N-42026-2027 GRA PR 01-03 - Proposed Rates (Tariffs)
15 passages
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.
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.
This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...
AI summary This rider outlines the terms and conditions for interruptible billing demand service, including customer obligations to reduce load upon notice, penalties for non-compliance, and procedures for converting between interruptible and firm service rates. It also specifies limitations on interruption duration and frequency.
per month Effective January 1, 2026 $11.330 Effective January 1, 2027 $12.270 32 cents per kilowatt reduction in demand charge where the transformer is owned by the customer.
AI summary The text presents a table showing the effective rates per month for January 1, 2026, and January 1, 2027, along with a charge of 32 cents per kilowatt reduction in demand charge for transformers owned by the customer.
ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...
AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs beyond those included in its revenue requirement, subject to approval by the Nova Scotia Energy Board. If actual costs are below the approved amount, the underspend is tracked and may be returned to customers after reaching a threshold. The Rider includes specific charges and cost allocation methods.
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.
2025 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2025 to December 31, 2025 are as f...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for 2025, including its components, Program Cost Recovery (PCR) and Balance Adjustment (BA), effective from January 1, 2025, to December 31, 2025.
Special Terms and Provisions - (1) Green Power, as defined for the purposes of this rider includes energy produced from renewable resources that have minimal impact on the environment, and could be independently certified by third party en...
AI summary This rider defines Green Power as energy from renewable resources with minimal environmental impact, potentially certified by third parties. Service under the rider may be limited based on the availability of green energy.
DEMAND CHARGE per month per kilovolt ampere of maximum demand Effective February 2, 2023 $8.332 Effective January 1, 2024 $8.332 Effective January 1, 2026 $7.506 Effective January 1, 2027 $8.143 32 cents per kilovolt ampere reduction in de...
AI summary The document outlines the demand charge rates per kilovolt ampere of maximum demand, effective from February 2023 to January 2027, with a reduction of 32 cents per kilovolt ampere for specific customer-owned transformers.
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.
per month Effective February 2, 2023 $13.428 Effective January 1, 2024 $13.428 Effective January 1, 2026 $11.330 Effective January 1, 2027 $12.270 32 cents per kilowatt reduction in demand charge where the transformer is owned by the custo...
AI summary The text provides a table showing rate changes effective on specific dates, including a reduction in demand charge based on kilowatt reduction when the transformer is customer-owned.
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 in cents per kWh for various tariff categories under the 2025 rate structure, including domestic, industrial, municipal, and other specific services.
STORM COST RECOVERY RIDER Page 3 of 3 Tariff Storm Riders in cents per kWh3 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use...
AI summary The document outlines the Storm Cost Recovery Rider (SCRR) and specifies that no storm riders are applied to various tariff categories, with a rate of 0.000 cents per kWh. It also details the process for submitting SCRR applications by April 30th to recover actual storm costs and compare them with forecasted recoveries.
2025 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2025 to December 31, 2025 are as f...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for 2025, including its components PCR and BA. It explains that the Balance Adjustment (BA2) for 2023 will be applied over the 2027-2031 term and will be based on revenue collected between February 2, 2023, and December 31, 2023, compared to DSM costs incurred during that period.
N-92026-2027 GRA Appendix 12 A-C - Cost of Service Study Process - Redacted
29 passages
Cost of Service Study Redacted 1 • Determination of usage for rate calculations: under the OATT the transmission rates are a 28 Currently, the DSM Rider is allocated as 75 percent to the cost of programs undertaken for the rate 29 class, w...
AI summary The document discusses changes to the allocation of the DSM Rider, proposing to remove the 25 percent allocation to system benefit and reallocate 100 percent of DSM costs to rate classes based on program spending. This aligns with stakeholder feedback and aims to better reflect cost responsibility and simplify cost of service treatment.
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.
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.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests 1 Request DR-76: 2 3 Please provide a basic summary of current and forecast DSM program costs and benefits, 4 including but not limited to the following: 5 6...
