N-42026-2027 GRA PR 01-03 - Proposed Rates (Tariffs)
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3 Proposed Rates (Tariffs). 4 5 Submission: 6 - 7 The proposed tariffs are provided as Attachment 1 (clean versions) and Attachment 2 (redline - 8 versions), as follows: 9 10
AI summary The document outlines proposed tariffs for a Nova Scotia regulatory proceeding, with clean and redline versions provided in Attachments 1 and 2. The submission includes these attachments as part of the rate proposal process.
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.
STORM COST RECOVERY RIDER Storm Cost Recovery charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.
AI summary The Storm Cost Recovery Rider applies additional charges or credits (in cents per kilowatt-hour) to the Tariff for the current rate year, in addition to the energy charge.
AVAILABILITY This tariff is applicable to electric energy used by any customer in a private residence for the customer's own domestic or household use, including lighting, cooking, heating, or refrigeration purposes. Upon application to th...
AI summary The Domestic tariff applies to residential electric energy use for domestic purposes, including specific conditions for outbuildings. It distinguishes between personal and commercial use, with the Public Utilities Act, R.S.N.S. 1989, c. 380, as amended, governing its applicability.
Optional Green Power Rider Customers taking service under this rider may choose to support NSPI's Green Power program by purchasing "blocks" of Green Power. For every block purchased, NSPI will provide 125 kWh per month from green energy s...
AI summary The Optional Green Power Rider allows customers to support NSPI's Green Power program by purchasing blocks providing 125 kWh/month of green energy at $5/month, in addition to standard Domestic Service rate charges. This displaces fossil fuel energy usage.
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.
CUSTOMER CHARGE per month Effective January 1, 2026 $20.24 Effective January 1, 2027 $21.38 ENERGY CHARGE cents per kilowatt-hour During a Critical Peak Event Non-critical Peak Hours Effective January 1, 2026 183.593 15.511 Effective Janua...
AI summary The document outlines the customer charge and energy charge rates effective January 1, 2026, and January 1, 2027. The customer charge increases from $20.24 to $21.38 per month. The energy charge includes a higher rate during Critical Peak Events (183.593 cents per kilowatt-hour in 2026, 193.231 cents in 2027) compared to non-critical peak hours (15.511 cents in 2026, 16.081 cents in 2027). A Critical Peak Event is defined as a four-hour period during the winter months.
The Critical Peak Event pricing applies when a Critical Peak Event is called. In all other hours in the Winter Period, and for all hours in the Non-Winter Period, the rate shall be the Non-critical Peak Hours rate in the table above.
AI summary The document outlines the application of Critical Peak Event pricing, which is only applicable during a Critical Peak Event. Outside of these events, the rate defaults to the Non-critical Peak Hours rate during the Winter and Non-Winter Periods.
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.
FUEL ADJUSTMENT MECHANISM (FAM) The FAM Actual Adjustment (AA) and Balance Adjustment (BA) charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the FAM Tariff, shall apply, in additio...
AI summary The Fuel Adjustment Mechanism (FAM) applies Actual Adjustment (AA) and Balance Adjustment (BA) charges or credits in cents per kilowatt-hour to the Tariff for the current rate year, in addition to the energy charge. These adjustments are outlined in the FAM Tariff.
FUEL ADJUSTMENT MECHANISM (FAM) The FAM Actual Adjustment (AA) and Balance Adjustment (BA) charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the FAM Tariff, shall apply, in additio...
AI summary The Fuel Adjustment Mechanism (FAM) outlines Actual Adjustment (AA) and Balance Adjustment (BA) charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, as detailed in the FAM Tariff. These adjustments apply in addition to the energy charge.
This tariff is only available to customers employing electric-based heating systems utilizing Electric Thermal Storage (ETS) equipment, and electric in-floor radiant heating systems utilizing thermal storage, and appropriate timing and con...
AI summary This tariff applies to customers with electric heating systems, including Electric Thermal Storage and in-floor radiant heating, and is available for domestic use in private residences. Specific rules apply for outbuildings on residential property, depending on their primary use.
- (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) NSPI may limit the number of customers who may subscribe to thi...
AI summary This section outlines the conditions for customers to subscribe to a specific tariff, including requirements to commence service on November 1st, the need for a Smart Meter, and restrictions on seasonal and net metering services.
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).
ENERGY CHARGE cents per kilowatt-hour For the first 200 kilowatt During a hours per month per Critical Peak maximum demand after Event Critical Peak Event usage For all additional kilowatt-hours Effective January 1, 2026 143.408 12.265 10....
AI summary The document outlines the Energy Charge structure, including rates for the first 200 kilowatt-hours and additional usage during Critical Peak Events, effective January 1, 2026, and January 1, 2027. A Critical Peak Event is defined as a four-hour period during the Winter Period, between 6:00 AM and 11:00 PM.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The maximum charge per kWh, applying to that portion of the bill which is not concerned with determination of the cost of the Critical Peak Events, will be that for a billing load factor of I 0% except t...
AI summary The text outlines the maximum charge per kWh applicable to portions of the bill not related to Critical Peak Events, with a billing load factor of 100%, and specifies that the minimum monthly bill cannot be less than a defined amount.
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 per kilowatt for customers who own transformers predating February 1, 1974, or under Special Condition (2).
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall not be less than the following. per month Effective January 1, 2026 $22.16 Effective January 1, 2027 $23.07 AVAILABILITY CO...
AI summary The text establishes a minimum monthly bill requirement, ensuring that even with a billing load factor of 10%, customers are not charged less than specified amounts effective January 1, 2026, and January 1, 2027.
ENERGY CHARGE cents per ki cents per kilowatt-hour Non-winter Period Off-peak On-peak April 1 through October 31 9:00 PM to 7:00 AM 7:00 AM to 9:00 PM Effective January 1, 2026 11.877 14.104 Effective January 1, 2027 11.858 14.081 cents pe...
AI summary The document outlines energy charge rates for Nova Scotia Power Inc. (NSPI) during non-winter and winter periods, with distinct on-peak, mid-peak, and off-peak pricing effective January 1, 2026, and 2027. Peak rates apply on weekends and specific holidays, including January 1, Good Friday, and Christmas.
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.
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 monthly based on the kilovolt ampere of maximum demand from the current month or the highest actual demand recorded in the previous December, January, or February over the past eleven months.
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required to make a c...
AI summary The special conditions outline requirements for metering and service provisions. Metering is typically at the low voltage side, but primary metering requires customer capital contributions to cover cost differences. Adjustments to kWh readings occur at high voltage levels. Non-standard service provisions may require customer ownership of transformers. Rate Code 22 applies to specific power ranges.
MINIMUM MONTHLY CHARGE The minimum monthly charge shall be as follows.
AI summary The document outlines the minimum monthly charge, though specifics are referenced in an image. NSPI is involved in the proceeding, but no detailed arguments or methodologies are presented in the provided text.
As follows, 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. per month Effective January 1, 2026 $9.280 Eff...
AI summary The text outlines a rate structure based on kilovolt ampere of maximum demand, with specific rates effective January 1, 2026, and January 1, 2027. It also references a 'Distribution Cost Adder' section, indicating potential additional costs related to distribution.
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 kilovolt-ampere reduction in demand charges for qualifying customers. The credit is based on the difference between contracted firm demand and billing demand, with specific rules for when the credit applies.
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 $7.667 respectively.
Availability These rates shall be applicable to the supply, operation, and maintenance, or where indicated, operation and maintenance only, of street and area lighting. Except where otherwise indicated, the rates apply to fixtures operatin...
AI summary The rates apply to supply, operation, and maintenance of street and area lighting, excluding costs from vandalism, which are charged to the customer. Fixtures operate approximately 4,000 hours annually.
Rates
AI summary The document section titled 'Rates' is present but contains no substantive content or analysis. Key acronyms related to regulatory mechanisms and entities are noted but not elaborated upon in the provided text.
(a) Operating, Maintenance, and Capital (full charge) kWh per per month ($) Rate Code Watts month 2026 2027 Other 121 250 100 26.76 28.87 122 400 150 36.51 39.40 123 70 32 13.47 14.54 124 100 45 16.00 17.27 125 150 65 20.01 21.59 126 100 9...
AI summary The table outlines rate codes (121-126) with associated wattage, kWh per month, and monthly charges for 2026 and 2027, reflecting operating, maintenance, and capital cost structures. Rate code 126 includes a note on 'Continuous operation.'
Demand Charge per month per kilowatt of connected load Effective January 1, 2026 13.499 Effective January 1, 2027 14.568 Energy Charge cents per kilowatt-hour for the first 200 kilowatt-hours per month per kilowatt of maximum demand for al...
AI summary The text provides details on demand and energy charges effective from January 1, 2026, and January 1, 2027, including rates per kilowatt of connected load and per kilowatt-hour of energy consumption.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate shall be $ as follows per month if such unmetered se...
AI summary The document specifies that the maximum charge per kWh is based on a billing load factor of 10%, with a minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate, applicable when unmetered service is billed separately from any metered account.
Maintenance Charge (if applicable) Cost of normal fixture maintenance and bulb replacement on the basis of current cost levels shall be used to calculate the monthly maintenance charge. This portion of the rate does not include any provisi...
AI summary The maintenance charge is calculated using current costs for normal fixture maintenance and bulb replacement. It excludes globe washing, cleaning, and vandalism-related repairs, which are billed separately to customers.
Maximum per kWh Charge/Minimum Bill The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall be as follows per month if such unmetered service is billed separately from any metered...
AI summary The document outlines the maximum charge per kWh based on a 10% billing load factor and specifies that a minimum monthly bill applies for unmetered services billed separately from metered accounts.
FUEL ADJUSTMENT The applicable charges for electric service to the Company's retail and municipal customers shall be increased or decreased to the nearest 0.001 cents per kWh to recover or credit the difference in actual fuel cost from the...
AI summary The Fuel Adjustment Mechanism (FAM) adjusts charges for electric service to NSPI's retail and municipal customers based on actual fuel costs compared to base rates using a rate class-specific formula.
Fuel Adjustment Rider = AA + BA Where: "AA" is a rate class-specific Actual Adjustment which is the difference between fuelrelated costs recovered from a rate class through the application of the base rates during the previous calendar yea...
AI summary The Fuel Adjustment Rider is calculated as the sum of AA and BA. AA represents the difference between fuel costs recovered through base rates and actual fuel costs for a rate class. BA adjusts for over- or under-collections from prior adjustments.
(1) Base Cost of Fuel The Base Cost of Fuel can be re-set in a General Rate Application or, absent a General Rate Application, every second year as part of the FAM adjustment process. Changes in the Base Cost of Fuel will be reflected in c...
AI summary The Base Cost of Fuel is reset via General Rate Applications or every two years through the FAM adjustment process. Changes affect customer rates using the Board-approved Cost of Service Methodology, applied consistently across customer classes.
(2) Incentive For a total fuel cost variance of up to $50 million dollars (Actual Fuel Costs - [(Actual Sales) x (Base Fuel Cost $/MWh)]), 90% of any savings or increase in cost will be credited or charged to customers. The portion of any...
AI summary The incentive structure outlines that for fuel cost variances up to $50 million, 90% of savings or additional costs are passed to customers. Excess variances are fully applied in the 'AA' calculation. Credits and charges are applied to the energy component of rates on a cents per kWh basis.
(a) To non-FAM classes When a customer transitions its load, whether in whole or in part, from a FAM class to a non-FAM class, NS Power shall determine the outstanding fuel cost imbalance of the customer at the time of transition. This det...
AI summary When customers transition from FAM to non-FAM classes, NS Power must calculate and adjust fuel cost imbalances, subject to NSEB approval. Adjustments are resolved through agreement between NS Power and the customer or by NSEB determination if unresolved.
(b) From non-FAM classes When a customer transitions its load, whether in whole or in part, to a FAM class from a non-FAM class, the customer will pay (or be reimbursed) outstanding FAM balances outside of the Fuel Adjustment Rider, on rea...
AI summary When customers transition from non-FAM classes to FAM classes, they pay or are reimbursed outstanding FAM balances outside the Fuel Adjustment Rider on reasonable terms agreed between the customer and NS Power, subject to NSEB approval. The process outlines charge structures by rate class.
Point-to-Point Transmission Service 2026 Delivery Period Charge ($) Yearly: One twelfth of $1,953.42 /MW of Reserved Capacity per year Monthly $162.79 /MW of Reserved Capacity per month Weekly $37.57 /MW of Reserved Capacity per week On-pe...
AI summary The document outlines Reserved Capacity charges for Point-to-Point Transmission Service in 2026 and 2027, detailing varying rates per delivery period (yearly, monthly, weekly, etc.).
Nova Scotia Power Incorporated Page 5 of 23 Open Access Transmission Tariff 2027 Delivery Period Charge ($) Monthly $176.94 /MW of Reserved Capacity per month Weekly $40.83 /MW of Reserved Capacity per week On-peak daily $8.17 /MW of Reser...
AI summary The document outlines Nova Scotia Power Inc.'s (NSPI) Open Access Transmission Tariff, specifying reserved capacity charges for different time periods (monthly, weekly, daily on/off-peak, and hourly on/off-peak). On-peak days are defined as Monday to Friday, with on-peak hours from 09:00 to 24:00 Atlantic Time.
SCHEDULE 3: REGULATION AND FREQUENCY RESPONSE SERVICE Regulation and Frequency Response Service is necessary to provide for the continuous balancing of resources (generation and interchange) with load and for maintaining scheduled Intercon...
AI summary Regulation and Frequency Response Service ensures continuous balancing of generation/load and maintains 60 Hz frequency. The Transmission Provider (or Operating Area operator) must offer this service, with Transmission Customers required to purchase it or arrange alternatives. Monthly charges apply, with costs passed through if the Operating Area operator provides the service.
The minimum period for which this service is available from the Transmission Provider is one day. 2026 Delivery Period Charge ($) Yearly: One twelfth of $3,099.33 /MW of Reserved Capacity per year
AI summary The document specifies that the minimum service period from the Transmission Provider is one day and outlines a yearly charge of $3,099.33 per MW of Reserved Capacity, divided into twelve monthly payments.
The Transmission Customer shall compensate the Transmission Provider each month for Reserved Capacity at the sum of the applicable charges set forth below. 2026 Charge ($) Yearly delivery: One twelfth of the demand charge of $63,996.09 /MW...
AI summary The Transmission Customer is required to pay the Transmission Provider monthly fees for Reserved Capacity based on different delivery periods (yearly, monthly, weekly, on-peak daily, and off-peak daily) with varying rates for 2026 and 2027.
Nova Scotia Power Incorporated Page 21 of 23 Open Access Transmission Tariff - (ii) any customer-initiated requests for discounts (including requests for use by one's Wholesale Merchant or an affiliate's use) must occur solely by posting o...
AI summary The document outlines rules for discount requests and postings on OASIS, requiring equal application of discounts to all eligible customers on unconstrained paths. On-peak days are defined as Monday to Friday, and on-peak hours as 09:00 to 24:00 Atlantic Time.
SCHEDULE 9: REAL POWER LOSS FACTORS For Point-to-Point service, the Transmission Provider will seasonally calculate loss factors to be used on a path-by-path basis. For each season, winter and summer, the power flow models used to calculat...
AI summary The document outlines procedures for calculating and applying real power loss factors for Point-to-Point and Network Service by the Transmission Provider (NSPI). Seasonal and annual loss factors are determined, with system average factors for Network Service and locational factors for new generation. Loss factors are posted on OASIS, and customers must account for losses in their service requests.
APPLICABILITY This schedule provides charges for Distribution System Access applicable to distribution-connected Renewable to Retail (RtR) Customers receiving supply of renewable low-impact electricity from a Licenced Retail Supplier as pr...
AI summary The schedule outlines charges for Distribution System Access applicable to Renewable to Retail (RtR) customers in Nova Scotia, who receive renewable low-impact electricity from licensed retail suppliers under the Electricity Act (Nova Scotia).
\ Note: for certainty, all capitalized terms shall, unless otherwise defined herein, have the meanings ascribed thereto in Distribution Tariff. Small Industrial Demand Charge ($/kVA) Minimum Monthly Charge ($/month) Transformer Ownership C...
AI summary The document outlines proposed changes to demand charges and minimum monthly charges for various customer categories in Nova Scotia, effective January 1, 2026, and 2027. Rates are adjusted for small, medium, large industrial, and unmetered customers, with transformer ownership credits applied where applicable. The note clarifies the application of demand charges based on historical demand data.
DEMAND SIDE MANAGEMENT (DSM) COST RECOVERY RIDER The Demand Side Management Cost Recovery Charge (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Demand Side Management Cost Recovery Rider, shal...
AI summary The Demand Side Management Cost Recovery Rider imposes an additional charge per kilowatt-hour on the Tariff for the current rate year, applied alongside the energy charge. This mechanism enables cost recovery for demand-side management initiatives.
STORM COST RECOVERY RIDER Storm Cost Recovery charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.
AI summary The Storm Cost Recovery Rider outlines charges or credits in cents per kilowatt-hour applicable to the current rate year's Tariff, in addition to the energy charge.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The same maximum per kWh charges and minimum bills will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above.
AI summary The document states that maximum per kWh charges and minimum bills for NS Power Bundled Service will follow existing tariff rates for each Rate Class, as outlined in the proceeding.
RATE FOR 2025 Tariff Storm Riders in cents per kWh1 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.374 Small General, Small General Time of Use, Small General Critical...
AI summary The document outlines the storm riders for 2025 and 2026, showing varying rates per kWh across different tariff categories. Notably, the rate for Domestic Service Critical Peak Pricing drops to 0.000 in 2026, while other categories maintain or adjust their rates.
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.
SCHEDULE A Effective: January 1, 2026
AI summary Schedule A, effective January 1, 2026, outlines regulatory provisions for Nova Scotia Power Inc. (NSPI) under the jurisdiction of the Nova Scotia Energy Board (NSEB). Key elements include the Fuel Adjustment Mechanism (FAM) and Demand Side Management Cost Recovery Rider (DCRR).
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.
STORM COST RECOVERY RIDER Storm Cost Recovery Ccharges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year, shown in the Storm Cost Recovery Rider, shall apply, in addition to the energy charge.
AI summary The Storm Cost Recovery Rider establishes charges or credits (in cents per kilowatt-hour) applicable to the Tariff for the current rate year. These charges apply in addition to the energy charge, as outlined in the rider.
Optional Green Power Rider Customers taking service under this rider may choose to support NSPI's Green Power program by purchasing "blocks" of Green Power. For every block purchased, NSPI will provide 125 kWh per month from green energy s...
AI summary Customers under the Optional Green Power Rider may purchase 'blocks' of Green Power from NSPI for $5/month, receiving 125 kWh/month from renewable sources. This charge is added to the Domestic Service rate bill, displacing fossil fuel energy.
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 The document defines 'Green Power' as renewable energy with minimal environmental impact, certifiable by third parties. Service under the rider may be limited by the company based on available green energy levels. A rate code (70) is referenced, though no specific matter or board orders are cited.
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.
DOMESTIC SERVICE TIME OF USE TARIFF Page 3 of 3 Rate Code 80
AI summary The document is page 3 of 3 for the Domestic Service Time of Use Tariff, listing Rate Code 80. No further details or arguments are provided in the text.
Effective: February 2, 2023 Annliachla in Dasamhan cents per ki lowatt-hour Applicable in December, January, and February 7:00 AM to 12:00 PM 12:00 PM to 4:00 PM 4:00 PM to 11:00 PM 11:00 PM to 7:00 AM Effective February 2, 2023 21.377 16....
AI summary The document outlines electricity rate schedules effective from February 2, 2023, with different rates for various time periods throughout the day. The rates are set to change on January 1, 2024, 2026, and 2027, with the 2026 rates highlighted. These rates apply to weekdays, with special billing for weekends and statutory holidays.
DOMESTIC SERVICE TIME-OF-DAY TARIFF (OPTIONAL) Page 3 of 3 Rate Codes 05, 06 Any outbuilding located on residential property adjacent to a domestic dwelling and supplied electrically through a separate meter shall have rates applied in acc...
AI summary The document outlines rules for applying tariffs to outbuildings on residential property. If supplied via a separate meter, rates are based on actual use. For personal use, the Domestic tariff applies; for commercial use, General or Industrial tariffs are used.
MINIMUM MONTHLY CHARGE The minimum monthly charge shall be as follows:
AI summary The document outlines the 'Minimum Monthly Charge' section, though no specific details or calculations are provided in the text. A table image is referenced but not described, suggesting the charge structure may be visually represented elsewhere.
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.
- (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) NSPI may limit the number of customers who may subscribe to thi...
AI summary The text outlines conditions for customers subscribing to a specific tariff, including requirements to start service on November 1st, the use of a Smart Meter, and restrictions on seasonal and Net Metering services.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall not be less than the rates in the table below. per month Effective February 2, 2023 $21.28 Effective January 1, 2024 $21.28...
AI summary The document outlines the maximum charge per kWh based on a billing load factor of 10%, with a minimum monthly bill requirement as specified in the table. The rates are set for specific effective dates from 2023 to 2027.
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required to make a c...
AI summary Special conditions outline customer responsibilities for metering costs, non-standard service provisions, and load management to maintain power system integrity. Customers may bear capital costs for primary metering, own transformers for non-standard services, and ensure their load does not compromise system reliability, harmonic levels, voltage stability, or fault levels.
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.
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.
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.
LARGE GENERAL TARIFF Page 1 of 2 (2,000 kVA or 1,800 kW and over) Rate Code 12
AI summary The document outlines a section of the LARGE GENERAL TARIFF, specifying Rate Code 12 for customers with 2,000 kVA or 1,800 kW and over. The page is part of a regulatory proceeding in Nova Scotia, though no further details or arguments are provided in the excerpt.
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.
LARGE GENERAL TARIFF Page 2 of 2 (2,000 kVA or 1,800 kW and over) Rate Code 12
AI summary This document outlines the LARGE GENERAL TARIFF for customers with electrical capacity of 2,000 kVA or 1,800 kW and over, designated under Rate Code 12. It is part of the second page of the tariff document, specifying rates for high-capacity users.
SMALL INDUSTRIAL TARIFF (up to 249 kVA or 224 kW) Rate Code 21 Page 1 of 2
AI summary The document outlines the Small Industrial Tariff for customers up to 249 kVA or 224 kW under Rate Code 21, part of a regulatory proceeding involving Nova Scotia Power Inc. (NSPI) and the Nova Scotia Energy Board (NSEB).
SMALL INDUSTRIAL TARIFF Page 2 of 2 (up to 249 kVA or 224 kW) Rate Code 21
AI summary The document outlines the Rate Code 21 for the Small Industrial Tariff, applicable to customers with up to 249 kVA or 224 kW capacity. However, the provided text lacks detailed information on tariff structure, cost recovery mechanisms, or regulatory considerations.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall not be less than as follows. per month Effective February 2, 2023 $21.28 Effective January 1, 2024 $21.28 Effective January...
AI summary The text outlines the maximum charge per kWh based on a billing load factor of 10%, with specific minimum monthly bill amounts set for different effective dates, starting from February 2, 2023, up to January 1, 2027.
MEDIUM INDUSTRIAL TARIFF Page 1 of 2 (250 kVA or 225 kW to 1,999 kVA or 1,799 kW) Rate Code 22
AI summary The document outlines the Medium Industrial Tariff (Rate Code 22) applicable to customers with electrical demand between 250 kVA/225 kW and 1,999 kVA/1,799 kW. No detailed discussion of rate structure, costs, or regulatory arguments is present in the provided text.
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.
LARGE INDUSTRIAL TARIFF Page 1 of 6 (2,000 kVA or 1,800 kW and over) Rate Code 23
AI summary The document outlines the Large Industrial Tariff for customers with 2,000 kVA or 1,800 kW and over, using Rate Code 23. It is part of a regulatory proceeding under the Nova Scotia Energy Board (NSEB) involving Nova Scotia Power Inc. (NSPI). Key elements include tariff structure and potential cost recovery mechanisms.
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 February 2, 2023 $1.632 Effective January 1, 2024 $1.632 Effective Jan...
AI summary A new charge applies to customers connected at the distribution level, with rates increasing from $1.632 in 2023 to $2.527 in 2027. Additionally, a 32-cent reduction in demand charge per kilovolt ampere is available for customers owning the transformer.
The minimum monthly charge shall be the greater of the demand charge or the amounts in the table below. per month Effective February 2, 2023 $21.28 Effective January 1, 2024 $21.28 Effective January 1, 2026 $22.16 Effective January 1, 2027...
AI summary The text outlines the minimum monthly charge, which is determined as the greater of the demand charge or the values listed in the table, with amounts increasing over time starting from February 2, 2023, up to January 1, 2027.
LARGE INDUSTRIAL TARIFF Page 3 of 6 (2,000 kVA or 1,800 kW and over) Rate Code 23 - (2) Metering will normally be at the low voltage side of the transformer. Should the customer's requirements make it necessary for the Company to provide p...
AI summary The Large Industrial Tariff (Rate Code 23) outlines metering requirements, minimum load conditions, service agreements, and power supply integrity standards. NSPI may withdraw the tariff if customers fail to meet load thresholds, with exemptions for interruptible service customers. Customers must ensure their operations do not compromise power system reliability, harmonic levels, or stability.
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 demand charge reduction for qualified customers based on billed interruptible demand, which is the difference between contracted firm demand and billing demand. The billed interruptible demand is determined using the maximum interruptible demand from the current month or the previous eleven months.
LARGE INDUSTRIAL TARIFF Page 5 of 6 (2,000 kVA or 1,800 kW and over) Rate Code 23 - (3) Following interruption, service may only be restored by the customer with approval of the Company. - (4) Failure to comply in whole or in part with a r...
AI summary The document outlines penalty charges for non-compliance with load interruption requirements under Rate Code 23 for large industrial customers. It specifies two types of penalties: a Threshold Penalty based on firm billing costs and a Performance Penalty calculated using a formula involving kVA values.
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.
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 maximum actual demand from the previous December, January, or February within the last 11 months, excluding peak demands during the first two hours after outage restoration. Customers are encouraged to manage demand peaks post-outage.
AVAILABILITY This tariff is applicable to three phase electric power and energy, supplied at the low voltage side of the bulk power transformer, to municipal electric utilities. Meter readings shall be increased by 1.1% for each transforma...
AI summary The tariff applies to three-phase electric power supplied to municipal electric utilities at low voltage. Meter readings are adjusted by 1.1% per transformation between the meter and the bulk power transformer to account for losses, with reductions applied when metering occurs at transmission voltage.
Page 2 of 20 D-4- C- d- Watta kWh per per mo nth ($) Othor Rate Code Rate Code Watts 2026 2027 Other 001 300 and less 97 25.14 27.16 002 Greater than 300 154 36.27 39.16 (b) Operating Only Rate Code Watts kWh per per mo onth ($) Other mont...
AI summary The text presents a table with rate codes and associated costs for different wattage levels in 2026 and 2027, as well as historical data from previous years. The tables are part of a regulatory proceeding document discussing electricity rates and pricing structures.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate shall be $ as follows per month if such unmetered se...
AI summary The text outlines a regulation for the Miscellaneous Lighting Rate, specifying the maximum charge per kWh based on a 10% billing load factor and setting a minimum monthly bill for unmetered service billed separately.
Maximum per kWh Charge/Minimum Bill The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall be as follows per month if such unmetered service is billed separately from any metered...
AI summary The document outlines the maximum charge per kWh at a 10% load factor and specifies that a minimum monthly bill applies when unmetered service is billed separately from metered accounts.
UNMETERED SERVICE RATES Page 20 of 20 Rate Code 41 A flat rate shall be calculated for any service requiring the supply of power and energy only, with a predeterminable usage, and where metering is considered to be impractical, such as: Te...
AI summary The document outlines the calculation of flat rates for unmetered services in Nova Scotia, specifically Rate Code 41. These rates apply to services with predeterminable usage where metering is impractical, such as telephone booths, traffic control lights, and railway signals. The approach ensures billing based on estimated consumption rather than actual metered data.
APPLICABILITY This schedule is a mandatory rider to all electric rate schedules, except the following tariffs: Generation Replacement and Load Following, Extra High Voltage Time-of-Use Real Time Pricing, High Voltage Time-of-Use Real Time...
AI summary The schedule applies to all electric rate schedules except specified tariffs. FAM adjustments apply to certain tariffs and Additional Energy under the Mersey System Agreement when priced at applicable tariffs.
FUEL ADJUSTMENT The applicable charges for electric service to the Company's retail and municipal customers shall be increased or decreased to the nearest 0.001 cents per kWh to recover or credit the difference in actual fuel cost from the...
AI summary The document outlines a formula to adjust electric service charges for NSPI's retail and municipal customers, increasing or decreasing rates by 0.001 cents per kWh to reconcile actual fuel costs with base rate costs. This mechanism ensures alignment between recovered fuel costs and established rates.
Fuel Adjustment Rider = AA + BA Where: "AA" is a rate class-specific Actual Adjustment which is the difference between fuelrelated costs recovered from a rate class through the application of the base rates during the previous calendar yea...
AI summary The Fuel Adjustment Rider (AA + BA) adjusts rates based on actual fuel costs and prior adjustments. AA reflects the difference between fuel costs recovered via base rates and actual costs, while BA corrects over or under-collections from previous periods. This mechanism ensures accurate cost recovery and rate adjustments for each rate class.
(1) Base Cost of Fuel The Base Cost of Fuel can be re-set in a General Rate Application or, absent a General Rate Application, every second year as part of the FAM adjustment process. Changes in the Base Cost of Fuel will be reflected in c...
AI summary The Base Cost of Fuel is reset via General Rate Applications or every two years through the FAM process. Adjustments affect customer rates using the Board-approved Cost of Service Methodology, applied uniformly across customer classes.
(a) \ To non-FAM classes When a customer transitions its load, whether in whole or in part, from a FAM class to a non-FAM class, NS Power shall determine the outstanding fuel cost imbalance of the customer at the time of transition. This d...
AI summary When customers transition from FAM to non-FAM classes, NS Power must calculate their fuel cost imbalance, adjust it in future FAM proceedings, and seek NSEB approval. Adjustments are resolved through agreement between NS Power and the customer or via NSEB determination if unresolved.
Page 4 of 4 Effective upon the date of the Board's decision ecision_ Rate Class Actual Adjustment (AA) in cents per kWh Balance Adjustment (BA 1) in cents per kWh Balance Adjustment (BA-2) in cents per kWh FAM AA/BA Combined\nin cents per...
AI summary The document presents adjustments for different rate classes, showing Balance Adjustments (BA) in cents per kWh for various categories, with the FAM AA/BA Combined value indicated for each. The Municipal and Outdoor Recreational Lighting categories have highlighted values.
Nova Scotia Power Incorporated Page 3 of 23 Open Access Transmission Tariff Delivery Period Charge ($) Yearly: One twelfth of $4,177.65 /MW of Reserved Capacity per year Monthly $348.14 /MW of Reserved Capacity per month Weekly $80.34 /MW...
AI summary The document outlines Nova Scotia Power Inc.'s Open Access Transmission Tariff (OATT) with reserved capacity charges for various delivery periods (yearly, monthly, weekly, on-peak/off-peak daily/hourly). On-peak hours are defined as 09:00–24:00 Atlantic Time, Monday to Friday.
(Point-to-Point Transmission Service) 2023 Delivery Period Charge ($) Yearly: One twelfth of $2,620.80 /MW of Reserved Capacity per year Monthly $218.40 /MW of Reserved Capacity per month Weekly $50.40 /MW of Reserved Capacity per week Dai...
AI summary The document outlines point-to-point transmission service charges for reserved capacity across 2023, 2024, and 2026. Rates are structured by delivery period (yearly, monthly, weekly, daily) with consistent values for 2023 and 2024, except for a slight increase in the 2026 yearly charge. Charges are calculated per MW of reserved capacity.
Nova Scotia Power Incorporated Page 19 of 23 Open Access Transmission Tariff 2027 Charge ($) Off-peak daily delivery $207.40 /MW of Reserved Capacity per day The total demand charge in any week, pursuant to a reservation for Daily delivery...
AI summary The document outlines the off-peak daily delivery charge of $207.40 per MW of Reserved Capacity per day under the Open Access Transmission Tariff for 2027. It also specifies that the total demand charge for a week cannot exceed the rate multiplied by the highest Reserved Capacity in any day of that week.
SCHEDULE 10: NETWORK INTEGRATION TRANSMISSION SERVICE RATE (1) The rate charged for Network Integration Transmission Service is: For 20236: $4,888.134,317.55/MW-month For 20247: $5,658.784,317.55/MW-month based on the Transmission Customer...
AI summary Schedule 10 outlines the Network Integration Transmission Service rate for 2023 and 2024, based on the Transmission Customer's Net Non-coincident Monthly Peak Demand. A formula is provided for calculating transmission congestion charges based on redispatch costs and load factors.
CHARGES Domestic Service, Domestic Service Critical Peak Pricing, Domestic Service Time-of-Use Customer Charge ($/month) Distribution Charge (¢/kWh) Minimum Monthly Charge ($/month) Effective February 2, 2023 19.17 1.786 19.17 Effective Ja...
AI summary The document presents tables showing changes in customer charges, distribution charges, and minimum monthly charges for various service types, including Domestic Service, Domestic Service Time-of-Use, and Small General, effective from February 2, 2023, and January 1, 2024, with further changes planned for January 1, 2026.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The same maximum per kWh charges and minimum bills will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above.
AI summary The document states that maximum per kWh charges and minimum bills for each rate class will follow the same rules as the NS Power Bundled Service tariffs, ensuring consistency across rate classes.
(11) Light Emitting Diode (LED) – Operating, Maintenance, and Capital (full charge) Data Cada Watts kWh per per mo onth ($) Othor Rate Code Watts month 2023 2024 - Other 724 55 18 6.75 7.02 740 190 63 15.02 15.15 741 261 87 17.38 17.48 742...
AI summary The document presents a table detailing Light Emitting Diode (LED) rate codes, associated wattage, kWh consumption, and monthly costs for 2023–2027. Rate codes 724, 740–743 are listed with varying wattage and cost adjustments over time, including deleted and updated values. The data reflects changes in pricing structures for LED-related charges.
RATE FOR 2026 1 OATT in $/kW 2 Usage in kW under OATT
AI summary The document outlines the 2026 rate structure under the Open Access Transmission Tariff (OATT), specifying charges in dollars per kilowatt (kW) and usage metrics in kW. Key entities involved include Nova Scotia Power Inc. (NSPI) and the Nova Scotia Energy Board (NSEB), which oversee regulatory proceedings related to electricity rates and transmission tariffs.
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.
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.
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.
DEMAND SIDE MANAGEMENT COST RECOVERY RIDER (DCRR) Page 5 of 5 - For bundled service customers other than those who take service in the Wholesale Market (whether in whole or in part), this approach applies to classes as a whole (not to indi...
AI summary The DCRR applies differently to bundled service customers and Wholesale Market participants. For non-Wholesale Market bundled customers, the approach applies to classes as a whole, while Wholesale Market customers are treated individually. The method applies to total Approved DSM costs.
Baseline Data NS Power Customers Customers Meter Reads Opt-out Customers Annual O&M Cost Tax $ 13,497 $ 14,868 $ 13,726 $ 11,896 Customer Care Rep $ 70,090 Average Total Cost (2025 to 2027) 825,335$ Total Cost $ 879,705 $ 830,884 $ 765,417...
AI summary The text presents baseline data related to NS Power customers, including annual O&M costs, customer care representative costs, and proposed AMI opt-out monthly charges for 2026 and 2027. It includes details on meter reads, opt-out customers, and proposed rate changes.
Interpretation and Definitions Page 3 of 6 " M et ٦r se ·al " "Meter seal" "meter seal" means either the seal placed on the meter by Industry Canada to prevent fraudulent interference with the passage of electricity through the meter or th...
AI summary The document defines 'meter seal' as a seal placed on a meter by Industry Canada or the Company to prevent fraudulent interference with electricity passage, including seals on demand reset and other required installations.
METER READING FOR NON-STANDARD METER SERVICE Charges apply to a Customer who is eligible to be provided with a meter which can be read remotely but who opts out and requires the meter to be read on the Customer's premises. These charges ar...
AI summary The document outlines charges for customers opting out of remote meter reading, detailing fees for connection, disconnection, and other services based on meter type and year (2026, 2027). Rates vary for customers with or without remote connect-enabled meters, with higher fees for non-remote options.
Regulation 7.1 Schedule of Charges Page 3 of 3 (m) All pole attachments for telecommunication common carriers, or broadcasters, exclusive of those under joint use agreements. $22.4423.81 per pole in 20236 and $22.8924.29 in 20247. per pole...
AI summary The document outlines pole attachment charges for telecommunication and broadcasting entities, excluding those under joint use agreements, and specifies non-standard meter reading charges under Regulation 5.1 for different customer categories in 2026 and 2027.
AMI Opt-Out Meter Reading "Opting out" or "opt-out" in the context of these Regulations refers to the process where customers choose non-standard meter service and incur the associated monthly charges. An opt-out request must be made by su...
AI summary The document defines 'opt-out' in AMI regulations, allowing customers to choose non-standard meter service with monthly charges. Pre-AMI opt-outs retain existing meters, while post-AMI opt-outs use disabled smart meters requiring manual reads. Domestic/Small General customers have semi-annual readings, while classes with demand charges require monthly readings. Billing between reads uses estimated data.
N-52026-2027 GRA Appendix 1-6 - Redacted
119 passages
TABLE OF STANDARDIZED FILINGS AND ATTACHMENTS Attachment 1 – COS Procedures Attachment 1a – Cost of Service Methodology Attachment 1b – Determination of Revenue Responsibilities by Rate Class Attachment 1c – Fuel and Purchased Power Relate...
AI summary The document lists standardized filings and attachments for a regulatory proceeding, covering cost-of-service methodologies, revenue responsibilities, fuel costs, unmetered services pricing, OATT calculations, and distribution tariff computations for 2026-2027. Attachments include partially confidential data and rate component tables.
PR-02 Cost Support for Proposed Regulation Changes Attachment 1 – AMI Opt-out Fee Development Attachment 2 – Miscellaneous Charges Development (Partially Confidential) Regulation 7.3 Schedule of Load Research Monitoring, Reporting and Anal...
AI summary The document outlines attachments related to AMI opt-out fee development and miscellaneous charges, alongside references to Regulation 7.3 concerning load research monitoring, reporting, and analytical charges. It pertains to cost support for proposed regulatory changes in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 1B Page 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).
2026-2027 GRA Direct Evidence Appendix 1B Page 4 of 4 REDACTED (CONFIDENTIAL INFORMATION REMOVED) OT Overtime OTE Overhead Transmission Equipment PCB Polychlorinated Biphenyls PCR Program Cost Recovery (for DSM) PHB Port Hawkesbury Biomass...
AI summary This document is an appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing a list of acronyms and their expansions relevant to energy regulation, infrastructure, and financial terms. The content is redacted, with confidential information removed, and focuses on technical, operational, and regulatory terminology used in the proceeding.
2026-2027 GRA Direct Evidence Appendix 3A Page 1 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding, focusing on direct evidence. Key elements include regulatory considerations, cost recovery mechanisms, and potentially rate design issues, though specific details are confidential.
Appendix 03A – Status of 2023-2024 GRA Directives Information about each directive is found below. A status summary table is provided at the end of this Appendix.
AI summary This appendix outlines the status of 2023-2024 GRA Directives, with a summary table provided at the end. No specific details or arguments are included in the text provided, focusing only on the directive status overview.
1. Storm Cost Reporting The directive related to storm cost reporting is at para. 332 of the Board's 2023-2024 GRA Decision: [T]he Board directs NS Power to submit annual reports summarizing actual storm restoration costs for each year of...
AI summary The Nova Scotia Energy Board (NSEB) requires NS Power to submit annual storm restoration cost reports from 2024 to 2026, assessing the Storm Rider's effectiveness and equity. NS Power has complied with the initial reports for 2023 and 2024, with the 2025 report due in 2026. These reports evaluate cost overruns/underruns against base rate allowances.
2026-2027 GRA Direct Evidence Appendix 3A Page 2 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED) and recovery above the level in base rates for 2025, it may choose to make an application in 2026 for recovery in 2027. That will complete N...
AI summary NS Power may apply in 2026 for recovery in 2027 to comply with the Nova Scotia Energy Board's directive on the Storm Rider from the 2023-2024 GRA, ensuring alignment with base rates for 2025.
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.
6. Depreciation Study The Board's directive regarding the depreciation study is found at para. 374 of the 2023-2024 GRA Decision: The Board agrees that a depreciation study is necessary and directs NS Power to file a depreciation study pri...
AI summary The Nova Scotia Energy Board (NSEB) directed NS Power to file a depreciation study prior to its next General Rate Application (GRA), including thermal assets with retirement dates beyond 2030 and specific facilities. The study aligns with the Decarbonization Deferral Account (DDA) process, though depreciation rates for pre-2030 assets will not be increased. The report is included in the current GRA filing.
2026-2027 GRA Direct Evidence Appendix 3A Page 5 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It contains confidential information removed, with no explicit content provided beyond the heading and page reference.
8. Annapolis Tidal Generation Facility The Board issued the following directive at para. 387 of the 2023-2024 GRA Decision: In the Board's opinion, the inclusion of the Annapolis Tidal Generation Facility in NS Power's regulatory amortizat...
AI summary The NSEB directed NS Power not to include the Annapolis Tidal Generation Facility in regulatory amortizations, citing a prior decision. NS Power has since forecast decommissioning the facility in 2027 and plans to apply for approval in 2026 to recover the remaining net book value over ten years.
9. Low-Income Customer Collections and Arrears In discussing the need to address concerns about rates for customers, the Board provided the following directive at paragraph 411 of the 2023-2024 GRA Decision: The proposed review and consult...
AI summary The Nova Scotia Energy Board directed NS Power, the Affordable Energy Coalition, and the Consumer Advocate to review the 2013 rate changes and establish a systematic evaluation method. A working group, including these entities, has implemented initiatives to assist low-income customers and those in arrears, with reports due by April 30, 2023.
2026-2027 GRA Direct Evidence Appendix 3A Page 6 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary Redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding, focusing on direct evidence. Context involves regulatory considerations for utility rate structures, cost recovery mechanisms, and potential impacts on customer classes.
10. Alternative Treatment of Interruptible Loads There were four directives arising from the 2023-2024 GRA which relate to the wholesale market, Open Access Transmission Tariff (OATT) and capacity-based ancillary services. The Board direct...
AI summary The Board directed NS Power to explore alternative treatment of interruptible loads following MEUs' support for the GRA Settlement Agreement and recommendations by Mr. Marshall. NS Power indicated interruptible loads are counted toward reserves when generation resources are insufficient. The Board urged analysis of cost implications for alternative treatments in the next GRA.
11. Alternative Treatment of -16 MW in AGC The Board's directive on this item is set out at para. 482 of the 2023-2024 GRA Decision: Prior to the next GRA, NS Power is directed to explore alternative treatment of the - 16 MW requirement an...
AI summary The Nova Scotia Energy Board directed NS Power to explore alternative treatment of -16 MW in AGC to avoid double-charging transmission customers, as outlined in the 2023-2024 GRA Decision. NS Power addressed this in its report (SR-01 Attachment 1e).
12. Wreck Cove Spinning and 10-Minute Supplementary Reserve The Board addressed this directive at para. 485 of the 2023-2024 GRA Decision: Regarding the suggestion that Wreck Cove capacity may be over-credited in the 10 minute spinning res...
AI summary The Nova Scotia Energy Board evaluated NS Power's evidence regarding potential over-crediting of Wreck Cove capacity in 10-minute spinning reserve cost calculations, as outlined in para. 485 of the 2023-2024 GRA Decision. The Board considered NS Power's argument that units are utilized for both spinning reserve and 10-minute supplementary reserve purposes.
2026-2027 GRA Direct Evidence Appendix 3A Page 7 of 14 REDACTED (CONFIDENTIAL INFORMATION REMOVED) supplementary reserve, so the CBAS charges reflect that actual use of those assets. However, considering Mr. Marshall's questioning of the c...
AI summary The text addresses the need for NS Power to clarify its calculation methodology for spinning reserve and 10-minute supplementary reserve utilization in CBAS charges, as directed by a regulatory proceeding. NS Power has responded to this directive in SR-01 Attachment 1e.
13. Exclusion of CT Units from 30-Minute Supplemental Reserve The final directive concerning capacity-based ancillary services is at para. 486 of the 2023-2024 GRA Decision: Regarding inclusion of less expensive CTs in the CBAS costing cal...
AI summary The Nova Scotia Energy Board (NSEB) directed NS Power to provide a more detailed explanation in its next GRA regarding the exclusion of CT units from 30-minute supplemental reserve calculations, finding NS Power's previous justification insufficient. NS Power addressed this in SR-01 Attachment 1e.
14. Updated FAM Tariff In the NSEB's Decision and Order for approval of the 2024 FAM AA/BA Rider, the Board directed NS Power to amend the FAM Tariff language to account for the transition of customers moving both to and from FAM rates. Pa...
AI summary The NSEB directed NS Power to amend the FAM Tariff to address customer transitions between FAM rates, as outlined in Para. 52 of the 2024 FAM AA/BA Decision. Amendments must be submitted for approval in NS Power's next general rate application.
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.
2026-2027 GRA Direct Evidence Appendix 3B Page 6 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It contains confidential information removed, with no substantive content provided in the excerpt.
2026-2027 GRA Direct Evidence Appendix 3B Page 15 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This redacted document is part of a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). It lists acronyms and references a Direct Evidence Appendix but contains no substantive content due to confidentiality restrictions.
2026-2027 GRA Direct Evidence Appendix 3B Page 16 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, with confidential information removed. It is part of a regulatory process involving utility cost recovery and rate design considerations.
2026-2027 GRA Direct Evidence Appendix 3B Page 32 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, focusing on direct evidence. Key content is confidential and removed, with no explicit claims or arguments visible in the provided text.
Re-design Re-design typically requires engineering input to modify/redevelop an asset to incorporate changes to reduce the risk of failure. In some cases, it may involve changing the design standard to ensure new assets of a particular typ...
AI summary Re-design involves modifying assets to reduce failure risks, often requiring engineering changes. It may alter design standards to improve performance or capacity, with costs classified as capital or operating expenditure. For example, increasing conductor sizing and re-designing fasteners can mitigate risks from wind events like hurricanes.
2026-2027 GRA Direct Evidence Appendix 3B Page 40 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, specifically Appendix 3B, Page 40 of 54. The content has been removed due to confidentiality, but it is part of a regulatory process involving cost recovery and rate-setting.
2026-2027 GRA Direct Evidence Appendix 3B Page 44 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 3B, part of a Nova Scotia regulatory proceeding. No substantive content is visible due to redaction, but it is associated with cost recovery, rate design, and regulatory processes.
2026-2027 GRA Direct Evidence Appendix 3B Page 46 of 54 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It includes a list of acronyms and terms relevant to energy regulation, cost recovery mechanisms, and infrastructure planning, though the actual content is confidential and removed.
2026-2027 GRA Direct Evidence Appendix 3C Page 9 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted page from Appendix 3C of the 2026-2027 General Rate Application (GRA) proceeding. It contains confidential information removed, focusing on regulatory evidence related to cost recovery, rate design, and energy management programs in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 3C Page 14 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 3C, part of a Nova Scotia regulatory proceeding. No substantive content is visible due to redaction, but it is part of a broader rate-setting process involving cost recovery and regulatory analysis.
2026-2027 GRA Direct Evidence Appendix 3C Page 20 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). Confidential information has been removed, and no substantive content is visible for analysis.
2026-2027 GRA Direct Evidence Appendix 3C Page 25 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing confidential information removed. It is part of a larger document with 38 pages, currently on page 25.
2026-2027 GRA Direct Evidence Appendix 3C Page 30 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is part of a 2026-2027 GRA (General Rate Application) proceeding in Nova Scotia, with the content redacted. It is Appendix 3C, Page 30 of 38, and contains confidential information removed.
2026-2027 GRA Direct Evidence Appendix 3C Page 37 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. The content is confidential and removed, but the appendix is part of a regulatory process involving cost recovery, rate design, and utility operations. Key entities include Nova Scotia Energy Board (NSEB) and Nova Scotia Power Energy Marketing Inc. (NSPEMI).
REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 1 of 38
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It contains confidential information and is part of a regulatory process involving utility rate structures and cost recovery mechanisms.
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 7 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing confidential information. Key acronyms related to energy regulation, cost recovery, and infrastructure are listed, though no substantive content is visible due to redaction.
REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 9 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It contains confidential information removed, with no substantive content provided in the excerpt.
- 5 Fuel costs are comprised of the delivered cost of solid fuels, natural gas, oil, and purchased power. - 6 The annual 2026-2027 GRA BCF is forecast to decrease from $1,039.1 million in the 2025 FAM - 7 Budget to an average of $918.5 mil...
AI summary The 2026-2027 GRA BCF is forecast to decrease from $1,039.1 million in 2025 to an average of $918.5 million, with total costs over two years reaching $1.8 billion. Fuel costs include solid fuels, natural gas, oil, and purchased power. Environmental regulations, such as the OBPS, are influencing costs, with compliance obligations increasing from $5.7 million in 2026 to $14.6 million in 2027.
1 Figure 5 – 2024-2027 NS Power Fuel and Purchased Power Costs Per MWh 4 Figure 6 – 2026 BCF Component Cost Changes vs 2024 GRA Refresh 2 3 - 6 As shown above in Figure 6 , there is a total fuel cost decrease of $22 million in the 2026 GRA...
AI summary Figure 5 and Figure 6 illustrate NS Power's fuel and purchased power cost trends from 2024-2027, highlighting a $22 million decrease in 2026 BCF component costs compared to the 2024 GRA Refresh. This reduction is attributed to key cost drivers outlined in the analysis.
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 14 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary Redacted page from a 2026-2027 GRA Direct Evidence Appendix in a Nova Scotia regulatory proceeding. Contains confidential information removed, with a list of acronyms related to energy regulation, cost recovery, and operational metrics.
1 Figure 10 - 2025 Breakdown of BCF by Fuel and Purchased Power Type REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 15 of 38
AI summary Figure 10 from the 2025 BCF breakdown by fuel and purchased power type is part of the 2026-2027 GRA Direct Evidence Appendix SA. It provides a visual representation of fuel cost allocation, contextualized within Nova Scotia's energy regulatory proceedings.
REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 16 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix, part of a regulatory proceeding. Confidential information has been removed, and the content is not available for analysis.
1 Figure 12 - 2027 Breakdown of BCF by Fuel and Purchased Power Type 2 3 4 The following sections provide details on NS Power's 2026-2027 foel requirements compared to 5 the 2024 GRA Refresh. All commodities purchased in USD have been conv...
AI summary NS Power's 2026-2027 fuel requirements are compared to the 2024 GRA Refresh, with USD commodities converted to CAD using a forecasted exchange rate. The methodology for deriving this rate is detailed in Section 1.2.11 of the Application.
1 1.2.3 Long-Term Contracts 2 3 Long-term contracts are contracts which have a duration of four years or more. 4 5 NS Power for solid fuel within the 2026-2027 GRA Period for which the contract 6 term spans four years or more as set out in...
AI summary The document outlines NS Power's long-term (four+ years) and medium-term (1-3 years) solid fuel contracts during the 2026-2027 GRA period, referencing Confidential Figures 14 and 15. Medium-term contracts are further detailed in Figure 15, with volumes in OE-01E. Long-term contracts span 2026-2027, while medium-term contracts cover 2022-2024.
24 1.2.6 Heavy Fuel Oil - 26 Depending on the relative market prices of each fuel, Tufts Cove may generate using HFO rather - 27 than natural gas in the dual-fired steam boilers (Units 2 & 3). 5 Swap contracts are financial instruments use...
AI summary Tufts Cove may use Heavy Fuel Oil (HFO) instead of natural gas based on market prices. Financial instruments like swap contracts and forward price curves are used to manage fuel costs. The Approvals of Natural Gas Transportation Contracts Regulations (N.S. Reg. 80/2019) under the Public Utilities Act allows approval of long-term transportation contracts.
REDACTED 2026-2027 GRA Direct Evidence Appendix SA Page 27 of 38
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. It includes technical and regulatory terminology related to energy management, cost recovery mechanisms, and utility operations, though no specific content or arguments are visible due to redaction.
1 1.2.9 Imports - 2 Over the 2026-2027 GRA period, there are two ways in which energy will be impoited into Nova - 3 Scotia: impo1ts through the Maritime Link and impo1ts through the interconnection between Nova - 4 Scotia and New Brnnswic...
AI summary The 2026-2027 GRA defines imports as energy from the Nova Scotia-New Brunswick interconnection and surplus Maritime Link energy, excluding the NS Block and Supplemental Energy. Confidential Figure 24 estimates total imports between 1,418 GWh and 1,435 GWh.
14 1.3.1 Background - 15 The NSUARB approved forecast Maritime Link Project costs in each year for inclusion in rates to - 16 reflect the forecast interim assessment for the Maritime Link. 17 - 18 The Nova Scotia Block commenced in mid-Aug...
AI summary The NSUARB approved forecast costs for the Maritime Link Project for inclusion in rates. The Nova Scotia Block, initiated in 2021, is expected to deliver 894 GWh of base energy by 2026-2027, with supplemental energy agreements concluding in 2027. NS Power plans to purchase market-priced energy from Nalcor via the Maritime Link during 2026-2027.
REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 34 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary Redacted page from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 5A. The document contains confidential information and includes a list of acronyms relevant to energy regulation, utility operations, and environmental policies.
18 1.4 HEDGING PLAN 19 20 Fuel costs are subject to a variety of risks including commodity market, volumetric, basis, and 21 counterparty risk. Reducing market exposure through physical and financial hedges enables the 22 Company to manage...
AI summary NS Power's Fuel Hedging Plan (FHP) was filed in 2016 under the Electricity Plan Implementation (2015) Act to manage fuel cost volatility through physical and financial hedging. The FHP was approved by the Board for the 2017-2019 Rate Stabilization Period.
REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 35 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1 RSP progresses, the strategies and principles in the Plan could be validly applied to 2020 and 2 beyond assuming similar market...
AI summary NS Power's Fuel Hedging Plan (FHP) has effectively protected customers from commodity price increases since 2016. The plan aims to reduce F&PP cost volatility and prevent significant fuel-related deferrals. NS Power intends to continue using the same hedging approach as previous periods, despite no legislative requirement for UARB approval.
REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 36 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is part of a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, with confidential information redacted. It references regulatory processes involving cost recovery, rate adjustments, and energy management systems, though specific details are omitted.
REDACTED 2026-2027 GRA Direct Evidence Appendix 5A Page 38 of 38 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This redacted document is part of a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). It contains confidential information removed from Appendix 5A, Page 38 of 38, likely involving evidence or data pertinent to rate-setting, cost recovery, or compliance with energy regulations.
11 1.4.4.2 Financial Contracts 12 13 Financial contracts primarily take the form of futures, forwards, and swaps. Generally, NS Power 14 is the buyer of these contracts which means it will be obligated to pay a fixed price known at the 15...
AI summary NS Power uses financial contracts (futures, forwards, swaps) to hedge fuel and purchased power costs, stabilizing expenses by offsetting price volatility. Contracts obligate NS Power to pay fixed prices in exchange for floating payments tied to market prices, reducing cost variability and enhancing predictability. Options and structured products may be used if economically viable and market conditions permit.
2026-2027 GRA Direct Evidence Appendix 5C Page 1 of 2 REDACTED (CONFIDENTIAL INFORMATION REMOVED) PNS-53466-P1K7V0 March 25, 2025 David Pickles COO, Nova Scotia Power Incorporated PO Box 910 Halifax, NS B3J 2W5
AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding, submitted by Nova Scotia Power Incorporated. It includes a letter from David Pickles, COO, dated March 25, 2025, addressing the GRA process. The content is partially redacted, likely due to confidential information.
2026-2027 GRA Direct Evidence Appendix 6A Page 1 of 10 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). It contains confidential information and no substantive content is visible in the provided text.
Appendix 6A FAM Framework
AI summary Appendix 6A discusses the Fuel Adjustment Mechanism (FAM) framework, a regulatory component for managing fuel cost fluctuations in energy pricing. It outlines methodologies for adjusting rates based on fuel expenses, ensuring alignment with operational costs and compliance with Nova Scotia's energy regulatory guidelines.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Direct Evidence Appendix 6A Page 2 of 10
AI summary The document is a redacted page from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 6A. It is page 2 of 10, with confidential information removed. The GRA process involves rate-setting and cost recovery mechanisms for utility services.
1 FAM FRAMEWORK The Fuel Adjustment Mechanism (FAM) is governed by the Plan of Administration (POA) which was introduced for the 2009 calendar year and which is periodically updated and approved by the NSEB. The FAM also uses the Cost of S...
AI summary The Fuel Adjustment Mechanism (FAM) is governed by the Plan of Administration (POA), introduced in 2009 and updated by the Nova Scotia Energy Board (NSEB). The FAM uses Cost of Service (COS) data to allocate fuel costs among customer classes.
1.1 FAM Plan of Administration The POA outlines the application and administration of the FAM. It includes descriptions of the base cost of fuel, adjustment components, calculation methodologies, audit provisions, and stakeholder review an...
AI summary The Fuel Adjustment Mechanism (FAM) Plan of Administration (POA) outlines procedures for resetting the Base Cost of Fuel (BCF) and adjusting rates. NS Power seeks approval for an updated POA as part of the 2026-2027 General Rate Application (GRA), including a new BCF. The current POA, approved by the Nova Scotia Energy Board (NSEB) in January 2024, allows BCF resets via GRA, legislation, or NSEB orders.
1.2.3 Balance Adjustment (BA) The BA represents the difference in the prior year between the actual fuel costs and the fuel-related revenue recovered from customers. As noted above, although the FAM AA calculation uses 12 months of actual...
AI summary The Balance Adjustment (BA) reconciles differences between actual fuel costs and recovered revenue, incorporating deferred Fuel Adjustment Mechanism (FAM) amounts and non-fuel revenue overrecoveries. BA rates are calculated using cumulative variances divided by forecast sales, with residual balances carried forward. The reporting process was updated in 2018 to use annual actual data, and the Plan of Administration (POA) is revised to include a Community Solar Energy Credit Rider.
2026-2027 GRA Direct Evidence Appendix 6A Page 7 of 10 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The last paragraph of the application stated: The on-bill credit related to the Community Solar Program, and other emerging customer renewab...
AI summary NS Power seeks approval for a Community Solar Energy Credit Rider and plans to revise the FAM POA to include on-bill credits from renewable programs as FAM costs. The NSUARB approved the rider, and the SWG had no comments on the POA revisions.
1.4.6 Housekeeping Updates The revised POA submitted includes a number of changes related to housekeeping items, including: - References to Nova Scotia Utility and Review Board (NSUARB) are changed to Nova Scotia Energy Board (NSEB); - Upd...
AI summary The revised POA includes updates to references from NSUARB to NSEB, revised dates for the 2026/2027 GRA process, and adjustments in section 3.1 for transitioning to a FAM class.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 1 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary Redacted appendix for the 2026-2027 General Rate Application (GRA) in Nova Scotia, focusing on direct evidence. The document is part of a regulatory proceeding involving cost recovery mechanisms and energy management systems, with confidential information removed.
NS Power FUEL ADJUSTMENT MECHANISM PLAN OF ADMINISTRATION IN EFFECT FOR 2026-2027
AI summary NS Power's Fuel Adjustment Mechanism Plan of Administration for 2026-2027 outlines the framework for managing fuel costs and related adjustments. The plan is subject to regulatory oversight by the Nova Scotia Energy Board (NSEB) and involves mechanisms like the DSM Cost Recovery Rider (DCRR) and General Rate Application (GRA).
1.0 GENERAL DESCRIPTION This document describes the plan for administering Nova Scotia Power Inc.'s (NS Power) Fuel Adjustment Mechanism (FAM), which was approved by the Nova Scotia Utility and Review Board (as of April 1, 2025 referred to...
AI summary The document outlines Nova Scotia Power Inc.'s Fuel Adjustment Mechanism (FAM), approved by the Nova Scotia Energy Board (NSEB), which recovers fuel costs from customers. The Base Cost of Fuel is reset every two years via General Rate Applications (GRA) or Board orders, with stakeholder input and audits ensuring transparency. The FAM adjusts rates based on actual vs. base fuel costs.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 4 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Interest will be added to all over/under-balance amounts and calculated at NS Power's Annual Weighted Average Cost of Capital (WACC)...
AI summary Interest is applied to over/under-balance amounts using NS Power's WACC. The Fuel Adjustment Mechanism (FAM) recovers fuel cost changes via Actual Adjustment (AA) and Balancing Adjustment (BA) for each rate class, calculated as the difference between actual fuel costs and Base Cost of Fuel (BCF) on a ¢/kWh basis.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 5 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. Confidential information has been removed, and the content pertains to direct evidence submitted as part of the regulatory process.
2.0 FAM COMPONENTS Each January 1 through December 31 period shall constitute a distinct FAM year. Under the FAM, an adjustment will normally be calculated once per year to reflect the over/-under recovery. The FAM adjustment will consist...
AI summary The Fuel Adjustment Mechanism (FAM) establishes annual adjustments (January 1–December 31) to recover fuel and purchased power costs. Adjustments are calculated yearly and consist of two components for cost recovery.
2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...
AI summary The Balancing Adjustment Component (BA) ensures correction of over/under-recovery from the Actual Adjustment Component by refunding or recovering funds from customers. It may also defer fuel and purchased power costs under specific Board approval, including those from FAM adoption or future decisions.
3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...
AI summary NS Power's Fuel Adjustment Mechanism (FAM) uses an annual formula combining Actual Adjustment (AA) and Balance Adjustment (BA) to reconcile fuel costs. AA reflects over/under recovery of Base Cost of Fuel (BCF) at specific dates, with October-December adjustments deferred. BA manages prior adjustments and deferred costs approved by the Board.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 7 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The BA rate is calculated for the following year (year 2) on the basis of the overor under-recovery of the Actual Adjustment and Bal...
AI summary The document outlines the calculation methodology for Balance Adjustment (BA) and Actual Adjustment (AA) rates, referencing Appendix A for FAM calculations and the FAM Tariff in Appendix D. Fuel-related costs are allocated to specific customer classes using test year principles, with a focus on non-FAM and ATL classes.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 8 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Wholesale Market Backup/Top-up Service Tariff (BUTU). - 2. For ATL and BUTU classes the following costs and credits - a. NS Power's...
AI summary The document outlines cost allocation methodologies for Wholesale Market Backup/Top-up Service Tariff (BUTU) and Above-the-Line (ATL) classes, including fuel costs, biofuel expenses, import costs, and export credits. Fuel costs are allocated based on energy contribution, while demand-related costs use load factors and peak contributions. Scaling via revenue-to-cost ratios ensures alignment with approved rates.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 9 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) relative share of the total fuel costs. - 6. The interest amount on the over- or under-recovery of fuel costs is apportioned to the...
AI summary The document outlines the methodology for apportioning interest on fuel cost variances to rate classes annually, distinguishing between over/under recovery scenarios. It details the calculation of the Actual Adjustment (AA) component for the Fuel Adjustment Mechanism (FAM), using forecast energy sales to determine credits or charges applied to customer bills for the subsequent year.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 10 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026 will be used to determine the AA charge or credit for 2027. The Balance Adjustment (BA) component of the FAM will be set to re...
AI summary The text outlines that 2026 data will determine the Actual Adjustment (AA) charge or credit for 2027. The Balance Adjustment (BA) component of the Fuel Adjustment Mechanism (FAM) recovers or refunds under/over-recovery from prior adjustments, including sales volume variances, Base Cost of Fuel (BCF) discrepancies, and interest. Other fuel-related factors require Board approval.
3.1 Treatment of load migrating between FAM/non-FAM classes When a customer transitions some or all of its load between FAM- and non-FAM classes, NS Power shall treat the customer's migrating load in accordance with Special Condition 3 of...
AI summary When customers migrate load between FAM- and non-FAM classes, NS Power must apply Special Condition 3 of the FAM Tariff. This establishes the methodology for handling load shifts between these classes under the regulatory framework.
3.2 Allowable Fuel and Purchased-Power Costs This section of the POA provides a framework for the fuel and purchased-power costs eligible for recovery through the FAM. Those costs will include allowable fuel expenses plus purchased-power e...
AI summary The section outlines allowable fuel and purchased-power costs recoverable via the FAM, including normal expenses and discrepancies supported by evidence. Exceptional costs are reviewed by the Small Working Group. NS Power acknowledges audit and NSEB approval requirements.
3.2.1 Natural Gas - Natural Gas Consumed - Financial Instruments used for Hedging (including gains, losses, fees and interest charges) - Pipeline Reservation Fees, Tolls, Penalties (such as imbalance charges) - Pipeline Losses - Natural Ga...
AI summary The section outlines various cost components related to natural gas, including consumption, hedging financial instruments, pipeline fees, storage costs, and GHG emission compliance program expenses.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 20 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from the 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia. No substantive content is visible due to redaction, but it is part of a regulatory process involving cost recovery, rate design, and utility operations.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 21 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 6B, page 21 of 33. It contains redacted confidential information related to regulatory proceedings in Nova Scotia. The GRA process involves cost recovery mechanisms, rate design, and evidence submission for utility services.
3.4 Deferrals During the 2026-2027 GRA Period, NS Power may include prior FAM deferrals for certain rate classes (Large General, Medium Industrial, and Large Industrial) in order to save additional interest charges which would accrue by fu...
AI summary During the 2026-2027 GRA Period, NS Power may include prior FAM deferrals for certain rate classes to avoid additional interest charges that would accrue by deferring these amounts until the end of the period. This approach aims to optimize financial obligations related to deferred costs.
Annual Filing Requirements for Fuel Adjustment Rider For the years 2026 and 2027 NS Power will submit as required a Fuel Adjustment Mechanism Formula filing for the AA and BA, which shall provide a forecast of general system requirements a...
AI summary NS Power is required to submit Fuel Adjustment Mechanism Formula filings for 2026 and 2027, including forecasts of general system requirements and proposed calculations for the Fuel Adjustment Mechanism Formula. These filings pertain to Actual Adjustment (AA) and Balance Adjustment (BA) components.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 24 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix 6B, part of a Nova Scotia regulatory proceeding. No substantive content is visible due to redaction, but it is associated with the General Rate Application process.
5.0 AUDIT AND OVERSIGHT The amounts charged through the FAM shall be subject to periodic audit to assure completeness and accuracy and to assure fuel and purchased power costs were incurred reasonably and prudently. The results of any audi...
AI summary The Fuel Adjustment Mechanism (FAM) is subject to periodic audits to ensure accuracy and prudent cost recovery. Audit results may influence future hearings for adjusting Base Cost of Fuel, Fuel Adjustment Factor, or General Rate Cases, with potential adjustments by the Board.
Significant FAM Changes Where, in the absence of a General Rate Application, an increase for any customer class of more than 10 percent compared with the rate payable in the prior year is caused by the application of the FAM procedures, th...
AI summary The document states that if the Fuel Adjustment Mechanism (FAM) causes a customer class rate increase exceeding 10% annually without a General Rate Application (GRA), the Board should implement measures to assist affected customers.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 27 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The Board will monitor the operation of the FAM closely and reservesthe right to intervene in any circumstance where it believes an...
AI summary The Nova Scotia Energy Board will monitor the Fuel Adjustment Mechanism (FAM) and retain authority to intervene if rate increases for customer classes are deemed unacceptable or against public interest, potentially deferring portions of increases to future periods.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 28 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, focusing on direct evidence. Confidential information has been removed, limiting the visibility of specific arguments or data.
6.0 STAKEHOLDER REVIEW AND DISCOVERY Monthly, quarterly and annual non-confidential and confidential reporting will be available for access and viewing. NS Power confidential reporting will be available electronically or in a confidential...
AI summary The document outlines stakeholder access to NS Power's non-confidential and confidential fuel cost reports, including requirements for confidentiality agreements. It details procedures for reviewing and challenging fuel cost methodologies, forecasts, and adjustments (AA/BA) during hearings. Definitions for key terms like Base Cost of Fuel (BCF), Actual Adjustment (AA), and Balance Adjustment (BA) are provided, along with access protocols for electronic data and reports.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 30 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Base Cost of Fuel Component – BCF: is the Base Cost of Fuel per kWh (¢/kWh) included in NS Power's rates. Business Day: is any day...
AI summary Defines terms related to Nova Scotia Power's rate structures, including Base Cost of Fuel (BCF), compliance filings, export sales, and fuel cost recovery mechanisms. Highlights the calculation of fuel costs recovered through BCF and the components of General Rate Applications.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 31 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) GRA Period refers to the period beginning January 1, 2026 and ending December 31, 2027 or to such time as determined by the NSEB. G...
AI summary The document defines key terms related to the 2026-2027 GRA, including GRLF revenue, administration costs, and financial adjustments like AA and BA. It references NSPEMI, a subsidiary of NS Power, and outlines mechanisms for fuel cost recovery and balance adjustments over the GRA period.
2026-2027 GRA Direct Evidence Appendix 6B (Clean) Page 32 of 33 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Prior Year's Accumulated Interest: the interest accumulated over the previous year on the balance in the 'Balancing Account' to be...
AI summary The document defines financial and operational terms for the 2026-2027 GRA, including interest recovery, balance adjustments, purchased power, system requirements, real-time pricing charges, and water royalties. These terms are part of a regulatory proceeding in Nova Scotia.
Fuel Adjustment Mechanism Plan of Administration in Effect for 20232026- 20242027 May 8XXXXXApril 25May 28, 20232025
AI summary The Fuel Adjustment Mechanism (FAM) Plan of Administration outlines the regulatory framework for fuel cost adjustments between 2023-2026 and 2024-2027. It governs how fuel costs are managed and passed on to consumers during the specified periods.
1.0 GENERAL DESCRIPTION This document describes the plan for administering Nova Scotia Power Inc.'s (NS Power) Fuel Adjustment Mechanism (FAM), which was approved by the Nova Scotia Utility and Review Board (as of April 1, 2025 referred to...
AI summary The document outlines NS Power's Fuel Adjustment Mechanism (FAM) plan, approved by the Nova Scotia Energy Board (NSEB). It details how the Base Cost of Fuel is calculated, reset via General Rate Applications (GRA), and adjusted for under-recovery balances. Stakeholders may challenge methodology and forecasts, with the Board conducting audits. Rates are adjusted based on the Cost of Service Study (COSS).
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 4 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The FAM will pass through the difference between actual costs and the Base Cost of Fuel to customers calculated on a ¢/kWh basis....
AI summary The Fuel Adjustment Mechanism (FAM) will pass through fuel cost differences between actual costs and the Base Cost of Fuel (BCF) to customers on a ¢/kWh basis. Interest on over/under-balances will be calculated using NS Power's Annual Weighted Average Cost of Capital (WACC). Adjustments include Actual Adjustment (AA) and Balancing Adjustment (BA) per rate class.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 5 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted appendix from a 2026-2027 General Rate Application (GRA) proceeding in Nova Scotia, containing confidential information removed. It is part of the Direct Evidence Appendix 6B (Redline), page 5 of 35.
2.0 FAM COMPONENTS Each January 1 through December 31 period shall constitute a distinct FAM year. Under the FAM, an adjustment will normally be calculated once per year to reflect the over/-under recovery. The FAM adjustment will consist...
AI summary The Fuel Adjustment Mechanism (FAM) establishes annual periods (January 1–December 31) for calculating adjustments to recover fuel and purchased power costs. Adjustments are determined yearly to reflect over/under recovery, with two components designed to ensure cost recovery.
2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...
AI summary The Balancing Adjustment Component (BA) corrects over/under-recovery from the Actual Adjustment Component (AA) and may defer fuel/purchased power costs with Board approval. The Fuel Adjustment Mechanism (FAM) includes AA and BA, with AA calculated annually based on fuel cost differences and BA managing prior adjustments and deferred costs.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 7 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The BA rate is calculated for the following year (year 2) on the basis of the overor under-recovery of the Actual Adjustment and B...
AI summary The document outlines the methodology for calculating Balancing Adjustment (BA) and Actual Adjustment (AA) rates for the 2026-2027 General Rate Application (GRA). It references Appendix A for sample Fuel Adjustment Mechanism (FAM) calculations and emphasizes fuel cost allocation across bundled and unbundled service classes, including Generation Replacement and Load Following (GRLF), Extra-Large Industrial Active Demand Control (ELIADC), and tariffs like Open Access Transmission Tariff (OATT).
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 8 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - d. All remaining fuel-related costs will be allocated to ATL classes and the Wholesale Market Backup/Top-up Service Tariff (BUTU...
AI summary The document outlines fuel cost allocation rules for ATL classes and BUTU, specifying 100% energy-related classification for certain costs. It details segregation of in-province purchased power from wind and biomass into energy/demand categories, using load factors and concurrent generation practices. Avoidable fuel costs apply to Wholesale Market Non-Dispatchable Supplier Spill Tariff and BUTU.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 10 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) e. Maritime Link imports under Nova Scotia Block will be classified to energy and demand on the basis of the system load factor a...
AI summary The document outlines methods for classifying and allocating costs related to Maritime Link imports, non-firm imports, and biomass generation. It specifies allocations based on system load factors, coincident contribution to system peaks, and energy requirements, with adjustments using revenue-to-cost ratios to align fuel costs with rate revenues.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 11 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) following approach: - a. In a year where the interest amount owed to customers by NS Power at the end of September coincides with...
AI summary NS Power outlines methods for apportioning interest expenses/credits tied to fuel cost variances and explains how the Fuel Adjustment Mechanism (FAM) calculates Actual Adjustment (AA) and Balance Adjustment (BA) components. Interest is allocated based on fuel cost variance shares, while AA/BA charges are determined using forecast energy sales and BCF variances.
3.1 Treatment of load migrating tobetween FAM/non-FAM classes When a customer transitions some or all of its load from abetween FAM-class to and non-FAM classes, NS Power shall treatdetermine the customer's outstanding fuel cost imbalance...
AI summary When customers migrate load between FAM and non-FAM classes, NS Power must calculate fuel cost imbalances using Special Condition 3 of the FAM Tariff. Adjustments are based on UARB decisions in subsequent proceedings and require UARB approval. Payment terms for imbalances must be agreed upon by NS Power and the customer, with carrying costs applied if unresolved.
3.2.1 Natural Gas - Natural Gas Consumed - Financial Instruments used for Hedging (including gains, losses, fees and interest charges) - Pipeline Reservation Fees, Tolls, Penalties (such as imbalance charges) - Pipeline Losses - Natural Ga...
AI summary The section outlines various costs associated with natural gas, including consumption, hedging financial instruments, pipeline fees, storage costs, and GHG emission compliance program expenses.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 17 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is part of the 2026-2027 General Rate Application (GRA) process, specifically Appendix 6B (Redline) from a Nova Scotia regulatory proceeding. The content is redacted, indicating confidential information has been removed, and it appears to be a draft or revised version of evidence submitted for review.
3.2.15 Limited-Duration Fuel Testing Page 21 of 33 These fuel testing costs (including solid fuel, liquid fuel and additives such as PAC) consist of the amounts directly incurred for shipping and handling and for conducting the test (e.g.,...
AI summary The document outlines costs associated with limited-duration fuel testing, including shipping, handling, and third-party analysis for solid, liquid fuels, and additives like PAC. These costs are restricted to non-capital expenses and must be separately identified in regulatory proceedings.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 22 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) the Company's accounting records.
AI summary Redacted page from the 2026-2027 GRA Direct Evidence Appendix 6B discussing the Company's accounting records as part of a Nova Scotia regulatory proceeding.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 23 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This document is part of the 2026-2027 General Rate Application (GRA) proceedings, focusing on direct evidence related to cost recovery and rate adjustments. Key entities include Nova Scotia Power and the Nova Scotia Energy Board, with topics covering rate design and DSM cost recovery mechanisms.
3.4 Deferrals During the 2023-20242026-2027 GRA Period, NS Power may include prior FAM deferrals for certain rate classes (Large General, Medium Industrial, and Large Industrial) in order to save additional interest charges which would acc...
AI summary NS Power may include prior Fuel Adjustment Mechanism (FAM) deferrals for Large General, Medium Industrial, and Large Industrial rate classes during the 2023-2024 to 2026-2027 General Rate Application (GRA) period to avoid additional interest charges by deferring amounts until the end of the period.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 24 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary This redacted page from the 2026-2027 GRA Direct Evidence Appendix 6B discusses confidential aspects of a regulatory proceeding, likely involving rate applications, cost recovery mechanisms, and energy management programs. Key focus areas include DSM, DER, and administrative cost allocations.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 26 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from a Nova Scotia regulatory proceeding related to the 2026-2027 General Rate Application (GRA). It includes a direct evidence appendix focusing on cost recovery mechanisms, though specific details are omitted due to confidentiality.
5.0 AUDIT AND OVERSIGHT The amounts charged through the FAM shall be subject to periodic audit to assure completeness and accuracy and to assure fuel and purchased power costs were incurred reasonably and prudently. The results of any audi...
AI summary The Fuel Adjustment Mechanism (FAM) charges are subject to periodic audits to ensure accuracy and prudence in fuel and purchased power costs. Audit results influence future Board hearings for adjusting Base Cost of Fuel or Fuel Adjustment Factor, or initiating a General Rate Case. The Board may adjust existing balances or recovered amounts, including interest, based on audit findings.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 29 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The Board will monitor the operation of the FAM closely and reserves the right to intervene in any circumstance where it believes...
AI summary The Nova Scotia Energy Board (NSEB) will monitor the Fuel Adjustment Mechanism (FAM) and retain authority to intervene if customer class rate increases are deemed unacceptable or against public interest, potentially deferring portions of increases to future periods.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 30 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix 6B, part of a Nova Scotia regulatory proceeding. No substantive content is visible due to confidentiality redactions.
ses. Notwithstanding the foregoing, stakeholders shall not be precluded from reviewing prior years' actual results versus prior forecasts in addressing the propriety of the succeeding year's forecast. 2026-2027 GRA Direct Evidence Appendix...
AI summary The document outlines stakeholder review processes for evaluating forecasts against prior years' actual results and defines key terms like Actual Adjustment (AA), Balance Adjustment (BA), and Annual Weighted Average Cost of Capital (WACC). It emphasizes transparency in fuel cost recovery and balance adjustments, with definitions critical to regulatory proceedings.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 33 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 20242026-2027 GRA Period refers to the period beginning January 1, 20236 and ending December 31, 20247 or to such time as determi...
AI summary The document outlines the 2026-2027 GRA period, defining terms like GRLF Revenue, Net Generation by Fuel Type, and NSPEMI. It discusses over/under-recovery of fuel costs and balance adjustments for prior years, impacting customer refunds or recoveries.
2026-2027 GRA Direct Evidence Appendix 6B (Redline) Page 34 of 35 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Prior Year's Accumulated Interest: the interest accumulated over the previous year on the balance in the 'Balancing Account' to b...
AI summary The document defines financial and operational terms related to the 2026-2027 GRA, including Prior Year's Accumulated Interest, Balancing Account balances, Total Purchased Power, System Requirements, Two-Part Real Time Pricing charges for ELI 2P-RTP customers, and Water Royalties. These terms outline mechanisms for cost recovery, pricing adjustments, and environmental compliance.
N-92026-2027 GRA Appendix 12 A-C - Cost of Service Study Process - Redacted
192 passages
Cost of Service Study Redacted 1 TABLE OF CONTENTS 2 3 1.0 INTRODUCTION 5 4 2.0 SUMMARY OF STAKEHOLDER PROCESS 7 5 3.0 SUMMARY OF COSS 10 6 3.1 The COSS Framework 10 7 3.2 Developments in the Company's Power System Impacting COS 11 8 4.0 O...
AI summary The document outlines the structure and contents of a redacted Cost of Service Study (COSS) being presented in a regulatory proceeding. It includes sections on the stakeholder process, proposed changes to the COSS, and a line loss study. Key topics include classification of generation and transmission costs, treatment of battery systems, and proposed changes to the DSM rider.
3 5.1 Classification of Generation Costs – SLF Methodology 4 - 5 NS Power's current approach to the classification of generation-related fixed costs (e.g. - 6 depreciation, financing) is first to classify environmental and fuel conversion-...
AI summary NS Power proposes shifting from a hybrid classification method (ELCC, SLF) to a uniform SLF-based approach for all generation costs, aiming to simplify cost tracking, enhance COSS transparency, and align with decarbonization goals. This reflects system changes due to renewable integration and asset retirements.
Cost of Service Study Redacted 1 COSS treatment that is applicable to generation assets, while also recognizing that non-firm PPAs 2 provide energy only. 3 4 5.3 Classification of Transmission Costs – Transmission 100 Percent to Demand 5 6...
AI summary The document discusses NS Power's use of the Service Life Factor (SLF) to classify transmission costs since the 1995 NSEB decision (NSPI864), aligning transmission with generation's energy and demand classification. It notes that transmission costs are demand-driven and that the SLF's relevance is diminishing due to coal phase-out and increased renewable energy adoption. The Elenchus Report is referenced for further details.
18 5.12 Decarbonization Deferral Account (DDA) 19 20 As a result of federal and provincial legislation regarding decarbonization, NS Power is required 21 to phase out coal generation, which will include addressing associated marine unloadi...
AI summary NS Power seeks to recover costs from retiring coal generation assets via the Decarbonization Deferral Account (DDA), approved by the Board on May 21, 2024. The DDA serves as a rate stabilization tool, with NS Power proposing it be classified and allocated similarly to other such tools. This addresses transition costs from decommissioning coal facilities by 2030 under federal and provincial decarbonization mandates.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 1 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Exhibit Reference Cells Modification formulae revised to receive no classification Exh 6 D172:M194 Allocations of transmission energy ex...
AI summary The document outlines modifications to the 2026-2027 GRA Direct Evidence Appendix 12A(1), including adjustments to transmission energy expense allocations, updates to values using the BCF file, and reclassifications to avoid division-by-zero errors in calculations.
1 Request for COSS Model Runs: Run # NSP Position Model Run Description 1 Yes NSP's positions in aggregate. This model includes the changes from model runs #2-5 below. 2 Yes New Intermediate Generation sub-function classified to demand and...
AI summary The document outlines a request for Cost of Service Study (COSS) model runs to evaluate various NSP positions, including the classification of generation and transmission, and the inclusion of specific rate classes and allocation methods.
3 Notes on COSS Model Runs: - 4 All changes to the model cells are denoted with orange highlighting. - 5 Model runs 1, 2, 4, 10a, 10b, and 11 require updates to the Base Cost Fuel ("BCF") file that is an - 6 input into the COSS. Revised ve...
AI summary The document discusses updates to the Base Cost Fuel (BCF) file in the COSS model runs, noting that changes create a mismatch between ATL revenues and costs, which is addressed by adjusting the Profit/Loss figures for BTL classes in specific model runs.
- table. 4 Intermediate Generation Unit Net Book Value Current Classification New Classification Tufts Cove 1 $16.5M 46.3% Energy 5.3% Energy 53.7% Demand 94.7% Demand 46.3% Energy 18.4% Energy Tufts Cove 2 $28.8M 53.7% Demand 81.6% Demand...
AI summary The table shows changes in the classification of intermediate generation units at Tufts Cove from energy to demand, with significant shifts in percentages and net book values. The average classification also reflects a notable change from demand to energy.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 14 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding. It outlines the methodology and considerations involved in conducting a cost of service study, which is a key component in determining appropriate rates for utility services.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 17 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding, indicating it is related to the analysis of costs associated with utility services in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 19 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary The document refers to the Cost of Service Study Process under NSUARB M11475, which is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(1). The study is likely related to analyzing the costs associated with service delivery for regulatory proceedings.
CONFIDENTIAL Exhibit Reference Cells Modification Exh 2b Rows 17-18, 41- 42 Intermediate Steam added Exh 3 Rows 17-18, 41- 42, 147-148, 171- 172 Intermediate Steam added Exh 4 Rows 27-28, 72- 73 Intermediate Steam added Exh 5 Rows 22-23, 3...
AI summary The text outlines modifications to various exhibits in a regulatory proceeding, including the addition of 'Intermediate Steam' and changes to classifications and allocations related to transmission demand and PHP as a separate ATL class. These adjustments involve updating rows and formulas in multiple exhibits to ensure proper categorization and avoid errors.
INTRODUCTION AND PURPOSE - My name is Bickey Rimal, and I am an Assistant Vice President with Concentric Energy Advisors, Inc. - ("Concentric"). I provided evidence related to class cost of service, pricing and rate design matters - in the...
AI summary Bickey Rimal, an Assistant Vice President with Concentric Energy Advisors, Inc., provides rebuttal testimony in the 2022 General Rate Application submitted by Nova Scotia Power. The testimony addresses claims and critiques from intervenors and consultants regarding the Minimum System Method, Minimum System Study, pole sub-functionalization study, cost allocation methods, and the methodology for calculating the Pole Attachment Rate.
Inclusion of Forecasted Costs - Mr. Briggs disputes the use of forecasted costs in the derivation of net book value and depreciation - expense associated with poles. [29](#page-73-2) It is appropriate to use both capital and O&M forecasted...
AI summary Mr. Briggs disputes the use of forecasted costs in calculating net book value and depreciation expense for poles. The NSUARB argues that both capital and O&M forecasted costs should be used in calculating the pole attachment rate, as the GRA revenue requirement is based on forecasted rate years. The prudency of these costs will be reviewed as part of the GRA.
NON-CONFIDENTIAL 1 Request DR-2: 2 3 Please state whether NS Power's proposal to use 3CP (and related) demand allocators is to 4 base class demand on (a) monthly coincident peak load hours or (b) monthly coincident net 5 peak load hours (e...
AI summary NS Power proposes to continue using 3CP demand allocators based on monthly coincident peak load hours, arguing that this method aligns with cost causation and is simple to implement, as winter peaking is driven by annual system peaks during winter months.
Critical Peak Pricing Events 2021 - 2023 Event Date Event Time 24-Feb-23 7:00 AM - 11:00 AM Atlantic 1-Feb-23 5:00 PM - 9:00 PM Atlantic 11-Jan-23 5:00 PM - 9:00 PM Atlantic 11-Jan-23 7:00 AM - 11:00 AM Atlantic 10-Jan-23 5:00 PM - 9:00 PM...
AI summary The text lists critical peak pricing events from 2021 to 2023, including specific dates and times. It also mentions a partially confidential appendix from the 2026-2027 GRA Direct Evidence.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests 1 Request DR-25: 2 3 Please confirm that using the SLF/CP3 method, costs are assigned to classes on an annual 4 basis and that it is not feasible to directly...
AI summary NSPI confirms that using the SLF/CP3 method, costs are assigned to classes on an annual basis and that it is not feasible to directly assign costs to seasonal, time-of-use, or hourly periods for cost-based ratemaking. However, winter season, on-peak demand charges can be set using the 3CPs that occur during peak hours in January, February, and December.
NON-CONFIDENTIAL 1 Request DR-26: 2 - 3 Please provide 2023 actual plus 2024-2027 forecast unamortized balances related to the early - 4 retirement of assets for environmental reasons. Please distinguish between assets that NS - 5 Power an...
AI summary The response to Request DR-26 outlines the unrecovered net book values of assets expected to be retired for decarbonization purposes, distinguishing between those included in the Decarbonization Deferral Account and others. Assumptions on early retirement dates align with the Company's 2023 10-Year System Outlook.
16 NS Power has not completed a forecast denoting the unrecovered net book value for these assets 17 for 2024-2027. NS Power would expect to complete this analysis in conjunction with a GRA 18 proceeding. - 20 In addition, in response to t...
AI summary NS Power has not yet completed a forecast for the unrecovered net book value of certain assets for 2024-2027, expecting to address this during a GRA proceeding. Additionally, NS Power is working to eliminate PCB-containing equipment by December 31, 2025 in compliance with the Canadian Environmental Protection Act 1999 and 2008 PCB Regulations.
Elapsed Time Percent Customer Contribution Up to 1 year 0 Year 1-2 20% Year 2-3 40% Year 3-4 60% Year 4-5 80% After 5 Years 100% Where the new requirement represents or indicates an expansion or upgrade of the prior facilities, the reduced...
AI summary The table outlines the percentage of customer contribution over time for a service upgrade or expansion, with increasing customer contribution as elapsed time increases. The reduced contribution applies only to costs related to equivalent service provision from prior facilities.
2.12 REFUNDS OF CAPITAL CONTRIBUTIONS Line/Service Extensions Less Than 184m Customers will be provided with 92 metres of line/service extension at no cost, as provided for under Regulation 2.6. Any line/service extensions in excess of 92...
AI summary The regulation outlines the policy for refunds of capital contributions for line/service extensions less than 184m. Customers receive 92m free, with additional extensions and connections subject to customer costs. Refunds are provided to contributors based on the number of additional customers connected within ten years, minus an administration fee.
Line/Service Extensions Longer Than 184m Customers will be provided with 92 metres of line/service extension at no cost. Any line/service extensions in excess of 92 metres will be at the cost of the customer. If any additional customers ar...
AI summary Customers are provided with 92 metres of line/service extension at no cost, with any additional length charged to them. Refunds are available for capital contributions if additional customers connect within ten years, but are reduced by 10% and capped at 90% of the original contribution. No refunds are issued after fifteen years.
2013 Cost of Service Study NSPI Responses to Consumer Advocate Data Requests 1 Request DR-6: 2 3 Derivation of "line losses," "demand line-loss adjustment," and "requirements" in "Input 4 Data Two" 5 6 Response DR-6: 7 8 The forecast of li...
AI summary The response to DR-6 explains how line losses are forecasted and assigned to rate classes based on historical patterns from prior COSS studies. Line losses are higher during peak demand hours and are scaled hourly to match annual energy targets. 'Requirements' refers to the total generation needed to meet customer demand, including both customer demand and losses.
Nova Scotia Power Cost of Service Study Methodology January 2022 2022-2024 GRA SR-01 Attachment 1a Page 2 of 12 COSS CA DR-53 Attachment 1 Page 2 of 62 PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 792 of 1218 R...
AI summary The document outlines the methodology for the Cost of Service Study (COSS) used by Nova Scotia Power for the 2022-2024 GRA. It discusses the allocation of costs to Above-the-line (ATL) customer classes after subtracting Below-the-line (BTL) costs, with the aim of identifying inter-class inequities through revenue/cost (R/C) ratios.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 797 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 7 of 12 COSS CA DR-53 Attachment 1 Page 7 of 62 Rate Base Exhibits 2,...
AI summary This document outlines the methodology used in the Nova Scotia Power Cost of Service Study for the 2022-2024 period, including the allocation of rate base to customer classes. It references the 2005 NSUARB decision and includes exhibits detailing net plant investment, allocation factors based on demand, energy sales, and customer numbers.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 801 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 11 of 12 COSS CA DR-53 Attachment 1 Page 11 of 62 Nova Scotia Power Co...
AI summary The document outlines the methodology used in the Nova Scotia Power Cost of Service Study, detailing how various costs such as bad debt, depreciation, and interest are allocated across customer classes. The allocation is based on factors like gross write-off experience, number of customers, and total rate base. Exhibit 7 is used to verify the accuracy of the cost allocation analysis.
Nova Scotia Power Fuel and Purchased Power Related COS Methodology January 2022 Forecast fuel costs for each test year are first apportioned to above-the-line (ATL) and below-the-line (BTL) classes using procedural step 1: 1. A portion of...
AI summary Nova Scotia Power outlines its methodology for allocating forecast fuel and purchased power costs between above-the-line (ATL) and below-the-line (BTL) classes. The company assigns a portion of fuel-related costs to specific BTL classes and unbundled tariffs, while allocating the remainder to ATL classes using modified procedural steps. Starting in 2023, the BUTU class will use the embedded cost allocation methodology for FAM customers.
Nova Scotia Power Fuel and Purchased Power Related COS Methodology January 2022 1 2 2. For ATL classes, NS Power's fuel costs will be classified as 100 percent energy related. 3 These costs will be allocated to each class based on its rela...
AI summary The document outlines Nova Scotia Power's methodology for classifying and allocating fuel and purchased power costs under the 2022-2024 Generation and Resource Assessment (GRA). Fuel costs are categorized as energy-related for ATL classes and allocated based on monthly energy requirements. Purchased power is classified between energy and demand based on generation source and NS Power's fixed cost base load generation practices.
Nova Scotia Power Unmetered Services Pricing January 2022 1 1.0 INTRODUCTION 2 3 This report is filed in support of NS Power's General Rate Application (GRA). The report provides 4 a description of unmetered services, an outline of the cur...
AI summary This document outlines Nova Scotia Power's General Rate Application (GRA) for unmetered services, including streetlight rates and the rationale for unmetered service eligibility based on impracticality of metering and high costs relative to energy consumption.
2.0 RATEMAKING METHODOLOGY FOR UNMETERED - 9 The ratemaking methodology is comprised of two steps: - 1. Determination of cost responsibilities of the Cost of Service Study (COSS)-based unmetered class, which is comprised of all costs of st...
AI summary The ratemaking methodology for unmetered classes involves determining cost responsibilities based on the Cost of Service Study (COSS), which includes street and area lighting and miscellaneous loads, followed by setting revenue responsibilities and calculating individual service rates.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 814 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1d Page 5 of 11 COSS CA DR-53 Attachment 1 Page 24 of 62 Nova Scotia Power Unm...
AI summary The document discusses the determination of unmetered electricity rates for streetlight fixture maintenance, including the allocation of capital costs using the Cost of Service Study (COSS) methodology. The rates are structured with a demand charge and declining block energy charges, and are subject to changes in GRA proceedings.
Nova Scotia Power Unmetered Services Pricing January 2022 Calculation of the demand and energy charges, for both the RTR Distribution Tariff and bundled service rate as based on the Miscellaneous Lighting Rates proposed, is shown at the bo...
AI summary The document outlines the calculation of demand and energy charges for the RTR Distribution Tariff and bundled service rates based on proposed Miscellaneous Lighting Rates. It provides revenue figures for Street and Crosswalk Lighting and miscellaneous load revenues for 2022, 2023, and 2024 under both standard (unsmoothed) and smoothed unmetered tariffs.
12 2.1.2 Allocation of Revenue Requirement 13 14 The second step in the calculation of transmission rates is to allocate the revenue requirement (i.e. 15 the costs associated with transmission) among the appropriate services. The following...
AI summary This section discusses the second step in calculating transmission rates, which involves allocating the revenue requirement among appropriate services. It outlines the need to define the transmission services to be provided as part of this process.
3 2.1.7 Allocation of Revenue Requirements to Services 4 5 The last step in the cost allocation analysis is to allocate total transmission costs to the services 6 that will be offered under the tariff. As noted above, these are Point-to-Po...
AI summary The document discusses the allocation of transmission revenue requirements to specific services, including Point-to-Point Service, Network Service, and Scheduling, System Control and Dispatch Service. It references the percentage share of usage for Point-to-Point and Network Services and refers to a figure illustrating the cost allocation.
REDACTED 1 Request DR-58: 2 3 For each customer class, please provide hourly estimates of the class load for each year 2014- 4 2023, even if NS Power has low confidence in the quality of the data for any particular time 5 period. 6 7 (a) P...
AI summary The document includes a request for hourly load estimates for customer classes from 2014 to 2023, along with explanations of data confidence levels and assumptions for unmetered load. NS Power refers to a load research sample and provides information on data precision based on metering and sampling methods.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 904 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 16 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - Fourth, Resource Insight do...
AI summary The text criticizes Resource Insight's recommendation for updating cost allocation methodologies, arguing that it lacks logical support and could lead to instability in cost allocation and rate design. The text emphasizes the importance of relying on precedents and the potential negative impact of abandoning them, including rate shocks for customers.
Inclusion of Forecasted Costs - Mr. Briggs disputes the use of forecasted costs in the derivation of net book value and depreciation - expense associated with po[les](#page-180-2). 29 It is appropriate to use both capital and O&M forecaste...
AI summary Mr. Briggs disputes the use of forecasted costs in calculating net book value and depreciation for poles. He argues that using forecasted net book value with historical pole counts may lead to inaccuracies, as capital additions may reflect asset replacement rather than growth.
- 21 per year are as follows: # of Interruption Events Total Duration (Hours: Minutes) 2024 YTD 2 2:48 2023 6 20:02 2022 10 37:16 3 M05473, NS Power 2013 Cost of Service Study, NS Power Application, Appendix H – 2013 COS Strawman Report V1...
AI summary The text presents a table showing the number of interruption events and total duration for the years 2022, 2023, and 2024 YTD. It also references a 2013 Cost of Service Study and a 2022-2024 General Rate Application, highlighting discussions around interruptible supply credit allocation and cost-of-service studies.
2009 General Rate Application (NSUARB P-888) NSPI Responses to Avon Information Requests 1 Response IR-168: (cont'd) 2 3 b) In its 2002 Rate Application, NSPI proposed that the credit be updated to 4 $3.08/kVA/month. The Board decided to a...
AI summary NSPI responded to Avon's information requests regarding its 2009 General Rate Application. The response discusses the 2002 rate application, the 2003 Generic Rate Design Hearing, and the decision not to change the interruptible credit. It also mentions the variability of CT costs and their alignment with market prices.
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.
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.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests 1 Request DR-3: 2 3 From the 2024 Load Forecast (released recently as part of another proceeding, but for the 4 purposes of supporting analysis in this one):...
AI summary NSPI is responding to data requests related to the 2024 Load Forecast, providing load forecast data for P10, P50, and P90 scenarios by rate class for 2024 and 2030. NSPI notes that demand by rate class is not modeled at the P10/P50/P90 level and that demand forecasts are not split between firm and interruptible for large industrial customers.
Resource Cost, Performance, & Financing Performance Inputs Financing Performance Inputs Financing System Depreciable Lifetime 35 % Financed w/ equity % Financed w/ debt Ongoing Costs Debt Interest rate Fixed O&M Costs ($/kW-yr) $17.69 Cost...
AI summary The document presents a table outlining performance inputs and financing details for a system, including system cost, depreciation lifetime, financing percentages, interest rates, tax assumptions, and levelized costs. It includes data on capital costs, O&M expenses, and PRM adjustments.
CONFIDENTIAL (Attachments Only) 1 Response DR-18: 2 3 4 (a) Written Responses: 5 (i) For the effect of MEU proposal to align OATT methodology with COS, please refer 6 to Attachment 1. The effect on individual rate class costs is around 0.0...
AI summary The response discusses the effect of aligning OATT methodology with COS, noting a negligible impact of 0.01 percent on individual rate class costs. It also references model requests and spreadsheet files related to NSP's unbundled service proposal and PHP ATL/BTL analyses, while indicating that certain analyses have not yet been conducted due to resource constraints.
NON-CONFIDENTIAL 1 (a) How cost and rate disparities between bundled and unbundled services, offered by 2 single utilities, are addressed in other jurisdictions? 3 4 (b) What changes would be required to the COSS methodology to ensure alig...
AI summary The response to question (a) indicates that Elenchus' survey of Canadian and US jurisdictions did not find information on cost and rate disparities between bundled and unbundled services, as Nova Scotia's regulatory framework allows both markets to operate in parallel. Utilities surveyed were either mandated to unbundle or remained vertically integrated.
NON-CONFIDENTIAL 1 Fixed-generation BUTU and RtR rates are calculated by the same COSS-based embedded 2 cost methodology, however, there is a phase-in adjustment applied to the BUTU rates in 3 2023 to limit the forecast revenue increase to...
AI summary The text explains the methodology for calculating BUTU and RtR rates using a COSS-based embedded cost approach, with a phase-in adjustment in 2023 to limit revenue increases. It also outlines how demand and energy charges are calculated, and summarizes the basis for FAM and non-FAM costs in different rate categories.
BUTU RtR Municipal FAM-related – "Energy-related Purchased Power and Fuel Cost" "Fuel Cost" "Energy Charge" Energy Allocated MWh Marginal/Avoided Cost Allocated MWh "Energy-related Fixed Generation Cost" "Fixed Cost Adder" "Energy Charge"...
AI summary The table compares different cost allocation methods across BUTU, RtR, and Municipal categories, including energy-related and demand-related costs. It outlines various cost components such as 'Energy-related Fixed Generation Cost,' 'Demand-related Purchased Power,' and 'Average NS Power Unit Cost.' The document is part of a confidential appendix in a regulatory proceeding.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1060 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests related to Peak Hour Pricing (PHP). The content highlights the procedural and analytical aspects of the study.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1061 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines the Cost of Service Study Process as part of the NSUARB M11475 proceeding, with NSPI providing responses to data requests related to Peak Hour Pricing (PHP).
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document pertains to the Cost of Service Study Process under NSUARB M11475, focusing on NSPI's responses to data requests related to Peak Hour Pricing (PHP).
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests 1 Request DR-12: 2 3 Please provide variations of the 2023 Cost Of Service Study Analysis with the following 4 changes: 5 6 (a) PHP included as a standalone...
AI summary NSPI is responding to PHP Data Request DR-12, which asks for variations of the 2023 Cost Of Service Study Analysis with specific changes. The request includes scenarios for PHP as a standalone customer class, functional allocation based on ELCC, and transmission expense allocations. PHP revised part (a) to include specific energy and demand parameters.
15 4. COST OF SERVICE CLASSIFICATION OF THE MARITIME LINK 16 The CA proposes, supported by MEUNSC, the following: - 17 (a) For the purposes of setting the Base Cost of Fuel for each year of the Rate 18 Stability Period, the Maritime Link c...
AI summary The CA proposes classifying Maritime Link costs as NS Power-owned hydro generation for the Base Cost of Fuel during the Rate Stability Period. The Parties agree to a consultative process to address cost allocation and will file a report with the Board by March 31, 2017. Disagreements will be resolved by the Board, and any changes to classification will not be retroactive and will not be implemented before January 1, 2020.
Cost of Service Classification of the Maritime Link Strawman Report 1 The purpose of this Report is to summarize the various options available with respect to the Cost 2 of Service allocation of the Maritime Link for the purposes of facili...
AI summary This report outlines the cost of service classification options for the Maritime Link, aiming to facilitate consensus among stakeholders. The report emphasizes that cost of service studies do not affect revenue recovery but focus on fair revenue apportionment among customer classes. NS Power seeks input by January 27, 2017, and plans to discuss the matter in a February 2017 meeting.
Cost of Service Classification of the Maritime Link Strawman Report 1 The Company also proposed that the Nova Scotia Block be treated in the same manner as NS 2 Power-owned hydro generation. This means that its costs would be classified to...
AI summary The document discusses the proposed cost of service classification for the Nova Scotia Block, suggesting it be treated similarly to NS Power-owned hydro generation. Energy and demand costs would be allocated based on system load factors and coincident system peaks, aligning with NS Power's COSS practices.
Cost of Service Classification of the Maritime Link Strawman Report 1 share of generation costs, would experience an additional increase of 1.1% under the Hydro-based approach compared to that under the Fossil Fuel Approach.[6](#page-178-1...
AI summary The document discusses the cost of service classification of the Maritime Link Strawman Report, with the IG and SBA supporting the Hydro-based cost allocation approach. NS Power's proposal to classify Maritime Link revenue requirements similarly to company-owned hydro plant costs is opposed by the CA's consultant, who suggests a different allocation based on benefits to customer classes.
Cost of Service Classification of the Maritime Link Strawman Report 1 should be allocated in proportion to the average of peak demands for the three winter months.[9](#page-179-0) 2 3 4 Mr. Wallach expressed concern that the Hydro-allocati...
AI summary The document discusses the allocation of costs for the Maritime Link project, with Mr. Wallach expressing concerns about the Hydro-allocation approach and its departure from past practices. NS Power argues that its benefits-based approach is consistent with the 2013 COS proceeding and the approved methodology, while also highlighting the distinctiveness of the Nova Scotia Block in terms of service delivery and costing treatment.
NON-CONFIDENTIAL - 1 Lines, are classified to demand and customer as determined in Exh 3c, Exh 3e, and Exh 3g. Please - 2 refer to section "3. Distribution system sub-functionalization and classification" of the evidence - 3 filed by Conce...
AI summary The document discusses the classification of various infrastructure investments into demand and customer categories, based on evidence provided in the 2023-2024 GRA. Specific classifications include poles and wires, substations, and streetlights, with references to attachments and exhibits for detailed breakdowns.
MEMORANDUM TO: Nova Scotia Power, Inc. FROM: Bickey Rimal, Concentric Energy Advisors DATE: January 2022 RE: GRA Allocated Cost of Service and Miscellaneous Charges Matters The purpose of this memorandum is to provide the results of: - Con...
AI summary This memorandum from Concentric Energy Advisors to Nova Scotia Power Inc. reviews the company's allocated class cost of service (CCOS) model, concluding that it is reasonable, follows industry-accepted methodology, and produces accurate results. The model uses a three-step process: cost functionalization, classification, and allocation, which are described in detail.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1151 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-4 Attachment 1 Page 6 of 7 The underlying data used to calculate the fee are cost based and the...
AI summary The document outlines the methodology for calculating pole attachment fees by NS Power, based on cost considerations. The fee is determined by allocating indirect and direct costs associated with poles between NS Power and third-party attachers. The allocation is based on the proportion of usable space occupied by non-power attachments, with a final adjustment for the average number of non-power attachments per pole. The fee is deemed reasonable and minimizes cross subsidization.
COSS SBA DR-6 Attachment 1 Page 7 of 24 281050 LT ACCRUED PENSION LIAB NSPI 283270 LT REGULATORY EMISSION COMPLIANCE 283300 LT UNEARNED REVENUE LIAB 283450 LONG TERM ACCRUED INTEREST 283500 LT DSU RSU 283900 LT LIABILITIES OTHER 283950 LT...
AI summary The document presents a list of long-term liabilities and revenue-related accounts, including pension liabilities, regulatory compliance costs, accrued interest, and liabilities related to demand-side management. It also includes revenue and cost recovery entries related to time-of-use pricing, small generators, and other regulatory matters.
COSS SBA DR-6 Attachment 1 Page 8 of 24 413250 REG RES ACCRUED FAM BA FUEL COST 413310 REG METERED OUTDOOR REC LIGHTS NON FUEL ENERGY 413330 REG METERED OUTDOOR REC LIGHTS FAM AA FUEL COST 413350 REG METERED OUTDOOR REC LIGHTS DSM COST REC...
AI summary The text lists various regulatory account codes related to fuel costs, energy usage, and cost recovery riders for different customer categories and usage types, including time-of-use and small generation. These codes are part of a financial and regulatory framework for Nova Scotia Power.
COSS SBA DR-6 Attachment 1 Page 9 of 24 414540 REG LARGE GENERAL FAM AA FUEL COST 414550 REG LARGE GENERAL FAM BA FUEL COST 414610 REG GENERAL TIME OF USE NON FUEL DEMAND BASE 414620 REG GENERAL TIME OF USE NON FUEL ENERGY ALLHOURS 414630...
AI summary The document lists various rate codes related to fuel costs, time-of-use pricing, demand base, energy charges, and revenue for different customer classes, including large, small, and medium industrial and general customers. These codes are part of a regulatory proceeding and appear to be associated with cost recovery and rate structures.
3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...
AI summary NS Power's Fuel Adjustment Mechanism (FAM) operates on an annual cycle with an over/under recovery mechanism, consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The AA is calculated based on the over- or under-recovery of the Base Cost of Fuel at the end of September, while the BA manages deferred fuel and purchased power costs approved by the Board.
3.1 Treatment of load migrating to non-FAM classes When a customer transitions some or all of its load from a FAM-class to a non-FAM class, NS Power shall determine the customer's outstanding fuel cost imbalance at the date of transition....
