COINCIDENT DMD. - PHP (68) SYSTEM COINCIDENT DMD. - BUTU (69) SYSTEM COINCIDENT DMD. - RTP SYSTEM COINCIDENT DMD. - EBS/RTR (70) SYSTEM COINCIDENT DMD. - EXPORT SALES 0 0 0 0 0 0 0 0 0 0 0 0...

AI summary The text provides a detailed breakdown of system coincident demand across various categories, including generation replacement, PHP, BUTU, RTP, EBS/RTR, and export sales. It includes data on interruptible demand and total coincident demand at customer meters and generators from 2020 to 2027. Some data is redacted due to confidentiality.

Calendar Month of System Peak 1 January February March April May June July August September October November December Total PHP INTERRUPTIBLE COINCIDENT DEMAND AT GENERATOR 59,456 59,300 131,222 130,702 130,379 129,884 130,278 130,353 130,...

AI summary The document provides a detailed breakdown of demand and loss factor percentages across different voltage levels and sectors for a specific calendar month. It includes data on PHP interruptible coincident demand, demand line loss adjustments for domestic, small general, general, large general, small industrial, and medium industrial sectors.

31 4,803 40,978.2 (84) DEMAND LINE LOSS ADJUSTMENT - MEDIUM INDUST. 5,665 4,467 3,378 2,929 3,018 2,389 3,162 2,458 3,062 3,262 4,308 3,856 41,952.2 (85) DEMAND LINE LOSS ADJUSTMENT - LARGE INDUST. 4,412 4,466 3,238 3,018 3,058 2,592 2,974...

AI summary The text provides a detailed breakdown of demand line loss adjustment figures across various categories such as medium industrial, large industrial, PHP, municipal, and others, with numerical data spanning multiple years and categories.

Winter kW Peaks January February March April May June July August September October November December 3CP Annual Peak ATL Classes Domestic Total 1,501,844 1,443,879 1,189,517 978,550 750,399 609,577 636,042 708,174 584,352 730,459 1,028,60...

AI summary The text presents a table showing winter kW peak demand data across different classes and months for various customer categories in Nova Scotia. It includes monthly and annual peak values for Domestic Total, Small General, General, Large General, Small Industrial, Medium Industrial, and Large Industrial classes.

Winter kW Peaks January February May June July August September October November December 3CP Annual Peak ATL Classes Domestic Total 1,495,207 1,437,837 750,419 600,757 627,956 703,573 572,585 730,872 1,033,180 1,418,145 4,351,189 1,495,20...

AI summary The document presents winter kW peak data across different customer classes from January to December, including annual peak values. The data is organized by customer category, such as Domestic Total, Small General, and Large General, with specific kW values for each month and the annual peak.

y. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing RB-01 Attachment 1 has been filed electronically. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing RB-02-RB-16 Attachment 1 has been...

AI summary The document outlines the submission of various attachments for the 2026-2027 General Rate Adjustment (GRA) Compliance Filing by NS Power, including filings related to rate base, demand-side management, and other regulatory matters.

The Fuel Adjustment Mechanism (FAM) and the Actual Adjustments (AA) or Balancing Adjustments (BA) is proposed to continue to operate in the normal course during 2026 and 2027, with new Base Cost of Fuel (BCF) amounts set for 2026 and 2027....

AI summary The Fuel Adjustment Mechanism (FAM) and related adjustments are proposed to continue operating in 2026 and 2027 with updated Base Cost of Fuel (BCF) amounts. The Demand Side Management Rider is also proposed to continue, with changes to its calculation method.

illion would accrue in the deferral if PHP remains as a Below-the-Line customer for the entirety of 2026 (Undertaking U-2), and there would also be a $5.7 million fuel balance captured under the FAM;

AI summary If PHP remains a Below-the-Line customer in 2026 (Undertaking U-2), a deferral would accrue, along with a $5.7 million fuel balance captured under the Fuel Adjustment Mechanism (FAM).

[37] The terms of the settlement agreement are set out in a schedule to the agreement and provide as follows: GRA Element Settlement Terms PHP Treatment a) NS Power's 2026/2027 cost of service study includes PHP as an above-the-line custom...

AI summary The settlement agreement outlines the treatment of Port Hawkesbury Paper (PHP) in NS Power's cost of service study, including its load characteristics, interruptible credit, and the analysis of Active Demand Control (ADC) as a potential rider to the cost-based rate.

ning, and execution of the 5-Year Reliability Plan. The company indicated that the reliability team is comprised of 59 employees, who support both the operational and capital parts of this initiative. [83] There is also a requested increas...