AI summary NSPI provided responses to data requests regarding the current and forecast DSM program costs and benefits, referencing the 2023-2025 DSM Plan, Rate and Bill Impact Analysis, and the 2019 DSM Potential Study. The information includes program costs, net participant benefits, capacity and energy benefits, and other quantified benefits.
4 5 6 2) The total value of interruptible demand on NSPI's system was estimated by multiplying the cost per kW by the system coincident interruptible demand served under the Interruptible Rider: 7 63 \ 202,000 kVA = 12,726,000. 8 9 10 11 1...
AI summary The text calculates the total value of interruptible demand on NSPI's system by multiplying the cost per kW by the system coincident interruptible demand. It then divides this value by the total non-coincident demand billing determinants to calculate a monthly credit of $3.43/kVA/month.
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.
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.
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 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.
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.
COSS SBA DR-6 Attachment 1 Page 10 of 24 415660 REG LARGE IND INTERRUPT RIDER REVENUE 415710 REG LARGE IND WHSLE MARKET BACKUPTOP UP NON FUEL DEMAND BASE 415720 REG LARGE IND WHSLE MARKET BACKUPTOP UP FAM BASE FUEL 415730 REG LARGE IND WHS...
AI summary The document contains a list of revenue codes related to various regulatory riders and programs, including load retention, shore power, and unmetered revenue. These codes are part of a regulatory proceeding and may be associated with cost recovery, demand-side management, and other energy-related topics.
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.
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.
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.
DSM Cost Recovery Process - To meet its obligations under the Public Utilities Act R.SNS 1989, c 380 (Act) to undertake cost-effective electricity efficiency and conservation activities NS Power enters into an agreement with EfficiencyOne...
AI summary NS Power enters into a multi-year supply agreement with EfficiencyOne to deliver electricity efficiency and conservation programs, with DSM costs recovered through DCRRs and direct billing for MEUs. The process is subject to UARB approval and involves annual rider approvals based on the supply agreement.
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.
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.
5. Classify Grid Scale Storage by ELCC Factor - ➢ Purpose: Subfunctionalize grid scale storage separately from EHV and HV Transmission and classify by the ELCC. - ➢ Model Notes: Grid scale storage is not operational in 2023 and all asset v...
AI summary The purpose is to subfunctionalize grid scale storage separately from EHV and HV Transmission and classify it by the ELCC factor. Grid scale storage is not operational in 2023, with all asset value being CWIP. The revenue requirement of grid scale storage is not significant in 2023, so the impacts of this change are not significant.
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.
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 This table discusses the allocation of DSM costs between system benefit and customer benefit. NS Power initially supported the status quo of 25% system benefit and 75% customer benefit but later updated its position to allocate 100% of DSM costs to customer benefit, citing consistency with other jurisdictions and simulation results indicating reduced system benefit compared to the status quo.
- 1 consider or advance. Discussions were supported by COSS model runs to demonstrate - 2 the expected impact of the changes being discussed. - 3 Section 3 provides an overview of NS Power's proposed COSS methodology. - 4 Sections 4 throug...
AI summary The text outlines the structure of a document discussing NS Power's proposed Cost of Service (COS) methodology, including sections on generation, transmission, and distribution, as well as additional matters like rate classifications, line losses, and the Decarbonization Deferral Account. Elenchus provides comments on the proposed approaches and alternative suggestions.
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.
11 7.6.1 CURRENT RATE RIDER METHODOLOGY - 12 NS Power applies a DSM rate rider to recover the costs of EfficiencyOne. The rate rider - 13 is calculated based on the costs of DSM programs applicable to each class and an - 14 assessment of N...
AI summary NS Power uses a DSM rate rider with a 75%/25% weighting to recover EfficiencyOne costs, where 75% is based on program costs per class and 25% on system benefits, determined by judgment.
19 7.6.2 NSP PROPOSED APPROACH - 20 NS Power is proposing to change the weighting of the DSM allocation so the rate rider is - 21 100% of costs incurred for each rate class and the system benefit will no longer be - 22 considered.
AI summary Nova Scotia Power (NSP) is proposing to adjust the weighting of the DSM allocation, making the rate rider cover 100% of costs incurred for each rate class, with the system benefit no longer being considered.