AI summary When a customer transitions load from a FAM class to a non-FAM class, NS Power must determine the fuel cost imbalance and adjust it according to UARB decisions. Adjustments require UARB approval and must be settled on terms acceptable to both parties, with carrying costs applied if payments are made over time.
- GHG Emission Compliance Program costs 502500 REG FUEL DIESEL OIL CONSUMED 504450 REG GRID SALES FUEL DIESEL PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1195 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED)
AI summary The document discusses the costs associated with the GHG Emission Compliance Program, including specific line items related to fuel consumption and grid sales fuel. It is part of a partially confidential GRA Direct Evidence Appendix.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1198 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-7 Attachment 1 Page 19 of 33 FAM POA Main Document (Redline) – Revision 11 / February 2023
AI summary This document is a partially confidential appendix from a 2026-2027 General Rate Application (GRA) proceeding, including a redline version of the Fuel Adjustment Mechanism (FAM) Plan of Administration (POA) as of February 2023. It is part of a Cost of Service Study (COSS) and includes references to other studies and mechanisms such as the Fuel Adjustment Mechanism Adjustment (FAMAA) and Balancing Adjustment riders (BARIDERS).
3.4 Deferrals During the 2023-2024 GRA Period, NS Power may include prior FAM deferrals for certain rate classes (Large General, Medium Industrial, and Large Industrial) in order to save additional interest charges which would accrue by fu...
AI summary During the 2023-2024 GRA Period, NS Power may include prior FAM deferrals for certain rate classes to avoid additional interest charges. This relates to the Fuel Adjustment Mechanism and the Plan of Administration, as outlined in the COSS SBA DR-7 and FAM POA documents.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1212 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-7 Attachment 1 Page 33 of 33 FAM POA Main Document (Redline) – Revision 11 / February 2023 Prior...
AI summary The document outlines various financial and operational terms related to energy management and billing, including accumulated interest, balancing account adjustments, purchased power costs, system requirements, real-time pricing charges, and water royalties. These terms are used in the context of rate calculations and financial reporting for energy providers.
The GRA Decision provided as follows: [361] In this proceeding, several concerns were raised about NS Power's cost of service methodologies applied in this GRA. These concerns included the use of the minimum system study for the classifica...
AI summary The GRA Decision addresses concerns about NS Power's cost of service methodologies, including the use of the minimum system study and LF/3CP method for cost classification. The Board agrees to update the COSS and Line Loss Study to reflect recent system developments and directs semi-annual progress reports starting in 2024.
Agenda - 1. Introduction and Project Description - 2. Generic Background on Cost Allocation Methodologies - 3. NS Power's Existing COSS Methodology - 4. Effect of Transitional and Technological Changes on COSS - 5. Survey - 6. Next Steps
AI summary The agenda outlines the topics to be discussed in a regulatory proceeding, including an introduction, background on cost allocation methodologies, NS Power's existing cost of service study (COSS) methodology, the impact of transitional and technological changes on COSS, a survey, and next steps.
Elenchus Research Associates Inc. ("Elenchus") - John Todd, President - Founded 1980 - Andrew Blair joined Elenchus in 2016 - Transferred to Power Advisory in 2023 - Elenchus has conducted Cost of Service/Cost Allocation and Rate Design (C...
AI summary Elenchus Research Associates Inc., founded in 1980, has conducted various regulatory and utility-related reviews. Key personnel include John Todd, President, and Andrew Blair, who joined in 2016 and transferred to Power Advisory in 2023. Elenchus has worked with multiple regulators and utilities, including NB Power and ENMAX, and has assisted with rate impact and bill analysis for E1, integrating with NSP's COS model. A strategic alliance was formed with Power Advisory in 2021.
Elenchus Approach to the Review - Facilitate NS Power's Stakeholder Process ‐ technical sessions, with goal being to: - Assist in clarifying and understanding the concerns and views of all parties - Distinguish between interest‐based and p...
AI summary The Elenchus Approach to the Review outlines a structured process to facilitate NS Power's stakeholder engagement, clarify stakeholder concerns, and review NS Power's cost allocation methodologies. It also includes a survey of utility practices in Canada and the US, and the preparation of evidence for filing with the Nova Scotia Utility and Review Board.
Purpose of the January 18th Session (Kick-off) - Canvass stakeholders to determine the parts of NS Power's COSS methodology that need to be explained in greater detail in future tech sessions. Future technical sessions will assist stakehol...
AI summary The January 18th session aims to engage stakeholders in reviewing NS Power's Cost of Service Study (COSS) methodology, identify areas requiring updates due to developments since 2013, and determine the implications of proposed changes on allocated costs. The session will also establish a timeline for future discussions.
Cost Allocation Methodologies – Conceptual Overview - Directly allocated costs Exclusive use by class (rare) - Shared Utility Assets and Expenses - > We all benefit from sharing - > Electrons flow through common infrastructure - Cost Causa...
AI summary This section provides an overview of cost allocation methodologies, emphasizing the use of cost causality as the main criterion for allocating shared utility assets and expenses. The goal is to achieve fair and reasonable rates, with rate design being a subsequent step that may incorporate policy considerations.
Cost Allocation Methodology – Three Basic Steps - > Functionalization: - Generation, Transmission, Distribution, Retail - Categorization or classification: - > Energy, Demand, Customer - > Allocation: - > Use Cost Drivers: kWh, kW, Custome...
AI summary The document outlines a three-step cost allocation methodology for electricity systems: functionalization, categorization, and allocation using cost drivers such as kWh, kW, and customer count. It also notes that fairness principles focus on cost recovery based on fully allocated embedded costs, though actual rates may differ due to policy considerations like conservation and clean energy incentives.
Cost Allocation Results - Revenue to cost ratios (R/Cs) by customer class - Target R/C is 1.00 - Above 1.00 – revenues higher than costs - Below 1.00 – revenues lower than costs - But allocation is not precise - Hence, goal is typically R/...
AI summary The document discusses the allocation of costs based on revenue to cost ratios (R/Cs) by customer class, aiming for a target R/C of 1.00 with a permissible range of 0.95 to 1.05 to reduce rate volatility. Adjusting R/Cs is the starting point for rate design, with additional steps involving monthly/demand/energy charges and policy-based rates such as time-of-use (TOU) rates.
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.
Revenue-related Attributes: - 1. Effectiveness in yielding the utility's total revenue requirement, under the fair return standard, without socially undesirable expansion of rate base or socially undesirable level of product quality or saf...
AI summary The text outlines three key attributes related to revenue in a regulatory context: effectiveness in achieving the utility's revenue requirement under a fair return standard, stability and predictability of revenue and rates, and historical continuity of rate structures.
Cost-related Attributes: - 4. Static efficiency of the use of rate classes and rate blocks in discouraging wasteful use of the service, while promoting all justified types and amounts of use. - 5. Reflections of all of the present and futu...
AI summary The text outlines key cost-related attributes for rate design, emphasizing efficiency, fairness, and equity in cost allocation. It highlights the need to consider both private and social costs and benefits, avoid discrimination, and promote innovation in response to changing demand and supply patterns.
Practical-related Attributes - 9. The related, practical attributes of simplicity, certainty, convenience of payment, economy in collection, understandability, public acceptability, and feasibility of application. - 10. Freedom from contro...
AI summary The text discusses practical-related attributes of utility rates, emphasizing simplicity, certainty, convenience, economy in collection, understandability, public acceptability, and feasibility of application, as well as freedom from controversies regarding interpretation. It references a textbook on public utility rates.
Generation Classification Methodologies - Variable costs (per MWh) are energy related - > Such as fuel costs - > How to classify capital and other fixed costs? - ➤ NARUC Manual (January 1992) identifies many acceptable options to use for t...
AI summary The text discusses methods for classifying variable and fixed costs in generation, referencing the NARUC Manual and exploring implications of modernization on cost allocation and rate design, particularly in relation to the 4D's (Decentralization, Decarbonization, Democratization, Digitization).
Generation Classification Methodologies (4) - > Time Differentiated Embedded Cost of Service Methods - Production Stacking - ➤ Base-Intermediate-Peak (BIP) - Loss of Load Probability (LOLP) Production Cost - ➤ Probability of Dispatch - > T...
AI summary The document discusses time differentiated embedded cost of service methods, including Production Stacking, Base-Intermediate-Peak (BIP), and Loss of Load Probability (LOLP) Production Cost. These methods are noted as complex and unstable but may become more feasible with the development of AMI, which provides better data and transparency.
Transmission Classification / Allocation Methodologies - ➤ Transmission is treated as an extension of generation and is classified to energy and demand based on the system load factor - ➤ Illustrative example: - > Allocation same as genera...
AI summary The document discusses transmission classification and allocation methodologies, treating transmission as an extension of generation and classifying it based on system load factor. It also raises questions about the implications of modernization and the 4D's impact on cost allocation and regulatory decisions.
Distribution Classification / Allocation Methodologies - > NS Power is consistent with standard practices - > Typical approach across utilities: - ➤ Use Minimum System Method for classification of lines and transformers - ➤ Multiple-CP for...
AI summary The text discusses NS Power's use of standard classification and allocation methodologies in distribution, including the Minimum System Method, Multiple-CP, and NCP allocation. It raises a question about the implications of modernization, specifically whether the 4D's impact on CA or RD is causal or driven by policy.
Above-the-Line / Below-the-Line - In NS Power's methodology, costs are allocated Above‐the‐Line after determining the cost responsibility of Below‐the‐Line customers - This review will focus on Above‐the‐Line rate classes
AI summary The document discusses NS Power's methodology for allocating costs Above-the-Line after determining the cost responsibility of Below-the-Line customers. The review will focus on Above-the-Line rate classes.
Agenda - 1. Introduction and Project Description - 2. Generic Background on Cost Allocation Methodologies - 3. NS Power's Existing COSS Methodology - 4. Effect of Transitional and Technological Changes on COSS - 5. Survey - 6. Next Steps
AI summary The agenda outlines the topics to be discussed in a proceeding, including the introduction of a project, background on cost allocation methodologies, NS Power's existing cost of service study methodology, effects of transitional and technological changes on the methodology, a survey, and next steps.
Methodologies in the Future Stakeholder views need to be considered. - ➤ Are NS Power's current methodologies appropriate as the sector evolves? - Please identify issues that need to be reconsidered - ➤ Review methodological precedents in...
AI summary The document discusses the need to reconsider NS Power's current methodologies in light of sector evolution, asking stakeholders to identify issues, review methodological precedents from other jurisdictions, and determine appropriate methodologies for both the current and future state of NS Power, including elements of the Cost of Service Study (COSS) and rate design considerations.
Evergreen IRP – Key Assumptions Environment • NS Power is planning for a decarbonized electricity system and economy • Evergreen IRP assumptions include the following environmental policies: CER (Net Zero 2035) Coal Phase-Out 2030 80% Rene...
AI summary NS Power is planning for a decarbonized electricity system and economy, with key environmental policy assumptions including a coal phase-out by 2030, renewable electricity standards, federal carbon pricing, and Nova Scotia's GHG Output-Based Pricing System.
Cost Allocation The amount of total costs to be allocated to individual rate classes.
AI summary The document discusses the allocation of total costs to individual rate classes, focusing on how costs are distributed among different customer categories for the purpose of rate setting.
Revenue responsibilities Determines the revenue responsibilities among rate classes and individual customers. Cost of Service Revenue Requirement Rate Design
AI summary The document discusses revenue responsibilities among rate classes and individual customers, focusing on the Cost of Service Revenue Requirement and Rate Design.
Definitions Cost of Service Studies The Cost of Service Study is a process used by a utility to apportion utility's costs among customer classes for the purpose of development of rates. Aside from determining overall cost responsibilities...
AI summary The Cost of Service Study is a process used by utilities to allocate costs among customer classes for rate development, establishing the foundation for rate structures.
1995 COS Generic Hearing (NSPI864) - Classification of generation and transmission should reflect the intent of the asset: - o All generation costs associated with environmental compliance and fuel conversion to be classified as energy-rel...
AI summary The document discusses the classification of generation and transmission costs, emphasizing the need to align them with the intent of the assets. It suggests that environmental compliance and fuel conversion costs should be energy-related, while fixed costs of Steam and Hydro generation and transmission should be based on annual system load factor. The Equivalent Peaker method was rejected due to inconsistent calculations, and transmission is treated as an extension of generation. Fuel costs are to be allocated on a monthly basis to reflect seasonality.
2013 COS Generic Hearing (M05473) - Upheld status quo regarding the most significant elements of the 1995 COS design - SLF-based classification and 3CP Allocation of non-fuel costs of base load generation and transmission was favored over...
AI summary The 2013 COS Generic Hearing (M05473) upheld the 1995 COS design's core elements, including SLF-based classification and 3CP allocation, but noted pending decisions on distribution costs. Adjustments were made to better align with cost causation and asset utilization, including sub-functionalizing purchased power costs and using a formulaic approach for billing and call center costs.
COS Generic Hearing (M05473) - Deferred Projects No Project Status 1 &2 Capacity contribution of ERIS and NRIS wind Consistent with Board's directive the COS treatment in BCF and GRA proceedings aligned with NSPI's planning assumption base...
AI summary The document discusses deferred projects under the COS Generic Hearing (M05473), including the capacity contribution of wind projects, treatment of Lingan Units 1 & 2 as base load units, a survey of the distribution system, and class load data collection and analysis. These projects are aligned with planning assumptions and regulatory proceedings.
Changes in treatment of BUTU Tariff in COSS - 2021 BUTU (M09940): - BUTU energy and demand charges to be fully embedded cost-based subject to a 4-year phase-in with years three and four to be postponed until an updated COSS is filed. - BUT...
AI summary The 2021 BUTU tariff (M09940) is subject to a 4-year phase-in of fully embedded cost-based energy and demand charges, with years three and four postponed until an updated COSS is filed. BUTU is also subject to the FAM adjustment and reflects fixed cost rate components from the Standby and Energy Balancing tariffs in the RtR market.
Summary - Methodology of NS Power's COS has evolved in response to NS Power's changing operating, regulatory and technological environments. - With the addition of new types of generation and implementation of hourly load research samples...
AI summary NS Power's Cost of Service (COS) methodology has evolved to include more accurate methods such as SLF-based classification and 3CP-based allocation, replacing the Average Excess method from 1995. The 2013 COS proceeding reviewed alternatives like Equivalent Peak and BP/BIP methods for generation and 100% Demand/12CP for transmission, but these were rejected by the Board due to complexity and lack of industry use.
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.
Revenue responsibilities Determines the revenue responsibilities among rate classes and individual customers. Cost of Service Revenue Requirement Rate Design (cent /kWh Rider)
AI summary The document discusses the determination of revenue responsibilities among rate classes and individual customers, focusing on the Cost of Service Revenue Requirement Rate Design, measured in cents per kWh rider.
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.
Time-differentiated Method considered in 2013 COS - Of interest to this proceeding; where parties indicated interest in finding a time-differentiated (TD) COS method that would better align cost apportionment to rate classes with timediffe...
AI summary The time-differentiated (TD) method for calculating the cost of service (COS) was considered in the 2013 proceeding. Mel Whalen, the Board's consultant, highlighted imperfections in TD methods, noting they oversimplify generation planning and fail to account for long-term forecasts, public policy, and technology changes. He also questioned the equitability of TD-based solutions and their poor prediction of on-peak generation capacity costs.
Evolving and adaptive nature of NS Power's COS In response to changing operating environment NS Power proposed various refinements to the COS methodology for stakeholders' review and Board's approval in GRA and Base Cost of Fuel (BCF) proc...
AI summary NS Power has proposed several refinements to its Cost of Service (COS) methodology in response to changes in the operating environment. These include the addition of new generation types, separation of fuel cost allocation, and changes to costing treatments for various energy sources and services, as discussed in various regulatory proceedings.
Challenges lying ahead - The pace of changes in NS Power's generation and power purchase mix is about to accelerate in the coming years. - The share of NSPI owned generation in total system energy requirement will continue to decline falli...
AI summary NS Power's generation mix is expected to change significantly, with a decrease in fossil fuel generation and an increase in renewable energy. This shift will impact cost classification and redistribution of generation costs among different rate classes.
Discussion - Material changes in operating environment require reviews of costing methodology to ensure proper alignment with cost causation and asset utilization. - It is also important to be mindful of established ratemaking principles,...
AI summary The discussion highlights the need to review costing methodologies in response to changes in the operating environment, emphasizing the importance of aligning with cost causation and asset utilization. It also addresses the balance between ratemaking principles and the simplicity of the SLF method, while noting the complexity of alternative methods like LOLP and Probability Dispatch.
NS Power's Position on classification of Transmission in past COS Proceedings - In its 1993 COS Application (NSPI864) NS Power proposed unbundling of transmission from production costs and classifying it 100% to demand cost allocated to ra...
AI summary NS Power has historically proposed different methods for classifying transmission costs in its COS Applications, including unbundling from production costs and allocating based on 3CP or 12CP. The UARB has influenced these classifications, and NS Power argues that 12CP better reflects the physical and operational realities of its transmission system.
MidAmerican developed the HCM because wind generation came to represent about half of generation costs - The Iowa Board approved the switch to the HCM in 2014, noting that "wind power has not been a significant source of generation in any...
AI summary MidAmerican developed the HCM due to wind generation representing about half of generation costs. The Iowa Board approved the switch to the HCM in 2014, citing that wind power was not a significant source in prior rate cases. The HCM is described as a cost allocation and pricing model that ensures consistency between the two.
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
AI summary The text suggests replacing MidAmerican's exponential function with California's probability-based curve, specifically using the sigmoidal logistic regression based on RMO event probability.
Retain System Load Factor (SLF) method for allocating legacy generation resource costs to energy - Existing coal and combined cycle unit costs split between capacity and energy - All thermal unit energy costs (not fuel, but also including...
AI summary The document proposes retaining the System Load Factor (SLF) method for allocating legacy generation resource costs to energy. It outlines how existing coal and combined cycle unit costs are split between capacity and energy, and how energy costs are allocated equally on an hourly basis. The premise is that all customers consuming energy in the same hour should pay the same rate for that energy.
Energy arbitrage is the opportunity to shift load to lower-priced hours - Currently, shifting demand from a 4-hour peak period to the surrounding four hours rarely saves much cost because marginal costs don't change much - Battery storage...
AI summary Energy arbitrage involves shifting load to lower-priced hours. However, shifting demand from a 4-hour peak period to surrounding hours rarely saves much cost due to minimal changes in marginal costs. Battery storage and time-varying pricing are tools that can help capitalize on cost differences.
Soon, there will be periods where most resources have near-zero dispatch cost • Does it make sense to allocate energy at a uniform cost when the hourly cost can be nearly zero at times?
AI summary The text raises a question about whether it is appropriate to allocate energy at a uniform cost when the hourly cost of energy can be nearly zero during certain periods, suggesting a potential need for more nuanced cost allocation methods.
The current time-varying pricing rates are "revenue-neutral" - The Critical Peak Price is not designed to recover average hourly costs - Marginal (not average) costs are used in NS Power's time-varying rate design - Instead, the rates are...
AI summary The current time-varying pricing rates are designed to be revenue-neutral, using marginal costs rather than average costs. This approach ensures that average customers pay the same for the same usage pattern regardless of behavior changes, but may create strategic winners and losers.
Designing time-varying rates to be cost-based - Cost-based rates result in cost-neutral rates - Same effect on behavior (reduced fuel costs during peak periods), but now the "strategic winners and losers" are paying their fair share
AI summary The document discusses designing time-varying rates based on cost, emphasizing that such rates are cost-neutral and ensure that 'strategic winners and losers' pay their fair share, while maintaining the same behavioral impact of reducing fuel costs during peak periods.
2. Definition of POD Method The NB Power evidence defines the POD method as allocating "the energy classified costs by looking at the cost of providing energy in each hour instead of assuming that each kilowatt-hour served throughout the y...
AI summary The document defines the POD method, which allocates energy classified costs based on hourly dispatch and probability of dispatch. E3 suggests improvements, such as including operating reserves and excluding dispatch for exports and interruptible loads. The method requires significant data and process changes for full implementation.
B. Generation (Capacity or Demand) Costs The POD and HCM method use substantially different methods for allocating the generation revenue requirement. The POD method allocates these costs equally to each MWh generated, although exactly how...
AI summary The document compares the POD and HCM methods for allocating generation revenue requirements, noting that the POD method equally distributes costs per MWh while the HCM method focuses on high-load hours. An s-shaped cost allocation curve is suggested for better representation of grid stress and time-varying rate design.
Excerpt from Exh. 1 than some of the other methods but may be less aligned with intra-hour cost-causation by - 2 assuming every kilowatt-hour in the year has the same cost. The improvements to this
AI summary The text discusses the assumption that every kilowatt-hour in a year has the same cost and mentions potential improvements to this method, though it does not elaborate further.
2.2 Average and Peak with Time of Use (TOU) Method - 7 The average and peak with time of use method increases the granularity of the data used in - 8 allocation of the energy classified costs by looking at the cost of providing energy in e...
AI summary The average and peak with time of use (TOU) method provides a more granular approach to allocating energy classified costs by considering hourly generation costs and loss of load probability (LOLP). However, it requires additional data not currently available in NB Power's systems and raises confidentiality concerns that may impact transparency in cost allocation.
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.
Table 3: Pros and cons of Average and Peak with Time of Use method Pros Cons Allocates energy classified costs proportionally to the Moderate data needs (hourly dispatch costs, LOLP). cost of providing energy in each hour (instead of Relie...
AI summary Table 3 discusses the pros and cons of the Average and Peak with Time of Use method. It highlights that this method allocates energy costs proportionally to the cost of providing energy in each hour and allocates peak-demand costs to the hours driving the need for capacity resources. However, it requires moderate data needs and relies on average demand and 3CP, which may not align with the generation mix.
Timing of COS Transition - § Now is the time to make changes to reflect rapidly evolving NS Power system. - § ELCC generating resource cost functionalization is both more forward looking and more dynamic than current methodologies. - § COS...
AI summary The document emphasizes the need for updating the Cost of Service (COS) model to better reflect the current and evolving NS Power system, advocating for a more dynamic and forward-looking approach that focuses on cost-causation and the role of assets rather than ownership.
1. Introduction 1. SBA Objectives for COSS The SBA believes that the timing is excellent for a fresh, comprehensive, and forward-looking review of the methodologies and assumptions used to establish the cost of service including allocation...
AI summary The SBA advocates for a comprehensive review of cost of service methodologies to ensure fair allocation of costs as electrification and decarbonization policies reshape energy usage and customer load profiles in Nova Scotia.
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.
Issue 1 Generation Issue 1 a - Should the use of System Load Factor (SLF) to allocate generation investment costs between demand and energy continue to be used? Are there alternatives to the use of the 3CP allocation factor? Can AMI data b...
AI summary The SBA proposes replacing the System Load Factor (SLF) with a peaker methodology for allocating generation investment costs, emphasizing reliability, energy cost minimization, and clean energy contributions. They also suggest classifying transmission facilities based on function rather than using SLF, with some classified as generation or energy investments.
Issue 2b - Functionalization of 'transmission' assets between transmission and generation (bulk Power Substation, BESS)? SBA View - The SBA refers to the discussion of Issue 1 a(i) above for this. A fresh look is needed, especially since t...
AI summary The SBA suggests that a fresh look is needed for the functionalization of transmission assets, such as bulk power substations and BESS, between transmission and generation. It notes that the existing methodology does not adequately address allocating some transmission costs as energy-related.
Issue 3b - Sub functionalization by voltage SBA View – The SBA believes that the functionalization methodology can remain as current. The SBA is extremely concerned that cost causation has not been studied to determine a better class alloc...
AI summary The SBA believes the current functionalization methodology should remain unchanged, expressing concern that cost causation has not been adequately studied to determine a better class allocator than non-coincident class demands, although data from AMI may eventually allow for a more thorough examination.
Basic Customer Methodology - The Basic Customer methodology classifies only customer-specific costs as customer-related and the remaining costs are classified as demand-related and/or energy-related. - Customer-specific costs typically inc...
AI summary The Basic Customer methodology classifies customer-specific costs such as meters and service lines as customer-related, while other distribution costs are categorized as demand-related or energy-related using a system load factor. This approach is not used in Canada.
Hypothesis - Methods to evaluate energy delivered and annual energy losses Network segment Method 1 Method 2 Transmission Lines PSSe simulations using 8760 data Power Transformers Inventory calculations PSSe simulations using 8760 data Dis...
AI summary The text outlines methods to evaluate energy delivered and annual energy losses across different network segments, using simulation tools like PSSe and CYME, along with inventory calculations. The goal is to compute loss allocation per customer type with a certain level of accuracy.
Agenda - Recap: Bundled vs Unbundled Services at NS Power - Renewable to Retail Market Tariff Design - OATT Pricing Foundations - Conclusions
AI summary The agenda outlines key topics for discussion, including bundled vs unbundled services at NS Power, renewable to retail market tariff design, and OATT pricing foundations, with a focus on regulatory and operational considerations.
2026-2027 GRA Direct Evidence Appendix 12A(3) Page 197 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Disaggregated Tariff Design – Flow of RtR Payments EBS = Energy Balancing Service SS = Standby Service Note: EBS & SS address: Top Up...
AI summary The document discusses the disaggregated tariff design, focusing on the flow of Renewable to Retail (RtR) payments, and includes references to Energy Balancing Service (EBS) and Standby Service (SS), which address Top Up, Spill, and provision of Backup supply.
RtR Market Transition Tariff - o For any electricity NS Power supplies to LRS load, fixed and deferred costs are recovered by the EBS and SS rates. - o When NS Power is not supplying electricity to LRS load, fixed and deferred costs are re...
AI summary The RtR Market Transition Tariff outlines how NS Power recovers fixed and deferred costs through EBS and SS rates when supplying electricity to LRS load, and through RTT when not supplying. The rate structure includes cost mitigation and annual energy cost adjustments, with embedded costs depending on RtR generation, load characteristics, and LRS usage of standby and energy balancing services.
- o The tariff is applied to each LRS in respect of its aggregate load and generation, not on a customer-specific basis.2023 2024 Variance Energy Charge by Components (cents per kWh) Fixed Cost Adder from Energy Balancing Service Tariff 3....
AI summary The tariff is applied to each Load-Serving Retailer (LRS) based on its aggregate load and generation, not on a customer-specific basis. The table shows energy and demand charges for 2023 and 2024, including components like the Energy Balancing Service Tariff and Annual Energy Cost Adjustment.
OATT Design Foundations - OATT was designed using FERC's pro forma OATT structure. - OATT Rates are designed for pricing purposes of transmission and generation ancillary services provided to - all customers in the fully unbundled markets...
AI summary The OATT (Open Access Transmission Tariff) was designed using FERC's pro forma structure for pricing transmission and generation ancillary services. It is intended for use in fully unbundled markets or by transmission customers of vertically integrated utilities selling power in wholesale markets, not as an alternate to bundled service rates for retail customers.
• Bundled Service Rates - priced in either c/kWh or both in c/kWh and $/kVa or $/kW - Reflective of test year costs subject to - revenue to cost ratio adjustments - Cost deferrals, caps and multi-year rate smoothing which might be solely a...
AI summary Bundled service rates are priced in c/kWh or both c/kWh and \/kVa or \/kW, reflecting test year costs with adjustments such as revenue to cost ratio, cost deferrals, caps, and multi-year rate smoothing that may apply specifically to bundled service rates.
COSS Model Exhibit Purpose 1 Summary of Existing and Proposed Revenue to Expense Ratio Ratios 2 Rate Base Functionalization & Classification 3 Rate Base Allocation 4 Operating Expense Functionalization 5 Operating Expense Classification 6...
AI summary The COSS Model is being analyzed through various runs, with specific changes to classifications and allocations of expenses and revenue. Key changes include the classification of PHP as a separate rate class, grid-scale storage by ELCC factor, and adjustments to transmission and generation classifications.
8. Allocate Service Drops on the Same Basis as Meters - ➢ Purpose: Analyse the impact of allocating service drops based on the allocation of meters, instead of the weighted customer count. - ➢ Model Notes: A new allocator is added to the m...
AI summary This section discusses the impact of allocating service drops based on meter allocation rather than weighted customer count. A new allocator is introduced, derived from each class's share of meter costs, resulting in a small shift in allocated costs from higher-weighted to lower-weighted classes.
9. Allocate Service Drops with the Customer Count Allocator - ➢ Purpose: Analyse the impact of allocating service drops based on unweighted customer counts, instead of the weighted customer count. - ➢ Model Notes: The weighting factors are...
AI summary This section discusses the impact of using unweighted customer counts instead of weighted customer counts for allocating service drops. The model notes indicate that weighting factors are set to 1 for each class, making the allocator function as an unweighted customer count. The overall impact is a relatively small shift in allocated costs from classes with higher weightings to those with lower weightings.
10a. Classify Steam Generation by Capacity Factor Instead of SLF - ➢ Capacity Factor = Average Hourly Generation / Peak Generation - ➢ Purpose: Analyse the impact of allocating steam generation by the weighted average capacity factor inste...
AI summary This section discusses the proposal to classify steam generation based on capacity factor rather than SLF (Steam Load Factor). It explains that the weighted average capacity factor is lower than SLF, leading to a reallocation of costs from energy to demand, with lower load factor classes bearing more costs.
3. Transmission Classified 100% as Demand - ➢ Purpose: Classify all Transmission as 100% demand instead of using the SLF as peak demands are the primary cost driver of Transmission costs. - ➢ Model Notes: The classification factors that sh...
AI summary This section discusses reclassifying all Transmission costs as 100% demand, removing classification factors that shift costs to energy. This change shifts cost responsibility from classes with high load factors to those with low load factors, with adjustments made to avoid cell definition errors in the model.
4. PHP as a Separate ATL Rate Class - > Purpose: Move PHP from a BTL rate class to a new interruptible ATL rate class. - ➤ Model Notes: This model is the same as PHP DR-12 part a). Loads are shifted from the BTL rate class to ATL rate clas...
AI summary The proposal to move PHP from a BTL rate class to a new interruptible ATL rate class is discussed. This change would affect the SLF calculation and increase the share of costs allocated by energy. NS Power supports the creation of a separate class if service is moved to ATL from BTL, but has not determined its position on PHP's assumed demand level.
Pricing Options Available to MEUs - MEUs have a choice to acquire their electric services in - 1. a bundled service market under the Municipal Tariff - 2. an unbundled wholesale market where in addition to energy purchases from third party...
AI summary MEUs can choose between bundled services under the Municipal Tariff or an unbundled wholesale market, requiring the use of OATT for transmission and ancillary services, with optional energy balancing and standby capacity services available under the BUTU and Spill Tariffs for nondispatchable sources like wind farms.
under either full or partial service arrangement. - Customers are free to pre-select their annual service mix on annual basis some time in advance (OATT 60 days, BUTU – months) - MEUs have exercised these pricing choices every year since 2...
AI summary Customers can pre-select their annual service mix in advance, with specific timelines outlined in OATT and BUTU. MEUs have been making these pricing choices annually since 2015.
Recap: How do rates in wholesale and retail markets compare? - Charges for energy balancing and standby capacity services are less in the wholesale market over a broad range of load factors starting at 10% LF because - Non-fuel cost recove...
AI summary The wholesale market has lower charges for energy balancing and standby capacity services compared to the retail market, particularly at load factors starting at 10%. This is due to differences in non-fuel cost recovery and the alignment of fuel costs between the BUTU and EBS Tariffs in 2024.
To quantify each customer class's impact, losses are allocated based on network connectivity. Class % Secondary % Primary % Transmission (1) Domestic 100% 0% 0% (5) Small General 100% 0% 0% (8) General 94% 6% 0% (11) GENERAL LARGE 0% 100%...
AI summary The text discusses the allocation of losses among different customer classes based on network connectivity. A table is provided showing the percentage distribution of losses across secondary, primary, and transmission categories for each class.
Step 02 : Calculation of loss allocation factors - Losses are calculated for each customer class across all network segments using a defined formula. Segment Losses = Customer Class Contribution % x Total Annual Energy Losses for the segme...
AI summary This section outlines the methodology for calculating loss allocation factors, where segment losses are determined by multiplying the customer class contribution percentage by total annual energy losses for each segment, and total energy loss for each class is obtained by summing losses across all segments.
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.
2026-2027 GRA Direct Evidence Appendix 12A(4) Page 2 of 18 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 2- Bundled/Unbundled Review May 9, 2024 unbundled rates for large customers procuring renewable energy. Manitoba, New Brunswick, and P...
AI summary The document discusses the availability of unbundled rates for large customers procuring renewable energy, noting that Manitoba, New Brunswick, and Prince Edward Island do not offer such rates. This is part of a broader review of bundled and unbundled rates.
2026-2027 GRA Direct Evidence Appendix 12A(4) Page 3 of 18 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 3- Bundled/Unbundled Review May 9, 2024 - 14 (1) By March 23, 2014, the commission must issue orders as follows: - (a) the commission...
AI summary This document discusses the withdrawal of unbundled transmission services by BC Hydro in British Columbia, citing regulatory directions from 2014 and 2019. BC Hydro has not reintroduced the service, and no customers used the Retail Access Program while it was active. The price of BC Hydro-supplied electricity remained lower than market prices.
2026-2027 GRA Direct Evidence Appendix 12A(4) Page 5 of 18 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 5- Bundled/Unbundled Review May 9, 2024 energy-classified costs, but fixed monthly customer charges were maintained at the same charge...
AI summary The document discusses the structure of energy-classified costs and fixed monthly customer charges, noting that demand charges are higher under certain rates, leading to lower energy charges. It also compares Capacity Reservation Service rates to SaskPower's Renewable Access Service Rate, suggesting they may be more aligned than standard large commercial and industrial rates.
2.4 MANITOBA Manitoba Hydro does not offer unbundled rates. The Manitoba Hydro Act states that "Subject to the regulations, no person other than the corporation shall engage in the retail supply of power in Manitoba".[12](#page-7-0) Manito...
AI summary Manitoba Hydro does not currently offer unbundled rates, as restricted by the Manitoba Hydro Act. However, it is considering the possibility of introducing unbundled rates in the future, as noted in its rate design evidence for the 2023/24 and 2024/25 General Rate Applications.
2026-2027 GRA Direct Evidence Appendix 12A(4) Page 8 of 18 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 8- Bundled/Unbundled Review May 9, 2024 paid by other customers. Capacity Reservation Service rates in SaskPower were created to maint...
AI summary The document discusses the concept of bundled and unbundled rate structures, noting that utilities typically apply rate increases uniformly across customer bills without rebalancing components to align with causal costs. This approach maintains historic continuity and bill stability, though it may lead to deviations from appropriate unbundled rates.
Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: October 11, 2024 Re: Written Response regarding Decarbonization Deferral Account (DDA) The COSS work plan outlines the following item for NS Power to pro...
AI summary NS Power outlines its approach to the Decarbonization Deferral Account (DDA) in response to stakeholder concerns. The DDA is used to defer costs related to retiring coal-fired assets and decommissioning facilities by 2030. The Board approved the DDA in May 2024, and NS Power proposes treating it as a regulatory asset for cost of service (COS) purposes.
are treated as follows: - Functionalized among the four service areas of generation, transmission, distribution (according to the portion of total rate base each function represents), and retail, - Classified to all services of energy, dem...
AI summary The text outlines how costs are allocated across different service areas and rate classes, ensuring that each function's share of the rate base is appropriately reflected in classifications and apportionments.
Memorandum To: Participants in NS Power COSS Stakeholder Process From: NS Power Date: November 1, 2024 Re: Written Response regarding Decarbonization Deferral Account (DDA) - Updated The COSS work plan outlines the following item for NS Po...
AI summary NS Power outlines its position on the Decarbonization Deferral Account (DDA) in response to the COSS Stakeholder Process. The DDA is a regulatory asset used to recover costs from retiring coal-fired assets by 2030. NS Power proposes treating the DDA as a regulatory asset in the same manner as other assets for cost-of-service (COS) purposes, citing historical practices from previous GRA filings.
2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 7 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) November 1, 2024 Memo to Participants in COSS Stakeholder Process - Func�onalized among the four service areas of genera�on, transmiss...
AI summary This memo outlines the methodology for func�onalizing and classifying costs across different service areas and rate classes as part of the 2026-2027 GRA Direct Evidence Appendix 12A(5) process.
Additional Comments NS Power was asked in the October 16th session to elaborate on the DDA memo on the following item: • Has NS Power given considera�on regarding whether DDA should be allocated as environmental goals? In addition, NS Powe...
AI summary NS Power was asked to elaborate on the DDA memo, specifically regarding the allocation of DDA as environmental goals. Additionally, NS Power was requested to clarify the location of regulatory assets in Exhibit 3 and provide a list of current or recent regulatory assets allocated in this manner.
NS Power Response Although the early retirements of coal units are driven by policy changes requiring NS Power to be off coal by 2030 and 80 percent renewable by 2030, the establishment of the DDA was primarily justified as a rate stabiliz...
AI summary NS Power explains that the Decarbonization Deferral Account (DDA) was established as a rate stabilization tool to avoid significant rate increases due to accelerated coal unit retirements. The company outlines pros and cons of classifying the DDA entirely to energy.
November 1, 2024 Memo to Participants in COSS Stakeholder Process Pros Cons Would be consistent with fuel conversion Does not align with the view that the DDA and emission reduction classification. is a rate stabilization tool and was esta...
AI summary The memo outlines a debate on the classification of the Decarbonization Deferral Account (DDA) and its alignment with rate stabilization tools. It also details the inclusion of regulatory amortization in corporate taxes and the apportionment of regulatory assets and expenses to rate classes based on their responsibilities for the rate base.
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 table outlines a comparison between the Status Quo and the Cost of Capital and Affordability Study (CCAS) reference, focusing on grid-scale storage issues. It includes columns for NS Power's initial position, updated position following a resolution session, and the justification for the updated position.
2026-2027 GRA Direct Evidence Appendix 12A(6) Page 4 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - Session 7: June 3, 2024 - o Full-day session - o Topics: Distribution functionalization (transmission vs distribution); subfunctionaliz...
AI summary The sessions discussed distribution functionalization, cost of service treatment for bundled and unbundled services, and line loss studies. NS Power presented their positions, and intervenors provided feedback. Topics included allocation of service drop costs, use of AMI data, and alignment of OATT with COSS.
2026-2027 GRA Direct Evidence Appendix 12A(6) Page 5 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - o Topic: Review of Models - o Summary: In this session, NS Power's third-party COSS consultant, Elenchus Research Associates Inc. (Elen...
AI summary This document outlines a series of sessions related to the 2026-2027 GRA Direct Evidence Appendix 12A(6). NS Power presented updates on the Cost of Service Study model, discussed bundled vs. unbundled service alignment, and provided a Line Loss Study update. Resolution sessions were held to address stakeholder concerns and find common ground.
1 EXECUTIVE SUMMARY 2 Nova Scotia Power Inc. ("NS Power") retained Elenchus Research Associates 3 ("Elenchus") in December 2023 to assist the company during its cost of service study 4 ("COSS") review process. The goal of this process was...
AI summary NS Power retained Elenchus Research Associates to assist with its cost of service study review process. The goal was to refine NS Power's methodology in light of developments since the 2013 COSS, including increased renewable integration, gas-fired generation, and grid-scale battery storage. Elenchus provided context on ratemaking principles and cost allocation practices.
Cost-related Attributes: - 4. Static efficiency of the use of rate classes and rate blocks in discouraging wasteful use of the service, while promoting all justified types and amounts of use. - 5. Reflections of all of the present and futu...
AI summary The text discusses principles of public utility rates, emphasizing the static efficiency of rate classes and rate blocks in discouraging wasteful use while promoting justified usage, and the reflection of present and future private and social costs and benefits of service provision, referencing a 1988 publication by Bonbright, Danielsen, and Kamerschen.
2026-2027 GRA Direct Evidence Appendix 12B Page 13 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -13- NSP COSS Consultation Report Draft April 25, 2025 1 Stability and predictability are criteria that deal with the need to use cost all...
AI summary The text discusses the importance of stability and predictability in cost allocation and rate design, emphasizing the need to avoid sudden and significant changes in customer bills. It suggests that when necessary changes occur, they should be phased in to mitigate impacts on consumers.
11 1.3.2 COST RELATED - 12 Fairness and equity are understood to mean that the utility's assets and expenses have - 13 been apportioned to the customer classes in a manner that has cost causality as the main - 14 criterion. The methodologi...
AI summary The text discusses the principles of fairness, equity, and economic efficiency in utility cost apportionment. It emphasizes cost causality as a key criterion for allocating assets and expenses to customer classes, and highlights the importance of rate design in promoting operational and dynamic efficiency, as well as resource conservation.
1 1.3.3 PRACTICAL RELATED - 2 Simplicity and administrative ease are criteria that address the need to use cost allocation - 3 and rate design methods that are understandable by stakeholders and customers and - 4 are implementable by the u...
AI summary The text emphasizes the importance of simplicity and administrative ease in cost allocation and rate design methods, highlighting the need for these methods to be understandable by stakeholders and customers, as well as implementable by the utility based on its available capabilities and resources.
4 Table 2 – Summary of NS Power Proposed Methodology Status Quo Change Generation • Allocation except for treatment of purchased power • No initial classification to energy for environmental and fuel conversion reasons • Use system load fa...
AI summary NS Power proposes changes to its methodology for classifying and allocating costs related to generation, transmission, and distribution. Key changes include refunctionalizing radial-to-generation, using system load factors for classification, and creating new storage sub-functions. These changes aim to improve cost allocation and align with updated regulatory practices.
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.
2026-2027 GRA Direct Evidence Appendix 12B Page 23 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -23- NSP COSS Consultation Report Draft April 25, 2025 1 part of its proposal, NS Power will remove the initial classification of environm...
AI summary NS Power proposes to classify all generation rate base, including environmental and fuel conversion, using the system load factor rather than discrete classification factors. This approach is consistent with practices in other Canadian jurisdictions and aims to align cost allocation with customer load profiles and regulatory requirements.
2026-2027 GRA Direct Evidence Appendix 12B Page 24 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -24- NSP COSS Consultation Report Draft April 25, 2025 - 1 would be primarily classified to energy and combustion turbines would be classi...
AI summary This excerpt from the NSP COSS Consultation Report Draft discusses the classification of assets, noting that certain classifications would be primarily energy-related, while others would be fully classified to demand, potentially leading to different rate impacts based on when investments in those assets occur.
4.2.1.3 ELENCHUS OPINION 5 The system load factor method is a simple and pragmatic approach to classifying costs 6 that are functionalized as generation costs as energy- and demand-related in a manner 7 that ignores the cost difference acr...
AI summary The Elenchus opinion critiques the system load factor method for allocating generation costs, noting that it oversimplifies by ignoring differences between supply resources. It raises concerns about the impact of new facilities on cost allocation and suggests that a more granular approach may not be equitable in the short term. The opinion emphasizes the need for a methodology that balances cost causality and fairness.
4.3.2.1 NSP CURRENT APPROACH - 6 Demand-classified purchases are allocated to rate classes based on each class's share - 7 of 3CP. - 8 Fuel and imports, all of which are classified to energy, are allocated to rate classes based - 9 on each...
AI summary Nova Scotia Power (NSP) allocates demand-classified purchases based on each rate class's share of 3CP. Fuel and imports are allocated monthly based on energy consumption, ensuring that classes consuming more during high-cost months pay more per kWh. Non-fuel energy purchases are allocated annually based on energy consumption.
10 4.3.3.2 NSP PROPOSED APPROACH - 11 NS Power is proposing to allocate demand-classified radial-to-generation and storage - 12 that is functionalized to generation, using the 3CP allocator, consistent with the allocator - 13 used to alloc...
AI summary NS Power is proposing a method to allocate demand-classified radial-to-generation and storage using the 3CP allocator, aligning with the approach used for other generation rate base, depreciation, and OM&A. Energy-classified radial-to-generation and storage are to be allocated based on annual energy consumption.
5.2.1.2 NSP PROPOSED APPROACH - NS Power is proposing to change the classification of transmission costs from the system - load factor to 100% demand. Classifying transmission costs by the system load factor is - not consistent with cost c...
AI summary NS Power proposes classifying transmission costs based on 100% demand rather than system load factor, arguing that this aligns with cost causality principles and practices of other Canadian utilities, as transmission costs are driven by peak demand rather than energy delivered.
5.2.3.2 NSP PROPOSED APPROACH - 2 NS Power proposes to classify transmission storage as 100% demand. - 5.2.3.3 ELENCHUS OPINION - 4 Storage facilities that are deemed to be transmission storage primarily serve the function - 5 of reducing...
AI summary NSP proposes classifying transmission storage as 100% demand, arguing that it reduces strain on the transmission system during peak times and avoids capacity-related costs. Elenchus supports this classification, emphasizing its function in reducing transmission strain.
5.3 ALLOCATION - 5.3.1 GENERAL TRANSMISSION - 5.3.1.1 NSP CURRENT APPROACH - Demand-classified EHV and HV transmission is allocated to rate classes using the same - 3CP allocator used to allocate demand-classified generation costs. - Energ...
AI summary NS Power proposes maintaining the current method of allocating demand-classified transmission costs using the 3CP allocator, while eliminating the energy classification of transmission costs. Elenchus supports this approach, aligning with NS Power's proposal to use a single sub-function for EHV and HV transmission costs in the revised cost of service study model.
5.3.2 RADIAL-TO-GENERATION & STORAGE - 5.3.2.1 NSP CURRENT APPROACH - 3 Radial-to-generation and storage costs are embedded within EHV and HV transmission - 4 costs so they are implicitly allocated using the same demand and energy allocato...
AI summary The document discusses Nova Scotia Power's (NSP) current and proposed approaches to allocating radial-to-generation and storage costs. NSP currently embeds these costs within transmission costs, while proposing to refunctionalize radial-to-generation away from transmission and apply the 3CP demand allocator to transmission storage. Elenchus supports the use of the 3CP allocator for transmission storage costs.
7 6.3.1.3 ELENCHUS OPINION - 8 Elenchus agrees with the allocators used to allocate Distribution demand and customer- - 9 classified costs. The non-coincident peak (i.e., the individual class peaks is the most - 10 commonly used method for...
AI summary Elenchus supports the use of non-coincident peak as the primary method for allocating distribution-classified demand costs, arguing that the distribution system must accommodate customer peaks, which may not align with system-wide peaks.
15 7.1.1 CURRENT RETAIL METHODOLOGY - 16 Retail costs include expenses like meter reading, customer service, and billing & - 17 collection. These costs are classified fully as customer-related.
AI summary The current retail methodology classifies retail costs, such as meter reading, customer service, and billing and collection, as fully customer-related expenses.
12 7.2.1 CURRENT GENERAL PLANT METHODOLOGY - 13 General plant is largely overhead-type plant that cannot be identified with any particular - 14 function, classification, or rate class. For example, administrative buildings are considered -...
AI summary The current general plant methodology involves classifying overhead-type plant, such as administrative buildings, across Generation, Transmission, Distribution, and Direct Assignment functions based on their share of plant in service. It is then allocated to rate classes using a weighted average of classified costs within each function, with a composite allocation approach similar to grossing-up net plant by the same percentage.
7.3.1 RATE CLASSIFICATIONS - Port Hawkesbury Paper ("PHP") is currently the only customer within the Extra Large - Industrial Active Demand Control ("ELIADC") rate class. The ELIADC rate class is - considered a below-the-line rate class, i...
AI summary Port Hawkesbury Paper is the sole customer in the ELIADC rate class, which is a below-the-line rate class with costs calculated outside the cost of service study model, particularly for energy costs.
2026-2027 GRA Direct Evidence Appendix 12B Page 48 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -48- NSP COSS Consultation Report Draft April 25, 2025 - 1 assigned based on the incremental cost of generation instead of an allocation o...
AI summary This text discusses NS Power's efforts to develop an above-the-line tariff for PHP, based on incremental generation costs and load characteristics relative to other classes. NS Power and PHP are collaborating to determine the viability of such a tariff.
7.3.2 NSP PROPOSED APPROACH - 7 NS Power has refined the COSS to facilitate scenarios that allocate costs to PHP as a - 8 separate rate class PHP's loads and customer characteristics would be included in the - 9 derivation of allocators as...
AI summary NSP has refined the COSS to allocate costs to PHP as a separate rate class, ensuring its loads and customer characteristics are included in the derivation of allocators. PHP, being a transmission-connected customer, will not receive any allocation of distribution costs.
7.3.3 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.
2026-2027 GRA Direct Evidence Appendix 12B Page 49 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -49- NSP COSS Consultation Report Draft April 25, 2025 - 1 levels by rate class was used to estimate rate class-specific demand and energy...
AI summary The document discusses the use of rate class-specific demand and energy loss estimation in the NSP COSS Consultation Report Draft from April 25, 2025. It highlights the use of levels by rate class and factors in the analysis.
7.5.1 NSP PROPOSED APPROACH - NS Power is required to retire coal-fired assets and associated marine unloading and fuel - delivery facilities by 2030. These assets have not yet reached their end of service life so - NS Power will not recov...
AI summary Nova Scotia Power (NSP) is required to retire coal-fired assets by 2030 and will not recover decommissioning costs by that date. NSP has been approved to use a Decarbonization Deferral Account (DDA) as a rate stabilization tool and proposes to allocate DDA costs using its prior methodology based on the weighted average of its rate base.
7.5.2 ELENCHUS OPINION - This weighted average approach effectively treats DDA costs as overhead-type costs in - the same manner as general plant. Though the costs are related to the generation - function, the need to recover DDA costs is...
AI summary The weighted average approach treats DDA costs as overhead-type costs, similar to general plant, despite their origin in legislation requiring NS Power to decarbonize. This raises concerns about whether DDA costs should be recovered based on the asset's original function or spread more broadly.
7.7.1 CHANGES TO ALIGN BUNDLED AND UNBUNDLED SERVICES - 7 NS Power is proposing to revise the calculation of the transmission revenue requirement - 8 underpinning the Open Access Transmission Tariff ("OATT") to make it consistent with - 9...
AI summary NS Power is proposing to revise the OATT transmission revenue requirement calculation to align it with the cost of service study. The current OATT method does not include radial-to-generation costs, and reclassifying these costs from transmission to generation will improve alignment. Additionally, OATT rates are based only on demand, leading to misalignment in cost classification when using the system load factor.
7.7.2 ELENCHUS OPINION - Bundled and unbundled rates should be aligned such that customers receiving unbundled - service should be charged rates that are consistent with the rates underpinning bundled - rates. For example, the portion of b...
AI summary The text discusses the alignment of bundled and unbundled rates, emphasizing that customers receiving unbundled service should be charged rates consistent with those underpinning bundled rates, particularly for transmission services aligned with OATT rates.
8 CONCLUSIONS 2 As stated in the Introduction the goal of this process was to identify appropriate changes 3 to NS Power's COSS in light of developments including the greater integration of wind 4 and other renewables, the addition of a gr...
AI summary The document discusses the need for refinements to NS Power's Cost of Service Study (COSS) methodology due to changes in technology and generation mix, such as increased renewables and gas-fired generation. It emphasizes that the fundamental principles of cost allocation remain unchanged, but adjustments are necessary to equitably assign costs to customer classes.
2026-2027 GRA Direct Evidence Appendix 12B Page 54 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -54- NSP COSS Consultation Report Draft April 25, 2025 1 with meeting the system's base, intermediate and peak demands. However, the 2 int...
AI summary The document discusses NSP's approach to classifying generation, transmission, and distribution costs in the context of evolving energy technologies and supply portfolios. It highlights the integration of renewable generation, storage, and PPAs, and proposes refining cost classifications to align with operational realities and best practices in ratemaking.
2026-2027 GRA Direct Evidence Appendix 12B Page 55 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -55- NSP COSS Consultation Report Draft April 25, 2025 1 of the functionalization of projects within general plant will better align suppo...
AI summary This text discusses refinements to NS Power's Cost of Service Study (COSS) to better align support costs with specific functions, address unique costing approaches for PHP, and update DSM rate rider weightings based on customer class. It also highlights a new line loss study conducted by BBA, which provides a more accurate basis for allocating line losses among rate classes.
3.5 Loss Allocation Factor The Loss Allocation Factor (LAF) is a calculated ratio used to allocate annual energy losses across customer classes based on their relative energy sales (consumption). It reflects the average amount of energy lo...
AI summary The Loss Allocation Factor (LAF) is a calculated ratio used to distribute annual energy losses among customer classes based on their energy sales. It reflects the average energy loss per kilowatt-hour sold and is calculated by dividing annual energy loss by energy sales.
N-142026-2027 GRA OP 01-15 - Redacted
56 passages
FINANCIAL REVIEW OF 2025
AI summary The document outlines the financial review for 2025, focusing on regulatory proceedings under Nova Scotia's energy framework. Key areas include cost recovery, rate design, and compliance with regulatory standards, though detailed analysis is not provided in the excerpt.
Highlights of the changes in fuel for generation and purchased power are summarized in the following table: For the Three months ended Six months ended millions of dollars June 30 June 30 Fuel for generation and purchased power –2024 $ 192...
AI summary The text summarizes changes in fuel for generation and purchased power for 2024 and 2025, including factors such as changes in generation mix, sales volumes, carbon tax, and commodity prices. It also references the FAM and FAM Regulatory Deferral.
2026-2027 GRA OP-01 Attachment 3 Page 11 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate...
AI summary The FPSC approved a rate case decision in February 2025, which was later challenged but ultimately upheld. A motion for reconsideration was denied, except for minor corrections. Additionally, a petition for recovery of $466 million USD in storm-related costs was approved, subject to a true-up mechanism. Capital investments in the Florida Electric Utility segment are expected to reach $1.7 billion USD in 2025.
Proven Strategy & ESG Alignment - Climate commitment, including a vision to achieve net-zero CO 2 emission by 2050 - Recognized for excellence in governance, including strong ESG governance
AI summary The document highlights a climate commitment with a vision to achieve net-zero CO2 emissions by 2050 and recognizes excellence in governance, including strong ESG governance.