AI summary The document discusses NS Power's proposed increases in OM&G costs for Communications and Public Affairs, attributed to new engagement initiatives and community outreach, as well as increases in Grid Modernization and Customer Integration, including Smart Meter Operations and customer engagement activities.

3.3.1.1 Findings [90] NS Power's proposed increase in OM&G costs is significant. It represents a 20% increase in 2027 (18.3% in 2026) from the OM&G costs included in rates approved in the 2023-2024 GRA. The burden is on NS Power to show th...

AI summary NS Power's proposed 20% increase in OM&G costs for 2027 is partially justified by the Board, citing increased customer service demands, the 5-Year Reliability Plan, and new grid-scale battery installations to meet RES requirements. The Board emphasizes NS Power must prove all costs are just and reasonable.

3.5.1.4 PHP Deferral [335] PHP currently takes service from NS Power under the Extra Large Industrial Active Demand Control (ELIADC) tariff, which is a Below-the-Line (BTL) tariff. The costof-service study supporting this general rate appl...

AI summary PHP was initially under the ELIADC (BTL) tariff, but NS Power's GRA assumed an ATL tariff for 2026-2027. The Board extended ELIADC until 2026 but required a successor ATL tariff (ELID) by 2025. NS Power applied for ELID, expecting PHP to switch by 2027, with ADC services and interruptible credits included in the new tariff.

[578] NS Power's proposed methodologies are listed in Table 2 in Elenchus' report: Status Quo Change Generation Allocation except for treatment of purchased power No initial classification to energy for environmental and fuel conversion re...

AI summary NS Power's proposed methodologies for allocation and classification of generation, transmission, and distribution costs are outlined in Table 2. Key changes include refunctionalization of radial-to-generation, new storage sub-functions, and the direct assignment of DSM costs without system benefit allocation.

Demand Side Management Rider Demand side management costs are currently allocated as 75% to the cost of programs undertaken for the rate class and 25% to the system benefit of the programs. NS Power is proposing to remove the allocation to...

AI summary NS Power proposes to reallocate 100% of demand side management (DSM) program costs to the benefiting rate class, eliminating the current 25% allocation to system benefits. This change aims to shift cost responsibility entirely to the classes directly benefiting from DSM initiatives.

Treatment of Port Hawkesbury Paper as an Above-the-Line Customer Port Hawkesbury Paper is currently served under a below-the-line rate with a term ending on December 31, 2026 (2025 NSEB 16). In the cost-ofservice studies for 2026 and 2027,...

AI summary Port Hawkesbury Paper (PHP) is currently under a below-the-line rate until 2026 but is modeled as an above-the-line customer in 2026/2027 cost-of-service studies. The load profile includes 8 MW firm load at three coincident peaks, 65 MW total load, and energy adjusted for projected wind farm supply from PHP's Goose Harbour Lake Wind Farm.

3.9.1 Innovation [645] In NSEB IR-132, NS Power was asked to describe any work it has done to develop new or innovative rate designs to leverage more granular data from Advanced Metering Infrastructure (AMI) meters, promote efficient use o...

AI summary In response to NSEB IR-132, NS Power outlined initiatives to innovate rate designs using AMI data, including TVP programs, customer energy management systems, and collaborations with EfficiencyOne and Port Hawkesbury Paper. These efforts aim to improve resource efficiency and adapt to decarbonization and market changes.

3.9.2.1 Findings [652] The Board accepts that there may be legitimate arguments for not setting customer charges for these classes directly from the cost-of-service study. However, given the potential impacts that the setting of customer a...

AI summary The Board acknowledges potential issues with setting customer charges directly from cost-of-service studies, emphasizing concerns about intra-class cost shifting, efficiency, and demand response. It directs NS Power to address this in future rate applications and references a method from an Ontario Energy Board discussion paper for setting fixed monthly customer charges.

4.1 Demand Side Management Cost Recovery Rider [686] In this GRA, NS Power proposed changes to the methodology for calculating the Balance Adjustment (BA) but did not propose changes to the Demand Side Management (DSM) rider amounts for 20...