7.6.3 ELENCHUS OPINION - 2 NS Power conducted an analysis that has indicated there is very little system benefit - provided by DSM. [12](#page-108-4) Based on this analysis, Elenchus agrees it is appropriate to remove - 4 the system-benefi...
AI summary Elenchus agrees with NS Power's analysis that there is very little system benefit provided by DSM, and therefore supports the removal of the system-benefit weighting for the allocation of the DSM rate rider.
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.
N-142026-2027 GRA OP 01-15 - Redacted
27 passages
PGS PGS anticipates earning at the bottom of its allowed ROE range in 2025. USD earnings for 2025 are expected to be consistent with 2024 primarily due to higher operating costs and depreciation driven by ongoing capital investments to sup...
AI summary PGS expects to earn at the lower end of its allowed ROE range in 2025, with USD earnings consistent with 2024 due to increased operating costs and depreciation from capital investments. PGS filed a rate case with the FPSC in March 2025, requesting a USD 93 million increase in annual base rates and additional adjustments for 2027. A settlement agreement in principle was reached in August 2025, with details expected to be filed with the FPSC.
Regulatory Arrangements In November 2023, the FPSC voted to approve the FPSC staff recommendation which supported an $107 million USD increase in annual base rates, as well as $11 million USD from the cast iron and bare steel replacement r...
AI summary In November 2023, the FPSC approved a recommendation to increase annual base rates by $107 million USD and added $11 million USD from the cast iron and bare steel replacement rider, reflecting a 10.15% midpoint ROE with an allowed equity capital structure of 54.7%.
Regulatory Construct 9.25% - 11.25% approved ROE 54% approved equity $10.2 billion rate base In year 3 of a 3 year rate agreement
AI summary The document outlines a regulatory construct with an approved return on equity (ROE) range of 9.25% to 11.25%, 54% approved equity, a rate base of $10.2 billion, and specifies that this is in the third year of a three-year rate agreement.
Regulatory Arrangements In November 2023, the FPSC voted to approve the FPSC staff recommendation which supported an $107 million USD increase in annual base rates, as well as $11 million USD from the cast iron and bare steel replacement r...
AI summary In November 2023, the FPSC approved a $107 million USD annual base rate increase and $11 million USD from the cast iron and bare steel replacement rider, reflecting a 10.15% midpoint ROE with an allowed equity capital structure of 54.7%.
Regulatory Arrangements In September 2023, NMGC filed a formal rate application with the NMPRC for new rates effective October 2024. NMGC requested a ~$49M USD increase in annual base rates, reflecting an ROE of 10.5% (currently 9.375%) an...
AI summary NMGC submitted a rate application to the NMPRC in September 2023, requesting a ~$49M USD annual base rate increase effective October 2024. The request includes a higher return on equity (ROE) of 10.5% and a capital structure of 53%/47% equity/debt.
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.
Peoples Gas Rate Case Details - $107M USD increase in annual base rates - $11M USD Cast Iron Bare Steel rider - 10.15% mid-point ROE up from 9.95% - Allowed equity thickness of 54.7% unchanged - Received 85% of the ask as filed
AI summary The Peoples Gas Rate Case details a proposed $107M USD annual base rate increase, a $11M USD Cast Iron Bare Steel rider, and a mid-point ROE of 10.15%, up from 9.95%. The allowed equity thickness of 54.7% remains unchanged, and the applicant received 85% of the requested rate increase.
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.
Regulatory Construct 8.75% - 9.25% approved ROE 40% approved equity $5.4 billion rate base In year 2 of a 2 year rate agreement
AI summary The regulatory construct outlines an approved return on equity (ROE) range of 8.75% to 9.25%, 40% equity, a rate base of $5.4 billion, and specifies that this is in the second year of a two-year rate agreement.
Regulatory Arrangements In November 2023, the FPSC voted to approve the FPSC staff recommendation which supported an $107 million USD increase in annual base rates, as well as $11 million USD from the cast iron and bare steel replacement r...