Our world is changing quickly, and we're ready Our proven strategy has been driving our growth for nearly two decades. Our strategic focus balances our efforts to deliver cleaner energy with critical reliability investments, without overlo...
AI summary The text highlights the company's strategy of balancing clean energy initiatives with reliability investments and cost management, emphasizing its readiness to address industry trends such as decarbonization, decentralization, and digitalization.
- Equity thickness set at 40% for rate setting purposes – previously 37.5% 2023 2024 Non-Fuel Base Rate 1.8% 0.0% DSM 3.6% 0.3% Total Non-Fuel Increase 5.4% 0.3% Fuel Related1 Fuel Rate Increase 1.5% 6.6% Total Increase 6.9% 6.9%
AI summary The equity thickness for rate setting has been increased from 37.5% to 40%. The table shows the non-fuel and fuel-related rate increases for 2023 and 2024, with significant changes in the DSM and fuel rate components.
Driving Progress towards Net Zero The team across Emera is working together to meet our Climate Commitment goals and our vision to achieve net-zero CO₂ emissions by 2050. 2050 VISION Net-Zero CO₂ emissions Note: Achieving our climate goals...
AI summary Emera is committed to achieving net-zero CO₂ emissions by 2050 as part of its Climate Commitment goals. This vision is subject to regulatory obligations and external factors beyond the company's control.
Clear Path to our 2025 CO 2 Goal Successful execution of Emera's strategy, which includes a focus on decarbonizing our generation fleet through investments in renewables and lower carbon energy sources, will reduce CO 2 emission by 55% by...
AI summary Emera's strategy focuses on decarbonizing its generation fleet through investments in renewables and lower carbon energy sources, aiming to reduce CO2 emissions by 55% by 2025.
Transitioning Away from Coal Generation Nova Scotia Power and Tampa Electric1,2 % OF GWh GENERATION 3 1 Tampa Electric was acquired by Emera in 2016; Emera has transformed its its generation fleet since 2005 and our committed capital proje...
AI summary Nova Scotia Power and Tampa Electric have significantly reduced coal generation, aiming for an 80% reduction by 2025. Renewables are expected to increase to 29% by 2025, with natural gas serving as a transition fuel. Emera has committed to further decarbonizing its portfolio through capital projects.
Proven Decarbonization Strategy at Tampa Electric Reducing coal generation by Investing in Solar & Natural Gas % OF GWh GENERATION 1
AI summary The document discusses Tampa Electric's strategy to reduce coal generation by investing in solar and natural gas, illustrated through figures showing the percentage of GWh generation.
Proven Decarbonization Strategy at Nova Scotia Power Reducing coal generation by investing in hydro, wind and transmission projects % OF GWh GENERATION1
AI summary Nova Scotia Power is reducing coal generation by investing in hydro, wind, and transmission projects, as illustrated in the provided figures. This strategy is part of a broader decarbonization effort.
Proven Strategy & ESG Alignment - Climate commitment, including a vision to achieve net-zero CO 2 emission by 2050 - Recognized for excellence in governance, including strong ESG governance
AI summary The document highlights a climate commitment with a vision to achieve net-zero CO2 emissions by 2050 and acknowledges excellence in governance, including strong ESG governance practices.
OUR STRATEGIC PRIORITIES Always leading with Health & Safety Advancing Cleaner Energy towards our Net-Zero Vision Enhancing Reliability Driving Innovation Empowering our Teams & Communities Always Working to Minimize Cost Impacts for Custo...
AI summary The text outlines strategic priorities focusing on health and safety, advancing cleaner energy toward net-zero, enhancing reliability, driving innovation, empowering teams and communities, and minimizing cost impacts for customers.
How we'll get there We'll seek to achieve these goals and realize our net-zero vision by adopting emerging technologies and working constructively with policymakers, regulators, partners, investors, and our communities. All while staying f...
AI summary The document outlines strategies for achieving net-zero goals through technology adoption and collaboration with stakeholders, while emphasizing reliability and cost impacts for customers. It highlights reductions in CO2 emissions and coal use since 2005 and significant investments in cleaner energy from 2024 to 2026.
Transitioning Away from Coal Generation Nova Scotia Power and Tampa Electric 1,2 % OF GWh GENERATION 3 Emera has transformed its its generation fleet since 2005 and our committed capital projects will further decarbonize our portfolio. - 8...
AI summary Nova Scotia Power, along with Tampa Electric, has significantly reduced coal generation and is transitioning to renewable energy and natural gas. By 2025, coal generation will be reduced by 80%, and renewables will increase to 26%, over five times the 2005 levels. Natural gas will serve as a transition fuel to support intermittent renewable energy.
Proven Decarbonization Strategy at Tampa Electric Reducing coal generation by Investing in Solar & Natural Gas % OF GWh GENERATION 1
AI summary The document discusses Tampa Electric's strategy to reduce coal generation by investing in solar and natural gas, with visual representations of generation percentages.
Proven Decarbonization Strategy at Nova Scotia Power Reducing coal generation by investing in hydro, wind and transmission projects % OF GWh GENERATION1
AI summary Nova Scotia Power is implementing a decarbonization strategy by reducing coal generation and investing in hydro, wind, and transmission projects. The text includes visual representations of generation data.
Key initiatives - Established a $5M Emera Diversity, Equity and Inclusion ("DEI") Fund. - $5M USD Endowment to support the Clean Energy Research Center in the University of Southern Florida College of Engineering - Large scale investments...
AI summary The document outlines key initiatives by Emera, including the establishment of a $5M DEI Fund, a $5M USD endowment for a clean energy research center, and significant investments in innovation and entrepreneurship. It also highlights community engagement efforts, such as 31,500 volunteer hours by Emera employees in 2022.
Cash Flow Drivers: - + Fuel and storm deferral recovery of $678M in 2023 at Tampa Electric - + Collected final outstanding balances in New Mexico related to Winter Storm Uri - + Increased cash flow from operations from regulated utilities...
AI summary The cash flow drivers include fuel and storm deferral recovery at Tampa Electric, collection of balances from Winter Storm Uri in New Mexico, and increased cash flow from operations due to new rates and growth. Additional deferrals at NSPI and expected fuel cost relief are mentioned, along with increased financing costs.
2 Forecasted USD capital spend translated at $1.30 in 2024-2026 o Request included increased revenue requirements of $297M USD in - Reached an unopposed settlement agreement with all intervenors on its active rate case in March 2024 - o Se...
AI summary The document outlines a settlement agreement reached in March 2024 for an active rate case, including a new base rate increase of $30M effective October 1, 2024, set at a 9.375% return on equity and 52% equity, with a weather normalization mechanism becoming a standard tariff. A final regulatory decision is expected in Q3 2024.
1. Timely recovery of rate base investments and operating costs - Minimizing regulatory deferrals effective fuel and storm mechanisms at TEC and NSPI - New rates PGS and anticipated at NMGC in 2024 and rate case filed at TEC for new rates...
AI summary The text discusses the timely recovery of rate base investments and operating costs, mentioning efforts to minimize regulatory deferrals at TEC and NSPI, new rates anticipated at NMGC in 2024, and a rate case filed at TEC for 2025. It also highlights a new fuel rate agreement with the Province of NS to mitigate fuel deferral at NSPI.
New Mexico Gas - Reached an unopposed settlement agreement with all intervenors on its active rate case in March 2024 - o Settlement includes $30M of new base rates, effective October 1, 2024 - o Rates set on a 9.375% ROE and 52% equity, u...
AI summary New Mexico Gas reached an unopposed settlement agreement in March 2024, including new base rates of $30M effective October 1, 2024, with a 9.375% ROE and 52% equity. The weather normalization mechanism is a permanent tariff, and the final regulatory decision is expected in Q3 2024.
Sustainability 47% Reduction in CO2emissions since 2005 1 77% Reduction in generation from coal since 2005 1 1 As at December 31, 2023 2 Based on Emera's 2024-2026 forecasted capital spend
AI summary The document highlights significant reductions in CO2 emissions and coal generation since 2005, with 47% and 77% reductions respectively as of December 31, 2023. It also references Emera's 2024-2026 forecasted capital spend and includes several images related to sustainability efforts.
Clear Path to our 2025 CO 2 Goal Successful execution of Emera's strategy, which includes a focus on decarbonizing our generation fleet through investments in renewables and lower carbon energy sources, will reduce CO 2 emission by 55% by...
AI summary Emera's strategy focuses on decarbonizing its generation fleet through investments in renewables and lower carbon energy sources, aiming to reduce CO2 emissions by 55% by 2025.
New Mexico Gas - On July 25, 2024, the New Mexico Gas rate case settlement agreement was unanimously approved by the New Mexico Public Regulation Commission - o Settlement includes $30M of new base rates, effective October 1, 2024 - o Rate...
AI summary The New Mexico Public Regulation Commission unanimously approved a rate case settlement agreement for New Mexico Gas on July 25, 2024. The agreement includes a $30M increase in base rates, effective October 1, 2024, with the rate of return on equity and equity percentage remaining unchanged. The weather normalization mechanism will transition from a pilot program to a standard tariff.
Proven Strategy & ESG Alignment - Climate goals, including a vision to achieve net-zero CO 2 emission by 2050 - Recognized for excellence in governance, including strong ESG governance
AI summary The section highlights the alignment of a proven strategy with environmental, social, and governance (ESG) goals, including a vision to achieve net-zero CO2 emissions by 2050 and recognition for strong ESG governance practices.
New Mexico Gas 2024 Rate Case Details - $30M USD increase in annual base rates effective October 1, 2024 - 9.375% ROE and 52% equity thickness, unchanged from current - Weather normalization mechanism formalized in the tariff, after five y...
AI summary The 2024 Rate Case for New Mexico Gas includes a $30M USD annual base rate increase effective October 1, 2024, with a 9.375% ROE and 52% equity thickness remaining unchanged. A weather normalization mechanism has been formalized in the tariff following a five-year pilot period.
Additional Drivers of Cash Flow and Credit Metric Improvement - $117M CAD securitization of NSPI's unrecovered fuel costs, by the NS government in April 2024 discussions on further securitizations continue - 6.9% rate increase at NSPI effe...
AI summary The text outlines additional drivers of cash flow and credit metric improvements, including a $117M CAD securitization of NSPI's unrecovered fuel costs, a 6.9% rate increase at NSPI effective January 1, 2024, and new base rates at various utilities. It also mentions continued strong performance of regulated operations.
Driving Progress Towards Net Zero
AI summary The section titled 'Driving Progress Towards Net Zero' includes a figure, likely illustrating progress or strategies related to achieving net zero emissions, though no detailed discussion is provided in the text.
% OF GWh GENERATION Emera has transformed its its generation fleet since 2005 and our committed capital projects will further decarbonize our portfolio. - 80% reduction in coal generation by 2025 4 - Renewables will increase to 26% in 2025...
AI summary Emera has significantly reduced coal generation and increased renewable energy production since 2005. The company plans to achieve an 80% reduction in coal generation by 2025, with renewables increasing to 26% of total generation, a more than fivefold increase from 2005 levels. Natural gas will be used as a transition fuel to support renewable energy.
Regulatory Arrangements Reached an unopposed settlement agreement which included $30M of new base rates, effective October 1, 2024. Rates set on a 9.375% ROE and 52% equity, unchanged from current. Settlement makes weather normalization me...
AI summary An unopposed settlement agreement was reached, setting new base rates of $30M effective October 1, 2024, with a 9.375% ROE and 52% equity. The weather normalization mechanism was incorporated into the normal tariff, and final regulatory approval was granted on July 25, 2024.
New Mexico Gas 2024 Rate Case - $30M USD increase in annual base rates effective October 1, 2024 - 9.375% ROE and 52% equity thickness, unchanged from current - Weather normalization mechanism formalized in the tariff, after five years as...
AI summary The New Mexico Gas 2024 Rate Case involves a $30M USD annual base rate increase effective October 1, 2024, with unchanged return on equity (9.375%) and equity thickness (52%). A weather normalization mechanism is now formalized in the tariff, following a five-year pilot period.
2026-2027 GRA OP-12 Attachment 1 Page 380 of 684 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Increased renewable energy generation from 11% to 43% over the last 10 years Reduced coal by 60% since 2005 Building three 50 MW grid-scale batter...
AI summary The document highlights significant progress in renewable energy generation in Nova Scotia, increasing from 11% to 43% over the last decade, with a 60% reduction in coal use since 2005. The province is building three 50 MW grid-scale battery storage facilities and has committed to achieving 80% renewable electricity sales by 2030. The Sustainable Development Goals Act is referenced as a key policy framework.
Proven Progress on Decarbonization Note: 2025 figures represent targets.
AI summary This section highlights progress on decarbonization, with 2025 figures representing targets. It includes a visual reference to support the discussion on decarbonization efforts.
1 Capital structures that support the rate base include deferred tax liabilities (DTL), a zero cost-of-capital component of the capital structure in Florida; 2023 capital structures included DTLs of approx. US$1,300 million at Tampa Electr...
AI summary The text discusses capital structures supporting the rate base, including deferred tax liabilities (DTL) at Tampa Electric and Peoples Gas, and excludes fuel and storm cost deferrals. It also mentions the inclusion of net investment in capital leases and the updated USD/CAD exchange rate for 2024.
Equity ~$400M per year on average through DRIP and ATM programs 1
AI summary The text mentions an average annual equity impact of approximately ~$400M through DRIP and ATM programs, highlighting their financial significance.
11% variable rate debt across the portfolio 1 Actions in 2024 to sell assets and raise equity significantly lowered exposure to variable rate debt Utilities have largely termed out their variable rate exposure and either have, or will have...
AI summary The document discusses the reduction in variable rate debt exposure by utilities through asset sales and equity raising in 2024. It notes that utilities have largely termed out their variable rate exposure and will incorporate interest expenses into rates by 2026. As of March 31, 2025, the exposure is at 11%.
Environmental, Social and Governance (ESG) commitments are core to our strategy and shape our culture of doing the right thing for our customers, investors, communities and each other. Our proven strategy has been driving our growth for ne...
AI summary The document emphasizes the importance of ESG commitments in shaping the company's strategy and culture, focusing on delivering cleaner energy, reliability, and managing customer costs while addressing industry trends like decarbonization, decentralization, and digitalization.
Rate Case $281M USD total revenue increase 1 Increase in ROE midpoint to 10.5% from 10.2% and no change to equity thickness 99% of operating expenses and capital expenditures approved No stay out period required
AI summary The rate case involves a $281M USD total revenue increase, an increase in the ROE midpoint to 10.5%, approval of 99% of operating expenses and capital expenditures, and no stay out period required.
Equity ~$400M per year on average through DRIP and ATM programs 1
AI summary The text mentions an average of ~$400M per year generated through DRIP and ATM programs, highlighting their financial impact.
Net-Zero Roadmap agreements. Tampa Electric projects/opportunities Nova Scotia Power/Tampa Electric common projects/opportunities This roadmap is subject to change and matters beyond our control and is dependent upon decisions of, and/or s...
AI summary The Net-Zero Roadmap outlines forward-looking investments by Nova Scotia Power and Tampa Electric, contingent on regulatory approval and external support. The roadmap is subject to change and highlights the importance of demonstrating prudence and cost-effectiveness to regulators.
Regulatory Arrangements PGS filed a general rate application on March 31, 2025, requesting revenue requirements of approximately $104 million and subsequent year adjustment for 2027 of approximately $27 million. Also requested a 11.1% ROE...
AI summary PGS submitted a general rate application requesting revenue requirements of approximately $104 million and a subsequent year adjustment of $27 million, along with a requested increase in ROE from 10.15% to 11.1%. The hearing is set for September 9-12, 2025, with a decision expected in Q4 2025 and new rates to begin on January 1, 2026.
Climate Progress Building on more than two decades of cost-effective investments, we're proud of our track record with system enhancements and reductions in CO2 emissions that have addressed government requirements along a path to net-zero...
AI summary The text highlights the company's achievements in reducing CO2 emissions and enhancing the system over two decades, contributing to the path toward net-zero by 2050, in line with government requirements.
Achieved: 49% reduction in C02 emissions3 80% reduction in coal used in generation3
AI summary The text highlights significant achievements in reducing CO2 emissions and coal usage in generation, with a 49% reduction in CO2 emissions and an 80% reduction in coal used in generation.
Continuing focus: - Newsolar + wind2 - Coal unitretirement (incl. fuel switching/ conversion) - Emerging technology 80% reduction in CO2 emissions and retirement of our last coal unit by end of 2040 Net-Zero CO2 emissions 1 Achieving our v...
AI summary The document outlines a commitment to achieving an 80% reduction in CO2 emissions and retiring the last coal unit by 2040, with net-zero CO2 emissions as a long-term goal. The plan includes reliance on external factors, government support, and emerging technologies. The reductions are measured against 2005 levels and include specific targets for Nova Scotia Power and Tampa Electric.
Update on Progress in 2023 Last year we highlighted Management's planned actions and next steps for 2023. We have executed against this plan and have and have improved and stabilized both the business and financial risk profiles of NSPI: -...
AI summary NSPI has stabilized its business and financial risk profiles in 2023 by receiving UARB approval for the GRA settlement, aligning with the Province on decarbonization mandates, securing government funding for prior period fuel costs, and focusing capital investments on reliability.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA OP-12 Attachment 2 Page 9 of 28 Decarbonization & Capital Program Update
AI summary The document contains a redacted section of an attachment related to a 2026-2027 GRA OP-12, focusing on a Decarbonization & Capital Program Update. Images are included but the content is not visible due to redaction.
Update on Progress in 2024 Last year we highlighted Management's planned actions and next steps for 2024. We have executed against this plan and have improved and stabilized both the business and financial risk profile of Nova Scotia Power...
AI summary Nova Scotia Power has made progress in 2024 by negotiating federal and provincial funding for prior period fuel costs, securing a loan guarantee increase, and receiving approvals for capital investments and a storm rider. They are also working on the 2030 Clean Power Plan and preparing for a General Rate Application expected to take effect in 2026.
Major Decarbonization Projects - Added ~600 MW of wind (~150 MW rate base and ~450 MW through IPPs) - Completed Maritime Link ($1.8 billion) project which is capable of transmitting 500 MW of hydro capacity - Refurbishment of Nova Scotia P...
AI summary The document outlines major decarbonization projects including the addition of wind capacity, completion of the Maritime Link transmission project, refurbishment of hydro facilities, and investments in grid-scale battery storage and transmission to support renewable energy and phase out coal by 2030.
CLIMATE PROGRESS Building on more than two decades of cost-effective investments, we're proud of our track record with system enhancements and reductions in CO2 emissions that have addressed government requirements along a path to net-zero...
AI summary The text highlights the organization's commitment to climate progress, emphasizing cost-effective investments, system enhancements, and reductions in CO2 emissions as part of a strategy to meet government requirements and achieve net-zero by 2050.
TRACK RECORD 2024 PROGRESS 2025+ MOMENTUM 2040 GOAL 2050 VISION - Achieved: 49% reduction - in C02 emissions3 80% reduction in coal used in generation3 2025-2029 Capital Plan investments include:4 - Grid reliability & modernization - Renew...
AI summary The document highlights a 49% reduction in CO2 emissions and an 80% reduction in coal usage in generation. The 2025-2029 Capital Plan includes investments in grid reliability, modernization, and renewable integration.
Continuing focus:5 - New solar + wind2 - Coal unit retirement (incl. fuel switching/ conversion) - Emerging technology 80% reduction in CO2 emissions and retirement of our last coal unit by end of 2040 Net-Zero CO2 emissions - 1 Achieving...
AI summary The document outlines a commitment to achieving an 80% reduction in CO2 emissions and retiring the last coal unit by 2040, as well as a net-zero CO2 emissions vision. These goals are conditional on external factors, regulatory approval, and the development of new technologies. The plan includes a focus on renewable energy, grid modernization, and cost-effective investments.
Governance Emera is guided by strong governance and effective risk management led by our Board of Directors. In 2024, the Board provided essential guidance and oversight to the strategic plan to strengthen our balance sheet, optimize our p...
AI summary Emera's governance structure is led by its Board of Directors, which provided strategic oversight in 2024, including guiding the company's balance sheet optimization and digital strategy. In 2025, the Board restructured its committees and appointed Karen Sheriff as new Chair following Jackie Sheppard's departure. The company also reported a 49% reduction in CO2 emissions since 2005.
CLIMATE PROGRESS Building on its strong decarbonization track record, Emera continues its carbon reduction efforts while managing the physical risks of climate change as we invest in a resilient grid for our customers. The Board of Directo...
AI summary Emera is advancing its decarbonization efforts and managing climate-related risks through the SRC, which reports to the Board of Directors. The company is investing in grid modernization, renewable energy integration, and technological innovation to deliver reliable, cleaner energy while complying with government climate policies.
Directors Are Increasing Their Share/DSU Ownership Over Time By virtue of the compensation payable in DSUs, more than 58 per cent of the annual retainer for Emera Directors will be paid in DSUs, which mirrors the value of Emera common shar...
AI summary Directors of Emera are increasing their share and DSU ownership over time, with more than 58% of their annual retainer being paid in DSUs, which are valued similarly to Emera common shares. This increase is driven by the compensation structure, with most nominees opting for DSUs instead of cash.
The table below identifies how much of the short-term incentive for 2024 that each NEO elected to allocate to DSUs: Name Percentage of 2024 annual incentive elected to deferred share units (%) Dollar amount of 2024 annual incentive elected...
AI summary The table outlines the allocation of short-term incentives for 2024 by each Named Executive Officer (NEO) to Deferred Share Units (DSUs), including the percentage and dollar amount elected by each individual.
N-44STATE OF CONNECTICUT
PUBLIC UTILITIES REGULATORY AUTHORITY
65 passages
C. CONDUCT OF THE PROCEEDING On October 1, 2024, UI submitted formal notice of its intent to file an application to amend its existing rate schedule. On November 12, 2024, the Company filed the 1 The 9.10% ROE reflects a 47 basis points re...
AI summary The document outlines the procedural steps taken by the Authority in handling UI's application to amend its rate schedules, including hearings, audits, and the submission of motions and briefs. Key events include the filing of the application, revenue audits, public comment hearings, and the issuance of a proposed final decision.
ated that a revenue increase of $63.7 million "is sufficient to enable the Company to operate its business and continue providing excellent service to its customers in Connecticut." Id., Ex. 1, p. 6. OCC actively participated in this proce...
AI summary OCC actively participated in the proceeding, recommending the rejection of UI's rate increase application and proposing a lower rate of return, disallowing certain expenses, and addressing customer service incentives and unjustified plant investments.
acknowledged concerns for high energy costs for residents and businesses but nonetheless offered support for investments in electrical service in order to maintain reliability. Id., 18:13–15, 19:1–5. The second in-person public comment hea...
AI summary Public comment hearings were held regarding energy costs and infrastructure investments. Attendees raised concerns about high rates for fixed-income households and the potential unaffordability of future increases. Some suggested canceling on-peak and off-peak programs and questioned the need for investments in a monopoly. Others supported infrastructure updates but requested transparency and future planning.
A. SUMMARY Rate base is a fundamental concept of cost-of-service ratemaking. Rate base is the investor-supplied facilities and other investments necessary to supply a utility service to consumers in a safe, reliable, and cost-effective man...
AI summary Rate base is central to cost-of-service ratemaking, representing the capital on which a return is earned. It is determined by proving that the utility's plant is in use and serving the public and that the capital investment was prudent and reasonable. Legal precedents and statutes support this approach.
ompany concluded that the investments were non-billable; and most importantly, [determine] why the Company incurred such extraordinary costs to accommodate third party attachments." OCC Brief, p. 132. OCC further argues that the Company fa...
AI summary The OCC argues that the Company improperly allocated make-ready costs to ratepayers, failing to follow the Authority's directive in Docket No. 19-01-52RE01 to equitably share costs among attachers when the cause of a safety violation cannot be determined. The Company's practice is seen as inefficient and not in line with regulatory decisions.
llowing such requests in future, the Authority will consider the status of previously allowed projects, which may indicate whether the Company's ability to forecast future needs should be relied upon. information about (1) the anticipated...
AI summary The Authority will consider the status of previously allowed projects when evaluating future requests, focusing on the Company's ability to forecast future needs. The text also requests information on the anticipated cost of completing the plant, its potential use, and whether it was prudently constructed.
6. Plant-in-Service Reconciliation Mechanism With regard to the future period plant additions, the Company proposes a reconciliation mechanism that it states will be used as one of the "guardrails" to "prevent customers from paying for pla...
AI summary The Company proposes a downward-only reconciliation mechanism for future plant additions to prevent customers from paying for unmaterialized investments. However, the Authority declines the proposal, arguing that future plant additions are not yet used and useful and should not be included in the base rate of return calculation, citing a legal precedent.
ii. Collections Lag The Collections Lag is a component of the Company's proposed revenue lag computation. Interrog. Resp. RSR-266, Att. 1. In the instant proceeding, the Company proposes the same collections lag of 44.27 days that it used...
AI summary The Company proposes a collections lag of 44.27 days based on 2021 data, but the Authority finds this reliance on outdated data unpersuasive. Using 2023 data, the collections lag is 41.86 days, leading to a reduction in CWC by $1,769,819.
5. Bond Yield Risk Premium The Company also proposed using the bond yield plus risk premium (BYPRP) model for determining ROE. Ex. UI-AEB-1, pp. 33–37. The BYPRP approach "is based on the fundamental principle that equity investors bear th...
AI summary The Company proposed using the bond yield plus risk premium (BYPRP) model to determine return on equity (ROE). However, the Authority rejected the BYPRP approach, citing its reliance on Commission-allowed ROEs rather than market-based methods like DCF or CAPM, and noting that it is not widely accepted in utility ratemaking.
a. Introduction The approved ROE is based on a similarly situated electric utility providing expert, efficient, and prudent management of the utility franchise; therefore, the Authority must consider whether to adjust the ROE for the Compa...
AI summary The Authority concludes that a 20 basis point reduction to the Company's allowed ROE is necessary due to its deficient performance in managing parts of its utility franchise, aiming to incentivize improvement and balance investor and consumer interests.
i. Background and AMI Plan Requirements As part of its broader efforts to accelerate the modernization of Connecticut's electric grid in innovative, cost-effective, and equitable ways, the Authority previously identified the deployment and...
AI summary The Authority emphasizes the importance of Advanced Metering Infrastructure (AMI) in modernizing Connecticut's electric grid. A Benefit Cost Analysis (BCA) is required in each EDC's AMI Plan to ensure that AMI investments align with economic, environmental, and policy goals, and to monitor actual costs and benefits.
ed in an agency proceeding when a majority of the members of the agency who are to render the final decision have not heard the matter or read the record, and the decision will be adverse to a party). Moreover, to the extent the Authority...
AI summary The document discusses due process considerations in a regulatory proceeding, emphasizing that parties had the opportunity to argue against the Authority's intended actions, including ROE reductions related to deficiencies in the Company's AMI Plan and BCA. The Authority finds no due process issues due to lack of notice.
i. DERMS Proposal On March 14, 2024, UI, together with Eversource, submitted a plan to allow multiple Distributed Energy Resource Management Systems (DERMS) to participate in the Energy Storage Solutions (ESS) Program. UI Order No. 19 Comp...
AI summary UI and Eversource submitted a plan to allow multiple DERMS to participate in the ESS Program, but UI failed to comply with the Authority's directive to develop a centralized DERMS platform in its next rate case application. UI attributes the non-compliance to PURA's reduction in operations and maintenance expenditures from its last rate case.
ii. Water Heater Rental Program As also discussed in Section [VI.A.17.j,](#page-185-0) [Water Heater Rental Program,](#page-185-0) below, in the Company's last rate case the Authority ordered UI to close participation to new customers in i...
AI summary The Water Heater Rental Program was ordered to be phased out by the Authority due to its unsustainability. The Company requested a new cost recovery mechanism for the phase-out, but the Authority declined and directed the program's phase-out to be completed by September 1, 2025.
1. Summary Allowable operating expenses must "reflect prudent and efficient management of the franchise operation." General Statutes § 16-19e(a)(5). Therefore, those expenses that are reasonable and necessary to provide service to the publ...
AI summary The document outlines the criteria for allowable operating expenses, emphasizing the need for prudence and efficiency. The Company proposed O&M expenses of $184,902,644, but the Authority approved $166,405,683 after adjustments, citing the need for expenses to be reasonable, necessary, and supported by evidence.
2. Inflation Adjustment The Company proposes to escalate a number of Test Year expenses using an inflation adjustment factor of 8.15%, resulting in a pro forma expense of $4,505,562. Late Filed Ex. 1, Att. 2, Sch. WP C-3.0, p. 2; Sch. WP C...
AI summary The Company proposes using an 8.15% inflation adjustment factor to escalate Test Year expenses, but the Authority rejects this approach as imprecise and not sufficiently measurable. The Authority emphasizes that specific cost escalations must be justified with evidence and that generic inflation adjustments are not acceptable unless supported by reasonable and measurable data. However, in some cases, the Authority allows limited adjustments despite the Company's lack of supporting evidence.
b. Active and Final Collections The Company proposes a $237,748 expense for the Rate Year for Active and Final Collections, which is the Company's $226,457 Test Year amount, a ($6,620) pro forma adjustment to the Test Year amount attribute...
AI summary The Company proposed a $237,748 expense for Active and Final Collections, including a $17,911 inflation adjustment. The Authority rejected the inflation adjustment as not reasonable or measurable and approved $219,837 instead, citing insufficient evidence to support the adjustment and noting that collections expenses are influenced by variables like commissions and future RFPs for legal collections.
g. Credit Card Fees The Company proposes $1,892,932 in credit card fee expenses for the Rate Year, which is an expense for which the Company did not report a Test Year expense but expects to incur in the Rate Year. [58](#page-107-0) Late F...
AI summary The Company proposes $1,892,932 in credit card fee expenses for the Rate Year, which it expects to incur but did not report in the Test Year. It seeks to use these expenses as a baseline for a deferral mechanism to be trued-up in the next rate case, citing the 22-08-08 Decision. However, the Authority allows recovery of $1,827,877 but refuses to defer these expenses for future years.
i. Customer Programs The Company proposes $157,409 in customer programs expenses for the Rate Year, which is the Company's $139,572 Test Year expenses plus a $5,978 pro forma adjustment and an $11,859 inflation adjustment. Sch. WP C-3.03....
AI summary The Company proposes $157,409 in customer programs expenses for the Rate Year, including adjustments for inflation and pro forma costs. The Authority allows recovery of $145,550, citing the lack of reasonable justification for the proposed inflation adjustment. The Company disputes the Authority's finding of double counting but provides no supporting evidence.
r whether the reported rate case expenses relate to the current proceeding or the Company's last rate case in Docket No. 22-08-08, the reported rate case expenses are not recoverable in the Rate Year. Rate case expenses incurred in relatio...
AI summary The Authority disallows $245,312 in reported expenses related to affiliate support of rate case efforts, citing General Statutes § 16-243p(b), which bars recovery of rate case expenses for proceedings initiated on or after January 1, 2024. Expenses related to prior proceedings are deemed nonrecurring and not expected to be incurred in the Rate Year.
d. Audit Expense The Company seeks to recover $1,124,867 in direct audit expenses for the Rate Year, which is the Company's $1,040,122 reported Test Year expense plus an $84,745 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP...
AI summary The Company seeks to recover $1,124,867 in audit expenses for the Rate Year, but the Authority allows only 50% of the direct audit expenses, excluding an $84,745 inflation adjustment. The Authority determines that shareholders should bear the remaining 50% of the audit costs, citing the interests of ratepayers and stakeholders.
f. IT, Security, & Safety The Company proposes $665,826 in Rate Year IT, security, and safety expenses, which is the Company's $615,665 Test Year expense plus a $50,161 inflation adjustment. Sch. WP C-3.06. The Authority permits the Compan...
AI summary The Company proposed $665,826 in IT, security, and safety expenses for the Rate Year, but the Authority allowed only $513,375, disallowing $110,565 in nonrecurring expenses related to an additional security guard and $41,824 in inflation adjustments due to inconsistent historical spending.
unlawful or unwarranted legal outcomes that affect the Company's ability to provide safe and reliable service to customers and meet its underlying public-service obligation." Interrog. Resp. OCC-561. The Company has already litigated an ad...
AI summary The Company has already litigated an appeal of the 22-08-08 Decision, which was largely dismissed by the Superior Court, resulting in nonrecurring legal expenses that will not recur in the Rate Year.
any's interim rate application in Docket No. 22-08-08, and appellate costs in relation to Docket No. 20-08-03. Late Filed Ex. 44, Interrog. Resp. ADJ-001; Interrog. Resp. ADJ-002; Hr'g Tr., 904:17–25. The Company states that its UPZ progra...
AI summary The Company's UPZ program, in place since 2014, involves trimming trees and limbs near utility infrastructure. The Authority directed the implementation of a new trimming priority sequence and a four-year work plan (2024-2027) with specific budget and cost requirements. The UPZ plan was later determined to comply with these directions.
ii. RM Expense The Company proposes $1,463,325 in RM expenses for the Rate Year, which is the Company's $1,353,082 Test Year expense plus a $128,243 inflation adjustment. The Authority allows $1,477,599 in RM expense for the Rate Year. The...
AI summary The Company requested $1,463,325 for RM expenses, including an inflation adjustment, but the Authority approved $1,477,599. The Authority found that using a generic inflation factor was inappropriate due to existing contract escalation factors. The RM program addresses hazardous conditions and customer requests and is separate from the UPZ program.
7. Storm Expense The Company proposes $6,623,074 in storm expenses for the Rate Year, which is the Company's $9,531,643 Test Year amount less a $2,908,569 Test Year pro forma adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.07. The Com...
AI summary The Company proposes $6,623,074 in storm expenses for the Rate Year, including minor storm expenses, a Handy Whitman adjustment, major storm expenses, and an annual storm reserve. The Authority allows $6,188,125 in storm expenses for the Rate Year. Previously, storm expenses were categorized by type, but the Company has now consolidated all storm activity into a new schedule.
c. Major Storms The Company states that there is no incremental major storm activity, either expense or deferral, reflected in the Rate Year on Schedule C-3.07a; however, it reflects a $14,844 Rate Year expense for major storms in this Sch...
AI summary The Company claims there is no incremental major storm expense in the Rate Year, but Schedule C-3.07a shows a $14,844 expense. The Authority disallows this amount, citing double recovery as the Company already has a cost recovery mechanism for major storms through storm deferral.
d. Storm Reserve Lastly, the Company is not requesting any changes to its $2,000,000 storm reserve currently collected in rates to offset major storm expenses. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.07a; Revenue Requirements Panel Reb...
AI summary The Company is not requesting changes to its $2,000,000 storm reserve, which is used to mitigate rate shocks from major storm recovery costs. The Authority approves the continuation of the reserve, noting its effectiveness in encouraging the Utility Industry to prepare for potential storms.
a. Operational Smart Grids The Company proposes $2,608,107 in OSG expenses for the Rate Year, which is the Company's $1,774,562 Test Year expense plus a $833,545 Rate Year adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. C-3.09 WP. The Tes...
AI summary The Company requested $2,608,107 in OSG expenses for the Rate Year, including $1,774,562 from the Test Year and an $833,545 adjustment. The Authority found that only $1,774,562 from the Test Year and $688,961 in new Rate Year expenses were reasonable, approving a total of $2,463,523 for recovery.
b. Customer Service The Company proposes $607,663 in customer service-related computer expenses for the Rate Year, which is the Company's $561,833 Test Year expense plus an inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3....
AI summary The Company proposed $607,663 in customer service-related computer expenses for the Rate Year, including an inflation adjustment. The Authority permitted recovery of $409,401 after determining that certain vendors would not be used and that an inflation adjustment was inappropriate.
i. Test Year FTEs The Authority finds that the Company's 529.14 Test Year FTEs are reasonable. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.15, p. 1.
AI summary The Authority determines that the Company's 529.14 Test Year FTEs are reasonable, citing a specific exhibit and page reference.
se in FTEs, while the remainder of the increase is attributable to the normal annual merit increase to base payroll since incentive pay is based upon a percentage of base payroll. Ex. UI-RRP-1, p. 58. Non-union employees receive incentive...
AI summary The document discusses the Company's Annual Performance Award (APA) Plan for non-union employees, which is based on achieving company objectives and includes a 1,000-point structure tied to Avangrid, business area, and individual performance. Incentive compensation is determined by ratings in each area, with payouts based on the employee's base pay and points earned.
d. Workers Compensation Expense The Company proposes a workers compensation expense of $426,356, or $433 per employee, for the Rate Year. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.16e. Based on the evidence presented, the Authority finds...
AI summary The Company proposed a workers compensation expense of $426,356 for the Rate Year, but the Authority approved a lower amount of $424,923 after considering evidence and adjusting for a reduction in Full Time Equivalents. The Authority found the Company's projection of $433 per employee reasonable.
v. Student Loan Payments The Company proposes a $15,976 student loan payment expense for the Rate Year, which is the Company's $14,772 Test Year expense plus a $1,204 inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.16g. T...
AI summary The Company seeks to recover $15,976 in student loan payments for the Rate Year, but the Authority disallows the expense, stating the Company has not demonstrated that the program is reasonable or necessary for safe and reliable service or maintaining staffing levels.
age share of total revenue, less the commodity (such as excluding Generation Services Charge revenue for UI), payroll, and net plant-in-service plus construction work in progress. Ex. UI-RRP-1, p. 36. UI further allocates its costs between...
AI summary The document discusses how UI allocates its costs between distribution and transmission business segments, including the use of FERC-approved allocations for determining revenue requirements and wage allocators. It highlights the inclusion of various rate mechanisms in the distribution wage allocator calculation.
b. Massachusetts Formula Allocation In the present case, the Company allocated certain costs to its combined transmission and distribution business segments by computing and applying a Massachusetts Formula allocator of 61.78%. Late Filed...
AI summary The Company used a Massachusetts Formula allocator of 61.78% and 63.93% for cost allocation to its transmission and distribution segments, but the Authority adjusted the 63.93% to 62.73% using Test Year data and corrected the methodology to exclude rate adjustment mechanism profit centers. This adjustment led to a disallowance of $643,415, and the Company will use the revised method for future rate calculations.
c. Severance Payments The Authority does not permit the Company to recover $45,818 in severance expenses allocated to UI in the Rate Year. Interrog. Resp. OCC-346 Supp. The Company asserts that employment contracts with severance arrangeme...
AI summary The Authority denies the Company's request to recover $45,818 in severance expenses, finding that the Company has not demonstrated that such payments are recurring, known, or measurable. The Authority also notes that the Company's claims are anecdotal and unsupported by data.
k. Inflation The Authority concludes that the Company failed to demonstrate that its proposed $676,198 inflation adjustment for corporate services expenses represents a reasonable known and measurable adjustment and, accordingly, does not...
AI summary The Authority rejects the Company's proposed $676,198 inflation adjustment for corporate services expenses, citing a lack of reasonable, measurable justification and noting a decline in corporate service charges over the past five years.
243,865, and a portion of compensation expense for 54 AMC and ASC executives was allocated to the Company for a total of $2,831,543. Late Filed Ex. 23, Att. 1, 2023 Test Year; Hr'g Tr., 546:23–547:2. Executive compensation is allocated to...
AI summary The document discusses the allocation of executive compensation for the Company, including fixed and variable components, and how a portion is recovered in base rates. It outlines the use of consumption drivers and the Massachusetts formula for allocation, and notes that only 75% of UI executive compensation is approved for recovery in base rates.
uthority finds it is necessary and appropriate to connect some portion of the recovery of UI, AMC, and ASC executive compensation from UI ratepayers to achievement of certain customer-focused metrics. The Authority will use the performance...
AI summary The Authority links the recovery of executive compensation from UI, AMC, and ASC to customer-focused performance metrics, aiming to increase accountability. Metrics are used to measure UI's performance, with recovery depending on meeting or exceeding these metrics. The Historical Period is defined as the average from 2021 to 2025, or the Test Year if data is unreliable.
g. Travel Expense The Company proposes $1,015,051 in Rate Year travel expenses, which is the Company's $961,573 Test Year expense, a ($22,993) pro forma adjustment to remove entertainment costs barred from recovery under General Statutes §...
AI summary The Company proposed $1,015,051 in travel expenses for the Rate Year, but the Authority rejected the $76,471 generic inflation adjustment due to insufficient evidence of its reasonableness. The approved amount is $938,580, after removing entertainment costs and adjusting for inflation.
h. Other O&M The Company proposes that it recover $4,750,911 in the Rate Year for "other O&M" expenses, which is the Company's $5,731,385 Test Year expense, a ($1,338,395) pro forma adjustment, plus a $357,921 inflation adjustment. Late Fi...
AI summary The Company proposed to recover $4,750,911 in 'other O&M' expenses for the Rate Year, but the Authority determined that the Company did not justify using a generic inflation factor. The Authority approved a reduced recovery of $4,392,990, reflecting a pro forma adjustment.
a. Summary The Authority includes the amortized recovery of certain deferred costs, with carrying costs, as expenses in the Company's revenue requirement. This method of recovery outside of rate base will allow the Company to recover its o...
AI summary The Authority permits the amortized recovery of certain deferred costs as expenses in the Company's revenue requirement over a three-year period. If the Company does not amend its rate schedules by 2028, it must account for any overcollection and propose a revised rate adjustment mechanism (RDM) rate in its 2029 filing.
Table 68: Property Tax Adjustment – Test Year Plant-in-Service Line Description Value 1 Plant-in-Service Adjustment ($3,392,530) 2 Months of Depreciation Assumed 33 3 Monthly Depreciation Rate 0.2358% 4 Total Change in Depreciation Reserve...
AI summary The document discusses the Property Tax Adjustment for the Test Year Plant-in-Service, detailing calculations involving depreciation reserves, distribution plant additions, and adjustments based on assessment percentages. The Authority assumed different depreciation periods for various disallowance periods, and the Company's plant activity was multiplied by 33% to reflect the fiscal year 2026-2027 in the rate year.
Table 76: Approved Revenue Requirement Section Revenue Component Amount ($) IV.A Allowed Rate Base 1,354,956,818 V.A Weighted Average Cost of Capital 7.040% Allowed Cost of Capital 95,388,960 Allowed Expenses: VI.A Operations & Maintenance...
AI summary Table 76 outlines the Approved Revenue Requirement, including the allowed rate base, cost of capital, and various expenses such as operations, depreciation, and taxes. Section VIII introduces the topic of rate design, indicating a focus on how rates are structured.
A. LEGAL STANDARD The Authority is statutorily charged with regulating the rates of Connecticut's public service companies and UI is a public service company within the meaning of General Statutes § 16-1. General Statutes § 16-19. Conseque...
AI summary This section outlines the legal framework for rate regulation in Connecticut, emphasizing the Authority's duty to ensure rates are just, reasonable, and adequate while promoting revenue stability and equitable distribution. The Authority uses principles such as cost causation, rate class equalization, and gradualism to avoid sudden rate shocks and undue burdens on low-income customers.
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.
C. COST-OF-SERVICE STUDY The Company filed an allocated cost-of-service study (ACOSS) based on the historical test year and rate year costs and revenues. Application, Ex. UI-BR-1, p. 12. The Company's proposed ACOSS utilizes the Minimum Sy...
AI summary The Company submitted an allocated cost-of-service study using the Minimum System Study approach, classifying distribution assets into customer- and demand-related costs. The Authority requested alternative models that calculate per-customer load-carrying capacity, leading to adjustments in how demand-related costs are allocated. CIEC supports the use of the MSS approach, while OCC applied a universal load-carrying capacity adjustment based on scenarios from Minnesota and Ontario.
secondary distribution plant. The Authority affirms the Company's proposed classification of AMI meters as 100% customer-related, which is consistent with cost causation principles, as argued by CIEC. The MSS approach is a just and reasona...
AI summary The Authority affirms the classification of AMI meters as 100% customer-related. The MSS approach is deemed just and reasonable, but the minimum system's load-carrying capacity should be considered when allocating residual demand-related costs. The Company did not account for this and failed to quantify the equal benefit all customers receive from the minimum system.
D. COST ALLOCATION The Company used non-coincident peak (NCP) demand to allocate demandrelated costs from the ACOSS to each customer class, except for costs associated with distribution substations, for which the Company used class-wide co...
AI summary The Company used non-coincident peak (NCP) demand and class-wide coincident demand with system peak (1CP) to allocate demand-related costs, except for distribution substations. The Authority directed the use of alternative allocators using AMI data, but the Company found them similar to NCP and 1CP. To achieve equalized rates of return, the Company adjusted its model, violating the Authority's 125%/75% rule.
(125% of the class average increase) or the rate increase at equal rates of return (whichever is lower). Interrog. Resp. OCC-362, Att. 38 Second Rev. Supp. The Company then eliminates rate decreases (which occur in cases where the revenue...
AI summary The document discusses two revenue allocation approaches for rate classes. The Company's method involves eliminating rate decreases and manually adjusting residential rates to balance revenue, resulting in 50% of the class-wide average increase. The Authority prefers an alternative approach that uses a minimum increase threshold and adjusts excess revenue proportionally, adhering to a 75/125 rule.
1. Time of Use Rates In the Company's previous rate case, the Authority directed the Company to propose TOU rates with a shorter, more concentrated on-peak time, an appropriate price differential between on- and off-peak rates consistent w...
AI summary The Company's proposal for Time of Use (TOU) rates includes near-term opt-in rates and end-state opt-out rates, but lacks a concrete implementation date. It also proposes using the ACOSS results to allocate revenue requirements, though the Authority identified anomalies in the rate design model.
3. Maximum Residential Customer Charge General Statutes §16-243bb, enacted in 2015, required the Authority to adjust each EDC's residential customer's [127](#page-218-2) fixed charge to recover only the fixed costs and O&M expenses "direct...
AI summary The document discusses the establishment of a Maximum Residential Customer Charge (MRCC) under General Statutes §16-243bb, enacted in 2015. It outlines the Authority's direction to EDCs to follow the MRCC Decision and submit conforming calculations. UI initially proposed a charge of $13.20, but revised it to $13.04 after a discovery request from the Office of the Chief Counsel (OCC).
1. Revenue Decoupling Mechanism The Authority approves the revenue elements included herein to be included as "other revenues" for purposes of the Company's Revenue Decoupling Mechanism (RDM) calculation. Generally, an EDC may only charge...
AI summary The Authority approves the inclusion of 'other revenues' in the Company's Revenue Decoupling Mechanism (RDM) calculation. These revenues include late payment fees, reconnect service fees, and others. The Authority defines 'allowed distribution revenues' and 'actual distribution revenues' and ensures that the Company's RDM calculation aligns with these definitions. The RDM is used to adjust rates annually based on over- or under-recovery of distribution revenues.
2. Earnings Sharing Mechanism The Company proposes that its earnings sharing mechanism (ESM) continue as it is currently constructed with two adjustments: (1) the ESM calculation should reflect UI's actual equity ratio, not its authorized...
AI summary The Company proposes adjustments to its Earnings Sharing Mechanism (ESM), including reflecting its actual equity ratio and including disallowed expenses. The Authority rejects these proposals, maintaining the existing 50/50 split between ratepayers and shareholders for over-earnings above the allowed ROE, citing concerns over capital structure balance and legal principles.
d. Maintenance Carrying Charge Adjustment for Vegetation Management Costs The maintenance carrying charge is a component of the FCC pole attachment rental rate formula, the purpose of which is to ensure that attachers pay the pole owner 13...
AI summary The maintenance carrying charge adjustment for vegetation management costs involves a correction in the reporting of costs from FERC Account 592 to 593, leading to an increase in the maintenance carrying charge factor and pole attachment rates. NECTA argues that UI should use the original data for transparency, but the Authority supports the correction for accuracy.
2. New Rate Recommendation The Authority is satisfied with the Company's analysis regarding the appropriateness of a new small commercial rate. In the Company's previous rate case, the Authority directed the Company to provide a recommenda...
AI summary The Authority is satisfied with the Company's analysis that a new small commercial rate is unnecessary, as the current GS-GST rate threshold adequately addresses the needs of C&I customers. The Company conducted a sensitivity analysis and subclass ACOSS, which showed similar load factors and average costs across C&I customers. The Authority required the Company to provide histograms and load profile analyses to support its recommendations.
Maximum Peak Load Number of Cumulative % of Increment Threshold Customers % of Customers Customers (by 5 kW Tranche) (Annualized) (by 5 kW Tranche) (Sum of 5 kW Tranches) 0-5 kW 4,202 28.3% 28.3% 5-10 kW 3,512 23.6% 51.9% 10-15 kW 2,797 18...
AI summary The text presents a table detailing the distribution of customers by maximum peak load in 5 kW increments, along with cumulative percentages. It also notes that no party contested UI's conclusion regarding the application of Rate GS to commercial customers under certain demand thresholds and the placement of higher-demand customers on time-of-use rates.
Table 93: Rate GS Analysis – Maximum Annual Billed Demand Maximum Peak Load Maximum Annual Maximum Annual Cumulative Annual Increment Thresholds Billed Demand Billed Demand Maximum Billed (by 5 kW Tranche) (kW) (%) (%) 0-5 kW 3,965 2.1% 2....
AI summary Table 93 presents an analysis of Maximum Annual Billed Demand across different kW tranches, showing the distribution of demand and cumulative percentages. The Authority concludes that the current 100 kW threshold for Rate GS/Rate GST is sufficient for most customers.
load but rather a significant reduction, and (5) clarifying the eligibility requirement that customers "not [be] engaged in local commerce." Chait Prefiled Test., pp. 22–25; CIEC Brief, pp. 18–19, 22. First, UI agreed with CIEC's recommend...
AI summary The document discusses the approval of UI's amended special contract policy, including the inclusion of the EDR and adjustments to the price floor based on long-run marginal distribution costs. The Authority rejects a 15% or 20% discount but allows for larger discounts if necessary. Only the delivery component of the bill is eligible for a discount under this policy.
1. Standard Bill The Company's standard bill complies with the applicable regulations. See Application, Sch. H-2.0. The standard bill reflects modifications to the EDCs' residential customer bills established by the Authority. Decision, Ju...
AI summary The Company's standard bill complies with regulations as determined by the Authority and EOE. Modifications to residential customer bills were established in a 2022 decision, and EOE confirmed compliance in a 2025 brief.
1. ESG Initiatives The Company promotes environmental, social, and governance (ESG) topics as part of its broader engagement with external stakeholders in the UI service territory. Interrog. Resp. UPA-33. UI's Community Relations team coor...
AI summary The Company promotes ESG topics through stakeholder engagement, working with Avangrid's Sustainability team and local organizations. Avangrid aligns its corporate sustainability goals with Connecticut's clean energy targets, though UI's specific contributions are not independently verified.
2. Standard Operating Procedures Revision Lag The Authority previously identified a significant lag in the Company's updates of the Standard Operating Procedures (SOPs). 22-08-08 Decision, p. 278. Specifically, the SOPs had not been update...
AI summary The Authority identified a lag in the Company's updates to its Standard Operating Procedures (SOPs), which failed to reflect recent statutory and Authority directives on energy affordability and customer service. The Company claims to have complied, but errors in the SOPs were identified, leading to additional modifications. The Authority stresses the need for accurate and up-to-date SOPs and will continue reviewing them in future proceedings.
A. CONCLUSION The Authority approves an annual revenue requirement for UI in the amount of $450,789,348 for the rate year commencing November 1, 2025. This represents an increase of $65,924,348 from the Company's currently authorized reven...
AI summary The Authority approves an annual revenue requirement of $450,789,348 for UI, an increase from the current $384,865,000. This includes an allowed return on equity of 9.45%, reduced by 20 basis points to 9.25% due to performance and management issues. The Authority also addresses cost allocation, rate design, revenue adjustment mechanisms, and customer service.
B. ORDERS For orders requiring a filing, the Company shall file an electronic version through the Authority's website at [www.ct.gov/pura.](http://www.ct.gov/pura) Submissions filed in compliance with the Authority's orders must be identif...
AI summary The document outlines orders for the Company to file revised rate design plans and adjust distribution wage allocators, excluding certain profit centers. Compliance must be submitted electronically and identified with specific details. These orders take effect November 1, 2025, and require adherence to the Authority's findings.
N-63OEB Cost Allocation Review
72 passages
1.1.1 Scope of the Review The March 9, 2005 letter indicated that the cost allocation review will be based "primarily on the existing rate classifications and a limited number of rate design issues". As explained below, certain potential r...
AI summary The scope of the cost allocation review is primarily based on existing rate classifications and limited rate design issues. A separate comprehensive study of distribution rate design will address topics such as density rates, seasonal rates, and time of use distribution rates, which are deferred from the current review.
Rate Design The cost allocation filings will also contain updated information that is helpful to assess the cost basis of the current monthly service charges. After analyzing the filing results and other relevant considerations, the Board...
AI summary The document discusses the review of rate design, including potential adjustments to monthly service charges and the consideration of new or modified rate classes, such as for scattered unmetered loads, embedded distributors, and the elimination of the legacy 'Time of Use' rate class.
1.1.3 Objectives Of Staff Discussion Paper The general purpose of this discussion paper is to facilitate the forthcoming consultations with stakeholders. The Paper: - addresses the major steps in a cost allocation study - identifies and in...
AI summary The Staff Discussion Paper aims to facilitate stakeholder consultations by outlining the major steps in a cost allocation study, identifying issues related to cost allocation and rate design, and presenting preliminary proposals for review and debate.
1.2.1 Consultation Process On July 20, 2005, Board staff held a public meeting to review the planned consultation process, amongst other items. Written submissions were received and considered. Following the release of the present Staff di...
AI summary The consultation process for the rate proceeding involved public meetings, written submissions, and the formation of a Technical Advisory Team. The team met in three phases focusing on cost allocation, rate design, and OEB filing requirements. Technical workshops and stakeholder discussions were organized, and funding was provided for eligible parties. Data availability was a key consideration in determining mandatory filing requirements.