AI summary NS Power proposed changes to the Balance Adjustment (BA) methodology without altering DSM rider amounts for 2026/2027. It filed a DCRR application (M12521) for 2026 DSM expenses, with the Board approving continuation of 2025 DCRR charges until further order. The 2026 DSM expenditure was set at $63.75M by legislation, with assumptions extended to 2027. NS Power argued that extending end-of-term variance recovery periods would reduce rate volatility and align with new five-year DSM planning terms.

4.1.1 Findings [693] The Board's Interim Order in Matter M12521 approved continuation of the 2025 DCRR charges commencing January 1, 2026, until further order of the Board in that matter, or as part of NS Power's GRA. In this current matte...

AI summary The Board's Interim Order in Matter M12521 continues 2025 DCRR charges until 2026, with final approval for 2026 rider amounts pending. NS Power proposes changes to the Balance Adjustment (BA) calculation but not DSM rider amounts for 2026/2027. The Board approves amended DCRR tariff amendments to address end-of-term variances and improve DSM cost recovery by allowing E1 to reallocate expenditures between rate classes.

oth ELG and ALG procedures (paras. [233-234]); - In its next depreciation study, to address Mr. Madsen's recommendations related to asset service life accounts 354, 356, 367, and 390.10 (para. [254]);

AI summary The text references ELG and ALG procedures and outlines a next depreciation study addressing Mr. Madsen's recommendations on specific asset service life accounts (354, 356, 367, 390.10) as per paragraphs [233-234] and [254].

CRITICAL PEAK EVENT PROCEDURE - (1) In the Winter Period, Critical Peak Events exclude all hours on the following holidays: January 1, Nova Scotia Heritage Day, Good Friday, Easter Monday, November 11, December 25 and December 26. If Janua...

AI summary The Critical Peak Event Procedure outlines how Nova Scotia Power Incorporated (NSPI) schedules and notifies customers during high-demand periods in the Winter. Events exclude holidays and weekends, with limits on frequency, and customers are notified in advance of higher energy charges during these periods.

per month Effective upon the date of the Board's Order $11.174 Effective January 1, 2027 $11.989 32 cents per kilovolt ampere reduction in demand charge where the transformer is owned by the customer.

AI summary The document presents two effective rates per month, one effective upon the date of the Board's Order and another effective January 1, 2027. It also mentions a reduction in demand charge based on kilovolt ampere reduction where the transformer is owned by the customer.

For customers connected at distribution level, the following charge also applies, subject to the same provisions as the Demand Charge section above. per month Effective upon the date of the Board's Order $2.161 Effective January 1, 2027 $2...

AI summary The document outlines a charge applicable to customers connected at the distribution level, with specific rates effective from the Board's Order and January 1, 2027. It also mentions a reduction in demand charge for customers owning the transformer.

This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...

AI summary This rider outlines the terms and conditions for interruptible billing demand service, including customer responsibilities, load interruption procedures, penalties for non-compliance, and conversion policies between interruptible and firm service rates. Penalties include threshold and performance components based on demand and compliance during interruptions.

APPLICABILITY This schedule applies to all electric rate classes with the exception of the Wholesale Market Non-Dispatchable Supplier Spill Tariff, the Load Retention Tariff, and the Extra Large Industrial Active Demand Control Tariff. For...

AI summary This schedule applies to most electric rate classes, excluding specific tariffs. For customers in the Wholesale or Renewable to Retail markets, costs related to electricity efficiency and conservation activities, as defined by the Public Utilities Act and approved by the Nova Scotia Energy Board, will be directly billed on the customer's energy bill as if served by Nova Scotia Power.

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

AI summary The franchise holder under the Public Utilities Act is responsible for seeking NSEB approval for all DSM activities, plans, and programs, including the DSM Cost Recovery Rider. NS Power must apply for approval by October 1 of the year before implementation and pay the approved amount monthly to fund DSM costs.

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

AI summary The Program Cost Recovery (PCR) encompasses all estimated costs for the Approved DSM Plan, including planning, implementation, and administrative expenses, and is calculated using the cost allocation methodology outlined in Schedule B of the tariff.

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date of...

AI summary The Balance Adjustment (BA) is updated annually to reflect BA1 and at the end of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR is applied to bills starting from the effective date of the change.

2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges and its components, PCR and BA, for the period from January 1, 2026, to December 31, 2026.

Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.642 0.006 0.648 Small General, Small Gener...

AI summary The table outlines applicable tariffs, including PCR, BA, and DCRR rates for various service types. It also explains the calculation of BA2 following the 2023-2026 term, which will be applied over the 2027-2031 term.

1 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) General, General Time of Use, General Critical Peak Pricing, Mu...