AI summary In November 2023, the FPSC approved a recommendation to increase annual base rates by $107 million USD and include a $11 million USD rider for cast iron and bare steel replacement, reflecting a 10.15% midpoint ROE with an allowed equity capital structure of 54.7%.
Grand Bahama Power Corporation ("GBPC") - On August 1, 2024, GBPC filed a rate plan proposal with their regulator - Proposal seeks a revision in base rates, charges and tariff classifications effective January 1, 2025 for a three-year peri...
AI summary Grand Bahama Power Corporation (GBPC) filed a rate plan proposal with their regulator on August 1, 2024, seeking a revision in base rates, charges, and tariff classifications effective January 1, 2025, for a three-year period. The proposed rates are based on an 8.5-8.7% allowable regulated return on rate base and a target regulatory ROE of 12.87%, with a decision expected by the end of 2024.
Regulatory Arrangements In November 2023, the FPSC voted to approve the FPSC staff recommendation which supported an $107 million USD increase in annual base rates, as well as $11 million USD from the cast iron and bare steel replacement r...
AI summary In November 2023, the FPSC approved an increase in annual base rates by $107 million USD and $11 million USD from the cast iron and bare steel replacement rider, reflecting a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent.
Peoples Gas 2023 Rate Case - $107M USD increase in annual base rates - $11M USD Cast Iron Bare Steel rider - 10.15% mid-point ROE up from 9.95% - Allowed equity thickness of 54.7% unchanged - Received 85% of the ask as filed
AI summary The Peoples Gas 2023 Rate Case proposes a $107M USD annual base rate increase and a $11M USD Cast Iron Bare Steel rider. The mid-point return on equity (ROE) is set at 10.15%, up from 9.95%, while the allowed equity thickness remains at 54.7%. The applicant received 85% of their requested rate increase.
Tampa Electric - Filed in April 2024 for new rates effective January 1, 2025 - o Request included increased revenue requirements of $297M USD in 2025, $100M USD in 2026 and $72M USD in 2027; - o 11.50% ROE midpoint up from the current 10.2...
AI summary Tampa Electric filed a request in April 2024 for new rates effective January 1, 2025, including increased revenue requirements of $297M USD in 2025, $100M USD in 2026, and $72M USD in 2027. The request includes a 11.50% ROE midpoint, up from the current 10.20%, and maintaining the current 54% equity thickness. A staff recommendation is expected on November 22nd, with a hearing on December 3rd.
PGS Effective January 1, 2024 $107M USD annual base rate increase & $11M cast iron bare steel rider 10.15% ROE and 54.7% equity thickness
AI summary The document outlines a base rate increase of $107M USD annually and a $11M cast iron bare steel rider, effective January 1, 2024, with a return on equity (ROE) of 10.15% and an equity thickness of 54.7%.
Storm Cost Recovery Received approval for a storm rider in 2025 to collect $22M of unrecovered storm restoration costs
AI summary Approval was received in 2025 for a storm rider to collect $22M in unrecovered storm restoration costs.
Storm Cost Recovery Received approval for a storm rider in 2025 to collect $22M of unrecovered storm restoration costs
AI summary Approval was received in 2025 for a storm rider to collect $22M in unrecovered storm restoration costs.
Other Nova Scotia Developments The Province has appointed the board of directors of the Nova Scotia Independent System Operator ("NSIESO"). NSPI continues to work constructively with the Province to support the phase in of the NSIESO and f...
AI summary The Province has appointed the board of directors of the Nova Scotia Independent System Operator (NSIESO), with NSPI working to support its full operations by 2026. NSPI also announced an agreement to construct a reliability intertie between Nova Scotia and New Brunswick, with regulatory approval expected by Q4 2025. The Province granted NSPI flexibility to reprofile its sulfur dioxide (SO2) emissions from 2025 to 2034.
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.
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.
Peoples Gas - Settlement agreement filed in August 2026 reflecting: - Revenue increase of $97M USD through 2028 (inclusive of CIBS rider) - $67M USD in 2026 - $25M USD in 2027 and - $5M USD in 2028 - Represents 81% of revised ask - ROE of...