1.2.2 Development of OEB Filing Model As the first phase of the Technical Advisory Team meetings progresses, the development of the new OEB cost allocation model will start. An outline of the model will be introduced at the October Technic...
AI summary The development of a new OEB cost allocation model is underway, with initial testing by two medium-sized distributors and a second version planned for April 2006, to be tested by three distributors of varying sizes.
1.2.3 Cost Allocation Informational Filings In March 2006, following stakeholder consultations, the Board will issue a Report adopting common cost allocation principles and methodologies for the OEB cost allocation review. Select rate desi...
AI summary In March 2006, the Board will issue a report adopting common cost allocation principles and methodologies following stakeholder consultations. Mandatory filing requirements and a model will be released in July 2006, with all Ontario electricity distributors required to submit new cost allocation studies publicly during the fall of 2006.
Section 2: Overview of Cost Allocation Cost allocation studies serve the following main purposes: - to allocate the costs to provide service to the various customer rate classes based on cost causation principles - to assess the reasonable...
AI summary This section outlines the purposes and processes of cost allocation studies, which are used to allocate distribution and operational costs to customer rate classes based on cost causation principles. The studies assess the reasonableness of rates and support rate design. A three-step process—functionalization, categorization, and allocation—is described for assigning costs to rate classes.
Basic Customer Method This approach categorizes as customer-related costs only those capital and operating expenses that are directly associated with adding another customer. Examples of such costs are the capital and operating costs assoc...
AI summary The Basic Customer Method focuses on capital and operating costs directly tied to adding new customers, such as meters and service drops. It differs from other methods by excluding upstream distribution infrastructure costs like transformers and primary conductors. Critics argue it takes a short-term view and ignores long-term infrastructure expenses. The method is used in the U.S. but has limited Canadian application, with stakeholder input sought on its elements.
Minimum System Method This method has been described as follows: "Classifying distribution plant with the minimum-size method assumes that a minimum size distribution system can be built to serve the minimum loading requirements of the cus...
AI summary The Minimum System Method classifies distribution plant costs based on the minimum size required to serve customer demand. It calculates customer-related costs using average book costs of equipment and determines demand-related costs as the difference between total investment and customer-related costs. While accepted by regulators like the OEB, it has sparked debate due to potential overstatement of customer-related components.
Note on Modified Minimum System In the past, Ontario Hydro did some empirical work which led to the development of the Modified Minimum System Method. Its distinctive feature is that it further categorizes the demand-related component into...
AI summary This note discusses the Modified Minimum System Method, developed by Ontario Hydro, which categorizes demand-related components into demand and energy under a two-part rate design. However, staff recommend focusing on the traditional Minimum System approach due to the complexity and effort required for the modified method.
5.2.2 Use of Two Categorization Methods to Assist in Reviewing Future Rate Design A key objective of the present informational cost allocation filing process is to identify potential anomalies in fixed monthly customer charges. This can be...
AI summary The informational cost allocation filing process aims to identify anomalies in fixed monthly customer charges by using two categorization methods—a floor and a ceiling—to establish a range of reasonableness. The Basic Customer Method provides a floor, while the Zero-Intercept or Minimum System Methods provide a ceiling. The goal is to help the Board identify significant outliers rather than determine exact charge levels.
5.2.3 Categorization Method to Review Class Revenue-to-Cost Ratios The other major objective of the forthcoming cost allocation filings is to assess the revenue-to-cost ratios for the various customer rate classes of each distributor. It m...
AI summary The document discusses the recommended approach for categorizing revenue-to-cost ratios for customer rate classes. It suggests using either the Zero-Intercept or Minimum System Method, both of which are accepted by Canadian regulators. Stakeholder input will be sought to determine the most suitable method, and default categorization figures will be proposed based on a consultant's survey.
5.2.4 Need for Distributor-Specific Categorization Studies During the first phase of consultations, Staff wishes to focus on the development of defensible standard categorization results that are broadly applicable. To maximize the flexibi...
AI summary Staff proposes developing defensible standard categorization results applicable to various utility types, considering factors like customer density and utility size. Input is sought on grouping methods and potential inaccuracy scenarios, with further discussion on utility-specific studies if needed.
6.1 Background The final stage of a cost allocation study is the allocation of costs to customer classes. At this stage, costs have been functionalized and categorized into demand and customer-related components. For demand-related costs,...
AI summary The final stage of a cost allocation study involves allocating costs to customer classes, with demand-related costs using load data and customer-related costs using accounting records or customer numbers.
Use of NCP as main allocator of joint distribution demand costs The 2003 Working Group generally agreed that NCP should be the approved method used to allocate most demand-related distribution costs. The reasons included the following: - I...
AI summary The 2003 Working Group recommended NCP as the primary method for allocating joint distribution demand costs due to its fairness and customer control. Staff agrees with this approach, noting that NCP better reflects customer usage and provides more transparency compared to CP.
Potential other NCP allocators The 2003 Working Group discussed allowing utilities the option of allocating demandrelated distribution costs using the NCP of a number of months if it could be justified. The discussion focused on the merits...
AI summary The 2003 Working Group considered allowing utilities to use 12 NCP as a demand-related distribution cost allocator, noting its historical use in legacy rates. However, the emphasis should be on cost causality rather than smoothing effects. Only 1 NCP will be allowed as the sole demand allocator unless compelling cost justifications exist for other methods.
Class NCP by Voltage Line Losses Demand allocation factors are derived from actual meter reading data. Meters are installed at different voltages. Adjustments must therefore be made for line/transformation losses to fairly compare intercla...
AI summary The document discusses the adjustment of demand allocation factors for Class NCP by voltage, emphasizing the need to account for line and transformation losses. It highlights the use of loss factors from the 2006 EDR applications and the distinction between primary and secondary voltage loads. The USoA is referenced as a basis for these adjustments, with a call for additional filing requirements to better track distribution costs.
Peak-load Carrying Capacity ("PLCC") Adjustment A Minimum System has a certain load carrying capability which can be viewed as being demand-related. As a result, the customer-related costs will have a demand component in them. If no adjust...
AI summary The document discusses the need for a Peak-load Carrying Capacity (PLCC) Adjustment to ensure fair allocation of demand-related costs among customers. It suggests that distributors should adjust for the PLCC of the assumed Minimum System and proposes that utilities may conduct their own analysis if it differs significantly from a generic default figure.
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.
Meter Reading At the current time, most residential and small commercial customers' meters are read manually. However, the frequency of meter readings may vary by rate class and by distributor. In contrast, the majority of interval meters...
AI summary The document discusses current meter reading practices, noting that most residential and small commercial meters are read manually, while larger customers use electronic interval meters. It outlines cost allocation considerations and potential factors for distributing meter reading costs, emphasizing the need to account for reading frequency and customer density.
Call Centre Activities in this category include responding to customer inquiries, and preparing educational and communication material. Call centre costs generally vary as a function of the number of customers and could be allocated to the...
AI summary Call centre activities involve responding to customer inquiries and preparing educational materials. Costs are typically allocated based on the number of customers per rate class, though some utilities use detailed records like time sheets or logs for more accurate tracking.
Customer Information System (CIS) CIS costs are commonly allocated in a fashion consistent with the treatment of billing and call centre costs. The allocation could hence be based on: - number of bills - weighted number of bills - number o...
AI summary The document discusses methods for allocating CIS costs, suggesting approaches such as the number of bills, weighted number of bills, number of customers, and weighted number of customers, with the weighted number of bills considering the effort and complexity of billing different customer classes.
7.2.3 Initial Recommendations For ease of administration and implementation, it is proposed that general plant be allocated pro rata to the allocated distribution plant. This would be the standard method for the allocation of general plant...
AI summary The document proposes allocating general plant pro rata to allocated distribution plant for simplicity, while allowing flexibility for distributors with detailed analyses to justify alternative allocations.
7.3.3 Initial Recommendations For ease of implementation, it is proposed that A&G be allocated pro rata to the allocated O&M expenses (excluding A&G). This would be the standard method of allocation. It is also proposed that some flexibili...
AI summary The text proposes allocating A&G pro rata to O&M expenses, excluding A&G, and allows flexibility for distributors with detailed analyses to group accounts based on plant activities, requiring justification and documentation.
Use of Load Data in Establishing Demand Allocators While there are a number of methods to allocate distribution demand-related costs, all require the use of load data. It is widely recognized that load data plays an important role in the a...
AI summary Load data is essential for accurately allocating distribution demand-related costs. The American Public Power Association highlights that the accuracy of demand load data significantly affects the allocation of capacity costs to customer classes of service.
8.1.2 OEB Load Data Directions The former (2001) Electricity Distribution Rates Handbook ("DRH") advised utilities: "Prior to the implementation of 2nd generation PBR the Board will require utilities to develop allocation studies that refl...
AI summary The document outlines the former Electricity Distribution Rates Handbook's guidance on load data collection prior to the implementation of 2nd generation PBR. The Board issued Load Data Collection Directions in 2003, requiring utilities to collect at least 12 months of statistically reliable load data and encouraging joint studies to achieve cost efficiencies.
8.1.3 Load Data Implementation Issues There are a variety of technical questions dealing with how the new load data will be processed and prepared for use in the cost allocation model. These will be examined in detail during the third phas...
AI summary The document discusses technical challenges related to implementing new load data in the cost allocation model, noting that specialized rate classifications may not be covered by industry research groups, requiring careful consideration by distributors.
9.3 Summary of the Study A summary will be required with the cost allocation filings including an explanation of the study results. In addition, the summary should include the rationale, and supporting documentation (including any material...
AI summary The summary of the study is required with cost allocation filings and must explain study results, rationale, and supporting documentation for alternative cost allocation methods. Examples include documentation for direct allocation of demand-related costs and load study methodology.
9.6 Output of the Model The details of the various outputs from the cost allocation filing model will be finalized during the third phase consultations. A standard set of outputs from the filing model will be prescribed. Given the key obje...
AI summary The document outlines the standard outputs from the cost allocation filing model, including revenue-to-cost ratios, fixed monthly charges, and unit costs. The model will be run twice using different methodologies, and additional technical information will be provided for stakeholder review. Audit trails and future rate design considerations are also mentioned.
Creation of a new class From a cost–causality perspective, there are merits in considering the creation of a new rate class for scattered unmetered loads (for example, their load profiles are distinctive, and customer costs differ from reg...
AI summary The text discusses the merits of creating a new rate class for scattered unmetered loads, noting their distinctive load profiles and differing customer costs. It argues for consistency across the province and suggests that distributors should treat such users as a separate rate grouping in upcoming filings.
Cost allocation studies Staff will seek stakeholder input on the development of a methodology to accurately track the costs for this new rate classification. This will ensure that other ratepayers are not unfairly treated by the creation o...
AI summary Staff proposes a methodology to allocate costs for a new scattered unmetered load class, ensuring fairness for ratepayers. Unmetered loads should bear full distribution asset costs, excluding metering and billing costs sent to a central office. Stakeholder input is requested on additional costs to allocate or exclude.
Rate Design Once costs are fairly allocated to this new class, the question remains whether it is preferable to recover customer-related costs through a per customer or per connection charge or a combination of the two. Some costs are like...
AI summary The text discusses the allocation of costs to a new class of customers and considers whether to recover these costs through per customer, per connection, or a combination of charges. It also references a 2005 comment suggesting that new rate classes should align with a consistent rate design philosophy.
Note on Streetlighting During the 2006 EDR process, a municipality raised concern about streetlighting rates. The question of designing streetlighting rates on a per customer or per connection basis will be addressed when the same topic is...
AI summary During the 2006 EDR process, a municipality expressed concerns about streetlighting rates. The document notes that the issue of designing rates on a per customer or per connection basis will be addressed later for the new scattered unmetered load class. It also mentions that streetlighting is generally off-peak in the summer and on-peak in part of the winter, with potential adjustments for this pattern to be discussed during consultations.
10.3 Initial Recommendations Staff recommends that a new scattered unmetered load class be set up as part of the cost allocation model and that a full cost allocation study be performed for the new class. Staff further recommends that the...
AI summary Staff recommends creating a new scattered unmetered load class and conducting a full cost allocation study. They also suggest splitting the fixed monthly charge into two components: one per customer and another for individual connection costs, with remaining distribution costs recovered through a volumetric charge.
11.1 Background Over the years, various approaches have been taken towards rate classification for larger General Service customers in Ontario. Before they became subject to regulation by the OEB, utilities were allowed to apply for a new...
AI summary This section discusses historical approaches to rate classification for larger General Service customers in Ontario, noting the lack of a common intermediate GS class between 50 kW and 5000 kW. It also mentions that the Board is not re-examining the GS 50 kW boundary but will focus on promoting consistency in treatment of larger GS customers.
11.2 Issues and Options It is useful to seek stakeholder input on the merits of different ways to assess the need for, and implications of, a common approach towards a GS intermediate rate classification. Several approaches are possible: -...
AI summary The document discusses various approaches to assessing the need for a common GS intermediate rate classification in Ontario. Options include surveys of other regions, examining voltage breaks, reintroducing the 10% test, and using load factors as a cost causality factor. Further analysis may not be available until early 2006.
11.3 Initial Recommendations Staff wishes to identify and obtain stakeholder comments on the various approaches towards the potential design of a new GS intermediate rate classification including the use of load factors, delivery voltages...
AI summary Staff proposes a new GS intermediate rate classification, considering load factors, delivery voltages, and the reintroduction of the 10% test. They seek stakeholder input on potential design approaches and ways to minimize adverse rate impacts and boundary concerns.
12.1 Background This section will deal with rate classification, cost allocation, and rate design issues in situations where a host utility transfers power to an embedded utility (also known as Low Voltage (LV) rates). Staff understands th...
AI summary This section addresses rate classification, cost allocation, and rate design in scenarios where a host utility transfers power to an embedded utility, noting the presence of 12 distributors with varying levels of service and the challenge of developing a consistent policy.
13.1 Background Prior to the opening of the electricity market, Ontario Hydro was a generator, transmitter and distributor of electricity. It charged the municipal utilities for the cost of power, which included generation and transmission...
AI summary This section outlines the evolution of electricity pricing in Ontario, focusing on the transition from a single-rate system to time-differentiated wholesale rates and the subsequent unbundling of retail rates. It also describes how the opening of the electricity market affected the regulation of commodity costs and the persistence of TOU sub-classes.
13.2 Issues and Options One option is to allow a distributor the discretion as to when these rate classifications are removed. This was the approach taken for 2006 rates (see section 10.3, 2006 EDR Handbook). On the basis of consistency am...
AI summary The document discusses two options for managing rate classifications: allowing distributors discretion in removing them, as done in 2006, or mandating their elimination for consistency and simplicity.
13.3 Initial Recommendations Staff recommends that the upcoming cost allocation studies assume the elimination of the sub-classification known as TOU and the absorption of the costs currently assigned to the equivalent non-TOU class. As no...
AI summary Staff recommends eliminating the TOU sub-classification and absorbing its costs into non-TOU classes. The introduction of new TOU rates will be considered after a comprehensive rate design paper is issued in 2006.
14.1 Filing Requirements for Adding/Deleting Rate Classifications In addition to producing information relevant to the fair recovery of costs between classes, the upcoming informational filings will gather information to address two rate d...
AI summary The filing requirements for adding or deleting rate classifications will collect information on rate design areas, including classification changes and a review of fixed monthly service charges. These issues will be addressed in subsequent phases of the consultations.
14.1.1 Background As previously mentioned, this review will also examine the need for, and implications of, introducing new rate classes for scattered unmetered loads, embedded distributors, and larger GS customers, and eliminating the exi...
AI summary This section discusses the potential introduction of new rate classes for specific customer types and the elimination of existing TOU distribution rates. It emphasizes the need to understand and document the financial implications for affected customers.
14.1.2 Issues and Options Affected distributors should be required to perform and file a cost of service study with both the new and existing rate classifications. This would provide sensitivity analysis at all stages of the cost allocatio...
AI summary The text discusses the need for distributors to perform cost of service studies under new and existing rate classifications, and suggests using typical load profiles to estimate customer impacts. It also raises concerns about the complexity of rate design if new classifications are introduced with minor cost differences.
14.1.3 Initial Recommendations In order to assess the implications of adding or deleting a rate class at the rate class level, it is recommended that distributors be required to file a supplemental cost of service study with the new rate c...
AI summary The initial recommendations suggest that distributors file a supplemental cost of service study when modifying rate classes and capture rate and bill impacts at both the rate class and customer levels using typical load profiles, with guidelines to be discussed during the consultation process.
14.2.1 Background Following receipt of all the informational filings in the fall of 2006, the Board should be in a position to identify fixed monthly service charge anomalies. The Board may later request that certain distributors proceed t...
AI summary The Board is preparing to identify fixed monthly service charge anomalies following informational filings from 2006. It may request rate applications to address significant rate issues. Current consultations will not address the appropriate balance of fixed monthly charges but will focus on information requirements for future reviews.
14.2.2 Issues and Options As previously indicated, Staff proposes that the review of the fixed monthly service charges be done by establishing a reasonable cost-based floor and ceiling. The costbased floor will be based on the results of t...
AI summary Staff proposes reviewing fixed monthly service charges by establishing a cost-based floor and ceiling, using the Basic Customer Method and survey results. Consultations should focus on the Minimum System approach, as previous methods led to high charges. Large users showed significant variations, and total distribution charges should be examined.
14.2.3 Initial Recommendations Staff recommends that the filing model incorporate both the Basic Customer Method, as well as generic figures based on a survey of the Minimum System and Zero-Intercept results. The former will generate a cos...
AI summary Staff recommends incorporating both the Basic Customer Method and survey-based figures into the filing model to set cost-based floors and ceilings for fixed monthly service charges. Distributors must explain charges outside the proposed range, and all rate classes should be considered.
14.3.1 Background Distributors across the province currently use different methods to measure peak demand. Peak demand is the billing determinant that is used to recover demand based distribution charges. Peak demand can be measured on the...
AI summary The document discusses how different methods are used to measure peak demand by distributors in Nova Scotia, which affects billing and distribution charges. Methods include clock hour, 15-minute, and rolling 60-minute interval readings, with clock hour readings used for wholesale transmission and commodity settlement.
14.3.2 Options and Issues The use of a particular method over another is likely to generate different peak demand results and therefore, different demand charges. This in turn would likely have ramifications on load research, cost allocati...
AI summary The text discusses the impact of different methods for measuring peak demand on demand charges, load research, cost allocation, and rate design. Staff proposes investigating a common definition of peak demand and seeks stakeholder input on the merits of various methods.
14.3.3 Initial Recommendations Staff recommends that this topic be discussed as part the Technical Advisory Team discussion and associated Workshop during the second phase of the consultations. In particular, Staff wishes to gather stakeho...
AI summary Staff recommends discussing the need for a common definition and measurement of peak demand across all distributors during the Technical Advisory Team discussion and associated Workshop in the second phase of consultations. Input on the merits of various methods is also sought.
Appendix 1 – Direct Assignment of Accounts Appendix 1 - Direct Assignment of Accoun its USoA Account # Accounts Direct Assignment Distribution Plant 1875 Street Lighting and Signal Systems х General Plant 1965 Water Heater Rental Units х 1...
AI summary This document outlines the direct assignment of accounts related to distribution plant and customer account expenses, including specific account numbers and their allocations. It also includes a table detailing the functionalization of selected accounts across various categories such as distribution, metering, and customer services.
Appendix 6 Illustrative Example of the Derivation of a Weighted Customer Allocation Factor - Metering Col.1 Col. 2 Col. 3 Col. 4 Customer Rate Class Cost per Meter (Installed) ($) Number of Meters Weighted Metering Costs (1) ($) Weighted F...
AI summary This appendix provides an illustrative example of how a weighted customer allocation factor for metering is derived. It shows the cost per meter, number of meters, weighted metering costs, and weighted factors for different customer rate classes, including residential, GS < 50 kW, GS > 50 kW, and large users.
Appendix 7 - Board's 2003 Load Data Collection Directions, RP-2003-0228 Ontario Energy Commission de l'Énergie Board de l'Ontario P.O. Box 2319 C.P. 2319 2300 Yonge Street 2300, rue Yonge 26th. Floor 26e étage Toronto ON M4P 1E4 Toronto ON...
AI summary The Ontario Energy Board issued directions in 2003 regarding load data collection, referencing the need for updated load profiles for cost allocation studies. The document outlines the formation and reactivation of a Cost Allocation Working Group and includes a joint proposal from over 40 distributors for province-wide load data collection.
Average v. Marginal Cost The Working Group was asked to assess the merits of an average versus a marginal cost approach to undertaking the upcoming cost allocation studies. The Group recommended use of an average ("embedded") cost approach...
AI summary The Working Group recommended using an average (embedded) cost approach for upcoming cost allocation studies, similar to Ontario's natural gas distributors. The Board accepted this recommendation, emphasizing that marginal pricing principles may still be considered during the rate design stage.
A) General Load Data Collection Directions The Board hereby issues the following Directions to all Ontario electricity distributors regarding the upcoming collection of load data. In these Directions, the term "rates classification" refers...
AI summary The Board provides directions to Ontario electricity distributors on collecting load data, defining 'rates classification' and outlining current rate classes and subclasses as per the Electricity Distribution Rate Handbook.
Issue 1) What type of load data should be collected? To provide the full range of data that may be needed when subsequently completing the cost allocation studies, the Working Group recommended interval load data be collected. The Board ag...
AI summary The Working Group recommends collecting interval load data for cost allocation studies. The Board agrees and specifies that the interval should not exceed one hour, addressing concerns raised by Guelph Hydro regarding appropriate time intervals.
Issue 3) In order to ensure reliability of the load data gathered, what sampling methodologies are appropriate? The Working Group recommended that any of the statistically-verifiable sampling methodologies discussed in the leading North Am...
AI summary The Working Group recommends using statistically-verifiable sampling methodologies from the AEIC's Load Research Manual for load data collection. The Board supports this and suggests that Ontario distributors may adopt a common methodology to facilitate data sharing. The Board also advocates for a province-wide sampling program to achieve cost efficiencies and ensure data reliability.
Issue 5) Is additional metering needed? Are there any practical constraints if additional metering is required? a) Re Timing: The Working Group advised that it is not feasible to commence load data collection on January 1, 2004 (as origina...
AI summary The Board addresses Issue 5 regarding the timing and costs of additional metering for load data collection. It acknowledges delays in metering due to installation and testing timelines and directs that data collection commence by February 1, 2004. The Board also agrees that a joint load data collection initiative is more economical than individual programs.
Issue 7) Meter Accuracy. The Working Group recommended that the individual customer metering to be installed for load data research purposes be within plus/minus 1% accuracy. The Board accepts this recommendation. It should be noted that t...
AI summary The Board accepts the Working Group's recommendation that individual customer meters for load data research should be within ±1% accuracy. However, it does not mandate the use of Measurement Canada approved meters for this purpose, emphasizing that interval meters should not replace approved billing meters unless they are also approved for billing.
Issue 8) Substation Metering. The Working Group recommended that measuring the load profile at a transformer station or substation feeder (or by means of SCADA) could be used as a check on the reasonableness of the profiles derived from ra...
AI summary The Board agrees with the Working Group's recommendation that load data from substations or SCADA systems can only be used to verify data from statistically-verifiable interval metering of individual customers, to ensure accuracy in rate-setting.
Issue 10) Is it acceptable that the load profile of a rate classification be estimated as a residual? The Working Group noted that the use of a residual estimate of a rate classification's load profile has been used in load data research s...
AI summary The Working Group considered the acceptability of using a residual estimate for load profiles of rate classifications. While some suggested any classification could be used, the Board recommends restricting this method to the most heterogeneous classification, General Service<50 kW, to ensure reliability.
Issue 11) Relationship between load data to be collected and rate classifications. The Working Group recommended that the present rate classifications be the starting point for designing the load research program and, as a result, each dis...
AI summary The Board accepts the Working Group's recommendations on load data collection for rate classifications, directing that updated interval load data be collected for each rate classification in the 2006 rates application, with exceptions for certain cases such as similar load profiles and deemed load profiles for specific uses.
Issue 12) Future Introduction of a new General Service Subclass. The RP-2000-0069 decision (see paragraph 3.5.7) indicated that "the Board will initiate a review of the rate design for the general service class". Several distributors, duri...
AI summary The document discusses the potential introduction of a new General Service subclass, noting that while some distributors support localized determination of subclass boundaries, others oppose a province-wide approach. The Board will proceed cautiously and may use existing load data from interval meters to inform future reviews.
Issue 13) Rate classifications potentially not requiring new sample metering. The Working Group believed that not every rate classification will require its own new sample metering. In particular:
AI summary The Working Group believes that not all rate classifications require new sample metering, suggesting that some may be grouped or handled differently to avoid redundant metering processes.
a) Street lighting and sentinel lights The Working Group recommended individual distributors use their approved street lighting hours of use when calculating a "deemed" street lighting load profile. The Board accepts this recommendation an...
AI summary The Working Group recommended using approved street lighting hours for calculating deemed load profiles, which the Board accepted. The Board also directed that distributors provide details on how these profiles are calculated and agreed to apply the deemed profile to sentinel lights.
c) Low density rates and poly-phase rates The Working Group noted that detailed cost data is required to support rate schedules that reflect differing customer density, and also to reflect three-phase versus singlephase service. But it und...
AI summary The Working Group recommends that detailed cost data be used for low density and poly-phase rates without requiring separate load data, as these classifications are not expected to have significantly distinctive load profiles. The Board agrees and will not require separate load profiles for these rates.
e) Intermediate Use The Working Group assumed that all customers in a distributor's Intermediate Use subclass are individually interval metered and therefore appropriate load data will be available. If this assumption proves incorrect for...
AI summary The Working Group assumes all Intermediate Use customers are individually interval metered, requiring appropriate load data. If incorrect, distributors must file additional data. The Board notes the current definition of Intermediate Use in the Distribution Rates Handbook may differ from approved subclasses, suggesting a potential review of the definition.
f) Time of Use ("TOU") distribution rates The Working Group assumed that if any distributor has approved TOU distribution rates, such customers will be individually interval metered and therefore the appropriate load data will be available...
AI summary The Board acknowledges the need for accurate interval load data for TOU distribution rates and requires distributors to collect such data. It also expects that the future role of TOU rates will be considered during rate design consultations, and distributors must justify the distinctiveness of distribution costs for TOU rate classifications.
g) Voltage-based rates The Working Group was unsure of whether additional data would be needed to support the introduction of voltage-based rates for Large or Intermediate use customers. The Board directs that any distributor planning to i...
AI summary The Working Group is uncertain if more data is needed to support voltage-based rates for Large or Intermediate use customers. The Board requires distributors to include load and financial data in their cost allocation filings if they plan to introduce such a rate classification.
s in this rate classification, which will provide new data to check and possibly refine the estimate. - · It will be assumed that all Intermediate and Large Use customers are interval metered already. Guelph Hydro commented that the incide...
AI summary The Board supports the Ontario Load Data Research Group's proposal for joint load data collection, acknowledging potential concerns about interval metering coverage but believing the data will be sufficient for cost allocation studies. The Board expects the group to begin data collection by February 1, 2004, and to report on progress by December 22, 2003, and February 2, 2004.
Load data research to support a future review of General Service Subclasses The Ontario Load Data Research Group is expected to investigate whether the data available from the thousands of interval meters already installed amongst their me...
AI summary The Ontario Load Data Research Group is investigating whether existing load data from interval meters can inform future discussions on adjusting General Service Subclasses, including potential changes to subclass boundaries and the introduction of a new subclass. The Board is not making a decision now but aims to organize data to support future stakeholder discussions.
N-64N-64.pdf
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COST ALLOCATION REVIEW Board Directions on Cost Allocation Methodology For Electricity Distributors
AI summary The document outlines the Board's directions regarding the methodology for cost allocation among electricity distributors, emphasizing the need for a fair and transparent approach to distributing costs.
1.2 Scope of the Review The Chair of the Ontario Energy Board advised stakeholders in a letter dated March 9, 2005 that a cost allocation review would proceed and that the review would be based "primarily on the existing rate classificatio...
AI summary The Ontario Energy Board's review of cost allocation is limited to existing rate classifications and a few rate design issues. Topics like rate classification boundary smoothing, distribution rate philosophy changes, and new time-of-use rates are outside the current scope. A separate study on distribution rate design is planned for 2007.
1.5.1 Common Cost Allocation Methodology In this Report the Board has established a common cost allocation methodology for use by Ontario electricity distributors. To assist in the completion and review of the filings, certain default valu...
AI summary The Board has established a common cost allocation methodology for Ontario electricity distributors, emphasizing sound cost causality and using consistent methodology with utility-specific inputs to support cost allocation reviews.
1.5.2 Cost Allocation Information The filings will provide the revenue to cost ratio, and rate of return, for each rate classification of a distributor. This information will document the extent of any inherent cross-subsidization between...
AI summary The filings will include the revenue to cost ratio and rate of return for each rate classification of a distributor, documenting any inherent cross-subsidization between rate classifications.
1.5.3 Rate Classification Information For the purpose of the cost allocation filings, the term "rate classification" will generally refer to any separate distribution rate class or subclass. Each rate classification will be modeled separat...
AI summary The document outlines potential changes to rate classifications for distribution services, including eliminating the 'Time of Use' class and introducing new classifications for large users and unmetered loads. These changes will be modeled separately, with historical data from 2004 used for assessment. The upcoming Electricity Distribution Rate Design Review will inform the implementation of these changes.
1.5.4 Customer Unit Cost Information The filing model will produce customer unit costs per month for each rate classification. To assist with reviewing the range of current fixed monthly customer service charges, the model will generate re...
AI summary The filing model generates monthly customer unit costs for each rate classification, including lower and upper end estimates. These unit cost data, along with other rate design goals, will be considered before implementing changes to fixed monthly customer service charges.
1.5.8 Specialized Situations This Report sets out a common cost allocation methodology that is intended to cover the great majority of the situations to be faced by a typical distributor. There may be specialized situations for which the R...
AI summary This section outlines a common cost allocation methodology for distributors, noting that it may not cover all specialized situations. It mentions that including generation assets in the rate base is rare and that distributors should use sound practices and explain any uncovered situations in their Filing Summary.
1.6 The OEB Cost Allocation Filing Model The OEB cost allocation review filing model and accompanying instructions are planned for release to all distributors shortly after the issuance of this Report. All licensed electricity distributors...
AI summary The OEB is planning to release a cost allocation review filing model for electricity distributors, with exceptions for certain entities. Most distributors are expected to use the standard model, while others must create their own with Board approval and ensure consistency with the outlined methodology.
1.7 Model Runs to be Filed Distributors will be required to submit a Run 1 and a Run 2 of the filing model. Run 1 will generally be based on the distributor's approved 2006 rate classifications including any approved interim rates. Special...
AI summary Distributors must submit two model runs (Run 1 and Run 2) based on approved rate classifications, with special rules for merging distributors. Run 2 must include specific rate classification changes identified in the report. Model filings should remain consistent, with exceptions documented. Run 3 is optional and must include explanations for changes. Alternative data methods are allowed if better data is available and must be documented.
1.11 Potential Future Implementation in Rates In light of the extensive effort given to this process and the Board's deliberations with respect to the appropriate cost allocation methodology, parties should expect that the Board will give...
AI summary The Board emphasizes the importance of the cost allocation methodology used in this Report, which will heavily influence future rate hearings. Adjustments to cost allocations, rate classifications, or rate design will be determined based on the review of filings and upcoming consultations. Distributors may be required to address specific matters in future rate applications, with potential implementation of new rates as early as May 2008.
2.1 Background When establishing the scope of the cost allocation review, the Board decided to base the review primarily on the approved 2006 rate classifications. These are to be incorporated in Run 1 of the filing model. The Board also d...
AI summary The Board is conducting a cost allocation review based on the 2006 rate classifications, with Run 1 incorporating these classifications and Run 2 including limited changes. Distributors may submit Run 3 for additional changes with supporting data. Special cost methodologies will be used for certain cases, and future discussions on Retail Transmission Service Rates are noted.
2.1.1 Modeling The OEB cost allocation model includes the rate classifications common to the bulk of distributors. The model to be issued will include space for several additional utility-specific rate classifications.
AI summary The OEB cost allocation model includes standard rate classifications for distributors and will be updated to accommodate additional utility-specific classifications.
2.1.2 Merging Distributors Separate rules (see Chapter 3 for details) will apply to distributors that have merged and there is a significant prospect that separate rate classifications will not be maintained. Where applicable, separate zon...
AI summary The section discusses rules for merged distributors, stating that separate rate classifications may not be maintained and that zonal rates may not be required in certain filings. Distributors that have merged are advised to review these rules.
2.2.1 Embedded Distributors For Run 1, the distributor should model its currently-approved rate structure. If the approved charge to an embedded distributor is represented as a separate rate classification in the 2006 rate order for the ho...
AI summary The text discusses modeling rate structures for embedded distributors, noting that if a separate rate classification exists in the 2006 rate order, it should be modeled in Run 1. For Run 2, customers receiving standard rates may be reclassified into the embedded distributor rate classification.
2.2.3 Load Displacement Generation ("LDG") Rate Classification for Run 1 Distributors with currently-approved "standby" rates, including interim standby rates, will be required to address load displacement generation in Run 1 of the filing...
AI summary The document outlines the requirements for distributors to address load displacement generation (LDG) in Run 1 of the filing. It discusses two approaches for allocating costs to LDG customers, depending on whether current standby rates are based on standard rate classifications. A common methodology is to be developed for cost allocation.
2.3 Run 2 of the Filings In Run 2 of the filing model, select rate classification changes must be incorporated. Specifics are listed below. The Board will consider implementation following the cost allocation review. The results of the Ele...
AI summary Run 2 of the filing model requires specific rate classification changes, with the Board considering implementation after a cost allocation review. The Electricity Distribution Rate Design Review results will be considered, though standby service rates are excluded from this change.
2.3.1 Test Year and Rate Classifications For 2006 EDR historic test year filers, the applicability of the classification changes will be assessed using 2004 data. For example, if a historic test year filer became a host distributor for an...
AI summary The document discusses how the classification changes for 2006 EDR historic test year filers will be assessed using 2004 data, with an example provided regarding embedded distributor rate classifications.
2.3.2 Elimination of Legacy Time of Use ("TOU") Rates The legacy distribution rates known as "Time of Use" must be eliminated in Run 2 of the filing. This will apply to any legacy TOU rates for GS>50 kW customers. These customers should be...
AI summary The document discusses the elimination of legacy Time of Use (TOU) rates for large customers (GS>50 kW) in Run 2 of the filing. Distributors must reclassify these customers under either an existing demand range or the existing GS>50 kW classification, with appropriate cost allocation. The merits of new TOU rates are not addressed in this project, but any interim TOU rates must be included and explained in the filing.
2.3.3 New Large User Rate Classification In some cases, a distributor may have a customer in a General Service classification that on a 12 month average has demand of 5,000 kWs or more. If this occurred in the test year underlying 2006 rat...
AI summary The document discusses the creation of a new Large User rate classification for distributors when a General Service customer has an average demand of 5,000 kWs or more over 12 months. If this occurred in the test year for 2006 rates, the Large User classification must be modeled in Run 2 of the filing, using the same cost allocation methodology as other rate classifications.
2.3.4 Common Separate Rate Classification for Embedded Distributors There are a number of host distributors that are providing a distribution service to embedded distributors. In some cases, host distributors have created a separate rate c...
AI summary The document discusses the need for a common separate rate classification for embedded distributors, noting that some host distributors have already created such classifications or treat embedded distributors as General Service customers. The Board recommends modeling a common classification in Run 2 filings, while acknowledging stakeholder concerns about the cost rationale for separate classifications.
2.3.5 Common Separate Rate Classification for Unmetered Scattered Loads It is understood that it is more common in other jurisdictions to treat USL as a separate rate classification. To provide further relevant information to the Board, Ru...
AI summary The document discusses the classification of Unmetered Scattered Loads (USL) as a separate rate classification in Run 2, requiring distributors to model USL as fully separate, including both photo-sensitive and non-photo-sensitive loads, to promote simplicity in rate classification.
2.3.6 Rate Classification for Customers with Substantial Load Displacement Generation In Run 2 of the filings, all distributors serving customers with significant load displacement generation will be required to model LDG rates as a fully...
AI summary This section discusses the requirement for distributors to model Load Displacement Generation (LDG) rates as a separate classification in Run 2 of filings, particularly for customers with a standby distribution service requirement of 500 kW or greater. It also addresses concerns about the reliability of load data and the use of the Run 1 approach if necessary.
2.4 Optional Rate Classification Changes in Run 3 A distributor will only be permitted to model the following items in an optional Run 3 filing:[6](#page-19-1) - the deletion of a rate classification with supporting rationale - the additio...
AI summary The text outlines the permissible changes for optional Run 3 filings by distributors, including the deletion or addition of rate classifications, adjustments due to customer loss, and specific modeling options. Certain rate classifications, such as density and seasonal based rates, cannot be added in Run 3. Zonal rates require additional load and cost data.
3.1 Load Data - General Requirements All distributors are generally expected to provide reasonable supporting load data for each separate rate classification to be modeled in Run 1, 2 or 3 of the cost allocation filing. Distributors consid...
AI summary This section outlines the general requirements for load data submission by distributors in cost allocation filings. Distributors must provide reasonable load data for each rate classification modeled in Runs 1, 2, or 3. Specific guidelines are provided for different classifications, including the use of interval meter data and approved load profiles. Special provisions apply to GS<50 kW and Unmetered Scattered Load classifications.
3.2 Load Data Requirements for Merging Distributors For Run 1, distributors will generally be required to model all their currentlyapproved rate classifications and provide supporting load data. Separate rules will apply to distributors th...
AI summary This section outlines the load data requirements for merging distributors, specifying that if a distributor has prior Board approval for rate harmonization or a commitment to it, separate load profiles and zonal rates are not required in Run 1 or Run 2 of the filing.
3.3 Information Required for Completion of Utility-specific Load Profiles A large group of distributors earlier gathered province-wide load data for the residential and GS>50 kW rate classifications. This load data has been analysed by the...
AI summary The document outlines the process for creating utility-specific load profiles for residential and GS>50 kW rate classifications. It requires distributors to provide specific information, such as appliance saturation surveys or estimates, and specifies that most distributors will use the Hydro One Load Data Team for this task.
3.4.1 Background – Weather Normalization of Load Data In order to make the important load data input more reliable for cost allocation purposes, the Board instructed in its letter of March 7, 2006 that distributors must weather normalize t...
AI summary The Board mandated in 2006 that distributors weather normalize their load profiles to improve reliability for cost allocation, adopting Hydro One's methodology as the standard approach.
3.5.1 Background As indicated, the Board has directed that the load profiles to be employed for the cost allocation demand allocators must be weather normalized using the established Hydro One methodology. That methodology uses average wea...
AI summary The Board has directed the use of a 31-year weather normalization methodology for load profiles in the cost allocation demand allocators. Historic data from the 2006 EDR process used a three-year average, and there is uncertainty about whether the difference in methodologies will be material. Some stakeholders believe the difference may not be significant, while others are concerned about its potential impact.
3.5.2 Directions – Additional Model Output For purpose of sensitivity analysis, the filing model should include an output to show the difference in revenue based on using the approved kWhs from the 2006 EDR model and the normalized kWhs pr...
AI summary The document outlines requirements for sensitivity analysis in a filing model, emphasizing the use of approved kWhs from the 2006 EDR model and normalized kWhs from the filer's load data service provider. It also highlights the need to adjust for losses in billing data and explains how distributors should compare methodologies in their cost allocation filings.
3.6 Load Profile for Separate Load Displacement Generation Rate Classification Two different load data approaches may be modeled for these customers in Run 2 and Run 3, as the Board considers it useful to obtain a broad range of informatio...
AI summary The document discusses two different load data approaches for modeling customers in Run 2 and Run 3, aiming to gather a wide range of information on cost allocation for load displacement generation customers. Stakeholders will be given a future opportunity to comment on these approaches.
3.6.2 Load Profile for Run 3 Distributors may file a Run 3 of the filing in which the load data for the separate LDG rate classification is modeled by an alternative method of adding the actual, or estimated if actual not available, metere...
AI summary The document discusses the method for modeling load data in Run 3 filings, specifically addressing the inclusion of load displacement generation (LDG) and the consideration of diversity among LDG customers. Stakeholders have expressed varying opinions on the availability of data and the need to account for diversity in load displacement generation.
3.7 Load Profile for Separate Unmetered Scattered Load Class Where USL[9](#page-26-0) is to be treated as a separate rate classification in the model (e.g. Run 2), the combined load profile must be calculated as follows: Step 1) Non-Photo-...
AI summary This section outlines the methodology for calculating the load profile for Unmetered Scattered Loads (USL) when treated as a separate rate classification. It specifies that non-photo-sensitive loads use a deemed load profile based on combined load shapes, with flat profiles for most types of non-photo-sensitive unmetered loads.
4.1.1 Background Cost allocation studies are generally performed using data for a one year reference period or "test year". For the purpose of the upcoming filings, the revenue requirement (as defined below) and the data underlying the app...
AI summary Cost allocation studies are based on a one-year reference period, and the 2006 distribution rates will be used for upcoming filings. Adjustments approved by the Board to the 2006 EDR revenue requirement must be reflected in the cost allocation filing.
4.1.3 Direction - Distributors that used a forward test year in the 2006 EDR applications For distributors that had earlier filed using a forward test year (i.e. Hydro One Networks Inc., Hydro Ottawa Limited, and Toronto Hydro-Electric Sys...
AI summary Distributors that used a forward test year in their 2006 EDR applications must use the trial balance from the Board-approved 2006 rates for cost allocation filings. They should not make additional adjustments, and must regroup trial balance accounts if detailed information was not provided. Non-utility operations and non-recurring regulatory accounts should be excluded, as well as adjustments for smart meters.
4.1.4 Direction – Distributor(s) that will not have approved 2006 rates at the time of its cost allocation filing In the case of any distributor that does not have approved 2006 rates at the time of its cost allocation filing, the distribu...
AI summary Distributors without approved 2006 rates must use their 2004 trial balance for cost allocation filings. Adjustments include averaging net fixed assets from 2003 and 2004, applying the 2005 MBRR and PILs, and removing non-utility and non-recurring costs. Revenue is based on current approved rates and 2004 customer and usage data.
5.1 Background As an initial step in a cost allocation study, a distributor should identify any significant distribution facilities that are dedicated exclusively to only one customer rate classification. The costs of such a facility, and...
AI summary The document discusses the principles and criteria for direct allocation of distribution costs to specific customer rate classifications. It emphasizes that direct allocation should only apply when facilities are exclusively used by a single classification and addresses scenarios involving redundancy and backup services. The Board prefers the 100% use test for direct allocation and rejects the use of a 'predominant' (90%) test due to complexity in cost allocation.
5.2 Direction – Direct Allocation Methodology Direct allocation must be applied if, and only if, 100% of the use of a clearly identifiable and significant distribution facility can be tracked directly to a single rate classification. If a...
AI summary The document outlines the conditions and requirements for using the direct allocation methodology in distribution cost allocation. It specifies that direct allocation must be used when 100% of the use of a distribution facility can be traced to a single rate classification and details the supporting documentation required.
6.2.1 Introduction The objective of breaking out accounts into sub-accounts is to better reflect the costs ultimately associated with specific assets according to the role of these assets in the distribution system, i.e., their function. T...
AI summary This section discusses the purpose of breaking out accounts into sub-accounts to better reflect the costs associated with specific assets based on their function in the distribution system. This approach will influence how costs are allocated to different rate classifications. Examples include the division of Account 1835 into sub-accounts based on functions such as bulk, primary, and secondary.
Stakeholder Discussions on Bulk Asset Test The Board believes the most appropriate manner to implement a functional approach towards identifying bulk assets involves a separation of the distribution assets to identify any assets that were...
AI summary The Board discusses the implementation of a functional approach to identify bulk assets, emphasizing the need for a clear definition to ensure consistent cost allocation. The approach focuses on system peak considerations and addresses stakeholder concerns about inconsistent application of the bulk asset test.
6.3.2 Direction - Breakout of Bulk, Primary and Secondary Sub-accounts The bulk, primary and secondary sub-accounts should be broken out to the corresponding rate classifications that use those assets. In particular: - Secondary costs will...
AI summary The text outlines how bulk, primary, and secondary sub-accounts should be allocated to rate classifications based on the use of corresponding assets, with specific rules for cost allocation depending on customer and load percentages.
6.3.3 Direction - Customer Data for Bulk, Primary and Secondary For each rate classification, a distributor will need to provide the number of customers that use the bulk (if any), primary and secondary assets. The customer numbers are not...
AI summary This section outlines the requirements for distributors to report the number of customers connected to bulk, primary, and secondary assets, emphasizing that these numbers include both direct and indirect connections. Examples in Appendix 6.2 are provided to guide the proper entry of these numbers into the filing model.
7.1 Introduction The categorization step, also referred to as "classification", consists of subdividing distribution assets and O& M expenses into the following cost-based groupings: - demand-related, and/or - customer-related. Distributio...
AI summary The categorization step, or classification, involves subdividing distribution assets and operating and maintenance expenses into demand-related and customer-related groupings based on cost causality. Joint costs will be divided into customer and demand-related proportions using generic minimum system results, and allocated to rate classifications using allocators detailed in subsequent chapters.
7.2 Direction – Identification of Accounts For the cost allocation filings, functionalized grouped costs will be ultimately classified into one of the four components: - 100% demand-related - 100% customer-related - joint related (both cus...
AI summary This section outlines the classification of functionalized grouped costs into four categories: 100% demand-related, 100% customer-related, joint related, and pro-rata related. Examples include metering and billing as customer-related, distribution stations as demand-related, and joint costs like poles and transformers. Pro-rata related costs are allocated based on specific methods outlined in Chapter 10.
7.3.1 Background Three principal options for categorizing joint distribution assets and operating expenses were initially identified. Each approach has been approved by various regulators across North America. The minimum system approach i...
AI summary Three principal options for categorizing joint distribution assets and operating expenses were identified. The minimum system approach is preferred for use in filings as the common categorization method, while the basic customer method is used for calculating lower end customer unit costs to assist with future rate design.
Option 2: Minimum System Method The minimum system method assumes that a minimum-size distribution system can be built to serve the minimum load requirements of the customer. The minimum system method involves determining the minimum size...
AI summary The minimum system method assumes a minimum-size distribution system can be built to serve customer load requirements. It classifies costs as either customer-related or demand-related. The method involves determining the minimum size of distribution infrastructure and adjusting for peak load carrying capability to ensure accurate cost allocation.
Option 3: Basic Customer Method This approach categorizes as customer-related costs only those capital and operating expenses that are directly associated with adding another customer. Examples of such costs are the capital and operating c...
AI summary Option 3, the Basic Customer Method, allocates customer-related costs only to those directly tied to adding a new customer, such as meters and service drops. Unlike other methods, it does not consider upstream distribution infrastructure costs. While it will not be approved for cost allocation, it may be useful for providing unit cost information for future reviews of fixed monthly customer charges.
7.3.2 Direction – Use of Minimum System Method and Basic Customer Method in Filings For cost allocation purposes, the minimum system approach will be used as the common categorization method. Generic minimum system results will be set out...
AI summary The document outlines the use of the minimum system method and basic customer method for cost allocation in filings. It specifies that the minimum system approach will be used for calculating revenue to cost ratios and splitting joint costs, with a standard PLCC adjustment. The basic customer method will be used to determine the lower range of unit costs, while the minimum system method will establish the upper range.
7.4.2.4 Direction – Density Thresholds and Measurements for Cost Allocation Filings For purposes of stratifying the generic minimum system results used in the cost allocation filings, 30 customers per kilometre will be the dividing line be...
AI summary This section outlines guidelines for determining density thresholds and measurement methodologies for cost allocation filings, specifying customer per kilometre thresholds and defining line length and customer count criteria. It also allows for alternative density classifications with appropriate justification and documentation.
7.5.1 Background – PLCC Adjustment The minimum distribution system will carry a small amount of demand. The actual amount of demand capability within the minimum system is a function of load density, minimum required clearances, minimum eq...
AI summary The PLCC adjustment aims to correct over-allocation of demand costs by crediting the minimum system's capacity against non-coincident peak demands. The Board approved a generic 0.4 kW adjustment per customer/connection, rejecting stakeholder suggestions for larger adjustments or zero thresholds, as they contradict the principle of equal cost allocation for the minimum distribution system.
Cost Allocation Adjustment The PLCC in kW per customer or per connection should be multiplied by each rate classification's number of customers or connections. For the purposes of the PLCC adjustment, the model will first consider if there...
AI summary The document outlines a method for adjusting the PLCC (Peak Load Carrying Capability) to allocate a distributor's capital and O&M costs based on the number of customers or connections in each rate classification. It specifies that this adjustment does not apply to bulk delivery facilities, and explains how the demand capacity is calculated and subtracted from non-coincident peak values.
Customer Unit Cost Adjustment Another output of the filing model is customer and demand unit costs by rate classification. These unit costs can be used to help set future distribution rates; however, to reflect the results of the PLCC adju...
AI summary The filing model produces customer and demand unit costs by rate classification, which can be used to set future distribution rates. To reflect the PLCC adjustment, customer-related costs should be moved into demand-related costs before rate determination, though the total cost allocated to the rate classification remains unchanged.
7.5.3 Filing Question If any distributor suspects its generic minimum system result and/or the generic PLCC adjustment has contributed to an anomalous filing result for a rate classification, an explanation should be included in the Filing...
AI summary The text states that if a distributor suspects that the generic minimum system result or the generic PLCC adjustment has caused an anomalous filing result for a rate classification, an explanation should be included in the Filing Summary.
7.6.2 Direction – Use of Distributor-Specific Minimum System Study While use of the generic minimum system results is encouraged for these filings, if a distributor does undertake a new minimum system study before its filing date, then the...
AI summary This section outlines the conditions under which a distributor may use its own minimum system study in filings, including requirements for disclosure in the Filing Summary. It also specifies the information that must be provided when using a distributor-specific study, such as methodology, system definitions, and PLCC adjustments.
8.2.1 Introduction Some version of NCP is generally used in Canada to allocate most demandrelated distribution costs. The reasons include: - In most cases, distribution assets are sized to meet the maximum demand for a group of customers a...
AI summary The text explains why Non-Coincident Peak (NCP) is commonly used in Canada to allocate demand-related distribution costs. It notes that distribution assets are sized based on maximum demand for customer groups, not system coincident peaks, and that NCP provides a fairer allocation of costs to rate classifications that use the assets, even if they are not consuming much electricity during system peaks.
8.2.2.1 Background There are various specific forms of a NCP allocator and stakeholder discussions focused on the merits of the following: - 1 NCP This option involves the use of highest monthly non-coincident demand peak. - 4 NCP This opt...
AI summary The document outlines different methods for allocating NCP (Non-Coincident Peak) based on the highest monthly non-coincident demand peak, the average of the four highest monthly non-coincident demand peaks, and the average of the 12 monthly non-coincident demand peaks.
1 NCP 1 NCP is the most common version of NCP used in other jurisdictions. It is a widely-held view amongst stakeholders that the demand capacity of a distribution system is generally designed to handle the greatest single peak whenever th...
AI summary The document discusses the use of 1 NCP (Non-Coincident Peak) in cost allocation, noting that while it is widely used, stakeholders have raised concerns about its reliability due to limited load data. The Board concludes that 1 NCP should be used only when a pronounced peak is confirmed. A suggestion to collect multiple years of load data is noted for future consideration.
4 NCP A criterion accepted in prior Ontario cost allocation analyses is the importance of choosing a stable cost allocation methodology. 4 NCP will function as a more stable methodology than 1 NCP and so has an important practical advantag...
AI summary The document discusses the use of 4 NCP as a more stable cost allocation methodology compared to 1 NCP and 12 NCP, emphasizing its importance in ensuring accurate cost causality and reliability, particularly in Ontario's distribution systems.
12 NCP It is understood that 12 NCP was the demand allocator used when historic bundled rates were set under the former regulator. The technical case for use of 12 NCP was clearer in the past when generation costs were part of the bundled...
AI summary The document discusses the use of 12 NCP (Non-Coincident Peak) as a demand allocator in the context of historic bundled rates and its current inapplicability in unbundled environments. Stakeholders expressed concerns about the impact on weather-sensitive customers if 1 NCP were used instead. The Board emphasizes the need for a sound cost allocation methodology and suggests using a combination of 1 NCP and 4 NCP for better cost causality.
8.2.2.2 Direction - Tests for Use of NCP in Filings NCP will be the demand allocator used when allocating assets identified by a distributor as primary or secondary assets. 4 NCP will be the starting point for the common demand allocator t...
AI summary The document outlines the use of Non-Coincident Peak (NCP) as a demand allocator for cost allocation filings, specifying that 1 NCP is used when a pronounced peak exists, confirmed by a test where the highest month exceeds 20% of the average of the highest four months. The NCP test formula is provided, with thresholds for using 1 NCP or 4 NCP, and 12 NCP may be used in optional Run 3 with justification.
8.3.2 Direction - Tests for Use of CP in Filings For distribution assets and related O&M accounts that are solely designed to meet the distributor's system demand, CP will be used as the demand allocator. For the filings, this will consist...
AI summary This section outlines the use of Coincident Peak (CP) as a demand allocator for distribution assets and related O&M accounts designed to meet system demand. It specifies that CP will be subdivided into transmission transformation CP (TCP) and distribution CP (DCP), and describes how the choice between 1 CP, 4 CP, or 12 CP will be determined through a test incorporated into the filing model.
CP Test #1 This test calculates the average of the twelve monthly system peaks as a percentage of the highest monthly system peak as follows: CP Test #1 = Average of 12 Monthly System Peaks ÷ Annual System Peak. A CP Test #1 result of 83 p...
AI summary CP Test #1 calculates the average of twelve monthly system peaks as a percentage of the annual system peak. A result of 83% or higher requires the use of the 12 CP method for allocating demand costs, while lower results necessitate conducting CP Test #2.