AI summary The text defines the Approved DSM Term and presents a table showing various tariffs, PCR, BA, and DCRR values for different service categories. It provides details on the rates applicable to various customer classes and services.

The Fuel Adjustment Mechanism (FAM) and the Actual Adjustments (AA) or Balancing Adjustments (BA) is proposed to continue to operate in the normal course during 2026 and 2027, with new Base Cost of Fuel (BCF) amounts set for 2026 and 2027....

AI summary The Fuel Adjustment Mechanism (FAM) and related adjustments are proposed to continue operating normally in 2026 and 2027 with updated Base Cost of Fuel (BCF) amounts. The Demand Side Management Rider is also proposed to continue with changes to its calculation method.

EfficiencyOne TAKE NOTICE that EfficiencyOne hereby intervenes in this proceeding in accordance with the Regulations. EfficiencyOne is a public utility and franchise holder for the provision of demand-side management to NSPI pursuant to th...

AI summary EfficiencyOne intervenes in the proceeding as the demand-side management franchise holder under the Public Utilities Act. It intends to fully participate in the hearing and provides contact details for communication.

Issue Rate design and proposed rates, including Domestic Service and Small General Customer charges, OATT, LIIR interruptible credit, DSM Rider

AI summary The issue involves rate design and proposed rates, including Domestic Service and Small General Customer charges, OATT, LIIR interruptible credit, and DSM Rider. These elements are central to the regulatory proceeding.

Request IR-43: - Reference: N-6 2026-2027 GRA Direct Evidence Appendix 7C Page 45-46 of 58 - Per N-6, (Appendix 7C), page 45-46 of 58, we understand that labour expense has increased - from 2024 compliance restated and 2024 actual to 2026...

AI summary The document requests explanations and cost breakdowns for increased labor expenses in 'transmission and distribution contractor management' from 2024 to 2026, citing factors like staffing increases, vacancies, higher utility demand, reorganization, and salary escalations. The request references Appendix 7C of the 2026-2027 GRA Direct Evidence.

Request IR-78: - Reference: FO-13 - Please provide detailed background calculations for the Deferred Charges- DSM Rider Deferral - from actual 2024 to proposed 2027. In particular, please provide any support and calculations - for adjustme...

AI summary Request IR-78 seeks detailed calculations for Deferred Charges- DSM Rider Deferral from 2024 to 2027, specifically addressing adjustments/interest outlined in FOR-13 attachment 1 lines 40-43. The request emphasizes the need for supporting documentation for these financial adjustments.

Request IR-88: - Reference: SR-04 Attachment 1 - Please provide a schedule of costs related to the most recent lag study (including costs for fuels, - OM&G labour, OM&G non-labour, grants in lieu of taxes, HST collected, HST/GST paid, and...

AI summary The request seeks a detailed schedule of costs from the most recent lag study, including fuel, OM&G labor and non-labor expenses, grants, HST, and DSM, all reconciled to the 2023 audited financial statements.

Request IR-91: - Reference: RB -02-16- Attachment 1 - Please provide detailed calculations of the 2026-2027 AFUDC, DSM, Storm, FAM & FCR - Interest.

AI summary The document requests detailed calculations for 2026-2027 AFUDC, DSM, Storm, FAM, and FCR interest, involving Nova Scotia Power Inc. (NSPI) and the Canada Revenue Agency (CRA) in a regulatory proceeding.

Questions: a) Please confirm that, while the new above-the-line (ATL) Tariff for PHP to be brought forward for approval by the Board later this year shall reflect the modeling noted above, it remains open to all Parties, including PHP, to...

AI summary The Board seeks confirmation that PHP may adopt any position in the ADC and tariff processes despite the new ATL Tariff's modeling basis, and that PHP is not obligated to accept the new ATL Tariff if the ADC and tariff outcomes are unsatisfactory post-Board decision.

NSUARB M12451 PHP Information Requests to NS Power 1 2 IR-2 3 Reference: Exhibit N-3, Direct Evidence, Section 13.5 DSM Rider, page 83: 4 5 "NS Power will make its 2026 DSM Rider application in accordance with current practice. Per COSS, 6...

AI summary The document contains information requests from the NSUARB to NS Power regarding the 2026 and 2027 DSM Rider applications and rate calculations for the Large Industrial and Above-the-Line classes. It seeks confirmation of energy requirements, revenue, and rates for these classes, assuming no R/C ratio adjustments or other riders are applied.