AI summary A settlement agreement for Peoples Gas, filed in August 2026, includes a revenue increase of $97M USD through 2028, with an 81% approval of the revised ask. The return on equity (ROE) is set at 10.3%, up from 10.15%, with equity thickness remaining at 54.7%. The final order is expected in Q4 2025, with new rates effective January 1, 2026.
Well established cost of service regulatory environment •Allowed ROE: 8.75% - 9.25% •Maximum Allowed Equity: 40% - • Approved rider mechanisms allow for the timely recovery of prudently incurred costs: - 〉 Fuel adjustment mechanism allows...
AI summary The regulatory environment in Nova Scotia allows for a return on equity between 8.75% and 9.25% and a maximum allowed equity of 40%. Approved rider mechanisms, such as the fuel adjustment and DSM rider, enable the recovery of prudently incurred costs. The UARB is an independent regulatory body responsible for oversight.
Financial Performance - Growing cash flow profile supported by strong customer growth and tax benefits in support of energy storage investments. - Decreased debt and improved credit metrics in 2024 due to sale of $117 million FAM asset to...
AI summary The financial performance section highlights improved cash flow and credit metrics due to asset sales, federal fuel funding, and a successful General Rate Application, with forecasts of strong adjusted cash flow to debt and EBIT coverage ratios through 2026.
Well-established cost of service regulatory environment - Allowed ROE: 8.75% - 9.25% - Maximum Allowed Equity: 40% - Approved rider mechanisms allow for the timely recovery of prudently incurred costs: - 〉 Fuel adjustment mechanism (FAM) a...
AI summary The document outlines the regulatory environment for cost of service in Nova Scotia, including an allowed ROE range of 8.75% to 9.25%, a maximum allowed equity of 40%, and rider mechanisms for recovering prudently incurred costs. The UARB is described as an independent regulatory body.
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.
Enabling Renewable Generation Nova Scotia Power continues to work collaboratively with the Provincial Government to implement the 2030 Clean Power Plan to phase out coal and increase renewable generation to 80% of sales by 2030. Updates si...
AI summary Nova Scotia Power is advancing renewable generation initiatives, including grid-scale battery installations and transmission line projects, in alignment with the 2030 Clean Power Plan. The creation of an Independent System Operator and partnerships with the Canada Infrastructure Bank and WMA are key aspects of these efforts.
N-27NSPI (NSEB) RIR 1-152 - Redacted (settlement agreement attached at IR-1)
27 passages
Terms of Settlement It is acknowledged that, subject to Board approvals, rate increases other than those identified herein may occur prior to the effective date of the next general rate application in the form of Board-approved riders. Rec...
AI summary The terms of settlement acknowledge that rate increases may occur before the next general rate application, subject to Board approvals. NS Power will support efforts to smooth or mitigate the impact of rate changes for the 2026-2027 test period, particularly in the 2026 FAM AA/BA proceeding for Large and Medium Industrial Classes.
Appendix "A" GRA Element Settlement Terms Storm Cost Recovery Rider a) The Storm Cost Recovery Rider will be implemented as described in the Draft GRA, subject to the following: (a) the Storm Cost Recovery Rider will not be implemented on...
AI summary The Storm Cost Recovery Rider is to be implemented on a pilot basis for 2026 and 2027, with costs eligible for the rider, rather than as a permanent measure as initially proposed.
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) is divided into two components: BA1, which reconciles revenue differences based on actual class load from the previous year, and BA2, which adjusts for discrepancies between approved DSM expenditures and actual costs, applying the adjustment over the remaining term of the DSM program.
2025 DSM Cost Recovery Rider Charges Effective: January 1, 20265January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Ja...
AI summary The document outlines the 2025 Demand Side Management (DSM) Cost Recovery Rider (DCRR) charges, including Program Cost Recovery (PCR) and Balance Adjustment (BA), effective from January 1, 2025, to December 31, 2025. It also explains how the Balance Adjustment for 2023 will be calculated and applied over the 2027-2031 term.
The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) Domestic Service, Domestic Service Time-of-Day, Domestic Service...