CP Test #2 This test calculates the average of the four highest monthly peaks as a percentage of the greatest monthly peak as follows: CP Test #2 = Average of the 4 highest Monthly System Peaks ÷ Annual System Peak. A CP Test #2 result of...
AI summary CP Test #2 calculates the average of the four highest monthly peaks as a percentage of the annual system peak. If the result is 83% or higher, the 4 CP method is used for demand cost allocation; otherwise, the 1 CP method is applied.
8.4.1 Background Using a one hour (i.e. clock hour) measurement of peak is the most common approach when determining the demand allocator for electricity sector cost allocation studies. A few jurisdictions (for example, Manitoba) use a lon...
AI summary The document discusses the use of a one-hour measurement period for determining peak demand in electricity sector cost allocation studies, noting that this approach, combined with the 4 NCP/1 NCP test, provides an appropriate balance of policy objectives. Some jurisdictions, like Manitoba, use longer periods.
8.4.2 Direction – Measurement of Hourly Peak for NCP and CP For cost allocation purposes, the definition of peak for NCP or CP will be the standard one hour (clock hour) measurement of the peak hour. The use of a rolling 15 minute window f...
AI summary The document specifies that for cost allocation, the peak for NCP and CP will be measured using a standard one-hour clock hour, and the use of a rolling 15-minute window for measuring peak is prohibited.
8.5.1 Background When customers with differing consumption patterns are pooled into a customer classification, this results in the sharing of the benefits of the diversity of their consumption patterns. These benefits arise because the cla...
AI summary This section discusses two approaches to sharing the benefits of diversity in customer classifications for cost allocation. Approach i) is preferred for its simplicity and alignment with North American practices, while approach ii) was suggested by some stakeholders but found to be less practical. The treatment of Unmetered Scattered Loads and Load Displacement Generation also has implications for diversity benefits and is addressed in Chapter 11.
8.5.2 Direction – Separate Treatment of Each Rate Class and Subclass For Cost Allocation Purposes Each "rate classification" (i.e. class or subclass) will be treated as independent and separate for cost allocation modeling and load data re...
AI summary The document outlines a directive for the separate treatment of each rate class and subclass in cost allocation modeling. Diversity is shared within rate classifications but not between them, except for certain charges linked to main classifications. This approach is for cost allocation only and does not affect future rate design discussions.
8.6.3 Filing Questions A distributor must provide the following information for future reference as part of its Filing Summary: - 1. Provide an estimation of "non-technical" energy losses (e.g. theft of power, billing accruals, metering pr...
AI summary The distributor is required to estimate and report both non-technical and technical energy losses as a percentage of energy purchased, with technical losses further broken down by system components such as >50 kV, bulk, primary, and secondary assets, using definitions from cost allocations filings.
9.1 Introduction Customer-related costs are commonly allocated by using the number of customers by rate classification, or by using weighted customer allocation factors. The weightings of customer allocation factors are typically developed...
AI summary Customer-related costs are allocated using rate classifications and weighted allocation factors that consider investment costs, service complexity, and customer density. These factors vary by asset type and O&M expenses to reflect specific cost characteristics, such as meter reading frequency and customer distribution.
9.3.1.1 Background A common allocator used to allocate customer-related costs that are related to billing activities is the number of bills issued. The major accounts allocated on this basis are billing, collecting and associated supervisi...
AI summary The document discusses the allocation of customer-related costs based on the number of bills issued, including billing, collection, and customer care costs. Some parties suggested applying weighting factors to account for differences in costs across customer classifications, which the Board agreed to. Flexibility is provided for handling rate classifications not covered in the survey and for using utility-specific factors.
9.3.2.2 Direction – Allocation of Meter Capital Costs Default installed meter capital costs will be provided for use when allocating meter capital costs. These are listed in Appendix 9.2. A distributor will enter the estimated number of in...
AI summary The document outlines a method for allocating meter capital costs across different rate classifications. It specifies the use of default costs, the inclusion of utility-installed meters, and the calculation of allocation percentages. Flexibility is provided for entering additional meter types if they differ significantly in cost from defaults, and small distributors may need to provide specific information if their costs differ materially.
9.3.3 Meter Reading Costs 9.3.3.1 Background At present, the meters for most Residential and General Service < 50 kW customers are read manually. The frequency of meter readings may vary by rate classification and by distributor. It is the...
AI summary The document discusses the allocation of meter reading costs, noting that manual readings are more expensive for customers spread out, while electronic readings for larger users are less costly. A weighted factor approach is used to allocate these costs fairly across rate classifications.
9.3.3.2 Direction – Allocation of Meter Reading Costs Default "relationship factors" related to meter reading costs are provided for use when allocating meter reading costs. Details are set out in Appendix 9.3. The cost to read a residenti...
AI summary The document outlines a method for allocating meter reading costs using relationship factors based on a residential urban outside meter as a base. Distributors must input data on installed meters and apply relationship factors to determine relative costs for each rate classification. Flexibility is allowed for up to five additional meter types if their reading costs differ by at least 10% from defaults.
9.3.4.1 Background The installed costs of overhead and underground service drops are included in Account 1855. These costs are customer related and it is appropriate to allocate the costs associated with these services (e.g. depreciation,...
AI summary The document discusses the allocation of costs for overhead and underground service drops, which are included in Account 1855. These costs are customer-related and should be allocated based on the weighted number of customers or connections, with some stakeholders noting that certain rate classifications may have zero costs due to distributor demarcation policies.
9.3.4.2 Direction - Allocation of Services Costs The weighted number of customers or connections will be used to allocate costs related to Services (Account 1855). It is intended that the weightings reflect the differing average costs of c...
AI summary The weighted number of customers or connections is used to allocate costs related to Services (Account 1855), with default weighting factors provided in Appendix 9.4. Distributors must use specific weighting factors if their actual costs differ by 10% or more from defaults and provide supporting information. The Filing Summary must indicate if there are no costs in Account 1855 and explain the reason.
10.2.2 Direction – Allocation of General Plant General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets (average of opening and closing balances for the test year), with no adjustment for con...
AI summary General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets, with no adjustment for contributed capital. Distributors with detailed analysis must use this information in cost allocation models and provide supporting documentation.
10.3.2 Direction – Allocation of A & G Except for property insurance and community safety program costs, a pro rata allocation of O&M with backing out of A&G will be the common methodology for allocating general expenses. For property insu...
AI summary The document outlines a pro rata allocation methodology for general expenses, excluding property insurance and community safety programs, which are allocated based on distribution net fixed assets. Contributed capital is handled separately as outlined in Chapter 6.
10.5.2 Direction – Allocation of PILs, Other Taxes, Cost of Debt, and Return on Equity A pro rata allocation of next fixed assets will be used to allocate PILs, Other Taxes, Cost of Debt, and Return on Equity.
AI summary A pro rata allocation method will be used to distribute PILs, Other Taxes, Cost of Debt, and Return on Equity among next fixed assets.
10.6.1 Background Bad debt expense consists of the amounts of uncollectible revenues. Many distributors monitor their bad debt write-offs at the rate classification level. The Accounting Procedures Handbook (Article 220) requires distribut...
AI summary The document discusses the allocation of bad debt expenses to customer rate classifications, recommending a method based on historical write-offs. It notes lack of stakeholder consensus and addresses concerns about normalization periods and fairness. The Board supports the staff's recommendation for cost allocation purposes.
10.6.2 Direction – Allocation of Bad Debt Expense Bad debt expense must be directly allocated to specific customer rate classifications based on their respective contribution to historical write-offs. For historical test year filers, an av...
AI summary The document outlines the allocation of bad debt expense to specific customer rate classifications based on historical write-offs. It specifies the use of average bad debt data from 2002–2004 for historical test year filers and 2003–2005 for future test year filers, excluding extraordinary bad debt. Pro rata allocation is recommended for new rate classifications without historical data.
10.7.1 Background Late payment charges (Account #4225) include the amounts of discounts forfeited or additional charges imposed because of the failure of customers to pay their electricity bills on or before a specified date. Collection ex...
AI summary Late payment charges and collection expenses are discussed in terms of their allocation based on rate classifications. A stakeholder suggested a common approach for both costs, but further data is needed. The allocator for collection expenses is the weighted number of bills, except for embedded distributors. Late payment charges should be allocated based on the three-year average of revenues by rate classification.
10.7.3 Filing Question To determine whether a similar cost allocation treatment of collection expenses and late payment charge revenues is feasible in the future, distributors should indicate whether the records are available to break out...
AI summary The proceeding discusses whether a similar cost allocation treatment of collection expenses and late payment charge revenues is feasible in the future, requiring distributors to indicate if records are available to break out collection costs by rate classification.
nces may exist between the electricity and gas distribution sectors, as a practical matter the Board concludes that the electricity sector status quo should be maintained for cost allocation purposes. In this regard, note that the 2006 Ele...
AI summary The document discusses the allocation of CDM operating expenses between rate classes, referencing the 2006 EDR Report and Handbook. It emphasizes direct allocation for identifiable O&M activities and aligns with the methodology used in the 2006 EDR model for distribution and administrative costs.
11. Cost Allocation and Unit Cost Calculations for Specialized Rate Classifications Directions on cost allocation and unit cost calculations for the following specialized rate classifications are presented in this Chapter. - Embedded distr...
AI summary This section outlines the directions for cost allocation and unit cost calculations for specialized rate classifications, including embedded distributor, density, seasonal, unmetered scattered loads, and load displacement generation.
11.1.1 Background Various approaches were used in the past to allocate costs to this rate classification. It is also understood that the rate structure has varied. The present filings will introduce a common cost allocation methodology and...
AI summary The document discusses past approaches to cost allocation for a rate classification and introduces a new common cost allocation methodology and customer unit cost calculation. It outlines the application of this methodology in Run 1 and Run 2, and notes that the Board will later decide on implementing a new common rate classification for embedded distributors.
11.1.2 Direction – Cost Allocation and Unit Cost Methodology for Embedded Distributor Classification The cost allocation methodology approved elsewhere in this Report must be applied when allocating costs to this rate classification. The s...
AI summary The text outlines the cost allocation methodology for embedded distributor classifications, requiring the use of a two-part customer unit cost calculation. It emphasizes proper account sub-division and references Chapter 6 for subfunctionalization methods. Alternative methodologies are permitted in Run 3 but must be justified and consistent with sound cost allocation practices.
11.2.1 Background It should be recognized that the average density for some currently-approved rate classifications varies significantly. In some cases, "urban" customers have been defined based on an average customer density higher than 6...
AI summary The document discusses the impact of customer density on cost allocation for rate classifications, noting that urban and suburban classifications have different customer densities. It outlines that density is a direct cost driver but may not be linear, and provides guidelines for cost allocation for distributors with approved density-based rate classifications.
11.2.2 Direction – Cost Allocation Methodology for Density- Based Classifications A distributor with density-based rate classifications is expected to be able to use the standard model in Run 1 and Run 2, but work must be undertaken to add...
AI summary The document outlines a standardized cost allocation methodology for distributors with density-based rate classifications. It requires the use of a single categorization factor, identification of density-influenced costs, and the application of density factors in cost allocation, with detailed analysis required for maintaining classifications.
11.2.3 Filing Question If a distributor intends to maintain its density-based rates, it must provide a rationale for the density threshold used for that rate classification.
AI summary The distributor must justify the density threshold used for maintaining density-based rates.
11.3.1 Background The standard cost allocation methodology will apply to any seasonal rate classification as no unique cost allocation issues were identified. There are few distributors with such separate rates currently in place. Adding a...
AI summary The document outlines the standard cost allocation methodology for seasonal rate classifications, noting that no unique cost allocation issues were identified. It emphasizes the need for full supporting data when considering changes to seasonal rates and highlights potential rate impacts from using a single NCP for demand-related cost allocation.
11.3.2 Direction – Cost Allocation Methodology for Seasonal Rate Classification[2](#page-89-1)3 Run 1 and Run 2 of the model must apply the cost allocation and customer unit cost methodology approved in this Report. Distributors wishing to...
AI summary The document outlines the cost allocation methodology for seasonal rate classification, requiring distributors to apply approved methods in Run 1 and Run 2 of the model. Run 3 requires justification for using 12 NCP based on the distribution system's cost characteristics.
11.4 Unmetered Scattered Loads ("USL") In the past, there had been variability in the treatment of unmetered scattered loads across the Province. The present filings are intended to lead to a common cost allocation approach for these custo...
AI summary The document discusses the need for a consistent cost allocation approach for unmetered scattered loads (USL) across the Province, with the same methodology applying to the Farm Rate classification.
11.4.1.1 Background The Technical Advisory Team examined this topic in detail. Set out below is the common methodology approved for use by all distributors when modeling USL as a fully separate rate classification (e.g. Run 2). The same ap...
AI summary The Technical Advisory Team has approved a common methodology for modeling USL as a fully separate rate classification, applicable to all distributors in Run 2 and to a select few in Run 1. This approach is not applicable to distributors whose 2006 USL rates were set using a special methodology from the 2006 EDR consultations.
11.4.1.2 Direction – Cost Allocation Methodology where Separate USL Rate Classification The cost allocation methodology approved in this Report for all rate classifications must also be applied to this rate classification, subject to any s...
AI summary This section outlines the cost allocation methodology approved in the report, which must be applied to all rate classifications, including this specific rate classification, with any special rules provided below.
11.4.2.1 Background The approach below is expected to apply to most distributors in Run 1, including all those whose 2006 USL charges were effectively based on the special rate calculation reached during the 2006 EDR process.[24](#page-91-...
AI summary The text outlines an approach for modeling USL rates for distributors in Run 1, noting that demand costs will be treated as related to the GS<50 kW rate classification. It also discusses the potential implementation of a metering credit and the need to collect revenue from other customers to maintain the distributor's revenue requirement.
11.4.2.2 Direction – Unit Cost for USL Metering Credit The following methodology must be used to determine the metering credit for USL customers in Run 1. The first step is to identify the following items in the cost allocation model. - a)...
AI summary This section outlines the methodology for calculating the metering credit for USL customers in Run 1, specifying the cost allocation model items to consider. It also notes that billing costs will not be included in the filing requirements as they are already reflected in the standard classification.
11.4.3.1 Background Run 2 of the filings will provide the Board with information on costs for USL as a separate rate classification. Once costs have been allocated to this potential rate classification, the question remains whether it is p...
AI summary Run 2 of the filings provides the Board with information on costs for USL as a separate rate classification. The filings will produce standard customer unit cost outputs for this classification, raising the question of whether unit costs should be determined on a per customer or per connection basis.
11.4.3.2 Direction – Modeling Unit Costs Where USL a Separate Rate Classification The cost allocation filing model will calculate a standard two-part unit cost output for USL.
AI summary The cost allocation filing model is designed to calculate a standard two-part unit cost output specifically for USL, treating it as a separate rate classification.
1. Customer-Related Unit Cost – Number of Connections The customer-related costs allocated to the USL classification will be divided by the number of connections to determine the customer-related unit cost.
AI summary This section outlines the calculation of customer-related unit cost by dividing the allocated customer-related costs for the USL classification by the number of connections.
2. Demand-Related Unit Cost – kWh The demand-related cost allocated to the USL classification will be divided by the kWh associated with the USL classification to determine the demandrelated unit cost. One stakeholder suggested that demand...
AI summary The document discusses the method for determining demand-related unit cost for USL customers, with stakeholders debating whether to use kWh or kW as the basis. It notes that kWh is the current basis for GS<50kW classification and will be used for USL as well.
11.5.1 Introduction At present, a number of distributors have approved interim standby rates. In some cases, there is an additional approved administrative charge. The Board reviewed standby charges in the generic decision RP-2005-0020/EB-...
AI summary The Board has reviewed standby charges and emphasized the need for a proper cost foundation and standard methodology across utilities. Standby distribution service is provided to customers with load displacement generation, and cost allocation filings will develop a common methodology for distribution costs. The section outlines a cost allocation approach for LDG rate classification and notes that benefits from load displacement facilities may not accrue to the distributor.
11.5.2.1 Background The LDG rate classification to be modeled refers to charges imposed by a distributor for distribution services provided to a customer with load displacement generation behind the customer's meter. The load displacement...
AI summary This section discusses the LDG rate classification, which applies to customers with load displacement generation behind their meter. The classification involves allocating distribution costs for both base load and incremental load when the generator is not operating. The section also mentions concerns about load data availability and reliability for these customers.
11.5.3.1 Background From a distribution system perspective, LDG service includes a commitment by the distributor to have sufficient conductor and transformation capacity available to meet the load displacement customer's total load require...
AI summary The document outlines the background and methodology for determining distribution rates for LDG (Load Displacement Generation) customers. It emphasizes using cost-based rate information from similar customers and highlights the need to consider additional savings or costs through separate charges or credits. Stakeholders are advised to provide best-efforts estimates and note concerns about data reliability.
Filing Step 1) Initial Customer Unit Costs to be Calculated by Model The cost allocation model will calculate a range of customer unit costs ($/customer/month) and a demand unit cost ($/kW/month) for all rate classifications. These same un...
AI summary The filing step outlines a model to calculate customer unit costs and demand unit costs for rate classifications, which will be used to determine initial distribution rates for LDG customers under a main rate classification. An example is provided to illustrate the calculation process.
Filing Step 2) Identify Items for Inclusion in Additional LDG Credit or Charge Unit Cost Calculation Further adjustments to the above initial unit costs must be considered by a distributor. The intent is to capture any unique distribution...
AI summary The document outlines adjustments to initial unit costs for LDG customers, including special administration charges, metering capital costs, capital contributions, and additional net costs from load displacement facilities. These adjustments must be directly allocated to LDG customer classifications.
Filing Step 3 - Calculation of LDG-specific Unit Costs The filing model cannot undertake the LDG credit or charge calculation itself. However, filing instructions on how to undertake the calculation will be 26 If little additional data is...
AI summary The document outlines the process for calculating LDG-specific unit costs, noting that the filing model cannot perform the calculation itself. Instructions are provided for undertaking the calculation, which could help in designing a LDG credit or charge if LDG customers are to be treated within a main rate classification.
Future Rate Design Steps The LDG-specific unit costs calculate above will be one of the items of information to be available and considered when designing and implementing new LDG rates. The unit costs calculated here should not be interpr...
AI summary The document discusses future rate design steps for LDG customers, emphasizing that LDG-specific unit costs will inform new rate design. It clarifies that these costs are not proxies for standby distribution rates and mentions a forthcoming Distribution Rate Design Review to examine various rate options.
11.5.4.2 Direction – LDG Rate Classification Threshold For the purpose of modeling the costs to be allocated to the separate LDG rate classification in Run 2, a customer will not be considered to be part of that separate rate classificatio...
AI summary This section outlines the criteria for classifying customers under the LDG rate classification, specifying that a customer must have standby distribution service requirements greater than 500 kW. It also provides steps for separating costs and revenues associated with LDG customers and guidelines for estimating standby requirements when detailed information is not available.
11.5.5.1 Background For Run 2 of the model, all distributors serving LDG customers with standby distribution service requirements above the 500 kW threshold should group these customers into a separate LDG rate classification and provide f...
AI summary This section outlines the methodology for grouping LDG customers with standby distribution service requirements above 500 kW into a separate rate classification for Run 2 of the model, requiring full supporting data. It also mentions that if suitable load data is unavailable, the first LDG cost allocation methodology should be used, and an explanation should be provided in the Filing Summary.
11.5.5.2 Direction – Cost Allocation Methodology Where LDG Rates Modeled as Separate Rate Classification The same cost allocation methodology approved for use with other rate classifications must be applied to this classification (for exam...
AI summary The cost allocation methodology approved for other rate classifications must also be applied to LDG customers. The default load data method is required for Run 2, with an alternative available for Run 3. Distributors must document estimates and address diversity issues. A two-part distribution charge will be generated for all rate classifications, including LDG.
11.5.5.3 Direction – Number of New LDG Rate Classifications Run 2 To better reflect cost causality, it was originally suggested that separate LDG rate classifications will be required, where relevant, for GS>50 kW, Intermediate and Large U...
AI summary The document discusses the direction for the number of new LDG rate classifications in Run 2, suggesting a single classification for better load data reliability. Distributors are required to report customer numbers by previous rate classifications in their Filing Summary. Some distributors may prefer multiple LDG rates in an optional Run 3, but load data reliability must be addressed.
11.5.6.2 Direction – Where LDG Customers Not Separate Classification In most cases, Run 1 will have the customers with load displacement in a standard rate classification and the diversity of the total standard rate classification will be...
AI summary In most cases, Run 1 will include LDG customers in a standard rate classification, with the diversity of the classification reflected in unit costs. Combined diversity benefits from LDG and other customers will be reflected in initial unit costs, while unique LDG customer costs should be identified for additional credit or charge calculations.
11.5.6.3 Direction – Where LDG Customers Separate Classification In Run 2, the customers with load displacement will be assigned to a separate rate classification and only the diversity benefits associated with the customers using LDG serv...
AI summary In Run 2, customers using Load Displacement Generation (LDG) will be assigned to a separate rate classification, and only the diversity benefits from these customers will be reflected in the classification's unit costs.
11.5.7 Future LDG Customer Rate Design Issues surrounding the design and implementation of new rates for load displacement customers (including the merits and design of charges for standby distribution service) will be further addressed in...
AI summary The document outlines the upcoming Distribution Rate Design Review to address issues related to future LDG customer rate design, including standby distribution service charges. It highlights the need for stakeholder input and the importance of analyzing cost allocation model runs to inform future rate decisions.
11.5.8.2 Direction - Optional Modeling In Run 3, an interested distributor has the option of modeling appropriate unit costs for merchant generation in place in the 2006 EDR test year. This will be required for a specific distributor under...
AI summary In Run 3, a distributor may model unit costs for merchant generation in the 2006 EDR test year, as required by a prior Board decision. The Filing Summary must explain the approach, supporting data, and any cost allocation methods used that differ from the current Report.
11.5.9 Hybrid Facilities There is also the situation where a generator is providing load displacement generation but also has significant generation above the customer's load. In this case the generator is performing a "hybrid" role of loa...
AI summary The document discusses hybrid facilities where generators provide both load displacement and merchant generation. It notes that distribution rates for these facilities are not further addressed but suggests that appropriate unit costs for such facilities in the 2006 test year can be modeled using optional Run 3 of the model. Distributors are advised to document their approach and any cost allocation methods used.
11.6 Other Specialized Rate Classifications Various utility-specific rate classifications exist (such as a small commercial rate or a water sewage facility rate).The affected distributor should apply the approved cost allocation methodolog...
AI summary This section discusses specialized rate classifications used by utilities, emphasizing the need for consistent cost allocation methodologies and proper justification for any changes or eliminations of such classifications. Distributors must explain and model the effects of changes in their Filing Summary.
12. Unit Cost Outputs The cost allocation filings will gather customer unit cost information to assist with future discussions on the following rate design areas: - a) Review of the range of monthly customer service charges. - b) Review of...
AI summary This section outlines how cost allocation filings will gather customer unit cost information to support future discussions on rate design areas, including monthly customer service charges and transformer ownership allowance alternatives.
12.1.1 Introduction The OEB's letter of June 24, 2005 advised that "the cost allocation filings will also contain updated information that is helpful to assess the cost basis of current monthly service charges". The filings will achieve th...
AI summary The OEB's letter highlighted the need for updated cost allocation filings to assess monthly service charges. The project aimed to identify distribution system cost drivers, while considering various rate design factors, including non-cost considerations. The review assumes continuation of a two-part distribution rate structure, but data collected may be relevant to those interested in a one-part structure.
12.1.2.1 Background Three versions of the Basic Customer Method were reviewed for use to calculate the lower end of the customer unit costs.
AI summary Three versions of the Basic Customer Method were reviewed for use in calculating the lower end of customer unit costs.
Option 1: Avoided Costs With a strict "avoided cost" approach, only meter related costs, billing and collection costs would be included. This approach has the advantage of focusing on the immediate costs of an additional customer. But no a...
AI summary Option 1, the 'avoided cost' approach, includes only meter, billing, and collection costs, focusing on immediate customer costs but excluding administrative overhead. A stakeholder suggested using this approach to strengthen conservation price signals, while the Board emphasizes that the filings aim to provide comprehensive information for future rate design decisions.
Option 2: Directly Related Customer Costs In this approach, additional costs viewed as directly related to the customer would be included, namely operations performed at the customers' premises. An example would be a disconnect and a recon...
AI summary Option 2 includes directly related customer costs such as disconnect and reconnect operations, with revenue from related services credited back to cost centres. Administration and general overhead are also allocated. This approach is commonly used and will be incorporated into the filing model.
12.1.2.2 Direction – Calculation of Lower and Upper End Customer Unit Costs in Filings Both Option 1 (avoided costs) and Option 2 (directly related customer costs) should be calculated in the filings to provide a broad range of information...
AI summary The document provides direction on calculating both lower and upper end customer unit costs in filings. Option 1 includes avoided costs, while Option 2 includes directly related customer costs. Appendix 12.1 outlines specific costs, and the filing model will incorporate these calculations. The upper end unit cost is determined using stratified minimum system results and adjusted for PLCC.
12.1.2.3 Smart Meter Adder The above lower and upper end customer unit costs must both be adjusted to include the smart meter adder, to be consistent with the monthly fixed charges approved in the 2006 rate orders. A distributor will enter...
AI summary The text discusses the inclusion of a smart meter adder in cost calculations, aligning with the monthly fixed charges approved in the 2006 rate orders. Distributors are instructed to apply the adder in the cost allocation model by rate classification, typically found in a specific location within the approved 2006 EDR model.
12.2.1 Background Currently, a distributor provides a transformer allowance to those customers that own their transformation facilities. With a few exceptions, the present level of transformer ownership allowance is $0.60 per kW. The amoun...
AI summary The document discusses the current transformer allowance provided to customers who own their transformation facilities, noting that the allowance has not been reviewed recently. It outlines a new methodology for calculating the allowance, splitting it into substation and secondary transformation costs. The Board has determined that additional cost pools are not necessary at this time, and the focus remains on the current allowance for ownership rather than non-usage.
12.2.2.1 Direction – Substation Transformation Ownership Allowance Unit Cost Output The following costs will be included in the new substation transformation ownership allowance unit cost calculation produced by the filing model. - a) Depr...
AI summary The document outlines the costs to be included in calculating the new substation transformation ownership allowance unit cost. These include depreciation, operation, maintenance, and allocated expenses, among others, which will be divided by appropriate kWs, kVa, and/or kWhs for customers using distributor-owned substation transformation assets.
12.2.2.2 Direction – Secondary Transformation Ownership Allowance Unit Cost Output The following costs will be included in the new secondary transformation ownership allowance unit cost calculation produced by the filing model. - a) Deprec...
AI summary The document outlines the components included in the new secondary transformation ownership allowance unit cost calculation. It specifies various expenses and allocations related to distribution transformers and how the unit cost will be determined based on rate classifications and customer usage metrics.
12.2.2.3 Direction - Primary and Secondary Conductors and Poles Cost Pools Calculation Appendix 12.2 sets out the additional information on primary and secondary conductors and poles cost pools to be gathered by the filing model for potent...
AI summary Appendix 12.2 outlines additional information on primary and secondary conductors and poles cost pools for future reference. Further discussions on rate classification and rate design policy are needed before determining how this information may be used.
- Newbury Power Inc. Rate Classification - Residential Data Requirements 1. Residential Class – accounts for individually metered residential sites taking electricity at < 750 volts (also includes HONI urban class). Generic load data/(LDC...
AI summary The text outlines various residential and general service rate classifications along with their corresponding data requirements, including load data, appliance surveys, and consumption data for different categories of customers.
NB: To use 2006 EDR data when assessing rate classification changes Rate Classification Data Requirements 3a. GS >50 kW – TOU Classification to be eliminated Rename as "Intermediate" if it meets legacy test for intermediate (customer load...
AI summary The document outlines proposed changes to rate classifications, including the elimination of certain classifications and the use of specific data requirements. It discusses the renaming and consolidation of classifications, the use of interval data, and the modeling of unmetered loads. The 2006 EDR data is referenced for assessing these changes.
N-91-(v)N-91-(v).pdf
62 passages
AVAILABILITY This tariff is applicable to electric energy used by any customer in a private residence for the customer's own domestic or household use, including lighting, cooking, heating, or refrigeration purposes. Upon application to th...
AI summary The Domestic tariff applies to electric energy used in private residences for domestic purposes. It may also apply to outbuildings on residential property if used for personal pursuits. Commercial use of such buildings requires application of General or Industrial tariffs. The tariff is governed by Section 73 of the Public Utilities Act.
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 customers to shift their energy usage from peak to off-peak periods and is available to those eligible under the Domestic Service Tariff.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-2-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Starting December 1, 2025, the Interim Energy Charge applies during all hours in both winter and non-winter periods, aligning with standard offer rates. Critical Peak Events are suspended during this period, and NS Power must notify TVP customers when system functionality is restored, with specific rate changes depending on the restoration date.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event Non-critical Peak Hours Effective upon the date of the Board's Order n/a 18.324 1 M12499 – Board Decision, 325286, page 5. October 28, 2025.
AI summary The document outlines an interim energy charge structure, specifying a rate of 18.324 cents per kilowatt-hour for non-critical peak hours, with no charge during critical peak events. This rate is effective from the date of the Board's Order, as detailed in Board Decision M12499.
ENERGY CHARGE cents per kilowatt-hour During a Critical Peak Event Non-critical Peak Hours Effective November 1, 2026 182.067 15.411 Effective January 1, 2027 191.990 15.956 The Critical Peak Event is of a four-hour duration and can be cal...
AI summary The document outlines the Energy Charge rates for Critical Peak Events and Non-critical Peak Hours, effective from November 1, 2026, and January 1, 2027, with specific rates provided in cents per kilowatt-hour. A Critical Peak Event is defined as a four-hour duration that can occur between 6:00 AM and 11:00 PM during the Winter Period.
The Critical Peak Event pricing applies when a Critical Peak Event is called. In all other hours in the Winter Period, and for all hours in the Non-Winter Period, the rate shall be the Non-critical Peak Hours rate in the table above.
AI summary The text outlines the application of Critical Peak Event pricing, which is only active during Critical Peak Events, while other periods use the Non-critical Peak Hours rate.
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 when and how Critical Peak Events are scheduled during the Winter Period, excluding certain holidays and weekends, and requires customers to be notified in advance of these events, during which a higher energy charge applies.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-6-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Effective November 1, 2025, the Nova Scotia Energy Board's decision on NS Power's Time-varying Pricing (TVP) Tariffs (M12499) introduces an Interim Energy Charge during periods of system unavailability. NS Power must notify TVP customers when functionality is restored and transition back to standard rates under specific conditions.
Rate Codes 05, 06
AI summary The text references Rate Codes 05 and 06, which are likely classifications or categories used in the regulatory process for utility rate structures or billing procedures.
This tariff is only available to customers employing electric-based heating systems utilizing Electric Thermal Storage (ETS) equipment, and electric in-floor radiant heating systems utilizing thermal storage, and appropriate timing and con...
AI summary The tariff applies to residential customers using specific electric heating systems and outlines conditions for domestic and outbuilding usage. It references the Public Utilities Act and specifies different tariff applications based on building use.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-14-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Effective December 1, 2025, the Nova Scotia Energy Board approved changes to NS Power's Time-varying Pricing (TVP) Tariffs, including the implementation of an Interim Energy Charge during system outages and the restoration of Critical Peak Pricing (CPP) rates once functionality is restored, with specific timelines and grace periods outlined.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event For the first 200 kilowatt-hours per month For all additional kilowatt-hours Effective upon the date of the Board's Order n/a 18.919 17.112 1 M12499 – Board Decisio...
AI summary The document outlines the interim energy charge rates during a Critical Peak Event, with different rates for the first 200 kilowatt-hours per month and additional kilowatt-hours. It references a Board Decision dated October 28, 2025.
Rate Code 72 cents per kilowatt-hour For the first 200 During a kilowatt-hours per Critical Peak month after Critical Event Peak Event usage For all additional kilowatt-hours Effective November 1, 2026 151.941 16.739 15.331 Effective Janua...
AI summary Rate Code 72 outlines a tiered pricing structure for electricity, with different rates for the first 200 kilowatt-hours during Critical Peak Events and for all additional kilowatt-hours. The Critical Peak Event is defined as a four-hour period during the winter months, between 6:00 AM and 11:00 PM.
SMALL GENERAL CRITICAL PEAK PRICING TARIFF Page 4 of 4 Rate Code 72 - (e) The customer cannot be taking seasonal service from NSPI under Regulation 3.3. - (f) The customer cannot be taking Net Metering service from NSPI under Regulation 3....
AI summary The document outlines eligibility criteria for the Small General Critical Peak Pricing Tariff, specifying that customers cannot be on seasonal service or Net Metering service under specific regulations.
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 Small General Tariff.
AI summary This optional tariff aims to encourage customers to shift their energy usage from peak to off-peak periods. It is available to those eligible under the Small General Tariff.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-18-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Starting November 1, 2025, the Nova Scotia Energy Board's decision on NS Power's 2025/26 Time-varying Pricing (TVP) Tariffs (M12499) implements an Interim Energy Charge during system unavailability, with specific billing and notification procedures for TVP customers based on when system functionality is restored.
DEMAND CHARGE per month per kilowatt of maximum demand Effective upon the date of the Board's Order $9.809 Effective January 1, 2027 $10.697 32 cents per kilowatt reduction in demand charge where the transformer was owned by the customer p...
AI summary The document outlines the demand charge rates effective from the date of the Board's Order and January 1, 2027, with a reduction of 32 cents per kilowatt for customers with transformers owned prior to 1974 or under Special Condition (2).
INTERIM ENERGY CHARGE Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-23-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy...
AI summary The Interim Energy Charge, effective December 1, 2025, applies during both winter and non-winter periods and is set to standard offer rates while system functionality is unavailable. Critical Peak Events will not be scheduled during this period, and NS Power must notify customers when system functionality is restored.
1 M12499 – Board Decision, 325286, page 5. October 28, 2025. Interim Energy Charge During a Critical Peak Event For the first 200 kilowatt hours per month per maximum demand For all additional kilowatt-hours Effective upon the date of the...
AI summary The document outlines the interim energy charge rates for Critical Peak Events, specifying different rates for the first 200 kilowatt-hours per month per maximum demand and for all additional kilowatt-hours. The rates are effective from the date of the Board's Order and are set to change on November 1, 2026, and January 1, 2027.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The maximum charge per kWh, applying to that portion of the bill which is not concerned with determination of the cost of the Critical Peak Events, will be that for a billing load factor of 10% except th...
AI summary The document outlines the maximum charge per kWh and the minimum monthly bill, specifying that the maximum charge applies to the portion of the bill not related to Critical Peak Events, with a billing load factor of 10% and a minimum monthly bill threshold.
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 maximum actual demand from the previous eleven months, specifically from December, January, or February.
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 text outlines a rate adjustment effective from the date of the Board's Order and January 1, 2027, along with a reduction in demand charge for customers owning transformers.
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, along with a reduction in demand charge for customers with transformers owned prior to 1974 or under Special Condition (2).
MEDIUM INDUSTRIAL TARIFF Page 2 of 2 (250 kVA or 225 kW to 1,999 kVA or 1,799 kW)
AI summary The document outlines the Medium Industrial Tariff for customers with electrical capacity ranging from 250 kVA or 225 kW to 1,999 kVA or 1,799 kW. It provides details on the applicable rates and structures for this specific range of service.
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 for qualified customers based on billed interruptible demand, which is calculated as the difference between contracted firm demand and billing demand. No credit is applied if billing demand is less than contracted firm demand.
reduction per kilovolt ampere reduction in demand charge Effective upon the date of the Board's Order $7.638 Effective January 1, 2027 $7.667 AVAILABILITY
AI summary The document outlines the effective dates and values for the reduction per kilovolt-ampere reduction in demand charge, which became effective upon the date of the Board's Order and is set to increase to $7.667 on January 1, 2027.
AVAILABILITY This tariff is applicable to three phase electric power and energy, supplied at the low voltage side of the bulk power transformer, to municipal electric utilities. Meter readings shall be increased by 1.1% for each transforma...
AI summary The tariff applies to three phase electric power and energy supplied at the low voltage side of the bulk power transformer to municipal electric utilities. Meter readings are adjusted by 1.1% for each transformation between the meter and the low voltage side to account for transformation losses, and reduced when metering is at transmission voltage.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate shall be $ as follows per month if such unmetered se...
AI summary The text outlines the maximum charge per kWh based on a billing load factor of 10%, with a specified minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate when billed separately from metered accounts.
Maintenance Charge (if applicable) Cost of normal fixture maintenance and bulb replacement on the basis of current cost levels shall be used to calculate the monthly maintenance charge. This portion of the rate does not include any provisi...
AI summary The maintenance charge covers the cost of normal fixture maintenance and bulb replacement at current cost levels. It does not include globe washing or cleaning, and vandalism-related repairs are charged to the customer.
Maximum per kWh Charge/Minimum Bill The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall be as follows per month if such unmetered service is billed separately from any metered...
AI summary The document outlines the maximum charge per kWh based on a 10% billing load factor, with a specified minimum monthly bill for unmetered service billed separately from metered accounts.
(1) Base Cost of Fuel The Base Cost of Fuel can be re-set in a General Rate Application or, absent a General Rate Application, every second year as part of the FAM adjustment process. Changes in the Base Cost of Fuel will be reflected in c...
AI summary The Base Cost of Fuel is adjustable through a General Rate Application or every second year via the FAM adjustment process. Adjustments impact customer rates and are applied consistently with the Board-approved Cost of Service Methodology.
2026 Effective upon the date of the Board's Order Rate Class Actual Adjustment (AA) in cents per kWh Balance Adjustment (BA 1) in cents per kWh Balance Adjustment (BA-2) in cents per kWh FAM AA/BA Combined in cents per kWh Domestic Service...
AI summary The document presents a table outlining various rate classes and their corresponding adjustments, including Actual Adjustment (AA), Balance Adjustment (BA 1 and BA-2), and the Fuel Adjustment Mechanism (FAM) AA/BA Combined, effective upon the date of the Board's Order and January 1, 2027.
Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Regulation is equal to 3.5 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.5 percent of...
AI summary The document outlines customer obligations for self-supply and third-party supply under two types of transmission services. For Point-to-Point Transmission Service, the obligation is 3.5% of Reserved Capacity and 9.1% for Load Following. For Network Integration Transmission Service, the obligation is 3.5% of Network Load and 9.1% for Load Following.
SCHEDULE 9: REAL POWER LOSS FACTORS For Point-to-Point service, the Transmission Provider will seasonally calculate loss factors to be used on a path-by-path basis. For each season, winter and summer, the power flow models used to calculat...
AI summary This document outlines the methodology for calculating real power loss factors for both Point-to-Point and Network Service by the Transmission Provider, including seasonal calculations, annual reviews, and the application of locational loss factors. It also details the rate for Network Integration Transmission Service and the formula for transmission congestion charges.
7. NS POWER RESPONSIBILITIES NS Power shall be responsible for: - (a) provision of Distribution System Access; - (b) processing RtR Customer Transaction Request Applications that are received from an LRS on behalf of the RtR Customer; - (c...
AI summary NS Power is responsible for providing distribution system access, processing customer transaction requests, providing billing data, and acting as a point of contact for RtR Customers. However, NS Power is not responsible for supplying electricity or enforcing contracts between RtR Customers and LRS.
10.1 Provision and Ownership NS Power will provide, install and seal all revenue class meters as necessary for application of this Distribution Tariff. The meters will be used for determining charges for Distribution System Access under th...
AI summary NS Power is responsible for providing, installing, and sealing revenue class meters for RtR Customers under the Distribution Tariff. The meters must have remote polling capability and comply with the Electricity and Gas Inspection Act regulations. Ownership of the meters and associated equipment remains with NS Power, and metering requirements are detailed in NS Power Regulations Section 4 - Metering.
11.1 Application of Distribution Tariff Rates The Distribution Tariff amounts payable by the RtR Customer will be calculated by NS Power using the RtR Customer's meter readings and the Distribution Tariff Rate Schedule applicable to the Rt...
AI summary The Distribution Tariff rates payable by the RtR Customer are calculated by NS Power based on meter readings and the applicable rate schedule. If the customer's operational or consumption characteristics change, NS Power will adjust the tariff rate accordingly.
11.2 Billing Unless NS Power directs otherwise, the RtR Customer shall be invoiced by the LRS and will pay the LRS for any charges or fees, inclusive of all applicable taxes, owing by the RtR Customer to NS Power under this Distribution Ta...
AI summary This section outlines the billing responsibilities of the RtR Customer under the Distribution Tariff, including charges for distribution system access, demand-side management, storm recovery, and other approved items. The RtR Customer agrees to pay the LRS for these charges and waives claims against NS Power related to billing by the LRS.
11.3 Real Power Losses Distribution System Real Power Losses associated with Distribution System Access are incorporated in the Distribution Tariff rates applicable to each RtR Customer's rate class. The RtR Customer is responsible for the...
AI summary Real power losses in the distribution system are included in the distribution tariff rates for each rate class. The responsibility for these costs falls on the RtR Customer.
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.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-114-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in al...
AI summary Effective December 1, 2025, the Nova Scotia Energy Board (NSEB) has approved an interim energy charge for NS Power's Time-varying Pricing (TVP) Tariffs (M12499). This charge applies during all hours in both winter and non-winter periods and is set at standard offer rates. Critical Peak Events will not be scheduled during this period, and customers will be notified once system functionality is restored.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event Non-critical Peak Hours Effective December 1, 2025 n/a 16.931 1 M12499 – Board Decision, 325286, page 5. October 28, 2025.
AI summary The document outlines an interim energy charge structure effective December 1, 2025, with a non-critical peak rate of 16.931 cents per kilowatt-hour. It references a Board Decision (M12499) from October 28, 2025, page 5, and includes a reference to a picture on page 114.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event Non-critical Peak Hours Effective upon the date of the Board's Order n/a 18.324 ENERGY CHARGE cents per kilowatt-hour During a Critical Non-critical Peak Event Peak...
AI summary The document outlines energy charge rates during critical peak events and non-critical peak hours, with specific rates effective on different dates starting from January 1, 2024, through January 1, 2027. A critical peak event is defined as a four-hour period between 6:00 AM and 11:00 PM during the winter period.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-118-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in al...
AI summary Effective November 1, 2025, the Nova Scotia Energy Board's decision on NS Power's 2025/26 Time-varying Pricing (TVP) Tariffs (M12499) outlines the application of the Interim Energy Charge during periods of system unavailability and the conditions for restoring TVP rates once functionality is restored.
cents per kilowatt-hour Interim Energy Charge (Winter Period) On-peak (evening) Off-peak November 1 through March 31 7:00 AM to 11:00 AM 11:00 AM to 5:00 PM 5:00 PM to 9:00 PM 9:00 PM to 7:00 AM Effective November 1, 2025 16.931 16.931 16....
AI summary The document outlines energy charge rates for different periods and time-of-use tiers, including interim and non-winter rates, with effective dates and adjustments. It specifies on-peak and off-peak rates during the winter period, along with applicable holidays and weekends.
CUSTOMER CHARGE per month Effective February 2, 2023 $19.17 Effective January 1, 2024 $19.17 Effective upon the date of the Board's Order $20.08 Effective January 1, 2027 $21.04 ENERGY CHARGE cents per kilowatt-hour Applicable in December,...
AI summary The document outlines the customer and energy charges effective from various dates, including February 2, 2023, January 1, 2024, the date of the Board's Order, and January 1, 2027. It specifies different rates for different times of the day and months of the year.
Effective: February 2, 2023 This tariff is only available to customers employing electric-based heating systems utilizing Electric Thermal Storage (ETS) equipment, and electric in-floor radiant heating systems utilizing thermal storage, an...
AI summary This tariff applies to residential customers with specific electric heating systems and outlines conditions for outbuildings on residential property. It specifies that the Domestic Service Time-of-Day Tariff is available to certain customers under the Public Utilities Act. Different rates apply depending on the primary use of the outbuilding.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-127-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in al...
AI summary The Nova Scotia Energy Board (NSEB) has approved changes to NS Power's Time-varying Pricing (TVP) Tariffs effective December 1, 2025. These changes include the implementation of an Interim Energy Charge, restrictions on Critical Peak Events, and provisions for restoring TVP rates once system functionality is restored.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event For the first 200 kilowatt-hours per month For all additional kilowatt-hours Effective December 1, 2025 n/a 17.567 15.841 Effective upon the date of the Board's Ord...
AI summary The document outlines energy charge rates for different periods, including rates during Critical Peak Events and for varying levels of kilowatt-hour usage. The rates are effective on specific dates and include a four-hour Critical Peak Event duration during the Winter Period.
- (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) NSPI may limit the number of customers who may subscribe to thi...
AI summary The document outlines conditions for customers subscribing to a new tariff effective November 1, 2025, including requirements for Smart Meters, restrictions on seasonal and Net Metering services, and NSPI's authority to limit enrollment.
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.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The maximum charge per kWh, applying to that portion of the bill which is not concerned with determination of the cost of the Critical Peak Events, will be that for a billing load factor of 10% except th...
AI summary The text outlines the maximum charge per kWh and the minimum monthly bill, specifying that the maximum charge applies to portions of the bill not related to Critical Peak Events, with a billing load factor of 10% and a minimum monthly bill threshold.
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 their electricity usage from peak to off-peak periods. It is available to customers eligible for service under the General Tariff.
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required to make a c...
AI summary Special conditions outline requirements for metering and service provisions. Customers may need to contribute to the cost of primary metering and adjust kWh readings by 1.9% if metering is on the high voltage side. Non-standard service provisions may require customers to own transformers typically provided by the company.
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 February 2, 2023 $1.632 Effective January 1, 2024 $1.632 Effective upo...
AI summary The text outlines a charge applicable to customers connected at the distribution level, with rates effective from February 2023 to January 2027. A reduction in demand charge is provided for customers who own the transformer, at a rate of 32 cents per kilovolt ampere.
DEMAND CHARGE As follows, per month per kilovolt ampere of the higher of: - (a) maximum actual demand of the current month; or - (b) the maximum actual demand of the previous December, January, or February occurring in the previous eleven...
AI summary The demand charge is calculated monthly based on the higher of the current month's maximum actual demand or the highest demand from the previous eleven months, excluding peak demands during the first two hours after outage restoration. Customers are expected to manage demand peaks following outages.
AVAILABILITY This tariff is applicable to three phase electric power and energy, supplied at the low voltage side of the bulk power transformer, to municipal electric utilities. Meter readings shall be increased by 1.1% for each transforma...
AI summary The tariff applies to three phase electric power and energy supplied at the low voltage side of the bulk power transformer to municipal electric utilities. Meter readings are adjusted by 1.1% for each transformation between the meter and the low voltage side to account for transformation losses, and readings are reduced when metering is at transmission voltage.
(a) Operating, Maintenance, and Capital (full charge) Rate Code Watts kWh per per month ($) month 2023 2024 Other 140 400 150 33.42 33.48 141 1,000 360 72.77 72.90 142 250 100 25.12 25.15 143 150 67 19.32 19.34 kWh per per month ($) Rate C...
AI summary The document presents rate codes and corresponding charges for electricity usage in Nova Scotia, detailing costs per kilowatt-hour for different wattage tiers across various years. This information is relevant to rate design and cost-to-customer considerations.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate shall be $ as follows per month if such unmetered se...
AI summary The document outlines the maximum charge per kWh based on a billing load factor of 10%, with a specified minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate when billed separately from metered accounts.
11.1 Application of Distribution Tariff Rates The Distribution Tariff amounts payable by the RtR Customer will be calculated by NS Power using the RtR Customer's meter readings and the Distribution Tariff Rate Schedule applicable to the Rt...
AI summary The Distribution Tariff amounts payable by the RtR Customer are calculated based on meter readings and applicable rate schedules. If the customer's operational or consumption characteristics change, NS Power will adjust the tariff rate accordingly.
\ Note: for certainty, all capitalized terms shall, unless otherwise defined herein, have the meanings ascribed thereto in the Distribution Tariff. General, General Critical Peak Pricing, General Time-of-Day Demand Charge ($/kW) Minimum Mo...
AI summary The text provides a table showing different rate structures for demand charges, minimum monthly charges, and transformer ownership credits effective on various dates, including dates tied to the Board's Order. It outlines rates for General, Large General, and Small Industrial categories as of 2023, 2024, and 2027.
101354Board Decision
87 passages
IN THE MATTER OF THE PUBLIC UTILITIES ACT - and - IN THE MATTER OF A GENERAL RATE APPLICATION by NOVA SCOTIA POWER INCORPORATED for approval of certain revisions to its Rates, Charges and Regulations BEFORE: Stephen T. McGrath, K.C., Chair...
AI summary Nova Scotia Power Inc. seeks approval for rate revisions under the Public Utilities Act. The proceeding involves intervenors including the Consumer Advocate, Small Business Advocate, and other groups. The Board members reviewing the application include Stephen T. McGrath, Roland A. Deveau, and Steven M. Murphy.
1.0 SUMMARY - [1] The Nova Scotia Energy Board is keenly aware that electricity rates are already challenging for many customers, and any rate increase will be difficult, especially for those with low or fixed incomes. However, the Board d...
AI summary The Nova Scotia Energy Board acknowledges the difficulty of electricity rate increases for low-income customers but lacks authority to set special rates under the Public Utilities Act. NS Power filed a GRA proposing 1.8%-4.1% rate increases for 2026-2027, with residential rates rising more sharply. The Board emphasizes its role in recovering prudently incurred costs, while NS Power claims the application resulted from collaborative negotiations with customer representatives.
Jurisdiction of Board - 30 (1) A Board has exclusive jurisdiction in all cases and in respect of all matters in which jurisdiction is conferred on the Board. - (2) The Boards, as to all matters within their jurisdiction pursuant to this Ac...
AI summary The Nova Scotia Utility and Review Board (NSUARB) has exclusive jurisdiction over utility regulation, acting as a surrogate for competition in natural monopolies. Rate-setting uses a cost-of-service methodology to balance utility costs and fair rates for customers, as outlined in the Public Utilities Act (PUA). Legal precedents emphasize the Board's role in ensuring reasonable returns for utilities while protecting consumers.
n s. 42(1) which states: - 42 (1) Every public utility shall be entitled to earn annually such return as the Board deems just and reasonable on the rate base as fixed and determined by the Board. … - 23 The concept of a utility securing a...
AI summary The Nova Scotia Utility and Review Board (NSUARB) determines that public utilities are entitled to earn a 'just and reasonable' annual return on their rate base, as defined by the Public Utilities Act (PUA). Rates must ensure this return after covering operating expenses and allowed capital expenditures, while preventing extravagance through strict oversight of rate base composition and allowable costs.
CRITERIA OF A SOUND RATE STRUCTURE - 1. The related, "practical" attributes of simplicity, understandability, public acceptability, and feasibility of application. - 2. Freedom from controversies as to proper interpretation. - 3. Effective...
AI summary The document outlines eight criteria for a sound rate structure, emphasizing simplicity, revenue stability, fairness, and efficiency. It references James Bonbright's principles and legal precedents, including the Public Utilities Act and statutory interpretation requirements. The criteria are used to assess current applications under Nova Scotia regulatory frameworks.
3.1 Should the Settlement Agreement be Approved? [36] On September 2, 2025, NS Power wrote to the Board to advise that it would be filing a general rate application for the 2026 and 2027 test years. It stated that it had reached a consensu...
AI summary NS Power advised the Board on September 2, 2025, of its intent to file a general rate application for 2026 and 2027, supported by customer representatives. However, the application was not filed until September 18, 2025, and the settlement agreement was only submitted on November 5, 2025, following information requests from Board staff.
[37] The terms of the settlement agreement are set out in a schedule to the agreement and provide as follows: GRA Element Settlement Terms Cost of Service ("COS") a) The COS as set out in the Draft GRA will be included in the 2026-2027 GRA...
AI summary The settlement agreement outlines terms for the 2026-2027 GRA, including the inclusion of the Cost of Service and MEU Treatment. The agreement specifies that the Minimum System methodology will be subject to a future proceeding, and data regarding PHP's use of the High Voltage transmission system will be collected and disclosed. The apportionment of assessment costs from the Maritime Link remains open for future determination.
[38] Previous decisions by the NSUARB set out the principles it applied in its consideration of settlement agreements. Those principles are still relevant and bear repeating. In its decision dated November 5, 2008, about a prior NS Power g...
AI summary The NSUARB emphasizes its commitment to ensuring that settlement agreements are just, reasonable, and in the public interest. It highlights the importance of settlement agreements in regulatory proceedings, noting their role in promoting collaboration and reducing controversy in rate applications. The Board also outlines its principles for evaluating such agreements, including the need to ensure that costs are prudently incurred and that all intervenor concerns are adequately addressed.
3.1.1 Findings [41] As noted above, the NSUARB has considered settlement agreements in past matters. The Board appreciates the efforts of parties to resolve contested issues in matters coming before it and encourages such initiatives to co...
AI summary The NSUARB emphasizes that while settlement agreements are valuable, they must be just, reasonable, and in the public interest. It notes that the current settlement was reached before the application was filed, affecting its weight. The Board approves some terms but requires amendments to ensure fair rates.
3.2 Fuel and Purchased Power [45] Fuel and purchased power expenditures are direct pass-through costs paid by NS Power's customers. Under the Fuel Adjustment Mechanism (FAM), those costs are identified as the Base Cost of Fuel (BCF). Actua...
AI summary Fuel and purchased power costs are pass-through expenses managed via the Fuel Adjustment Mechanism (FAM), with actual costs tracked against forecasts. Over/under recoveries are adjusted through AA and BA riders. NS Power provides regular updates, and an independent Board-appointed auditor conducts biennial audits reviewed in public proceedings.
3.2.1 Base Cost of Fuel [46] Fuel and purchased power costs comprise the largest portion of NS Power's revenue requirement. During the two-year test period, NS Power has forecast those costs to be $918.6 million for 2026 and $918.4 million...