Request IR-135: - Reference: Exhibit N-3 GRA Direct Evidence, Section 13 Rate Design - On page 82 of the application, NS Power notes that it has updated the interruptible credit for the - Large Industrial Interruptible Rider. Please compar...

AI summary NS Power has updated the interruptible credit for the Large Industrial Interruptible Rider in its GRA application. The text requests a comparison between the avoided costs of a combustion turbine and capacity used for DSM programs.

DSM Rider

AI summary The document heading 'DSM Rider' indicates a regulatory proceeding related to Demand Side Management (DSM) programs. No substantive content is provided in the text, so key arguments, entities, or citations cannot be determined from the given material.

Request IR-143: - Reference: Exhibit N-3 GRA Direct Evidence, Section 13.5 DSM Rider - On page 82, NS Power stated: - NS Power is not proposing changes to the DSM rider amounts for 2026 or 2027. However, NS Power is proposing changes to ho...

AI summary NS Power is not proposing changes to the DSM rider amounts for 2026 or 2027 but is seeking to alter the Balance Adjustment (BA) calculation method. The request includes questions about illustrative examples, justification for the BA change, confirmation of DSM expenses, and whether specific DSM initiatives were requested from EOne.

please explain. 1 (c) When will NS Power file its FAM AA/BA Application? 2 3 4 5 (d) If the BCF is approved as filed, and the 2026 FAM AA/BA rider is approved as filed, and if the forecast bears out, should the FAM balance be nil at the en...

AI summary The text contains a series of questions and requests related to NS Power's FAM AA/BA Application, DSM budget and plan, and distribution cost adder for the Large Industrial Tariff. It asks for clarification on timing, budget increases, assumptions, and the inclusion of all riders in figures.

20 26 34 39 44 27 The GRA includes average rate increases across all customer classes of approximately 2.1% a year 28 in each of the two test years, 2026 and 2027. The rate increases for the Residential Class are 29 greater than the averag...

AI summary The GRA includes average rate increases of 2.1% annually for all customer classes, with higher increases for residential customers due to changes in the Cost of Service Model. The Consumer Advocate supports the GRA, noting reductions in revenue through cost cuts. A Board proceeding will review the Cost of Service Model, and improvements to riders and the Demand Side Management Program are included.

, page 102, line 19 to page 103, line 2. MCINNES COOPER Page 5 January 30, 2026 result in better alignment of NS Power COSS with the methodologies generally approved in other Canadian jurisdictions. Other refinements to the treatment of ge...

AI summary The text discusses refining NS Power's Cost of Service Study (COSS) to align with Canadian methodologies, including reclassifying radial transmission costs as generation-related and adjusting transmission costs to 100% demand. It also addresses demand-side management (DSM) rider weighting based on customer class benefits and emphasizes a consultative process focused on cost causation.

act of rate changes for the 2026-2027 test period. At the time of negotiations, the 2026 DSM Plan decision was pending, and the AA/BA filing was anticipated, with a material forecasted FAM balance. While the GRA (and media reports) paint t...

AI summary The document discusses rate changes for the 2026-2027 test period, noting that Large and Medium Industrial customers will face significant rate increases once riders are included. NSPI committed to working with affected parties under the Consensus Agreement. Amendments to the DSM Rider and concerns over EfficiencyOne's mid-course adjustments are highlighted.

ic tariff structure as set out above. Clause (g) outlines that NSPI may request a deferral account – the need for which is driven by the decision to assume PHP would be ATL for the entirety of 2026: (g) NS Power may seek Board approval for...

AI summary The PHP Tariff Application's deferral account provisions differ from the settled terms in the GRA. NSPI seeks Board approval for a deferral account to address revenue variances in 2026-2027 under three scenarios: (1) Board decisions conflicting with GRA assumptions, (2) tariff timing discrepancies, or (3) PHP opting out of ATL entirely. The GRA defines the deferral account's scope to these specific scenarios.

DATE FILED: February 6, 2026 Page 33 of 37 30 double recovery of amounts already embedded in rates for depreciation of the DDA 27 SBA Closing Submissions, page 7, lines 25-28. 1 assets. Finally, by limiting the deferral period to when the...

AI summary The text discusses concerns about the double recovery of depreciation costs for DDA assets and references the Public Utilities Act and its enabling regulations, which may incentivize NSPI to recover securitization debt promptly.