AI summary The document outlines the Approved DSM Term, which refers to the full DSM Plan period in effect, such as 2023-2026 or 2027-2031. It also includes a table showing various tariff rates, including PCR, BA, and DCRR, for different service categories.
Regulated electric revenue: Electric revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricit...
AI summary Electric revenues are recognized when electricity is delivered to customers, based on approved rates and metered usage. Unbilled revenue is estimated periodically, considering factors like energy demand, weather, and customer class changes.
Maritime Link: The Maritime Link is a $1.8 billion (including AFUDC) transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15,...
AI summary The Maritime Link is a $1.8 billion transmission project connecting Newfoundland and Nova Scotia, which became operational in 2018. NSPML received UARB approval in November 2024 to recover up to $197 million from NSPI in 2025, including a $158 million annual cost assessment and a $39 million supplemental assessment for federal loan guarantee repayment.
Storm Rider: NSPI has a UARB approved a storm rider for each of 2023, 2024 and 2025, which gives NSPI the ability to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given ye...
AI summary NSPI has a UARB-approved storm rider allowing recovery of major storm restoration costs exceeding $10 million annually. In 2024, the UARB approved the recovery of $24 million deferred in 2023, to be recovered over 12 months starting January 1, 2025.
"FAM and other deferrals" recognized in the Consolidated Statements of Income consisted of the following: For the Year ended December 31 millions of dollars 2024 2023 FAM: Over (under)-recovery of fuel costs (1) (2) $ 350 $ (78) 2020 – 202...
AI summary The Consolidated Statements of Income show that 'FAM and other deferrals' for 2024 totaled $350 million, driven largely by a $486 million over-recovery of fuel costs due to a refund of previous NSPML assessment payments. This contrasts with a $98 million deficit in 2023.
As at December 31, 2024, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments to be re...
AI summary The text presents a table showing future minimum lease payments to be received by the company for each of the next five years and in aggregate thereafter, as of December 31, 2024. The section title 'RELATED PARTY TRANSACTIONS' suggests that the following content will discuss transactions involving related parties.
Storm Rider: On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and incremental financing costs deferred to NSPI's storm rider in 2023 to be recovered over a 12-month period beginning on January 1...
AI summary The UARB approved the recovery of $24 million in major storm restoration and incremental financing costs deferred to NSPI's storm rider in 2023, to be recovered over a 12-month period starting January 1, 2025.
February 2024. Accessed at: https://energy.novascotia.ca/sites/default/files/community-solar-program-guide.pdf - 2 NS Power will administer the program billing and assist project owners in subscriber management. - 3 To date, NS Power has s...
AI summary NS Power is administering the Community Solar Program, including billing and subscriber management. They have provided feedback on program guides and PPAs, developed a Community Solar Energy Credit Rider, and filed it with the NSUARB. As of November 2024, 40 preliminary assessments have been completed for potential projects totaling 335 MW of installed capacity.
(2) YTD is June as of June 30 as regulated financial statements are only calculated quarterly. 1 Request IR-16: 2 3 Reference: Exhibit N-3 GRA Direct Evidence, Section 9.2 Details of Rate Base 4 5 On page 52 of the application, NS Power no...
AI summary NS Power proposes to recover costs related to the Reliability Intertie Project through a rider rather than general rates, citing section 21B of the Public Utilities Act. The request seeks clarification on the appropriateness of this approach, the expected commencement date of the rider, and its impact on customer rates.
Five-Year Reliability Plan – 2025-2029 NON-CONFIDENTIAL 2026-2027 GRA NSEB IR-20 Attachment 1 Page 6 of 40 1 1) Improve the customer reliability experience by reducing SAIDI by 20 percent from 2 the current five-year average of 5.10 and ac...
AI summary The Five-Year Reliability Plan aims to improve customer reliability by reducing SAIDI by 20% from the current five-year average of 5.10 to 4.10 by 2029. It also focuses on enhancing grid resilience against climate change impacts, referencing past storms like Hurricane Dorian, Fiona, and Lee. NS Power acknowledges the Board's direction on evaluating the Value of Lost Load (VoLL) for investment decisions.