AI summary NS Power's application for new Base Cost of Fuel (BCF) amounts for 2026 and 2027 is under review. The proposed BCF adjustments aim to smooth rate increases for each rate class during the 2026-2027 GRA period, resulting in over-collection in 2026 and under-collection in 2027. Board Counsel engaged Bates White to review the application, and NS Power applied for an extension of the AA/BA riders on an interim basis.
competition in two ways. It sets an unrealist benchmark of posted retail rates for comparison purposes, and it creates an ongoing fuel liability for customers looking to leave NSPI bundled service. … REI respectfully requests that the Boar...
AI summary REI argues that NSPI's fuel cost forecasts are inaccurate and requests adherence to the FAM POA for annual recovery of overages. NS Power counters that its methods are audited by Bates White and compliant with the POA, thus no directive is needed.
3.2.2 FAM Plan of Administration and Fuel Manual
AI summary The FAM Plan of Administration and Fuel Manual outlines procedures for managing fuel costs and administrative processes under Nova Scotia's Fuel Adjustment Mechanism. It addresses regulatory oversight, compliance with energy policies, and ensures alignment with utility operations and rate design frameworks.
3.2.2.1 Plan of Administration [60] In its application, NS Power requested approval of amendments to the FAM Plan of Administration as described in Section 6 and Appendix 6A and set out in Appendix 6B. On page 32 of the application, NS Pow...
AI summary NS Power seeks approval to amend the FAM Plan of Administration (POA) for the 2026-2027 GRA period, including aligning fuel costs with COSS, adding renewable program credits, and moving OM&G expenses to FAM. The NSEB requested clarification on language in the amendment, and NS Power referenced prior Board decisions and matter M11127.
3.2.2.2 Fuel Manual and Hedging Plan [64] On page 29 of its application, NS Power stated: NS Power's currently approved version of the Confidential Fuel Manual, which sets out the requirements for fuel and purchased power procurement, is i...
AI summary NS Power submitted administrative updates to its Fuel Manual and Hedging Plan, including generic references to the Hedging Plan and minor language changes. The Board typically does not approve these documents but accepts them for informational purposes, with changes intended to extend beyond the prior rate stability period.
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.
Rates of utility to include allowance for depreciation 41 In fixing rates, tolls and charges to be paid to a public utility for any service, the Board shall include proper allowances for depreciation. [122] NS Power owns significant assets...
AI summary The Nova Scotia Utility and Review Board (NSUARB) mandates that utility rates include depreciation allowances. NS Power uses asset pools to track depreciation, recovering original costs and salvage expenses over asset lifetimes. The Public Utilities Act (PUA) permits recovery of prudently incurred costs, including depreciation, from customers.
3.4.1.1.1 Production Plant [142] As it relates to its generation assets, NS Power's depreciation study requires it to estimate the future cost of decommissioning its generation sites, as depreciation rates are generally set to recover the...
AI summary NS Power's depreciation study for generation assets includes decommissioning cost estimates, with separate studies for hydro and non-hydro plants. The GRA settlement agreement removed inflation and contingency costs, lowering proposed depreciation rates. Partial decommissioning costs (excluding dams and archaeological expenses) are included, while full decommissioning and archaeological costs are excluded to balance rate pressure and cost recovery.
3.4.1.2 Estimated Average Asset Service Lives [151] Key elements influencing the determination of depreciation expense are average asset service lives and survivor curves. Survivor curves (also referred to as Iowa curves) are a series of c...
AI summary The document discusses methods for estimating average asset service lives using survivor curves, with changes made via the GRA settlement agreement. Gannett Fleming's study informed these estimates, but Mr. Madsen disputed certain curve selections, proposing alternatives. Adjustments to service lives for specific accounts reduced NS Power's depreciation rates.
ion rates for the purposes of the current GRA. This can be reconsidered for NS Power's next depreciation study, should the 2025/26 IRP determine that decommissioning of Mersey is the preferred option. [163] The Tusket system has a total ca...
AI summary The Nova Scotia Utility and Review Board (NSUARB) excludes decommissioning costs for Wreck Cove, Mersey, and Tusket hydro systems from current depreciation rates, pending future Integrated Resource Plan (IRP) findings. The decision applies to 2026-2027 test years, with reconsideration possible if the 2025/26 IRP favors Mersey decommissioning. The Tusket system's small size and potential replacement with renewables support the exclusion, while NS Power plans to seek approval for Tusket refurbishment.
nt agreement itself, there is nothing in the current evidentiary record before the Board to provide support to exclude inflation costs beyond 2024 from generation Plant decommissioning cost estimates. [176] The Board also has other concern...
AI summary The document highlights concerns about the settlement agreement adjustments to net salvage rates for NS Power's production Plant assets, noting a significant reserve deficiency. This deficiency implies that depreciation rates have been too low, leading to potential future rate increases and intergenerational inequity.
s the composite remaining life for Nova Scotia Power. So fundamentally the analysis is not a Nova Scotia Power focused analysis and is providing a result that makes that is, in my mind, misleading. The final point that I would make before...
AI summary The analysis of the ALG and ELG procedures for Nova Scotia Power is criticized for being misleading and not focused on the company. The ALG procedure would recover more revenue in the short term but is less favorable on a net present value basis by about $100 million. The analysis assumes a 2% growth rate and a 6.15% weighted average cost of capital, but no crossover point between the two procedures is expected by 2050.
3.4.3.1 Findings [243] In Undertaking U-8, NS Power provided calculations showing the dollar effect of implementing the changes recommended in Table 8 of Mr. Madsen's evidence. NS Power performed the analysis using both the ALG and ELG dep...
AI summary NS Power provided calculations showing the financial impact of implementing Mr. Madsen's recommended average service life changes, showing reductions in depreciation expenses under both ALG and ELG procedures. These changes would lower average rate increases for customers, though partially offset by increased return on rate base. The Board must determine if Mr. Madsen's recommendations are warranted.
e installed but did not know when the related retirements occurred. Then, based on the addition and retirement pattern, simulation was used to place a reasonable age on the retirements that did occur. [251] In general, the Board agrees wit...
AI summary The Board acknowledges NS Power's position on depreciation rates requiring professional judgment but finds Mr. Madsen's evidence on asset service lives more compelling, noting NS Power's service lives are lower than peers. However, the Board will not mandate changes due to securitization uncertainties, which could risk NS Power's credit rating and increase ratepayer costs.
t salvage rates for Plant accounts not subject to settlement agreement adjustments and for the three transmission and distribution Plant accounts which are subject to settlement agreement adjustments. [271] The Board has intergenerational...
AI summary The Board approves settlement agreement adjustments to net salvage rates for NS Power's production plant accounts despite intergenerational equity concerns and uncertainty about decommissioning costs, particularly for hydro assets. The decision is based on unresolved questions about future decommissioning scenarios, with a directive for NS Power to address these issues in the next GRA.
of this mechanism being proposed by an investor-owned regulated utility in Canada. A form of securitization was applied in Ontario a few years ago for Ontario Power Generation, a Crown-owned utility. [287] A successful securitization shoul...
AI summary The text discusses securitization as a potential cost-saving mechanism for ratepayers, contrasting the current weighted average cost of capital (6.65%) with projected bond issuance rates (5%). It notes NS Power's historical reluctance to adopt securitization, despite previous regulatory encouragement and its use in addressing FAM balances and coal plant retirement costs. The Board and intervenors have urged NS Power to explore this option.
oncrete steps to solve problems at NSPI – such as the securitization of the stranded FAM balances – was rewarded by the markets with lower yields on NSPI bonds. [Emphasis added] [Exhibit N-36, p. 18] [299] Morrison Park confirmed that secu...
AI summary The document discusses NSPI's securitization of stranded FAM balances, arguing it reduces business risk and improves credit metrics. Morrison Park highlights that failing to secure rate increases or securitize could miss the 10% FFO:Debt target, risking credit downgrades. Emrydia supports securitization but urges a full review of cost recovery periods.
322] As noted above, the approval of the potential securitization is not before the Board in this application. Whether securitization ultimately proceeds is a policy matter for the Province to decide. [323] NS Power requested the deferral...
AI summary The Board approves the securitization deferral account requested by NS Power, noting that depreciation and financing costs relate to assets under the Decarbonization Deferral Account (DDA). The Province opposes immediate securitization due to asset valuation concerns but supports the deferral. NS Power's request was motivated by potential customer benefits from early securitization, which the Board finds justifiable.
3.5.1.4 PHP Deferral [335] PHP currently takes service from NS Power under the Extra Large Industrial Active Demand Control (ELIADC) tariff, which is a Below-the-Line (BTL) tariff. The costof-service study supporting this general rate appl...
AI summary PHP was initially under the ELIADC (BTL) tariff, but NS Power's GRA assumed an ATL tariff for 2026-2027. The Board extended ELIADC until 2026 but required a successor ATL tariff (ELID) by 2025. NS Power applied for ELID, expecting PHP to switch by 2027, with ADC services and interruptible credits included in the new tariff.
3.5.1.4.1 Findings [349] NS Power requests a PHP Deferral account to track any variances in revenue between that which would occur based on the assumptions in the GRA cost-ofservice study treating PHP as an ATL customer versus that which r...
AI summary NS Power requests the creation of a PHP Deferral Account to track revenue variances between assumptions in the GRA cost-of-service study and the eventual ELID tariff. The Board finds it appropriate to approve the deferral account, which will account for revenue variances arising from differences in the PHP tariff, its unavailability, or unsatisfactory outcomes of the PHP ADC and tariff processes.
3.5.1.5 GRA Deferral [354] In its general rate application, NS Power asks for a deferral of its GRArelated costs of the present matter and to collect those costs in rates on a straight-line basis over the two-year test period. Such costs i...
AI summary NS Power is requesting to defer GRA-related costs, including those for the company, consumer advocates, the Board, and expert consultants, and recover them over a two-year test period. The amount was reduced from $4.0 million to $2.0 million via a settlement agreement. The deferral aligns with the Board's prior approval in the 2023-2024 GRA Decision and the recovery of costs from the Cost-of-Service Study and Line Loss Study.
he deferral of operating costs, which were canvassed by the Nova Scotia Regulatory and Appeals Board in Halifax Regional Water Commission 2026-2027 General Rate Application , 2025 NSRAB 142 (M12257):
AI summary The document references the deferral of operating costs discussed in the Nova Scotia Regulatory and Appeals Board's decision on the Halifax Regional Water Commission's 2026-2027 General Rate Application (M12257), highlighting regulatory considerations around cost deferral mechanisms.
3.6.1.1 Findings [367] NS Power's estimated capital investment for the GRA test period amounts to $671.3 million in 2026 and $556.1 million in 2027. The capital additions to rate base for the test period have generally been approved by the...
AI summary NS Power's capital investment forecasts for 2026 and 2027 are reviewed, with most projects approved by the Board. Discrepancies between GRA and ACE Plan projects are attributed to timing and asset management updates. The Board finds the total forecast spending reasonable, noting NS Power will align its capital program with the GRA forecast.
irement dates". The parties agreed to resolve these matters in a "black box" settlement agreement to lower rates for customers in the next general rate application and this was approved by the NSUARB. [388] The approved depreciation rates...
AI summary NS Power's depreciation rates were implemented in 2013-2014, with no subsequent rate application until 2022. NS Power cited changes in federal and provincial environmental policies, including Equivalency Agreements (2015-2020) that delayed coal plant retirement until late 2021. In its 2023-2024 rate application, NS Power addressed coal asset depreciation and decommissioning costs.
3.6.3.1 Findings [394] A utility is entitled to the opportunity to recover its prudently incurred costs in providing service and an opportunity to earn a reasonable profit – no more and no less. While the Board can disallow costs found to...
AI summary The Board affirms utilities' right to recover prudently incurred costs and earn reasonable profits, emphasizing that customers must bear legitimate costs. Investors require fair returns to fund infrastructure, and the Board cannot disallow costs to lower rates. This aligns with prior NSUARB decisions on rate applications.
[397] In essence: A public utility is obligated to provide services that are reasonably safe and adequate and is entitled to compensation therefor by the charging of rates that are not unjustly discriminatory and will provide the public ut...
AI summary Public utilities must provide safe, adequate services and earn fair rates to cover expenses and capital needs. The Supreme Court of Canada defined a fair return as equivalent to returns on alternative investments, emphasizing that low returns risk deterring investment, harming credit ratings, increasing borrowing costs, and limiting market access.
3.6.3.1.1 The Value of the Rate Base [399] The "value" of NS Power's rate base, as framed in the Department's submissions, is based on an historic concept that has been displaced by the widely accepted prudent original cost method for valu...
AI summary The document argues that Nova Scotia Power's rate base valuation should use the prudent original cost method, as mandated by the Public Utilities Act since 1943, rather than the Department's outdated approach. Two expert witnesses supported this method, and the Department failed to provide evidence or cross-examine them. Bonbright's 1988 work is cited as historical context.
and expense reports. A further complication, of course, is that major technological improvements tend to make questionable any year-to-year measure of depreciation that is determined by this process. In the cost allocation concept, the ori...
AI summary The cost allocation concept treats asset original costs as prepaid expenses, allocating depreciation to accounting periods based on service provision. This method aligns with accounting principles by matching expenses to revenues and ensures verifiability. NARUC (1996) endorses this approach for regulatory depreciation calculations in cost-reflective tariff settings.
3.6.3.1.2 Assets No Longer "Used and Useful" and the Decarbonization Deferral Account [419] Referring to "core ideas" from the UAD line of cases and their relevance to Nova Scotia, the Department submitted, "Once an asset is no longer used...
AI summary The Department argues that assets no longer 'used and useful' can be removed from rate base, with losses borne by shareholders. NS Power cites the Alberta Court of Appeal's 2023 decision in ATCO Electric Ltd. v Alberta Utilities Commission , which rejected binding precedent on stranded assets from natural disasters. The Court emphasized that legislation did not limit the AUC's discretion over depreciation or stranded assets, challenging prior assumptions.
within the discretion of the Commission, to be exercised consistently with the words of the Electric Utilities Act , having regard to all relevant considerations, while disregarding irrelevant ones. - [61] In conclusion, the decision under...
AI summary The text discusses judicial review of rate-setting decisions, emphasizing the Commission's discretion under the Electric Utilities Act and Public Utilities Act . It highlights errors in the original decision regarding asset recovery, leading to a redetermination by the AUC allowing recovery of destroyed assets' net book value. The Alberta Court of Appeal's ruling aligns with the NSUARB's approach to asset valuation.
etiring coal assets to be recovered from customers that are higher than they should have been. The second, is that NS Power unnecessarily invested in these assets in the face of impending retirements. [433] As discussed previously in this...
AI summary The Board critiques NS Power for overestimating coal asset retirement costs and unnecessary investments. It references a 2010 depreciation study settlement (M03665) that lowered rates, later implemented in 2011. NS Power's 2022 rate application omitted updated depreciation studies but proposed the DDA to address coal plant closures. Subsequent DDA proceedings saw no claims to reduce costs due to imprudent depreciation rates.
3.7 Return on Equity and Capital Structure [440] NS Power's existing rates are set based on a current capital structure that includes 40% equity and 60% debt, with an approved return on equity of 9%. Under the current framework, NS Power m...
AI summary NS Power's current rates are based on a 40% equity, 60% debt structure with a 9% ROE cap of 9.25%. They propose maintaining a 9% ROE range (8.75%-9.25%) and the same debt-to-equity ratio for rate-setting.
3.7.1 The Fair Return Requirement [442] NS Power operates as a natural monopoly in Nova Scotia, where the absence of meaningful competition means the competitive forces of the market do not apply. Section 45 of the Public Utilities Act ent...
AI summary NS Power, a natural monopoly in Nova Scotia, requires a fair return on its rate base to ensure financial stability and attract investment. The Board must set parameters for returns to maintain investor confidence, prevent rising borrowing costs, and avoid loss of debt market access, which could increase customer costs. Legal standards for approving returns are rooted in the Public Utilities Act.
3.7.2.1 Return on Equity [453] Determining a fair return on equity generally entails the use of several wellestablished financial models. These include, but are not limited to, the discounted cash flow (DCF) model; the capital asset pricin...
AI summary The document discusses methodologies for determining a fair return on equity (ROE) for Nova Scotia Power (NSP), including DCF, CAPM, and risk premium models. A consensus agreement sets NSP's ROE at 9% with an 8.75%-9.25% earnings band and retains a 40% equity thickness. Concentric Energy Advisors' analysis, using market data up to February 2025, supports these figures.
3.7.4 Party Submissions [503] The Affordable Energy Coalition's (AEC) opening statement submitted that the Board must ensure rates are sufficient to cover NS Power's cost-of-service, while preventing the recovery of excess spending and pro...
AI summary The Affordable Energy Coalition (AEC) argues that Nova Scotia Power's (NS Power) rates must cover costs without allowing excess profits, citing low-income affordability concerns and suggesting a reduced return on equity (ROE) of 7.6%. NS Power defends its current ROE and capital structure, citing Concentric's evidence, to balance affordability and investment needs.
sked the NSUARB to conduct an independent review of the utility's state of preparedness before the storm. Many questioned why a rate increase should be considered in the circumstances. The Board said: - [14] Just prior to November 15, 2004...
AI summary The NSUARB was requested to review Nova Scotia Power Inc.'s preparedness for a 2004 storm that caused power outages. The public hearing was delayed due to the outages, and Premier John Hamm urged the Board to conduct an independent review under the Public Utilities Act to assess restoration program improvements.
o, it has departed from what was proposed. But as noted, the evidence does not otherwise point to a better placement for the return on equity within the high and low points set by the expert evidence. [552] The parties to the settlement ag...
AI summary The Board considers a settlement agreement recommending NS Power's current 9% return on equity (ROE) and 40% equity ratio, acknowledging trade-offs while noting the agreement's alignment with expert evidence. Dr. Cleary supports the settlement but emphasizes market-based ROE recommendations. The agreement involves sophisticated parties representing NS Power's rate classes.
3.8 Cost of Service Study [561] Under the PUA , a utility is afforded the opportunity to recover its "reasonable and prudent" costs of providing service and a "just and reasonable" return on its rate base. The total amount of these costs a...
AI summary The section outlines the regulatory framework under the Public Utilities Act (PUA) for cost recovery and rate setting, emphasizing 'reasonable and prudent' cost recovery and 'just and reasonable' returns. It references the Nova Scotia Court of Appeal's decision in Dalhousie Legal Aid Service v Nova Scotia Power Inc. , which prohibits rate discrimination based on customer ability to pay, and highlights factors for grouping customers into classes.
[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.
Fuel Adjustment Mechanism Related Cost Sub-Functionalization Fuel adjustment mechanism related purchases that provide firm capacity will be classified between energy and demand based on the system load factor, while purchases that provide...
AI summary Fuel Adjustment Mechanism (FAM) purchases are classified between energy and demand based on system load factor. Firm capacity purchases are split accordingly, while non-firm imports are fully classified as energy. This aligns with generation asset treatment and recognizes non-firm agreements provide only energy.
Classification of Transmission Costs 100% to Demand NS Power currently uses the system load factor to classify transmission rate base and costs to energy and demand. To reflect anticipated need for increased investment in the transmission...
AI summary NS Power proposes classifying 100% of transmission costs to demand, citing increased transmission investment needs, reduced coal reliance in Cape Breton, higher wind generation, and a shift from radial to network system design. Current classification uses system load factor for energy and demand.
Changes to Open Access Transmission Tarriff to Align Bundled and Unbundled Service NS Power said methodological differences in how rates are set for transmission service in the unbundled market under the Open Access Transmission Tariff (OA...
AI summary NS Power identifies discrepancies in transmission rate methodologies between the OATT and bundled service cost-of-service studies, proposing alignment through equal revenue requirements, full demand cost classification, and forecasted usage application.
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.
Decarbonization Deferral Account NS Power considers its approved decarbonization deferral account to be a rate stabilization tool and proposes that it be classified and allocated in the same manner as other rate stabilization tools. [580]...
AI summary NS Power proposes classifying its approved Decarbonization Deferral Account as a rate stabilization tool. The proposed changes to cost-of-service methodologies negatively impact residential customers, increasing their costs by approximately $26 million in 2026 and $25.3 million in 2027.
[581] The parties to the settlement agreement included the following terms relating to cost-of-service methodology used to determine rates for 2026 and 2027: Cost of Service ("COS") a) The COS as set out in the Draft GRA will be included i...
AI summary The settlement agreement outlines terms related to the cost-of-service methodology for determining rates in 2026 and 2027. It specifies that the Draft GRA will be included in the 2026-2027 GRA and subject to future proceedings, including data collection on PHP's use of the High Voltage transmission system and apportionment of assessment costs from the Maritime Link.
Q. Considering the consensus agreement in this GRA, what do you recommend regarding the Company's COSS methods? A. While I do not support several of the Company's COSS methodologies, particularly the use of the minimum system method for cl...
AI summary The respondent acknowledges a settlement agreement in the GRA but opposes certain COSS methods, advocating for their revision in future proceedings. Renewall Energy Inc. raised concerns about inconsistencies between NS Power's COSS methodologies and OATT charges.
3.8.1 Findings [584] For the purposes of setting rates in this proceeding, the Board accepts the proposed cost-of-service changes and the cost-of-service studies presented in this proceeding, except NS Power is directed to implement a load...
AI summary The Board accepts NS Power's cost-of-service studies but requires adjustments, including a load carrying capability adjustment. NS Power must address concerns from Ms. Palmer and Renewall, particularly regarding distribution cost allocation and OATT tariff issues. These adjustments are to be addressed in future applications.
3.8.2 Minimum System v. Basic Customer Methods [586] NS Power's cost-of-service study classifies portions of its distribution system as customer-related using the minimum system method. Under this approach, a minimum system study estimates...
AI summary NS Power's cost-of-service study classifies distribution system costs using the minimum system method, deeming costs of a hypothetical minimum system as customer-related. The Board considers evidence supporting this approach as standard in Canada, with references to general rate applications and prior studies.
eed to bring electric service to geographically dispersed customer locations." Thus, there is little justification for classifying costs in these accounts as customer-related. [Exhibit N-37, pp. 6-7] [591] Ms. Palmer said the number of pol...
AI summary Ms. Palmer argues that the minimum system method overstates customer-related distribution costs and recommends using the basic customer method instead. NS Power analyzed the impact of this method and found it would shift approximately $30 million in costs from the residential class to other rate classes.
[605] In its submissions, the Consumer Advocate noted: The Consumer Advocate shares Ms. Palmer's concerns regarding the Minimum System Method, and through the Settlement Agreement, and resulting GRA, NS Power has agreed that the use of the...
AI summary The Consumer Advocate supports a separate proceeding for the Minimum System Method, while the NDP and Liberal Caucuses advocate for the basic customer method to fairly allocate distribution costs. NS Power defends using the COSS for cost allocation.
3.8.2.1 Findings [608] Under a cost-of-service model, the objective is to fairly allocate costs to customers based on cost causation. This has been a chronically difficult thing to do for distribution system costs. It would be inappropriat...
AI summary The Nova Scotia Utility and Review Board (Board) finds that neither the basic customer method nor the minimum system method adequately allocates distribution system costs under a cost-of-service model. The Board criticizes NS Power for not addressing this issue in the settlement agreement and requires further information. The matter will be revisited in a future proceeding due to unresolved concerns about cost causation and stakeholder input.
3.8.3.1 Findings [616] As with the discussion about the use of the minimum system method or the basic customer method, the Board finds that a more satisfactory resolution of this issue would result from a broader debate about this issue. T...
AI summary The Board emphasizes the need for a comprehensive analysis of distribution system cost classification, beyond jurisdictional scans. Key issues include how customer classes use the primary distribution system, residential service at primary voltages, and system demand relative to peak capacity. The Board directs these matters to be addressed in the engagement process.
3.8.4 Peak Load Carrying Capability Adjustment [617] Ms. Palmer also recommended that a peak load carrying capability adjustment be applied to account for the demand component served by the minimum system, if the basic customer method is n...
AI summary Ms. Palmer recommends applying a peak load carrying capability adjustment to account for the minimum system's load-carrying capacity, citing examples from Ontario, Excel Energy, and National Grid. NS Power agrees with the theoretical capability of the minimum system. A 1.5 kW/customer adjustment is suggested for infrastructure costs classified via the minimum system study.
Proposed COSS Methodology Modified COSS Methodology as per U-6 Variance Smoo othed Sm oothed Smoo thed Customer Class 2026 2027 2026 2027 2026 2027 Domestic 3.8 4.1 3.2 3.7 (0.6) (0.4) Small General 3.6 3.9 3.4 3.8 (0.2) (0.1) General (0.2...
AI summary The table compares proposed and modified Cost-of-Service Study (COSS) methodologies under Undertaking 6 (U-6), showing variances in cost allocations across customer classes (e.g., Domestic, Large Industrial). The data highlights differences between 2026 and 2027 projections, with significant variations in cost estimates for specific classes. The exhibit (N-77) is referenced as part of the regulatory proceeding.
3.8.4.1 Findings [624] Notwithstanding the settlement agreement, the Board finds that it is appropriate to direct NS Power to implement a load carrying capability adjustment in this proceeding. Unlike the evidence relating to the use of th...
AI summary The Board directs NS Power to implement a 0.4 kW/customer load-carrying capability adjustment, rejecting Excel Energy's 1.5 kW figure as inappropriate. The adjustment must be addressed now, not deferred, and NS Power must conduct further analysis before customer engagement. The decision emphasizes independent evaluation of load-carrying capability, separate from rate impacts.
e only outstanding issue that would be addressed in the future proceeding noted in the agreement was the use of the minimum system method beyond the test years in the current general rate application: - Q. So N-37, page 20 in the PDF, line...
AI summary The discussion focuses on future considerations of Cost-of-Service Study methods beyond the current General Rate Application, specifically the Minimum System method. Nova Scotia Power expects a standalone application in 2026, with parties not bound by prior positions, though avoiding redundant processes is anticipated.
[634] NS Power submitted: NS Power applied the approved OATT and COS methodologies, as amended in the Settlement Agreement, to determine the proposed bundled and OATT charges. The transmission costs are allocated to the bundled rate classe...
AI summary NS Power applied OATT and COS methodologies to allocate transmission costs using 3CP and 12CP approaches. Renewall Energy Inc. raised concerns about a discrepancy in coincident factors (78.6% vs. 91.66%) affecting network service charges. NS Power clarified the factors served different purposes and were not directly used in rate calculations.
3.8.6.1 Findings [640] Because these technical issues were only raised in closing submissions, the Board has a poor record before it to make an informed decision on these points. As a result, the Board accepts the relevant calculations inc...
AI summary The Board accepts NS Power's calculations from the settlement agreement but questions the outdated methodology for OATT rates. Renewall emphasizes the need for competitive electricity markets, while the Board directs NS Power to address these concerns in future applications. The transmission tariff transition to IESO Nova Scotia by 2027 is noted, with the Board highlighting issues around confidential information disclosure in Excel files.
3.9 Rate Design [644] In its application, NS Power did not propose to introduce new concepts or materially change the design of any of its rates. The parties to the settlement agreement accepted the changes to tariff language and the updat...
AI summary NS Power did not propose new rate concepts or major changes. Settlement parties accepted tariff updates and charges. The Board approved these items without further issues.
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.
3.9.1.1 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 emphasizes the need for improvement, citing limited rate options, outdated systems, and the impact of a recent cyber attack. The TVP program's suspension due to data access issues is highlighted, alongside Bonbright's criteria for effective rate structures promoting innovation and efficiency.
3.9.2 Residential and Small General Customer Charges [649] In its last general rate application, NS Power proposed to increase customer charges for the domestic service and small general customer classes to align those charges with costs u...
AI summary NS Power proposed increasing customer charges for residential and small general customer classes to align with costs from its cost-of-service study. Other parties raised concerns, leading to a settlement where charges were set at 75% of the proposed amounts. In the current proceeding, NS Power suggests increasing these charges in line with smoothed non-fuel cost revenue increases for these classes.
Document: 328719 Ι Domestic Service Tariff Capped Customer Charge COSS-based Customer charge Variance Percent Variance 2026 Standard Rate Customer Charge ($/month) $20.24 $29.32 $9.07 45% Energy Charge (cents/kWh) 18.349 17.306 (1.043) -6%...
AI summary The document presents a comparison of customer charges and energy charges under different tariff structures (Capped and COSS-based) for the years 2026 and 2027, highlighting variances in both dollar amounts and percentages for Domestic Service Tariff and Small General Tariff.
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.
3.10.1 OATT [654] NS Power's Open Access Transmission Tariff (OATT) includes terms, conditions and rates for Transmission Services and Ancillary Services. It also includes operating agreements under which service will be provided, and the...
AI summary NS Power updated its Open Access Transmission Tariff (OATT) to reflect changes in revenue requirements and system usage since 2016, proposing methodology changes based on 2024 Cost-of-Service studies and forecasted usage. Amendments aim to align OATT rates with bundled service rates and revise reactive power calculations. The 2023-2024 GRA (M10431) provided directives on OATT and capacity-based ancillary services.
3.10.1.1 Findings [668] As noted above, OATT rates have been updated to reflect changes in the generation and transmission asset mix and costs, and changes in system usage since the last update in the 2023-2024 GRA. NS Power also amended t...
AI summary NS Power updated OATT rates to reflect changes in generation and transmission assets, costs, and system usage since the 2023-2024 GRA. Amendments were made based on consultation in the 2024 Cost of Service proceeding and addressed the Board's directives from M10431. The Board approved the proposed OATT amendments.
3.10.3 Revised Fees and Regulations [685] In its application, NS Power proposed revisions to its Schedule of Charges, such as for connection, reconnection, returned cheques, installation of recording equipment, contribution for three-phase...
AI summary NS Power proposed revisions to its Schedule of Charges, including connection, reconnection, and pole attachment fees, among others. The Board approved these revisions, contingent on prior findings regarding the AMI opt-out fee.
4.1 Demand Side Management Cost Recovery Rider [686] In this GRA, NS Power proposed changes to the methodology for calculating the Balance Adjustment (BA) but did not propose changes to the Demand Side Management (DSM) rider amounts for 20...
AI summary NS Power proposed changes to the Balance Adjustment (BA) methodology without altering DSM rider amounts for 2026/2027. It filed a DCRR application (M12521) for 2026 DSM expenses, with the Board approving continuation of 2025 DCRR charges until further order. The 2026 DSM expenditure was set at $63.75M by legislation, with assumptions extended to 2027. NS Power argued that extending end-of-term variance recovery periods would reduce rate volatility and align with new five-year DSM planning terms.
4.1.1 Findings [693] The Board's Interim Order in Matter M12521 approved continuation of the 2025 DCRR charges commencing January 1, 2026, until further order of the Board in that matter, or as part of NS Power's GRA. In this current matte...
AI summary The Board's Interim Order in Matter M12521 continues 2025 DCRR charges until 2026, with final approval for 2026 rider amounts pending. NS Power proposes changes to the Balance Adjustment (BA) calculation but not DSM rider amounts for 2026/2027. The Board approves amended DCRR tariff amendments to address end-of-term variances and improve DSM cost recovery by allowing E1 to reallocate expenditures between rate classes.
4.3 Climate Change Adaptation Plan [702] The NSUARB, in its decision in NS Power's last general rate application, directed the utility to develop and file a climate change adaptation plan in consultation with interested parties: [339] The...
AI summary The NSUARB directed NS Power to develop a formal Climate Change Adaptation Plan by 2025, citing the need for structured climate resilience measures. The Board noted NS Power's existing steps but emphasized the need for a consultative, formalized plan to support storm cost recovery, enhance capital planning, and align with practices like Hydro-Québec's plan. Costs will be deferred for recovery post-next general rate application.
4.5 Rate Setting – Alternative Form of Regulation [723] In its closing submissions the Nova Scotia Liberal Caucus urged the Board to exercise its statutory authority to move Nova Scotia toward a five-year rate plan that delivers stability,...
AI summary The Nova Scotia Liberal Caucus advocates for a five-year rate plan under the Public Utilities Act, emphasizing stability and fairness. The 2024 amendment allows the Energy Board to approve alternative regulation methods, aligning with the Energy and Regulatory Boards Act's definition of 'alternative form of regulation.'
4.5.1 Findings [726] While the Board appreciates the complexity and challenges, a transition to performance-based rates should be explored. Key goals in such a transition would be the development of more predictable rate setting processes,...
AI summary The Board acknowledges the complexity of transitioning to performance-based rates but emphasizes the need for more predictable rate-setting processes, reduced regulatory burden, and better alignment of utility incentives with customer interests. This transition is framed as a key goal for future consideration.
4.6 Implementation of New Rates (Cyber Incident Impact) [727] At the hearing, NS Power said that it now has communication with roughly 400,000 of its customer meters and has targeted the end of March to have all meters (approximately 555,0...
AI summary NS Power discussed implementing new rates affected by a cyber incident, noting challenges in prorating rate changes due to extended meter reading intervals. It acknowledged potential for higher charges during colder periods but emphasized progress with AMI technology, though historical data storage is limited to 60-90 days.
4.6.1 Findings [730] The Board is concerned that customers who have higher usage during the recent colder period of the year might end up paying more than the approved current rate for the electricity they are currently using because of th...
AI summary The Board is concerned that prorating electricity bills during a rate increase may unfairly burden customers with higher usage during colder periods, especially after a cyber attack prolonged meter reads. With AMI meters, precise energy usage tracking before and after rate changes should avoid prorating. The Board directs NS Power to justify prorating in its compliance filing or use AMI data to apply approved rates based on actual consumption timing.
ce captured under the FAM; - The EIFEL deferral, allowing NS Power to defer incremental tax expense of about $7 million if an exemption is not enacted by the Government of Canada as it has announced; - The inclusion of four Maritime Link t...
AI summary The Nova Scotia Utility and Review Board approved adjustments to Nova Scotia Power Inc.'s rate base, including Maritime Link transmission projects, revised Storm Cost Recovery Rider terms, OATT rate updates, and tariff language changes. Amendments to the General Rate Application and cost allocation among customer classes were also mandated.
6.0 COMPLIANCE FILING [736] NS Power is to file a compliance filing based on the Board's findings in this decision. The compliance filing is to include, among other things: - A further reduction of $8 million in Operating, Maintenance and...
AI summary NS Power is required to file a compliance filing based on the Board's findings, including reductions in operating expenses, executive compensation, and fuel costs, as well as adjustments to the FAM POA and tariff. The Board approved the rates for 2026 and 2027, but emphasized the importance of timely filings to avoid confusion for customers.
101825Board Order
49 passages
The Board orders that: - 1. The application is approved, except where inconsistent with the Board's findings and directions in its decision. - 2. A return on equity of 9.0% and an equity ratio of 40% are approved for rate setting purposes,...
AI summary The Board approves the application with specific conditions, including a 9.0% return on equity, a 40% equity ratio, and a securitization deferral for depreciation and financing costs related to coal plants and thermal assets starting May 1, 2026.
DOMESTIC SERVICE TARIFF Page 1 of 2 Rate Codes 02, 03, 04
AI summary The document outlines the Domestic Service Tariff, specifically Rate Codes 02, 03, and 04. It provides information on the rates applicable to domestic service customers in Nova Scotia.
AVAILABILITY This tariff is applicable to electric energy used by any customer in a private residence for the customer's own domestic or household use, including lighting, cooking, heating, or refrigeration purposes. Upon application to th...
AI summary The Domestic tariff applies to electric energy used in private residences for domestic purposes. It may also apply to outbuildings on residential property, depending on their primary use. If used for commercial purposes, the General or Industrial tariff applies instead.
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 customers to shift their electricity usage from peak to off-peak periods. It is available to those eligible under the Domestic Service Tariff.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-6-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Effective December 1, 2025, Nova Scotia Power will implement an Interim Energy Charge as per the Nova Scotia Energy Board's decision on its Time-varying Pricing Tariffs. The Interim Charge applies during both winter and non-winter periods and is set to standard offer rates. Critical Peak Events will not be scheduled during this period, and NS Power must notify customers when system functionality is restored.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event Non-critical Peak Hours Effective upon the date of the Board's Order n/a 18.324 1 M12499 – Board Decision, 325286, page 5. October 28, 2025.
AI summary The document presents an interim energy charge structure, specifying a rate of 18.324 cents per kilowatt-hour for non-critical peak hours, with a separate rate during critical peak events. A reference is made to a Board Decision (M12499) dated October 28, 2025.
ENERGY CHARGE cents per kilowatt-hour During a Critical Peak Event Non-critical Peak Hours Effective November 1, 2026 182.067 15.411 Effective January 1, 2027 191.990 15.956 The Critical Peak Event is of a four-hour duration and can be cal...
AI summary The document outlines the energy charge rates for Critical Peak Events and non-critical peak hours, effective from November 1, 2026, and January 1, 2027. A Critical Peak Event is defined as a four-hour period during the Winter Period, between 6:00 AM and 11:00 PM, on any day of the week.
The Critical Peak Event pricing applies when a Critical Peak Event is called. In all other hours in the Winter Period, and for all hours in the Non-Winter Period, the rate shall be the Non-critical Peak Hours rate in the table above.
AI summary The text outlines the application of Critical Peak Event pricing, which is only applicable during a Critical Peak Event. Outside of these events, the Non-critical Peak Hours rate applies during the Winter and Non-Winter periods.
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 and when Critical Peak Events are scheduled during the Winter Period, excluding certain holidays and weekends. Customers are notified in advance, and a higher energy charge applies during these events to encourage reduced electricity usage.
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 customers to shift their electricity usage from peak to off-peak periods. It is available to those eligible under the Domestic Service Tariff.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-10-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Effective November 1, 2025, the Nova Scotia Energy Board's decision on NS Power's Time-varying Pricing (TVP) Tariffs (M12499) introduces an Interim Energy Charge during system functionality outages, with specific provisions for rate restoration based on when functionality is restored.
Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-18-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Effective December 1, 2025, the Nova Scotia Energy Board's decision on NS Power's 2025/26 Time-varying Pricing (TVP) Tariffs (M12499) outlines the application of an Interim Energy Charge, restrictions on Critical Peak Events, and procedures for notifying customers once system functionality is restored.
cents per kilowatt-hour Interim Energy Charge During a Critical Peak Event For the first 200 kilowatt-hours per month For all additional kilowatt-hours Effective upon the date of the Board's Order n/a 18.919 17.112 1 M12499 – Board Decisio...
AI summary The document outlines an interim energy charge structure, with different rates during critical peak events and for varying levels of kilowatt-hour consumption. It references a Board Decision (M12499) dated October 28, 2025, which is effective upon the date of the Board's Order.
Rate Code 72 cents per kilowatt-hour For the first 200 During a kilowatt-hours per Critical Peak month after Critical Event Peak Event usage For all additional kilowatt-hours Effective November 1, 2026 151.941 16.739 15.331 Effective Janua...
AI summary Rate Code 72 outlines a tiered pricing structure for electricity during Critical Peak Events, effective from November 2026 to January 2027. The rate increases significantly for the first 200 kilowatt-hours used during these events, with additional usage charged at a lower rate.
SMALL GENERAL CRITICAL PEAK PRICING TARIFF Page 4 of 4 Rate Code 72 - (e) The customer cannot be taking seasonal service from NSPI under Regulation 3.3. - (f) The customer cannot be taking Net Metering service from NSPI under Regulation 3....
AI summary The Small General Critical Peak Pricing Tariff outlines eligibility criteria, specifying that customers cannot be on seasonal service or Net Metering service under specific regulations.
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 Small General Tariff.
AI summary This optional tariff aims to encourage customers to shift their energy usage from peak to off-peak periods. It is available to those eligible under the Small General Tariff.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-22-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in all...
AI summary Starting November 1, 2025, the Nova Scotia Energy Board's decision on NS Power's 2025/26 Time-varying Pricing (TVP) Tariff application introduces an Interim Energy Charge during system unavailability, modifies billing procedures for Small General Time of Use Tariff customers, and outlines rate restoration timelines contingent on system functionality restoration.
DEMAND CHARGE per month per kilowatt of maximum demand Effective upon the date of the Board's Order $9.809 Effective January 1, 2027 $10.697 32 cents per kilowatt reduction in demand charge where the transformer was owned by the customer p...
AI summary The document outlines the demand charge rates effective upon the Board's Order and on January 1, 2027. It also includes a reduction in demand charge for customers who own transformers predating February 1, 1974, or under Special Condition (2).
MAXIMUM PER KWH CHARGE/MINIMUM BILL The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall not be less than the rates in the table below.
AI summary The document outlines the maximum charge per kWh based on a 10% billing load factor, with a stipulation that the minimum monthly bill cannot fall below specified rates listed in a table.
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 their energy usage from peak to off-peak periods. It is available to customers eligible for service under the General Tariff.
DEMAND CHARGE per month per kilowatt of maximum demand Effective upon the date of the Board's Order $9.809 Effective January 1, 2027 $10.697 32 cents per kilowatt reduction in demand charge where the transformer was owned by the customer p...
AI summary The document outlines the demand charge rates effective from the date of the Board's Order and January 1, 2027, along with a reduction credit for customers with transformers owned prior to 1974 or under a specific special condition.
INTERIM ENERGY CHARGE Effective December 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-27-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy...
AI summary The Interim Energy Charge, effective December 1, 2025, applies during both winter and non-winter periods and is set to standard offer rates until system functionality is restored. Critical Peak Events are suspended during this period, with specific provisions depending on when functionality is restored.
1 M12499 – Board Decision, 325286, page 5. October 28, 2025. Interim Energy Charge During a Critical Peak Event For the first 200 kilowatt hours per month per maximum demand For all additional kilowatt-hours Effective upon the date of the...
AI summary The document outlines the interim energy charge rates during a Critical Peak Event, specifying different rates for the first 200 kilowatt-hours per month per maximum demand and for all additional kilowatt-hours, with effective dates in October 2025 and November 2026.
MAXIMUM PER KWH CHARGE/MINIMUM BILL The maximum charge per kWh, applying to that portion of the bill which is not concerned with determination of the cost of the Critical Peak Events, will be that for a billing load factor of 10% except th...
AI summary The document outlines the maximum charge per kWh, which applies to portions of the bill not related to Critical Peak Events. The charge is based on a billing load factor of 10%, with a specified minimum monthly bill.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill shall not be less than the following. per month Effective upon the date of the Board's Order $22.00 Effective January 1, 2027 $22...
AI summary The document sets a maximum charge per kWh based on a billing load factor of 10%, with a minimum monthly bill of $22.00 upon the Board's Order and $22.73 effective January 1, 2027.
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 monthly 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.
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 $2...
AI summary The document outlines a charge applicable to customers connected at the distribution level, with specific rates effective from the Board's Order and January 1, 2027. It also mentions a reduction in demand charge for customers owning the transformer.
INTERRUPTIBLE RIDER TO THE LARGE INDUSTRIAL TARIFF (RATE CODE 25) Customers who qualify for interruptible service will receive a per month per kilovolt ampere reduction in demand charge for billed interruptible demand, as shown in the tabl...
AI summary The Interruptible Rider to the Large Industrial Tariff (Rate Code 25) provides a monthly reduction in demand charges for customers qualifying for interruptible service. The reduction is based on the difference between contracted firm demand and billing demand, with specific rules for calculating billed interruptible demand.
(c) Operating Only kWh per per month ($) Rate Code Watts month 2026 2027 Other 301 125 52 9.98 10.60 302 175 69 13.24 14.06 303 250 97 18.62 19.77 304 400 154 29.56 31.38 305 700 260 49.90 52.98 306 1,000 363 69.67 73.97 (3) Fluorescent
AI summary The text presents a table outlining rate codes with corresponding wattage, kWh per month, and associated costs for the years 2026 and 2027. The table includes various rate codes and their respective pricing structures, likely related to electricity tariffs.
The maximum charge per kWh will be that for a billing load factor of 10% except that the minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate shall be $ as follows per month if such unmetered se...
AI summary The text outlines a regulation regarding the maximum charge per kWh based on a billing load factor of 10%, with a specified minimum monthly bill for the electric power and energy portion of the Miscellaneous Lighting Rate when billed separately.
Maintenance Charge (if applicable) Cost of normal fixture maintenance and bulb replacement on the basis of current cost levels shall be used to calculate the monthly maintenance charge. This portion of the rate does not include any provisi...
AI summary The maintenance charge covers the cost of normal fixture maintenance and bulb replacement based on current costs, excluding globe washing or cleaning. Vandalism-related repairs are the customer's responsibility.
(1) Base Cost of Fuel The Base Cost of Fuel can be re-set in a General Rate Application or, absent a General Rate Application, every second year as part of the FAM adjustment process. Changes in the Base Cost of Fuel will be reflected in c...
AI summary The Base Cost of Fuel can be reset through a General Rate Application or every second year via the FAM adjustment process. Adjustments to this cost will be reflected in customer rates and applied consistently across customer classes using the Board-approved Cost of Service Methodology.
2026 Effective upon the date of the Board's Order Rate Class Actual Adjustment (AA) in cents per kWh Balance Adjustment (BA 1) in cents per kWh Balance Adjustment (BA-2) in cents per kWh FAM AA/BA Combined in cents per kWh Domestic Service...
AI summary The document presents a table outlining various rate classes and their corresponding balance adjustments (BA) and fuel adjustment mechanism (FAM) values in cents per kWh, effective upon the date of the Board's Order and January 1, 2027.
Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Regulation is equal to 3.5 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.5 percent of...
AI summary The document outlines customer obligations for self-supply and third-party supply under Nova Scotia's transmission services, specifying percentages of reserved capacity and network load for both Point-to-Point and Network Integration Transmission Services.
SCHEDULE 9: REAL POWER LOSS FACTORS For Point-to-Point service, the Transmission Provider will seasonally calculate loss factors to be used on a path-by-path basis. For each season, winter and summer, the power flow models used to calculat...
AI summary Schedule 9 outlines the methodology for calculating real power loss factors for Point-to-Point and Network Service, including seasonal and annual loss factors, and the application of locational loss factors for new generation. It also describes the rate for Network Integration Transmission Service and the formula for transmission congestion charges.
3. SCOPE OF THE DISTRIBUTION TARIFF The Distribution Tariff is applicable to all RtR Customers connected to the Distribution System. This Distribution Tariff is not applicable to RtR Customers directly connected to the Transmission System...
AI summary The Distribution Tariff applies to all RtR Customers connected to the Distribution System, excluding those directly connected to the Transmission System, which must arrange access under the OATT. The tariff outlines terms and conditions for Distribution System Access and retail services.
7. NS POWER RESPONSIBILITIES NS Power shall be responsible for: - (a) provision of Distribution System Access; - (b) processing RtR Customer Transaction Request Applications that are received from an LRS on behalf of the RtR Customer; - (c...
AI summary NS Power is responsible for distribution system access, processing customer transaction requests, providing billing data, and acting as a point of contact for RtR Customers. However, it is not responsible for supplying electricity or enforcing contracts between RtR Customers and LRS.
10.1 Provision and Ownership NS Power will provide, install and seal all revenue class meters as necessary for application of this Distribution Tariff. The meters will be used for determining charges for Distribution System Access under th...
AI summary NS Power is responsible for providing, installing, and sealing revenue class meters for RtR Customers under the Distribution Tariff. These meters must meet regulatory requirements and remain NS Power's property. Interval meters with remote polling capabilities are required for all RtR Customers.
11.1 Application of Distribution Tariff Rates The Distribution Tariff amounts payable by the RtR Customer will be calculated by NS Power using the RtR Customer's meter readings and the Distribution Tariff Rate Schedule applicable to the Rt...
AI summary The Distribution Tariff amounts payable by the RtR Customer are calculated based on meter readings and applicable rate schedules. If the customer's operational or consumption characteristics change, NS Power will adjust the tariff rate accordingly.
11.2 Billing Unless NS Power directs otherwise, the RtR Customer shall be invoiced by the LRS and will pay the LRS for any charges or fees, inclusive of all applicable taxes, owing by the RtR Customer to NS Power under this Distribution Ta...
AI summary The text outlines billing procedures for RtR Customers under the Distribution Tariff, specifying that they are invoiced by the LRS and must pay all applicable charges, including Demand Side Management Cost Recovery Charges and Storm Cost Recovery Charges, among others. The RtR Customer also agrees not to hold NS Power liable for billing actions taken by the LRS.
11.3 Real Power Losses Distribution System Real Power Losses associated with Distribution System Access are incorporated in the Distribution Tariff rates applicable to each RtR Customer's rate class. The RtR Customer is responsible for the...
AI summary Real power losses in the distribution system are included in the distribution tariff rates for each RtR customer's rate class, and the RtR customer is responsible for these costs.
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.
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.
Conditions Effective: January 1, 2026 - 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). - Fo...
AI summary The conditions outlined apply to bundled service customers, distinguishing between those in the Wholesale Market and others. The approach applies to classes as a whole for non-Wholesale Market customers and to individual customers for those in the Wholesale Market. It also applies to total Approved DSM costs.
1. The Actual Adjustment Component (AA) a. Established at a rate expected to recover the amount of the difference between the prior FAM year's actual fuel and purchased power costs and those recovered through the Base Cost of Fuel Componen...
AI summary The Actual Adjustment Component (AA) is established to recover the difference between the prior Fuel Adjustment Mechanism (FAM) year's actual fuel and purchased power costs and those recovered through the Base Cost of Fuel Component over a 12-month period.
2. The Balancing Adjustment Component (BA) - a. The Balancing Adjustment Component will provide for a correction to ensure that over/under-recovery produced by the Actual Adjustment Component is tracked and refunded to or recovered from cu...
AI summary The Balancing Adjustment Component (BA) is designed to correct over/under-recovery from the Actual Adjustment Component and may include deferrals of fuel and purchased power costs, subject to Board approval. It becomes effective May 1, 2026.
3.0 CALCULATION OF THE FAM RATE NS Power's FAM is a forecasted base fuel rate operating on an annual cycle that includes an over/under recovery mechanism consisting of an Actual Adjustment (AA) and Balance Adjustment (BA). The following fo...
AI summary This section outlines the Fuel Adjustment Mechanism (FAM) used by NS Power, detailing how the FAM rate is calculated annually using an Actual Adjustment (AA) and a Balance Adjustment (BA). The mechanism includes deferral of over- or under-recovery amounts and allocation of fuel-related costs to specific rate classes.
Wholesale Market Backup/Top-up Service Tariff (BUTU). - 2. For ATL and BUTU classes the following costs and credits - a. NS Power's plant fuel costs - b. costs of biofuels of purchased biomass generation - c. non-firm imports costs - d. ex...
AI summary The Wholesale Market Backup/Top-up Service Tariff (BUTU) outlines how various costs and credits, including fuel costs and import costs, are classified and allocated to different classes based on their energy contribution and load factors. The allocation method ensures alignment with revenue from approved rates using a revenue-to-cost ratio.
99748NSEB (NSPI) IR 1 to 152
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NOVA SCOTIA ENERGY BOARD IN THE MATTER OF: THE PUBLIC UTILITIES ACT - and - IN THE MATTER OF: A GENERAL RATE APPLICATION by NOVA SCOTIA POWER INCORPORATED for approval of certain revisions to its Rates, Charges and Regulations
AI summary The Nova Scotia Energy Board is considering a general rate application by Nova Scotia Power Incorporated under the Public Utilities Act, seeking approval for revisions to its rates, charges, and regulations.
Request IR-4: - The following directive has been issued by the Board since the last general rate application with - a bring forward date for the next general rate application (and was not outlined in Appendix 3A). - Please outline how this...
AI summary The Board has issued a directive since the last general rate application, requiring NS Power to address the bring forward date for the next application. Specifically, in matter M11598, NS Power must describe how the 191-253 engine refurbishment costs were considered in depreciation studies and estimate the rate impact of any depreciation rate adjustments.
Request IR-5: - a) Related to the directive in IR-4, please explain how NS Power considered the costs of the LM 191-332 engine refurbishment and LM 191-443 engine replacement (Matter M12416) in setting depreciation rates. - b) Please ident...
AI summary Request IR-5 asks NS Power to explain how engine refurbishment and replacement costs (Matter M12416) were considered in depreciation rate calculations and to identify estimated rate impacts of proposed depreciation rate adjustments.
Request IR-8: - Reference: Exhibit N-3 GRA Direct Evidence, Section 1.2 Overview of 2026-2027 GRA - On page 10 of the application, NS Power compares the proposed rate impacts of this GRA to recent annual average rate increases experienced...
AI summary The document requests NS Power to identify Atlantic Canadian utilities referenced in its rate comparisons, specify their rate increases since 2023, and compare annual rates for a residential customer across 2025-2027, including all riders. It focuses on rate impacts and comparator utility analysis.
Request IR-12: - Reference: Exhibit N-3 GRA Direct Evidence, Section 1.4 Reliability and System Strength - On page 11 NS Power notes that over 65 community meetings were held throughout Nova Scotia - to discuss reliability and understand c...
AI summary Request IR-12 seeks information on NS Power's community engagement for reliability planning, VoLL data improvements, customer satisfaction metrics, reliability investments, revenue requirements, and cost recovery methods for the Reliability Intertie project. It references prior board matters and requests data validation, including outage numbers and reliability calculation methodologies.
Request IR-26: Reference: Exhibit N-3 GRA Direct Evidence, Section 5 Fuel and Purchased Power - On page 27 of the application, NS Power states, "To facilitate having more uniform increases - across the two test years, NS Power has adjusted...
AI summary NS Power adjusted fuel rates to smooth increases over two years, leading to overcollection in 2026 and undercollection in 2027. The regulator requests confirmation on whether non-fuel costs were smoothed, the impact on FAM balance, future fuel cost adjustments, and necessary rate increases in 2028.
References: - 1. On pages 21 and 98 of the application, NS Power seeks Board approval of "administrative" changes to the introduction to Appendix Q (the Hedging Plan) of the Fuel Manual. - 2. On page 35 of Appendix 5A, NS Power notes there...