[37] The terms of the settlement agreement are set out in a schedule to the agreement and provide as follows: GRA Element Settlement Terms PHP Treatment a) NS Power's 2026/2027 cost of service study includes PHP as an above-the-line custom...

AI summary The settlement agreement outlines the treatment of Port Hawkesbury Paper (PHP) in NS Power's 2026/2027 cost of service study. It includes PHP as an above-the-line customer, load characteristics for firm and interruptible loads, and the value of interruptible credits. It also mentions discussions on Active Demand Control (ADC) and its potential cost recovery as a rider.

3.3 Operating, Maintenance and General Costs

AI summary This section discusses Operating, Maintenance and General (OM&G) costs, a critical component in utility regulatory proceedings. It likely addresses cost structures, recovery mechanisms, and compliance with Nova Scotia's energy regulations, involving entities like Nova Scotia Power Inc. and the Nova Scotia Utility and Review Board.

3.5.1.4 PHP Deferral [335] PHP currently takes service from NS Power under the Extra Large Industrial Active Demand Control (ELIADC) tariff, which is a Below-the-Line (BTL) tariff. The costof-service study supporting this general rate appl...

AI summary PHP currently uses NS Power's ELIADC BTL tariff, but a GRA assumed an ATL tariff by 2026. NS Power extended ELIADC until 2026 (M12184) and applied for a successor ELID ATL tariff (M12661), with PHP expected to switch by 2027. The GRA included ADC service recovery and interruptible credits for ATL customers.

Demand Side Management Rider Demand side management costs are currently allocated as 75% to the cost of programs undertaken for the rate class and 25% to the system benefit of the programs. NS Power is proposing to remove the allocation to...

AI summary NS Power proposes to reallocate 100% of demand side management (DSM) program costs to the benefiting rate class, eliminating the current 25% allocation to system benefits. This change aims to shift cost distribution from system-wide benefits to specific rate classes.

s to demand. Additionally, she submitted an adjustment should be made to recognize the minimum system's peak load carrying capability. These issues are discussed in more detail later in this decision. [602] In their closing submissions, pa...

AI summary The document discusses a regulatory proceeding involving a settlement agreement on cost-of-service methodology changes, with the Industrial Group opposing proposed adjustments due to insufficient evidence. The Basic Customer method's limited use in Canada and flaws in its cost allocation are highlighted, while the minimum system method remains recognized in the NARUC Cost Allocation Manual. Parties seek approval of the settlement terms pending future proceedings.

3.9.1 Innovation [645] In NSEB IR-132, NS Power was asked to describe any work it has done to develop new or innovative rate designs to leverage more granular data from Advanced Metering Infrastructure (AMI) meters, promote efficient use o...

AI summary NS Power outlined initiatives to innovate rate designs using AMI data, including TVP programs, customer energy management systems, and collaborations with EfficiencyOne and Port Hawkesbury Paper. These efforts aim to promote efficient resource use and adapt to market changes from decarbonization and decentralization.

3.9.1.1 Findings [647] The Board accepts that NS Power is engaged in appropriate activities relating to the development of new rate designs. However, the Board believes that more can be done and encourages NS Power to do so. For example, w...

AI summary The Board acknowledges NS Power's efforts in developing new rate designs but urges improvement, noting limited customer rate options and operational challenges from outdated systems and a cyber attack. The TVP program's suspension highlights these issues, while Bonbright's criteria emphasize dynamic rate structures aligned with energy transition goals.

3.9.2.1 Findings [652] The Board accepts that there may be legitimate arguments for not setting customer charges for these classes directly from the cost-of-service study. However, given the potential impacts that the setting of customer a...

AI summary The Board acknowledges potential issues with directly setting customer charges from cost-of-service studies but emphasizes the need for a principled basis to avoid intra-class cost shifting and ensure fairness. They direct NS Power to address this in the next rate application and reference methods from the Ontario Energy Board's discussion paper.

3.10 Miscellaneous Charges and Regulations

AI summary The section '3.10 Miscellaneous Charges and Regulations' outlines various charges, adjustments, and regulatory frameworks relevant to utility operations and rate structures in Nova Scotia. It references multiple acronyms and entities involved in energy regulation and management.

4.1 Demand Side Management Cost Recovery Rider [686] In this GRA, NS Power proposed changes to the methodology for calculating the Balance Adjustment (BA) but did not propose changes to the Demand Side Management (DSM) rider amounts for 20...