2 A Major Event is defined as a significant weather-related or other disruptive event that results in at least one Major Event Day (MED). MED and other key terms are defined in Appendix 1. 3 M11692 2025 Storm Cost Recovery Rider (SCRR)
AI summary The text defines a Major Event as a significant weather-related or other disruptive event that results in at least one Major Event Day (MED), with definitions provided in Appendix 1. It also references M11692, the 2025 Storm Cost Recovery Rider (SCRR).
NON-CONFIDENTIAL treated as a one-time reduction in the carrying balance of the FAM in April 2024. As the interest rate on the repayment of $117 million to Invest Nova Scotia is less than NS Power's weighted average cost of capital, the re...
AI summary NS Power is managing a one-time reduction in the FAM balance due to a repayment to Invest Nova Scotia, which results in lower interest recovery from customers. The repayment is collected on behalf of Invest Nova Scotia, and the amounts are tracked outside the FAM. NS Power anticipates filing an AA/BA Application in Q4 2025 and is working with stakeholders to mitigate rate impacts for the 2026/2027 test period.
22 (b) Please see the table below: ($ million) 2020 2021 2022 2023 2024 2020-2024 Average 24 government official about the revocation of the pay play referenced in the Nova Scotia 25 Power Incorporated Regulations. 26 27 (f) Please provide...
AI summary The text discusses the revocation of the Senior Officials Pay Plan and its impact on NS Power's rate calculations. NS Power confirmed the amendment of the pay plan, leading to the revocation of the prior version, and used the amended plan to determine recoverable amounts through rates. There were no communications with government officials regarding this change.
REDACTED 2 3 Reference: Exhibit N-6(ii), Corporate Office of Secretary and General Counsel 4 With respect to the reasons given for the following significant projected increases for 2026 5 over 2024 actuals: 17 appeal heard. The outcome of...
AI summary The text discusses the significant projected increases in costs for 2026 over 2024 actuals, referencing the General Rate Adjustment (GRA) appeal. The litigation's outcome depends on discovery motions, and the timing and resolution of the matter are uncertain. NS Power cannot provide an estimate of future costs at this time due to external factors.
NON-CONFIDENTIAL 1 Request IR-62: 1 Request IR-63: 2 3 Reference: Exhibit N-6(ii), Regulatory Affairs 4 5 The consulting expense forecast for 2026 is 57% higher than 2024 compliance and slightly 6 below 2024 actuals. Board staff assumes th...
AI summary The consulting expense forecast for 2026 is 57% higher than 2024 compliance and slightly below 2024 actuals. The majority of incremental cost associated with the 2026-2027 GRA is expected to be incurred in 2025, not reflected in the Regulatory Affairs operating expense as it is being deferred and amortized over the test period.
Earnings Outlook Earnings for NSPI have generally been very stable, reflecting the regulated nature of its operations. The Company has a FAM in place that allows it to recover actual fuel costs from customers through annual rate adjustment...
AI summary NSPI's earnings have been stable due to its regulated operations and a Fuel-Adjustment Mechanism (FAM) that recovers fuel costs. Earnings rose in 2023 due to a 1.8% base-rate increase, but ROE was below the approved band. Financial improvement is expected with the next General Rate Application (GRA) in 2026.
Appendix 2—Regulation - NSPI operates under the NSUARB's regulatory environment using a COS methodology that allows the Company to recover all prudently estimated operating expenses and earn a reasonable return on approved capital investme...
AI summary NSPI operates under the NSUARB's regulatory framework, with a target ROE range of 8.75% to 9.25%. Bill 212 in 2022 imposed caps on base-rate increases and ROE. In 2023, the NSUARB approved a negotiated settlement with a 6.9% average rate increase for 2023 and 2024, including a Storm Rider and a FAM. In 2024, the NSUARB approved a Storm Rider of $24 million and the 2024 ACE plan. NSPI also sold a portion of its FAM asset to the Province and issued debt guaranteed by the federal government.