AI summary NS Power seeks Board approval for changes to its Hedging Plan in the Fuel Manual. The document questions legislative requirements for Board approval of hedging strategies, references a 2016 Board decision (2016 NSUARB 129) on the Fuel Stability Plan, and asks whether NS Power's proposed changes are for information or formal approval. It highlights statutory obligations under the EPIA and the role of the Fuel Adjustment Mechanism (FAM).
Request IR-33: - Reference: Exhibit N-5, Appendix 6A (FAM Framework) and 6B (FAM Plan of Administration) - NS Power proposes a change to s. 3.2.8 of the FAM POA to include costs associated with renewable energy programs (e.g., on bill cred...
AI summary NS Power proposes to include renewable energy program costs in the FAM POA. The request asks how to distinguish recoverable from non-recoverable costs and the appropriateness of additional language about costs not recoverable from participants.
Request IR-34: - Reference: Exhibit N-3, GRA Direct Evidence, Section 6 Fuel Adjustment Mechanism and - Appendix 6B - NS Power notes that it has proposed changes to the FAM Plan of Administration to move some - costs previously included in...
AI summary NS Power proposes moving certain costs from OM&G to the FAM, but the Board staff notes that ash hauling and Tufts Cove Wharf costs were added to the POA, requiring a GRA (M11127) for FAM inclusion. The Board requests confirmation of all proposed cost movements, 2024 GRA amounts, and clarification on OM&G forecast adjustments for 2026/2027.
Request IR-35: - Reference: Exhibit N-5, Appendix 6A Fuel Adjustment Mechanism Plan of Administration, Section - 3.1 - Why has NS Power removed the reference to carrying costs being paid by customers paying a - balance owing over time?
AI summary The document raises a question about NS Power's removal of a reference to carrying costs being paid by customers with outstanding balances in the Fuel Adjustment Mechanism Plan of Administration, specifically in Exhibit N-5, Appendix 6A, Section 3.1.
Request IR-36: - Reference: Exhibit N-3 GRA Direct Evidence, Section 2.2 FAM Treatment - a) Please reconcile the forecast total FAM balance owing from customers at the end of 2025 of approximately $94 million (from the August 2025 monthly...
AI summary The document requests clarification on the Fuel Adjustment Mechanism (FAM) balance, incorporation of receivables into BCF amounts, and confirmation of NS Power's intention to file a FAM AA/BA application by Q4 2025, along with its implications.
Request IR-37: - Reference: Exhibit N-3 GRA Direct Evidence Appendix 5A - Prior general rate applications have included a Fuel Update in late August of the filing. - a) Please provide the date on which the fuel and purchased power assumpti...
AI summary Request IR-37 seeks the date for fuel and purchased power assumptions in the GRA application, referencing Exhibit N-3. Prior applications included a Fuel Update in late August. The GRA application's assumptions are under scrutiny for alignment with historical practices.
Request IR-38: - Reference: Exhibit N-3 GRA Direct Evidence Appendix 5A - On page 34 of Appendix 5A, the application states that NSPML's forecast assessments for the - Maritime Link against NS Power are $200.5 million in 2026 and $203.9 mi...
AI summary Request IR-38 asks NSP to explain the increase in Operating & Maintenance costs from $21.7 million in 2026 to $29.0 million in 2027, referencing Exhibit N-3 GRA Direct Evidence Appendix 5A and mentioning the Maritime Link and Federal Loan Guarantee.
Request IR-40: - Reference: Exhibit N-3 GRA Direct Evidence, Section 1.1 Support for 2026-2027 GRA - On page 8 of the application, NS Power notes that the GRA does not include costs related to the - cybersecurity attack. While not included...
AI summary NS Power states that the GRA for 2026-2027 does not include costs from a cybersecurity attack. The request seeks a detailed breakdown of these anticipated costs and recent forecasts.
Request IR-42: - a) Please provide a listing showing the total number of 2026 forecast full-time equivalent employees (FTEs) included in each operating expense category compared to current (2025) actuals and the numbers included in the 202...
AI summary Request IR-42 seeks data on 2026 FTE forecasts compared to 2025 actuals and 2024 compliance filings, including variances and explanations for increases over 10%.
Request IR-46: - a) Please identify the amount budgeted in proposed rates for OM&G costs for vegetation management in 2026 and 2027. - b) Please provide a table showing the amount of OM&G funds spent on vegetation management for each year...
AI summary Request IR-46 seeks information on budgeted and historical spending for vegetation management OM&G costs (2026-2027 and 2019-2024), with a requirement to separate distribution and transmission funds, and similar data on capital funds for routines and work orders.
Request IR-50: - Reference: Exhibit N-3 GRA Direct Evidence, Section 7.3 Five-Year Operating Cost Forecast - On page 36, NS Power stated that "The consensus approach to this GRA results in a greater - year-over-year increase from 2027 to 2...
AI summary NS Power's GRA includes a Five-Year Operating Cost Forecast with significant increases from 2027 to 2028. The request seeks explanations for the forecast's variance, itemization of cost components, and the 2029-2030 cost reduction.
Request IR-56: - Reference: Exhibit N-6 Appendix 7A - On page 27 of Appendix 7A, NS Power advises it has increased expense in Grid Modernization - and Customer Integration to hire seven additional employees on the Customer Experience team...
AI summary NS Power is increasing expenses by hiring employees for customer experience and data analytics to expand services and improve asset management. The request asks about new services and whether the outdated Customer Information System (CIMS) limits rate expansion, referencing Matter M11884.
Request IR-58: - Reference: Exhibit N-6, Appendix 7A, page 7 of 37 - NS Power notes a significant increase in the utilization of thermal plants and combustion turbines, - which was 4,525 GWh estimated capacity and 6,148 GWh used capacity,...
AI summary NS Power notes increased utilization of thermal plants and combustion turbines, leading to higher operating expenses in 2024. The request asks for explanations, mitigation plans, and future expense projections.
Request IR-63: - Reference: Exhibit N-6(ii), Regulatory Affairs - The consulting expense forecast for 2026 is 57% higher than 2024 compliance and slightly below 2024 actuals. Board staff assumes that much of the work leading into the GRA w...
AI summary The consulting expense forecast for 2026 is 57% higher than 2024 compliance but slightly below 2024 actuals. Board staff assumes significant GRA-related work (e.g., depreciation, line loss studies) was completed in 2024. The request asks why expenses remain stable despite expecting greater regulatory work volume and scope in 2026-2027.
Request IR-78: - Reference: Exhibit N-3, GRA Direct Evidence - On page 35, NS Power states "Information Technology costs per business entity full-time - equivalent employee is significantly below the utility industry median". a) Please exp...
AI summary NS Power's assertion that IT costs per FTE are below the industry median is questioned in the context of a recent cybersecurity incident, as part of Exhibit N-3 in the GRA Direct Evidence. The significance of this statement is under scrutiny.
Request IR-85: - Reference: Exhibit N-7, Appendix 8E - a) Please explain the difference between the estimated costs to fully decommission NS Power's hydroelectric system on page 18 of 33 of Appendix 8B and page 14 of 129 of Appendix 8C, an...
AI summary Request IR-85 seeks clarification on NS Power's hydro decommissioning cost estimates, differences between full and partial decommissioning costs, documentation supporting partial decommissioning claims, and justification for potential risks to customers and shareholders if full decommissioning is required.
Request IR-86: - Reference: Exhibit N-7, Appendix 8E - NS Power notes it has excluded the costs of decommissioning the Wreck Cove, Mersey and Tusket hydroelectric assets from the proposed depreciation rates. - a) Please reconcile the decom...
AI summary NS Power excluded decommissioning costs for Wreck Cove, Mersey, and Tusket hydroelectric assets from proposed depreciation rates, prompting questions about cost recovery, customer impact, and the 80% renewable electricity standard's justification for perpetual asset operation. Regulators seek reconciliation of costs, documentation on decommissioning obligations, and explanations for future customer risk.
Request IR-97: - Reference: Exhibit N-3, GRA Direct Evidence - On page 61 of the application, NS Power states that since the Maritime Link transmission projects - have met the Board's threshold test, the transmission assets are forecast in...
AI summary NS Power asserts that Maritime Link transmission projects meeting the Board's threshold test justify forecasting transmission assets at their net book value in the GRA. The request seeks a continuity schedule detailing the opening rate base amount for inclusion in the GRA forecast starting January 1, 2026.
Request IR-100: - Section 30(5)(b) of the Public Utilities Act directs the Board to set different levels of return on - equity for different classes of capital assets of NS Power to ensure that investment incentives are - aligned with rate...
AI summary The Board is directed by Section 30(5)(b) of the Public Utilities Act to set different return on equity levels for NS Power's capital assets. The request asks NS Power to detail how it addressed this requirement in its application.
Request IR-119: - Reference: Exhibit N-8, Appendix 10A, CEA exhibits EO, CEA Summary -1 - In CEA Summary -1, why do the proxies use calculated ROEs instead of their Regulated ROE? - a) Please provide the approved ROE for each proxy company...
AI summary The document requests clarification on why proxies in CEA Summary -1 use calculated ROEs instead of the approved Regulated ROE, asking for the approved ROE for each proxy company in CEA-1.
Request IR-121: - Reference: Exhibit N-8, Appendix 10A, CEA-5 Multi-Stage DCF - CEA-5 Multi-Stage DCF, column [9] uses a GDP Growth (perpetuity) from Consensus Economics - Consensus Forecast October 7, 2024, for 2030-2034 = (GSP x (1+ CPI)...
AI summary The document questions the scope of GDP and CPI estimates in the CEA-5 Multi-Stage DCF model, specifically whether Canada Proxy Group data applies to Canada, Nova Scotia, or the U.S., and why the Bank of Canada's inflation target midpoint is not used. It also references Proxy Group formulas for Canada and the U.S.
COST OF SERVICE
AI summary The document pertains to a regulatory proceeding analyzing the cost of service for Nova Scotia Power Inc. (NSP), involving entities, programs, and mechanisms such as the Fuel Adjustment Mechanism (FAM) and Renewable to Retail (RTR). Key stakeholders include NSP, the Canada Revenue Agency (CRA), and regulatory bodies like NERC.
Request IR-128: - Reference: Exhibit N-3 GRA Direct Evidence, Section 12 Cost of Service, p.76 - NS Power notes that "the Parties are in agreement that the use of the Minimum System - methodology after the 2026-2027 test period will be sub...
AI summary NS Power and the Board agree that the Minimum System methodology's use post-2026-2027 will be determined in a future proceeding. The Board anticipates a thorough review after NS Power's 2025 cost-of-service study. Questions are posed regarding the impact of reclassifying distribution classifications to 100% demand and the resulting percentage increases by customer class.
Request IR-129: - Reference: Exhibit N-3 GRA Direct Evidence, Section 12.4 PHP COSS Treatment - On page 79 of 99, NS Power stated: In addition, PHP's ATL treatment includes the value of priority interruption service provided, if any. For t...
AI summary NS Power's GRA Direct Evidence (Exhibit N-3, Section 12.4) explains the 10% premium applied to LIIR credit for priority interruption service. Questions seek clarification on differences from current practices, interruption data (2022-2025 YTD), and the rationale for the 10% premium.
Request IR-130: - Reference: Exhibit N-3 GRA Direct Evidence, Section 12.4 PHP COSS Treatment - On page 80 of the application, NS Power proposed a PHP Deferral account for revenue variances - between Board-approval of a tariff for PHP to b...
AI summary The text outlines a request (IR-130) addressing NS Power's proposed PHP Deferral account for revenue variances related to the General Rate Application (GRA). Questions are raised about the assumptions in the tariff, isolating revenue variances, and estimating deferred amounts by month if PHP doesn't take service under an above-the-line rate.
Request IR-131: - Reference: Exhibit N-3 GRA Direct Evidence, Section 2.1 Electricity Rate Impact - Regarding Figure 2-1 of the application, please identify and quantify the specific factors that are - causing rate increases for Domestic C...
AI summary Request IR-131 seeks clarification on factors causing Domestic Class electricity rate increases approximately double the system average, referencing Exhibit N-3 of the GRA Direct Evidence under Section 2.1 Electricity Rate Impact.
Request IR-132: - Reference: Exhibit N-3 GRA Direct Evidence, Section 13 Rate Design - On page 81 of the application, NS Power notes it is not proposing to introduce new concepts or - materially modify any of its rate design. Please descri...
AI summary The document requests NS Power to describe any work done on innovative rate designs leveraging AMI meters, efficient resource use, and addressing market changes due to decarbonization and decentralization, despite NS Power's assertion of not proposing new concepts or modifications.
Request IR-133: - Reference: Exhibit N-3 GRA Direct Evidence, Section 13 Rate Design - On page 81 of the application, NS Power notes its proposed increases in the customer charges - for domestic and small general customers have been capped...
AI summary NS Power proposes capped increases in customer charges for domestic and small general customers relative to 2026-2027 COSS. They request a table showing the differences in dollars and cents/kWh between proposed rates and COSS-based rates.
Request IR-134: - Reference: Exhibit N-3 GRA Direct Evidence, Section 13 Rate Design - On page 81, NS Power stated: If the customer charges were to be set directly based on changes in the customer-related costs from the 2026-2027 COSS, the...
AI summary NS Power's explanation for a 50% increase in customer charges in 2026 and a single-digit increase in 2027 under the GRA Direct Evidence, Section 13 Rate Design.
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.
Request IR-136: - Reference: Exhibit N-4, PR-01 Attachment 01D, Domestic Service Time-of-Day Tariff - a) Please provide a copy of the charges as originally approved for this tariff and explain the rationale used to set the peak, shoulder,...
AI summary Request IR-136 seeks details on the Domestic Service Time-of-Day Tariff, including original charges, percentage comparisons of shoulder and off-peak rates relative to peak rates for 2026 and 2027, and justifications for any changes.
Request IR-137: - Reference: OATT Updates SR-01 Attachment 1e - On page 32 of 42, NS Power stated: However, as part of developing this consensus GRA, it was agreed that for the 2026-2027 test periods the costing approach will utilize 50 pe...
AI summary NS Power's GRA proposes using 50% of estimated average hourly demand for LIIR interruptible load as 10-minute operating reserve, reducing supplemental capacity from 136 MWs to 101 MWs. The request seeks clarification on the rationale for selecting 50% and the financial impact of this adjustment.
Request IR-138: - Reference: OATT Updates SR-01 Attachment 1e - On page 42 of 42, NS Power stated: … NS Power conducted an analysis of historical day-ahead dispatch plans for the years 2021 to 2023. On average, the Combustion Turbines (CTs...
AI summary NS Power adjusted cost allocation for 30-Minute Supplemental Reserve based on Combustion Turbines' contribution (35% hourly). OATT requests clarification on dollar impact, demand charge decreases in 2026, and details about extending the Storm Cost Recovery Rider (SCRR) pilot. Questions focus on cost recovery mechanisms, pilot success metrics, and alignment with regulatory frameworks like the Public Utilities Act.
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.
Request IR-150: - Reference: Exhibit N-8, Appendix 13C - NS Power stated there are approximately 18,140 opt-out customers who continue to have their meters read manually at the meter every other month (i.e., six readings per meter). It als...
AI summary NS Power's proposal to reduce manual meter readings from six to two per year for opt-out customers would lower annual reads to 33,333, with estimated costs of $22/year ($1.83/month). However, the proposed $3.81/month fee is over double the actual cost, raising questions about where the additional costs are incurred.
REGULATIONS Request IR-152: - Reference: PR-03 Attachment 01c - Attachment 01c shows NS Power's proposed increases to its Schedule of Charges (Regulation - 7.1). Those proposed increases cover a wide range, some around 6%, while other are...
AI summary The document requests specific justifications for NS Power's proposed rate increases (ranging from 6% to 50%) under Regulation 7.1 and seeks clarification on differing charges for items a) and e) for customers with remote connect-enabled meters.
101354Board Decision
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IN THE MATTER OF THE PUBLIC UTILITIES ACT - and - IN THE MATTER OF A GENERAL RATE APPLICATION by NOVA SCOTIA POWER INCORPORATED for approval of certain revisions to its Rates, Charges and Regulations BEFORE: Stephen T. McGrath, K.C., Chair...
AI summary Nova Scotia Power Inc. seeks approval for rate revisions under the Public Utilities Act. The proceeding involves multiple intervenors, including consumer advocates, small business representatives, and industry groups, with legal counsel from various organizations. The board members overseeing the case are Stephen T. McGrath, Roland A. Deveau, and Steven M. Murphy.
SWEB DEVELOPMENT Mason Baker BOARD COUNSEL: William L. Mahody, K.C. HEARING DATE(S): January 7-13, 2026 FINAL SUBMISSIONS: February 6, 2026 DECISION DATE: March 25, 2026 DECISION: The application is approved as amended by the Board. The re...
AI summary The Board approved Mason Baker's application as amended, with revised rates to be confirmed via a compliance filing. The hearing occurred January 7-13, 2026, with final submissions on February 6, 2026, and a decision on March 25, 2026.
1.0 SUMMARY - [1] The Nova Scotia Energy Board is keenly aware that electricity rates are already challenging for many customers, and any rate increase will be difficult, especially for those with low or fixed incomes. However, the Board d...
AI summary The Nova Scotia Energy Board cannot set special rates for low-income customers due to legal constraints under the Public Utilities Act . NS Power filed a GRA proposing rate increases (1.8% in 2026, 2.4% in 2027) with variations across customer classes. The Board must allow recovery of prudent costs, and NS Power's application was supported by a settlement agreement filed in November 2025.
Approving and fixing rates, regulatory powers - 6 (1) In approving or fixing just and reasonable rates, tolls, charges or tariffs pursuant to this Act or any other enactment, the Energy Board may adopt any method or technique that it consi...
AI summary The Energy Board is authorized to approve rates and tariffs using appropriate methods, considering factors like competition, sustainability, and reliability. It regulates entities including the Independent Energy Systems Operator and Halifax Water's district energy project, while adhering to legislative frameworks such as the Public Utilities Act and More Access to Energy Act .
Jurisdiction of Board - 30 (1) A Board has exclusive jurisdiction in all cases and in respect of all matters in which jurisdiction is conferred on the Board. - (2) The Boards, as to all matters within their jurisdiction pursuant to this Ac...
AI summary The Nova Scotia Utility and Review Board (NSUARB) has exclusive jurisdiction over utility regulation, acting as a surrogate for competition in natural monopoly sectors. Rate-setting balances utility costs with fair customer rates, guided by the Public Utilities Act (PUA) and judicial precedents like Dalhousie Legal Aid Service v Nova Scotia Power Inc. (2006 NSCA 74). The Board ensures utilities recover reasonable costs while maintaining financial stability.
Amount utility entitled to earn annually - 45 (1) Every public utility shall be entitled to earn annually such return as the Board deems just and reasonable on the rate base as fixed and determined by the Board for each type or kind of ser...
AI summary Regulatory framework dictates public utilities' annual earnings based on the Board's determination of a 'just and reasonable' return on the rate base. The Board may require amortization fund contributions, reducing allowable earnings. Legal references emphasize the Board's discretion under the Public Utilities Act (PUA) and its public interest mandate, citing court cases like Nova Scotia (Attorney General) v NSUARB (2019 NSCA 66) and Nova Scotia (Public Utilities Board) v Nova Scotia Power Corporation (1976).
CRITERIA OF A SOUND RATE STRUCTURE - 1. The related, "practical" attributes of simplicity, understandability, public acceptability, and feasibility of application. - 2. Freedom from controversies as to proper interpretation. - 3. Effective...
AI summary The document outlines seven criteria for a sound rate structure, emphasizing simplicity, revenue stability, fairness, and efficiency. It references James Bonbright's principles and cites legal precedents, including the Public Utilities Act and the Supreme Court of Canada's Vavilov decision, to guide regulatory assessment.
3.1 Should the Settlement Agreement be Approved? [36] On September 2, 2025, NS Power wrote to the Board to advise that it would be filing a general rate application for the 2026 and 2027 test years. It stated that it had reached a consensu...
AI summary NS Power informed the Board on September 2, 2025, that it would file a general rate application for 2026 and 2027, supported by customer representatives. However, it delayed filing until September 18, 2025, and only submitted the settlement agreement on November 5, 2025, after being requested by Board staff.
[37] The terms of the settlement agreement are set out in a schedule to the agreement and provide as follows: GRA Element Settlement Terms Capital Structure a) An equity thickness of 40% for rate setting purposes will be retained. DSM Ride...
AI summary The settlement agreement outlines terms related to capital structure, DSM Rider amendments, and the removal of a Weather Normalization Mechanism request. NS Power is required to adjust its DSM Rider and engage in an information session regarding weather normalization mechanisms.
[38] Previous decisions by the NSUARB set out the principles it applied in its consideration of settlement agreements. Those principles are still relevant and bear repeating. In its decision dated November 5, 2008, about a prior NS Power g...
AI summary The NSUARB outlines its principles for approving settlement agreements in rate proceedings. The Board emphasizes that settlement agreements, when supported by all customer classes and based on thorough evidence, are in the public interest. The Board ensures that only fair and prudently incurred costs are approved, and that customer rates remain just and reasonable.
3.1.1 Findings [41] As noted above, the NSUARB has considered settlement agreements in past matters. The Board appreciates the efforts of parties to resolve contested issues in matters coming before it and encourages such initiatives to co...
AI summary The NSUARB acknowledges the value of settlement agreements but emphasizes they must be just and in the public interest. While recognizing efforts to resolve disputes, the Board notes this settlement occurred before the application was filed, reducing its evidentiary weight. The Board approves some terms but requires amendments to ensure fair rates.
3.2 Fuel and Purchased Power [45] Fuel and purchased power expenditures are direct pass-through costs paid by NS Power's customers. Under the Fuel Adjustment Mechanism (FAM), those costs are identified as the Base Cost of Fuel (BCF). Actua...
AI summary Fuel and purchased power costs are pass-through expenses managed via the Fuel Adjustment Mechanism (FAM), with adjustments through Actual Adjustment (AA) and Balance Adjustment (BA) riders. NS Power provides regular updates, and an independent auditor appointed by the Board conducts biennial audits reviewed in public proceedings.
3.2.1 Base Cost of Fuel [46] Fuel and purchased power costs comprise the largest portion of NS Power's revenue requirement. During the two-year test period, NS Power has forecast those costs to be $918.6 million for 2026 and $918.4 million...
AI summary NS Power is seeking approval for new Base Cost of Fuel (BCF) amounts of $927.3 million for 2026 and $850.9 million for 2027, which would result in rate smoothing by over-collecting fuel costs in 2026 and under-collecting in 2027. Board Counsel engaged Bates White to review NS Power's fuel and purchased power costs, including the BCF and commodity price forecasts. NS Power also applied for an extension of the existing AA/BA riders on an interim basis, which was granted in Matter M12640.
'26, it's only 198.7. So we know that number. It's not a projection any more. We actually know it. Two million dollars, you know, is $2 million over two years would be you know, it's $4 million. A. (Williams) Mr. Deveau, if I may and I agr...
AI summary The text discusses concerns raised by Renewall Energy Inc. (REI) regarding Nova Scotia Power Inc.'s (NSPI) inaccurate fuel cost forecasts, which led to lower customer rates and unfair competition. REI argues that this creates an ongoing fuel liability and distorts market benchmarks. A response notes that a $2 million shortfall will be addressed due to rate changes post-2026.
3.2.1.1 Findings [57] The Board notes that NS Power's proposed BCF was deemed acceptable to customer representatives who signed the settlement agreement. The Board also notes Bates White's statements that, although the commodity prices and...
AI summary The Board accepts NS Power's Base Cost of Fuel (BCF) as per the settlement agreement, noting Bates White's approval of its reasonable commodity price and load forecast assumptions. NS Power must correct a $1.8M overstatement in its 2026 revenue requirement and update FLG figures for 2027. The Board emphasizes NS Power's need to improve fuel cost forecasting to address discrepancies impacting the Renewable to Retail market.
3.2.2.1 Plan of Administration [60] In its application, NS Power requested approval of amendments to the FAM Plan of Administration as described in Section 6 and Appendix 6A and set out in Appendix 6B. On page 32 of the application, NS Pow...
AI summary NS Power seeks amendments to the Fuel Adjustment Mechanism (FAM) Plan of Administration (POA) for the 2026-2027 General Rate Application (GRA) period, including aligning fuel costs with the Cost-of-Service Study (COSS), adding renewable program credits, and moving OM&G expenses to FAM. The Nova Scotia Energy Board (NSEB) requested clarification on language in the proposed changes, which NS Power addressed. The Board's 2024 FAM AA/BA decision also influenced the amendments.
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 grid-scale battery integration to meet RES requirements. The Board emphasizes NS Power must prove all costs are just and reasonable.
Rates of utility to include allowance for depreciation 41 In fixing rates, tolls and charges to be paid to a public utility for any service, the Board shall include proper allowances for depreciation. [122] NS Power owns significant assets...
AI summary The Nova Scotia Utility and Review Board (NSUARB) mandates that depreciation allowances be included in utility rates. NS Power uses asset pools to track depreciation over estimated useful lifespans, recovering original costs and salvage expenses via customer rates, as permitted by the Public Utilities Act (PUA).
3.4.1.1.1 Production Plant [142] As it relates to its generation assets, NS Power's depreciation study requires it to estimate the future cost of decommissioning its generation sites, as depreciation rates are generally set to recover the...
AI summary NS Power's depreciation study for generation assets includes decommissioning cost estimates, with the GRA settlement agreement removing inflation and contingency costs, leading to lower depreciation rates. Certain hydro systems' decommissioning costs are excluded from customer rates to balance cost recovery and rate pressure, with studies conducted by firms like Stantec and Hatch Ltd.
3.4.1.2 Estimated Average Asset Service Lives [151] Key elements influencing the determination of depreciation expense are average asset service lives and survivor curves. Survivor curves (also referred to as Iowa curves) are a series of c...
AI summary The section discusses the use of survivor curves to estimate asset service lives for depreciation calculations. The GRA settlement agreement extended service lives for two accounts, reducing depreciation rates. Mr. Madsen disputed the recommended survivor curve for Account 353, proposing an alternative curve while agreeing with the curve for Account 390.10.
3.4.1.3.1 Exclusion of Wreck Cove, Mersey and Tusket Hydro System Decommissioning Costs from Proposed Depreciation Rates [157] NS Power believes that removing the Wreck Cove, Mersey and Tusket hydro system decommissioning costs from custom...
AI summary NS Power argues excluding decommissioning costs for Wreck Cove, Mersey, and Tusket hydro systems from depreciation rates balances cost recovery and rate pressure, citing environmental, cultural, and reliability impacts. Mr. Madsen raised intergenerational equity concerns but supported the exclusion due to future cost burdens.
hose Plant accounts to be acceptable. However, for the reasons that follow, the Board has some concerns about the settlement agreement net salvage rate adjustments for Power Production Plant accounts. [170] The settlement agreement removes...
AI summary The NSUARB has concerns about the settlement agreement's net salvage rate adjustments for Power Production Plant accounts, particularly the removal of archaeological reconnaissance costs from decommissioning estimates, which significantly reduces costs compared to Gannett Fleming's study. The Boreas archaeology report outlines the methodology for archaeological cost estimation.
3.4.1.3.3 Adjustments to Estimated Asset Average Service Lives [190] In his evidence, Mr. Madsen proposed a number of changes to Gannett Fleming's recommended estimated asset average service lives. This is discussed in more detail in secti...
AI summary The Board rejects Mr. Madsen's proposed changes to asset service lives but approves specific settlement adjustments for NS Power's Account 353 and 390.10, noting peer data support for slight life extensions. The changes align with the GRA and are deemed appropriate for the current proceeding.
resulting in more use of the procedure. He also noted that ELG is currently used in Alberta and Newfoundland. His evidence also indicated that ALG is used by Maritime Electric in Prince Edward Island. [204] For this GRA, NS Power submitted...
AI summary NS Power advocates for using the Equal Life Group (ELG) method over Average Life Group (ALG) in its General Rate Application (GRA), arguing ELG reduces rate base and financing costs more effectively. The Board will evaluate ELG vs. ALG, focusing on procedure appropriateness and intergenerational equity implications.
3.4.3.1 Findings [243] In Undertaking U-8, NS Power provided calculations showing the dollar effect of implementing the changes recommended in Table 8 of Mr. Madsen's evidence. NS Power performed the analysis using both the ALG and ELG dep...
AI summary NS Power analyzed depreciation expense changes using ALG and ELG methods, showing reductions in 2026/2027. However, the Board's decision to not require ALG adoption rendered ALG results moot. ELG results still indicate lower rate increases, offset by higher return on rate base. The Board must determine if Mr. Madsen's service life recommendations are justified.
t salvage rates for Plant accounts not subject to settlement agreement adjustments and for the three transmission and distribution Plant accounts which are subject to settlement agreement adjustments. [271] The Board has intergenerational...
AI summary The Board considers salvage rate adjustments for NS Power's production plant accounts, acknowledging intergenerational equity concerns but approving adjustments due to uncertainty around decommissioning costs, particularly for hydro assets. The decision is conditional on NS Power addressing decommissioning clarity in the next GRA.
3.5.1.1 Background [281] Securitization was described by NS Power as the "centrepiece" of its general rate application and the settlement agreement. The practical impact of securitization in this matter is that it would result in ratepayer...
AI summary NS Power's general rate application includes securitization, which would lower financing rates for ratepayers by restructuring coal plant assets into debt, saving $90M over 2026-2027. Securitization improves credit metrics but removes assets from the balance sheet, ending shareholder returns on those assets.
oceed and confirmed its request for the securitization deferral. [293] NS Power also noted in its application that it had to address some preliminary corporate items in advance of the securitization: … No Canadian investor-owned utility ha...
AI summary NS Power is seeking to securitize approximately $700 million of DDA assets over the GRA period. The process involves addressing credit rating, trust indenture, and tax considerations. The settlement agreement supports NS Power's application but does not address the securitization deferral directly.
wer's Battery Energy Storage Project and an increase in the return paid to the Canada Infrastructure Bank from 1.15% to 9.00% on the Wasoqonatl Transmission project for the NS/NB Reliability Intertie. [320] The Board places significant wei...
AI summary The Board considers Morrison Park's evidence on the impact of credit ratings on NS Power's borrowing costs and the effect of delaying securitization on customer savings. A six-month delay reduces estimated savings by 25%, though partial savings may still occur if securitization proceeds. The Board emphasizes that securitization approval is a provincial policy decision.
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.
3.5.1.4.1 Findings [349] NS Power requests a PHP Deferral account to track any variances in revenue between that which would occur based on the assumptions in the GRA cost-ofservice study treating PHP as an ATL customer versus that which r...
AI summary NS Power requests a PHP Deferral account to track revenue variances based on different tariff scenarios for PHP. The deferral account was contemplated in the settlement agreement and is approved by the Board. The account will account for variances arising from differences in the PHP tariff, unavailability of the tariff, or unsatisfactory outcomes of the ADC and tariff processes.
3.5.1.5 GRA Deferral [354] In its general rate application, NS Power asks for a deferral of its GRArelated costs of the present matter and to collect those costs in rates on a straight-line basis over the two-year test period. Such costs i...
AI summary NS Power seeks to defer GRA-related costs of $2.0 million over two years, reduced from $4.0 million via a settlement agreement. The Board approved deferral of these costs, aligning with its 2023-2024 GRA Decision, which allowed recovery of study costs (e.g., Cost-of-Service Study, Line Loss Study) and the Climate Change Adaptation Plan. NS Power confirmed updated costs for the 2026-2027 GRA and studies.
3.5.1.5.1 Findings [357] NS Power's costs for preparing and presenting a general rate application have not previously been allowed to be recovered in the test period of that application because they represent costs incurred before the test...
AI summary NS Power's pre-test period general rate application costs cannot be recovered in the test period and should be budgeted separately. The Board opposes deferring operating costs to attract returns, citing prior decisions. Exceptions to retroactive ratemaking require specific criteria, as outlined in referenced cases.
he Department submits that, at least as early as 2016, NS Power knew that its coal assets must be retired by 2030 but did not take this into consideration when valuing its assets. The Department said: In the 2022 GRA, the Department submit...
AI summary The Department argues that NS Power failed to write down coal assets by 2030, leading to ratepayer costs, and the 2020 Integrated Resource Plan contradicted federal policy. Regulatory standards require impairment when early retirement is probable, yet NS Power did not adjust valuations despite clear legislative mandates.
Power to determine value of property of utility - 30 (1) The Board may at any time, with the assistance of such engineers, accountants, valuators, counsel and others as it deems wise or advisable to employ, inquire into and determine the e...
AI summary The Energy Board has authority to assess utility property values using prudent original cost minus depreciation, with straight-line depreciation calculation. It mandates valuation of Nova Scotia Power Inc.'s assets by March 31, 2024, and may set differentiated return on equity for capital asset classes to align investment incentives with ratepayer interests.
irement dates". The parties agreed to resolve these matters in a "black box" settlement agreement to lower rates for customers in the next general rate application and this was approved by the NSUARB. [388] The approved depreciation rates...
AI summary NS Power's depreciation rates were adjusted in 2013-2014 and 2022-2023 rate applications. The NSUARB approved a 'black box' settlement agreement to lower rates. NS Power cited Equivalency Agreements (2015-2020) allowing continued coal plant operations until 2030, but federal-provincial decarbonization policy changes in 2021 altered this. The 2023-2024 application proposed mechanisms for coal asset decommissioning costs.
3.6.3.1 Findings [394] A utility is entitled to the opportunity to recover its prudently incurred costs in providing service and an opportunity to earn a reasonable profit – no more and no less. While the Board can disallow costs found to...
AI summary The Board affirms that utilities must recover prudently incurred costs through customer rates, with reasonable profit, and cannot disallow legitimate costs to make rates more affordable. Investors require fair returns to fund infrastructure, and this principle was previously addressed in NS Power's 2023 general rate application (NSUARB 2023 NSUARB 12).
[397] In essence: A public utility is obligated to provide services that are reasonably safe and adequate and is entitled to compensation therefor by the charging of rates that are not unjustly discriminatory and will provide the public ut...
AI summary Public utilities must provide safe and adequate services, compensated through non-discriminatory rates ensuring revenue for operating expenses, depreciation, taxes, and capital needs. The Supreme Court of Canada emphasized fair returns on capital investment to attract investment and maintain credit ratings, with low returns risking higher borrowing costs and market exclusion.
3.6.3.1.1 The Value of the Rate Base [399] The "value" of NS Power's rate base, as framed in the Department's submissions, is based on an historic concept that has been displaced by the widely accepted prudent original cost method for valu...
AI summary The document argues that the prudent original cost method, as outlined in the Public Utilities Act, is the correct approach for valuing NS Power's rate base, displacing the Department's historic concept. Expert witnesses supported this method, and the Department failed to provide evidence or cross-examine them. The Public Utilities Act (s. 30(2)) explicitly endorses this approach since 1943.
Summary and Conclusion - [60] To summarize, the issue is where the losses resulting from forces of nature should fall: on the utility's consumers or on the utility's shareholders: - (a) In legal terms the issue is where a just and reasonab...
AI summary The issue centers on allocating losses from natural forces between consumers and shareholders. The Commission's decision on insurance and self-insurance is relevant, with the conclusion that the Commission's discretion under the Electric Utilities Act determines the outcome, not depreciation schedules or property law principles.
- [57] Ms. Runge supports NS Power's recovery of its prudently incurred investments in its coal generation assets: - 75. The no hindsight principle should always be applied in the assessment of the return of capital to a utility. If the in...
AI summary Ms. Runge advocates for NS Power's recovery of prudently incurred coal generation investments, emphasizing the 'no hindsight' principle to ensure fair treatment of utilities and rate payers. She argues that this principle provides long-term certainty for utilities and reduces risk for rate payers compared to the 'used and useful' test, which could lower returns on equity and debt costs.
3.7 Return on Equity and Capital Structure [440] NS Power's existing rates are set based on a current capital structure that includes 40% equity and 60% debt, with an approved return on equity of 9%. Under the current framework, NS Power m...
AI summary NS Power's current rates are based on a 40% equity, 60% debt structure with a 9% return on equity (ROE), allowing up to 9.25% annually. They propose maintaining this ROE range and debt-to-equity ratio for rate-setting, returning excess earnings to customers.
l-recognized and long-standing legal standard the Board must follow when approving a utility's return on its invested capital. A century ago, the Supreme Court of Canada described the test as follows: 18 The duty of the Board was to fix fa...
AI summary The text outlines the legal standard for fair return on invested capital, citing the Supreme Court of Canada's 1929 decision that rates must balance consumer fairness and company returns equivalent to other investments. The court emphasized that a fair return should mirror returns from comparable securities, ensuring neither overcharging consumers nor undercompensating the utility.
3.7.2 Overview of Cost of Capital Evidence
AI summary This section provides an overview of the evidence presented regarding the cost of capital in a regulatory proceeding, likely related to utility rate-setting or investment recovery. Key focus areas include methodologies for determining capital costs, regulatory considerations, and stakeholder arguments.
3.7.2.1 Return on Equity [453] Determining a fair return on equity generally entails the use of several wellestablished financial models. These include, but are not limited to, the discounted cash flow (DCF) model; the capital asset pricin...
AI summary The document discusses methodologies for determining a fair return on equity (ROE) for Nova Scotia Power (NS Power), including DCF, CAPM, and risk premium models. A consensus agreement sets NS Power's ROE at 9% with an 8.75%-9.25% earnings band and 40% equity thickness. NS Power's experts, James Coyne and John Trogonoski of Concentric Energy Advisors, provided evidence using market data up to February 2025.
3.7.4 Party Submissions [503] The Affordable Energy Coalition's (AEC) opening statement submitted that the Board must ensure rates are sufficient to cover NS Power's cost-of-service, while preventing the recovery of excess spending and pro...
AI summary The Affordable Energy Coalition (AEC) argues that Nova Scotia Power's (NS Power) rates must cover costs without allowing excess profits, citing Emera's high shareholder returns and recommending a 7.6% return on equity. NS Power counters that a fair return requires a higher equity ratio but maintains current affordability-focused structures.
- [16] As part of the outage review, the Board has received a number of comments from members of the public questioning, among other things, why NSPI's request for a rate increase should be considered when the service provided by NSPI is,...
AI summary The Nova Scotia Utility and Review Board acknowledges public dissatisfaction with NSPI's service but explains that rate increases are based on cost-of-service principles. As a regulated monopoly, NSPI must recover reasonable costs, and the Board balances this with ensuring fair rates. The Board cannot base rate decisions solely on reliability or public opinion.
o, it has departed from what was proposed. But as noted, the evidence does not otherwise point to a better placement for the return on equity within the high and low points set by the expert evidence. [552] The parties to the settlement ag...
AI summary The document discusses the settlement agreement between NS Power and customer representatives, which recommends maintaining NS Power's current allowed return on equity of 9% and 40% equity ratio. Dr. Cleary acknowledges the agreement's influence despite his market-based recommendations, while the Board considers the agreement's implications for public interest and rate class representation.
3.8 Cost of Service Study [561] Under the PUA , a utility is afforded the opportunity to recover its "reasonable and prudent" costs of providing service and a "just and reasonable" return on its rate base. The total amount of these costs a...
AI summary The Cost of Service Study outlines how utilities recover 'reasonable and prudent' costs under the PUA, setting rates to meet revenue requirements. Rate classes must be based on service conditions, not customer ability to pay, as per Dalhousie Legal Aid Service v Nova Scotia Power Inc. (2006 NSCA 74). Discrimination in rates is judged by factors like load factor and time of use.
[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 cost allocation and classification in generation, transmission, and distribution are outlined in Table 2 of Elenchus' report. The changes include refunctionalizing certain assets, creating new storage sub-functions, and adjusting how costs are allocated, including for DSM rate riders and the DDA methodology.
Fuel Adjustment Mechanism Related Cost Sub-Functionalization Fuel adjustment mechanism related purchases that provide firm capacity will be classified between energy and demand based on the system load factor, while purchases that provide...
AI summary The Fuel Adjustment Mechanism (FAM) classifies purchases providing firm capacity based on system load factor between energy and demand, while non-firm imports are fully classified as energy. This aligns with generation assets and acknowledges non-firm agreements supply only energy.
Classification of Transmission Costs 100% to Demand NS Power currently uses the system load factor to classify transmission rate base and costs to energy and demand. To reflect anticipated need for increased investment in the transmission...
AI summary NS Power proposes to reclassify 100% of transmission costs to demand, citing increased investment needs, reduced coal reliance in Cape Breton, expanded wind generation, and a shift from radial to network system design. This replaces the current system load factor method for classifying transmission costs.
Changes to Open Access Transmission Tarriff to Align Bundled and Unbundled Service NS Power said methodological differences in how rates are set for transmission service in the unbundled market under the Open Access Transmission Tariff (OA...
AI summary NS Power argues methodological differences between the Open Access Transmission Tariff (OATT) and bundled service cost-of-service studies cause inconsistent transmission service pricing. Proposals include aligning revenue requirements, fully classifying transmission costs to demand, and using forecasted test year usage in OATT calculations to harmonize bundled and unbundled service costs.
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.
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. This includes 8 MW firm load at three coincident peaks and 65 MW total load, incorporating projected wind farm supply.
General Plant General plant primarily consists of NS Power's investment in facilities, such as buildings structures and grounds, communication equipment, vehicles and information technology infrastructure. Currently, costs are apportioned...
AI summary NS Power proposes reallocating general plant costs above $1 million to specific functions like transmission and distribution based on allocators such as operating costs and rate base, as opposed to the current apportionment based on net book value.
[581] The parties to the settlement agreement included the following terms relating to cost-of-service methodology used to determine rates for 2026 and 2027: Cost of Service ("COS") a) The COS as set out in the Draft GRA will be included i...
AI summary The settlement agreement outlines the cost-of-service methodology for 2026 and 2027, including the inclusion of the Draft GRA, the use of the Minimum System methodology in future proceedings, data collection regarding PHP's use of the High Voltage transmission system, and the apportionment of assessment costs from the Maritime Link.
Q. Considering the consensus agreement in this GRA, what do you recommend regarding the Company's COSS methods? A. While I do not support several of the Company's COSS methodologies, particularly the use of the minimum system method for cl...
AI summary The responder acknowledges the settlement agreement in the GRA but recommends revisiting certain COSS methodologies, particularly the minimum system method. They argue that the proposals should be non-precedential and case-specific. Renewall Energy Inc. raises concerns about inconsistencies between NS Power's COSS methods and OATT charges.
3.8.2 Minimum System v. Basic Customer Methods [586] NS Power's cost-of-service study classifies portions of its distribution system as customer-related using the minimum system method. Under this approach, a minimum system study estimates...
AI summary NS Power classifies distribution system costs using the minimum system method, deeming costs of a hypothetical minimum-specification system as customer-related. Remaining costs are demand-related. NS Power cites jurisdictional scans and evidence from Concentric Energy Advisors to support the use of this method in Canadian regulatory practices.
[605] In its submissions, the Consumer Advocate noted: The Consumer Advocate shares Ms. Palmer's concerns regarding the Minimum System Method, and through the Settlement Agreement, and resulting GRA, NS Power has agreed that the use of the...
AI summary The Consumer Advocate supports a separate proceeding for the Minimum System Method post-test years, aligning with Ms. Palmer's concerns. The NDP and Liberal Party advocate for the basic customer method to reduce residential costs, while NS Power defends the COSS as the basis for cost allocation.
3.8.2.1 Findings [608] Under a cost-of-service model, the objective is to fairly allocate costs to customers based on cost causation. This has been a chronically difficult thing to do for distribution system costs. It would be inappropriat...
AI summary The Nova Scotia Utility and Review Board (NSURB) acknowledges challenges in allocating distribution system costs under a cost-of-service model, noting neither the basic customer method nor the minimum system method is adequate. The Board expresses concern over NS Power's proposal to leave the issue unaddressed in the settlement agreement, emphasizing the need for broader customer group participation and further consideration in a future proceeding.
3.8.3.1 Findings [616] As with the discussion about the use of the minimum system method or the basic customer method, the Board finds that a more satisfactory resolution of this issue would result from a broader debate about this issue. T...
AI summary The Board directs a comprehensive analysis of distribution system cost classification, emphasizing the need for broader debate beyond jurisdictional scans. It expects issues identified by Ms. Palmer, including primary system usage, residential service at primary voltages, and demand relative to peak, to be thoroughly addressed in the proceeding.
3.8.4 Peak Load Carrying Capability Adjustment [617] Ms. Palmer also recommended that a peak load carrying capability adjustment be applied to account for the demand component served by the minimum system, if the basic customer method is n...
AI summary Ms. Palmer recommends a peak load carrying capability adjustment to account for demand served by the minimum system, citing examples from Ontario (0.4 kW), Excel Energy (1.5 kW), and National Grid's approach. NS Power agrees that the minimum system has load-carrying capacity and supports crediting 1.5 kW/customer for non-coincidental peak demands.
Proposed COSS Methodology Modified COSS Methodology as per U-6 Variance Smoo othed Sm oothed Smoo thed Customer Class 2026 2027 2026 2027 2026 2027 Domestic 3.8 4.1 3.2 3.7 (0.6) (0.4) Small General 3.6 3.9 3.4 3.8 (0.2) (0.1) General (0.2...
AI summary The table compares proposed and modified Cost-of-Service Study (COSS) methodologies under Undertaking U-6, showing variances in cost allocations across different customer classes in Nova Scotia. Variances range from -7.0% to +7.9% for specific classes, with total variance at 0.0%.
3.8.4.1 Findings [624] Notwithstanding the settlement agreement, the Board finds that it is appropriate to direct NS Power to implement a load carrying capability adjustment in this proceeding. Unlike the evidence relating to the use of th...
AI summary The Board directs NS Power to implement a 0.4 kW/customer load carrying capability adjustment, citing expert agreement and the need for immediate action. The 1.5 kW figure from Excel Energy is deemed inappropriate. NS Power must conduct further analysis before future proceedings.
e only outstanding issue that would be addressed in the future proceeding noted in the agreement was the use of the minimum system method beyond the test years in the current general rate application: - Q. So N-37, page 20 in the PDF, line...
AI summary The discussion centers on the future consideration of the 'Minimum System' method in cost-of-service studies beyond the current test period. Nova Scotia Power (NSP) acknowledges the Settlement Agreement's provision to address this in a standalone 2026 proceeding, but emphasizes that parties are not bound by prior positions. NSP expects future cost-of-service issues to be evaluated in subsequent General Rate Applications (GRA) without rehashing prior processes.
[634] NS Power submitted: NS Power applied the approved OATT and COS methodologies, as amended in the Settlement Agreement, to determine the proposed bundled and OATT charges. The transmission costs are allocated to the bundled rate classe...
AI summary NS Power applied OATT and COS methodologies to allocate transmission costs, using different peak period metrics for bundled and open-market services. Renewall challenged discrepancies in coincident factors (78.6% vs. 91.66%) affecting network service charges, but NS Power explained the factors serve distinct purposes in rate calculations.
3.8.6.1 Findings [640] Because these technical issues were only raised in closing submissions, the Board has a poor record before it to make an informed decision on these points. As a result, the Board accepts the relevant calculations inc...
AI summary The Board accepts NS Power's settlement agreement calculations but acknowledges Renewall's concerns about outdated methodologies and the need for competitive energy markets. The transmission tariff transition to IESO Nova Scotia by 2027 requires NS Power to address Renewall's issues in future applications. Confidential information handling in filings is emphasized.
3.9 Rate Design [644] In its application, NS Power did not propose to introduce new concepts or materially change the design of any of its rates. The parties to the settlement agreement accepted the changes to tariff language and the updat...
AI summary NS Power did not propose new rate concepts or significant changes to rate design in its application. The settlement agreement parties accepted proposed tariff language updates and charge adjustments. Other parties did not raise concerns about these changes in evidence or submissions. The Board accepts these items as filed unless otherwise directed.
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 Residential and Small General Customer Charges [649] In its last general rate application, NS Power proposed to increase customer charges for the domestic service and small general customer classes to align those charges with costs u...
AI summary NS Power proposed increasing customer charges for residential and small general customers to align with cost-of-service study findings. Other parties raised concerns, leading to a settlement where charges were set at 75% of the proposed amounts. In the current proceeding, NS Power seeks to increase these charges in line with smoothed non-fuel cost revenue increases.
Document: 328719 Ι Domestic Service Tariff Capped Customer Charge COSS-based Customer charge Variance Percent Variance 2026 Standard Rate Customer Charge ($/month) $20.24 $29.32 $9.07 45% Energy Charge (cents/kWh) 18.349 17.306 (1.043) -6%...
AI summary The document presents a comparison of capped and COSS-based customer charges and energy charges for Domestic Service and Small General Tariffs in 2026 and 2027, showing significant variances in both dollar amounts and percentages.
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.
3.10.1 OATT [654] NS Power's Open Access Transmission Tariff (OATT) includes terms, conditions and rates for Transmission Services and Ancillary Services. It also includes operating agreements under which service will be provided, and the...
AI summary NS Power seeks to update its Open Access Transmission Tariff (OATT) rates and methodology, reflecting changes in revenue requirements, generation mix, and system usage since 2016. Proposed changes include using forecasted test year usage, adjusting transmission rates via Cost-of-Service studies, and modifying reactive power calculations. Amendments aim to align OATT with 2023-2024 GRA (M10431) directives on capacity-based ancillary services.
3.10.1.1 Findings [668] As noted above, OATT rates have been updated to reflect changes in the generation and transmission asset mix and costs, and changes in system usage since the last update in the 2023-2024 GRA. NS Power also amended t...
AI summary The Nova Scotia Utility and Review Board (Board) approved Nova Scotia Power Inc.'s (NS Power) amendments to Open Access Transmission Tariff (OATT) rates, reflecting changes in generation, transmission, and system usage since the 2023-2024 General Rate Application (GRA). NS Power revised the OATT methodology following consultation in the 2024 Cost of Service proceeding and addressed directives from the Board's hearing order (M10431).
3.10.3 Revised Fees and Regulations [685] In its application, NS Power proposed revisions to its Schedule of Charges, such as for connection, reconnection, returned cheques, installation of recording equipment, contribution for three-phase...
AI summary NS Power proposed revisions to its Schedule of Charges, including connection, reconnection, and other fees. The Board approved these revisions, except for the AMI opt-out fee, which is subject to prior findings.
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.
4.2.1 Findings [701] As noted above, the 2026 and 2027 values for the SCRR rider are zero. The proposed amendments are expected to correct the unbalanced asymmetrical nature of the current version of the rider. The amendments should also m...
AI summary The 2026 and 2027 SCRR rider values are zero. Proposed amendments aim to correct asymmetry and reduce administrative burdens from refunding small underspent funds. The Board approves the SCRR as a pilot during 2026-2027.
SS and Line Loss Study discussed later in this decision, the Board approves the deferral of the costs of developing this plan for recovery through rates after NS Power's next general rate application. [2023 NSUARB 12] [703] NS Power filed...
AI summary NS Power submitted a Climate Change Adaptation Plan and Wildfire Mitigation Plan as part of its general rate application. The Board approved deferring associated costs for recovery through future rates. The plan involves climate data integration into asset management but lacks detailed vulnerability assessments and mitigation timelines. NS Power cited consultation with the Climate Adaptation Leadership Program during development.
as required by the North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council (NPCC) requirements. It explained the changes to the coal plant retirement timelines: (a) The retirement assumption for Ling...
AI summary The retirement timelines for Lingan Unit 2 and Trenton Unit 5 were extended due to updated load forecasts and system outlooks. Lingan 2's retirement was delayed to 2027 following a 108 MW increase in 2024 firm peak load, while Trenton 5's timeline was updated based on the 2023 Evergreen IRP and further adjusted in the 2024 DDA report, delaying decommissioning until after 2029.
4.5 Rate Setting – Alternative Form of Regulation [723] In its closing submissions the Nova Scotia Liberal Caucus urged the Board to exercise its statutory authority to move Nova Scotia toward a five-year rate plan that delivers stability,...
AI summary The Nova Scotia Liberal Caucus advocates for a five-year rate plan under the amended Public Utilities Act, enabling the Energy Board to use alternative regulation methods. The 2024 amendment allows rate-setting based on techniques deemed appropriate by the Energy Board, aligning with definitions in the Energy and Regulatory Boards Act.
4.5.1 Findings [726] While the Board appreciates the complexity and challenges, a transition to performance-based rates should be explored. Key goals in such a transition would be the development of more predictable rate setting processes,...
AI summary The Board acknowledges the complexity of transitioning to performance-based rates but emphasizes the need for more predictable rate-setting processes, reduced regulatory burdens, and better alignment of utility incentives with customer interests. The Board intends to further explore this transition.
4.6 Implementation of New Rates (Cyber Incident Impact) [727] At the hearing, NS Power said that it now has communication with roughly 400,000 of its customer meters and has targeted the end of March to have all meters (approximately 555,0...
AI summary NS Power discusses challenges in implementing new rates due to a cyber incident, including prorating rate changes and potential billing discrepancies from extended intervals between meter reads. It notes progress in deploying AMI technology, with 400,000 meters communicating and a target of full deployment by March. Historical data recovery is limited to 60–90 days without interval usage details.
4.6.1 Findings [730] The Board is concerned that customers who have higher usage during the recent colder period of the year might end up paying more than the approved current rate for the electricity they are currently using because of th...
AI summary The Board expresses concern that prorating electricity bills during a billing cycle with prolonged meter reads (due to a cyber attack) may unfairly increase costs for customers using more energy during colder periods. It questions why prorating is necessary with AMI meters, which can track energy use pre- and post-rate changes, and directs NS Power to avoid prorating if AMI data can be used.
ce captured under the FAM; - The EIFEL deferral, allowing NS Power to defer incremental tax expense of about $7 million if an exemption is not enacted by the Government of Canada as it has announced; - The inclusion of four Maritime Link t...
AI summary The Nova Scotia Utility and Review Board (NSURB) approved adjustments to Nova Scotia Power's (NS Power) rate base, including Maritime Link projects, revised Storm Cost Recovery Rider terms, and OATT rate updates. The Board also amended the General Rate Application (GRA) to reduce revenue requirements and reallocate costs among customer classes.