AI summary NS Power proposed changes to the Balance Adjustment (BA) methodology in its GRA but maintained 2026/2027 DSM rider amounts. The Board approved continuation of 2025 DCRR charges until further order. NS Power assumed $63.75M DSM expenditure for 2027, aligning with legislative requirements. The new BA proposal extends variance recovery/refund periods to reduce rate volatility and reflect multi-year DSM planning.

4.1.1 Findings [693] The Board's Interim Order in Matter M12521 approved continuation of the 2025 DCRR charges commencing January 1, 2026, until further order of the Board in that matter, or as part of NS Power's GRA. In this current matte...

AI summary The Board approved continuation of 2025 DCRR charges until further order or as part of NS Power's GRA. NS Power proposes changes to the Balance Adjustment (BA) calculation but not DSM rider amounts for 2026/2027. The amended DCRR tariff aims to address end-of-term variances and improve DSM cost recovery, leading to approval by the Board.

SUMMARY OF MAJOR FINDINGS AND DIRECTIVES [733] The Board approves most components of the settlement agreement, subject to its findings below that amend the application. The following are approved:

AI summary The Board approves most components of the settlement agreement, subject to amendments based on its findings. Key components include adjustments to demand-side management programs and cost recovery mechanisms, with specific conditions for implementation.

CRITICAL PEAK EVENT PROCEDURE - (1) In the Winter Period, Critical Peak Events exclude all hours on the following holidays: January 1, Nova Scotia Heritage Day, Good Friday, Easter Monday, November 11, December 25 and December 26. If Janua...

AI summary This section outlines the procedure for Critical Peak Events during the Winter Period, including excluded holidays, scheduling criteria, customer notifications, and limitations on the frequency of events.

(a) The customer must commence service under this tariff on November 1st, unless NSPI grants a waiver. - (b) The customer must be equipped with a standard Smart Meter. - (c) The customer must be on electronic billing and have a MyAccount p...

AI summary The text outlines conditions for customers to commence service under a specific tariff, including requirements for Smart Meters, electronic billing, and restrictions on Net Metering service. NSPI retains the authority to limit enrollment or close it temporarily.

DEMAND CHARGE per month per kilovolt ampere of maximum demand Effective upon the date of the Board's Order $7.496 Effective January 1, 2027 $8.143 32 cents per kilovolt ampere reduction in demand charge where the transformer was owned by t...

AI summary The document outlines the demand charge rates effective from the date of the Board's Order and January 1, 2027. It also specifies a reduction in demand charge for customers with transformers owned prior to February 1, 1974, or under Special Condition (2).

INTERRUPTIBLE RIDER TO THE LARGE INDUSTRIAL TARIFF (RATE CODE 25) Customers who qualify for interruptible service will receive a per month per kilovolt ampere reduction in demand charge for billed interruptible demand, as shown in the tabl...

AI summary The interruptible rider to the Large Industrial Tariff (Rate Code 25) provides a monthly reduction in demand charges based on billed interruptible demand, defined as the difference between contracted firm demand and billing demand. Credits apply only when billing demand is less than contracted demand, with specific rules for calculating billed interruptible demand.

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

AI summary The franchise holder under the Public Utilities Act must seek NSEB approval for all DSM activities, plans, and programs, and itemize related costs. NS Power must apply for DSM Cost Recovery Rider amounts by October 1 each year and pay the approved amount monthly to the Franchise Holder.

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

AI summary The Program Cost Recovery (PCR) encompasses all estimated costs for the Approved DSM Plan, including planning, development, implementation, and evaluation, and is calculated using the cost allocation methodology in Schedule B of the tariff.

Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date of...

AI summary The Balance Adjustment (BA) is updated annually and at the end of each Approved DSM Term, with the NSEB-approved Demand Side Management Cost Recovery Rider (DCRR) being implemented in bills after its effective date.

2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...

AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the year 2026, including its components PCR and BA, effective from January 1, 2026, to December 31, 2026.

1 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) General, General Time of Use, General Critical Peak Pricing, Mu...

AI summary The document defines the Approved DSM Term as the full DSM Plan period in effect, such as 2023-2026 or 2027-2031. It also presents a table outlining various applicable tariffs, including PCR, BA, and DCRR values for different service categories.

1 costs associated with the DDA to the weighted average of 2 Nova Scotia Power's rate base and allocate those 3 classified costs by a weighted average of the allocation 4 of rate base. Is that correct? 5 A. (Blair) Yes, that's correct. 6 Q...

AI summary The discussion centers on the allocation of costs associated with the DDA (Demand-side Management Program) to Nova Scotia Power's rate base. The witness confirms the current allocation method and notes that the DDA's impact on rates is minimal due to securitization, which is expected to reduce the amount allocated to the DDA.

1 cost of service, Nova Scotia Power is proposing to remove 2 the allocation system benefit so that 100 percent of DSM 3 costs would be allocated to classes in accordance to 4 program spending. Is that correct? 5 A. (Willett) That's correc...

AI summary The discussion revolves around Nova Scotia Power's proposal to allocate 100% of DSM costs to classes based on program spending, and a review of an analysis that suggested only a small system benefit from DSM, contrary to initial assumptions.

NSP COST OF SERVICE PANEL 183 Questions, (Chair) 1 100 percent demand to the primary systems. It would be 12 A. (Blair) That's correct. 13 Q. And can you say why you don't 14 agree with that? 15 A. (Blair) One of the this 16 report, it's a...

AI summary The discussion revolves around the allocation of costs in a demand-side management context, with a mention of a report being perceived as more advocacy-oriented than focused on proper allocation.

NSP DEPRECIATION PANEL 205 In-ch, (Clarke) 1 been conducting depreciation studies for utility companies 14 as of kind of January 7, 2026, the rates that are in place 15 are the ones that were in place for 2025; correct? 16 (Williams) They'...

AI summary The document discusses depreciation studies for utility companies, specifically referencing the general rates in place as of January 7, 2026, which are based on the 2025 rates. It mentions the inclusion of depreciation expenses and financing costs for the DDA (Demand-side Management Program) in the general rates confirmed in the previous GRA (General Rate Application).

1 within this proceeding does show a different impact 2 towards the domestic class as compared to some of the 3 other rate classes. Is that fair? 4 A. (Williams) Yes. 5 Q. But you can confirm for me that 6 the rates that are applied for in...

AI summary The discussion highlights that the rates applied in the proceeding do not fully represent the actual rates charged in 2026 and 2027, with additional riders such as DSM and securitization being applicable in those years.

1 when that comes on, and the cost apportionment of the cost 2 related to securitization is, as we've previously 3 discussed, yet to be determined, but it is expected that 4 it would be in place during the test period. And then, 5 obviousl...

AI summary The text discusses ongoing regulatory proceedings involving rider applications, including the 2026 DSM Rider Application (Matter M12521) and the FAM AA/BA rider, which relates to true-up of FAM costs. The discussion also touches on securitization cost apportionment and the expected implementation of cost recovery mechanisms during the test period.

picture so that if things were to be taken out of the 1 Settlement Agreement, it would show a full picture as to 2 how this will impact our customer class. 3 THE CHAIR: I think that would be 4 helpful, Mr. Williams. I'd assume you'd do it...

AI summary The discussion revolves around the impact of the Settlement Agreement on customer classes and the need to provide a detailed breakdown of the AA/BA FAM riders' effect on individual customer class rates. The Chair requests a formal undertaking to articulate the information for the record.

1 JONATHAN MacINTOSH, Previously Affirmed: 15 is that would relate to the incentives that would be in 16 place to fund or pay for some of those and changes to 17 those programs. 18 The elimination of those Q. 19 incentives. Okay. INTERNATI...

AI summary The text discusses the impact of reducing heat pump programs on load forecasts and rates, as well as the fuel cost smoothing mechanism, including over-collection in 2026 and under-collection in 2027. These topics are part of a regulatory proceeding involving rate adjustments and program evaluations.

INTERNATIONAL REPORTING INC. CERTIFIED COURT REPORTERS 1 2027 period than it is currently. 2 In addition, the as I mentioned, 3 the large developer support program, that is a newer 4 program. 5 Q. How is the scope from My Energy 6 Insights...

AI summary The discussion focuses on the expansion of the My Energy Insights program and its impact on Nova Scotia Power's costs. The program is expected to grow in '26 and '27 with increased customer uptake, though specific cost implications are not detailed.

INTERNATIONAL REPORTING INC. CERTIFIED COURT REPORTERS Q. And in speaking with my friend concerning the numbers set by Ontario I believe you said that the number was perhaps dated or old. A. Oh, I just mean simply that I understand this wa...

AI summary The witness discusses the Minimum System used by utilities, noting that it may have grown over time with larger equipment installations and that current usage could reflect updated system capabilities. The discussion also touches on demand-related costs and class revenue percentages.