NON-CONFIDENTIAL Category ($ Million) 2023 2024 2025 2026 2027 17 (d) See NS Power's response to NSEB IR-47(b). 18 19 (e) See NS Power's response to NSEB IR-47(b). 20 21 (f) NS Power's forecast was based on a point in time. The IESO-NS com...
AI summary The document outlines NS Power's responses to the NSEB regarding various financial and operational forecasts, including deferrals, cost reductions, and potential tax expenses. It references the IESO-NS, GRA, and other regulatory processes, highlighting uncertainties and future considerations.
1 2027 COSS Change on Total Allocated Costs in $ Million Revenue to Expense Ratio 19 (d) Please outline the amount, by month, that the actual revenue amounts will be 20 measured against in order to calculate any deferral. 21 22 (e) Please...
AI summary The response outlines the ongoing development of the PHP ATL Tariff and the uncertainty in forecasting revenues and costs due to potential differences between assumed and proposed tariffs. The company emphasizes the difficulty in confirming revenue variances until the Board makes decisions on related proceedings.
6 charge would be recovered through an increase in the energy charge. Request IR-134: 11 The interruptible credit is $160 kW/year and the most recently calculated levelized avoided costs 12 of capacity is $140 kW/year. Differences between...
AI summary The document discusses the interruptible credit for the Large Industrial Interruptible Rider (LIIR), explaining that the credit is based on the avoided cost of a combustion turbine. The credit reflects the deferral of future generation capacity costs and is designed to mimic the operation of a peaking facility. The updated credit values are supported by SR-01 Attachment 4.
(a) Please refer to the following figure; only OATT Schedules 5 and 6 are impacted by this change. OATT Revenue (as proposed in 2026-2027 GRA) OATT Revenue (fully cost based) Dollar Impact 14 retail. The rate classes, which are smaller use...
AI summary The text discusses a request for clarification regarding the Storm Cost Recovery Rider (SCRR) pilot extension, including the proposition being tested, success determination, and metrics for evaluation. NS Power responds by referencing previous answers and outlines that the SCRR aims to ensure customers pay only actual storm restoration costs.
(b) Any storm underspend could be returned to customers effective January 1 of the following year; however, if the SCRR was structured in that manner it could result in an SCRR application every year, regardless of its materiality. Structu...
AI summary The text discusses the structure of the Storm Cost Recovery Rider (SCRR), noting that returning underspend to customers annually could lead to frequent SCRR applications, regardless of their significance. Instead, the proposed structure allows NS Power to make SCRR applications only after three consecutive years or when the underspend reaches $2.5 million, ensuring applications are made only when there is a material amount to recover.
Proposed DCRR Framework If approved, the proposed DCRR framework would be in effect during the 2027-2031 DSM Term. For example, the 2028 DCRR would include: (b) The proposed DCRR framework adds a BA 2 component to the BA to reconcile, by r...
AI summary The proposed DCRR framework would be effective during the 2027-2031 DSM Term. It introduces a BA2 component to balance differences between approved and actual DSM expenditures by rate class. This aims to reduce rate volatility by spreading variances over a four-year recovery period, starting in year two of the following Term.
N-44STATE OF CONNECTICUT
PUBLIC UTILITIES REGULATORY AUTHORITY
55 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.
e for ratemaking purposes, the company must demonstrate, by a preponderance of the evidence, that the capital proposed for inclusion in rate base (1) is used and useful and (2) was invested prudently. Rate base is calculated by taking the...
AI summary The document discusses the requirements for including capital in the rate base for ratemaking purposes, emphasizing that the company must prove the capital is used and useful and invested prudently. It explains how rate base is calculated using the test year net book value and mentions a proposed increase in the rate base by the company.
Based on the record evidence, the Authority approves a Rate Year average rate base of $1,354,956,818, an adjustment of $29,690,819, as summarized i[n Table 2,](#page-14-1) below.
AI summary The Authority has approved a Rate Year average rate base of $1,354,956,818, with an adjustment of $29,690,819, as detailed in Table 2.
ii. Net Metering Plant Additions The Company seeks to include $2,226,469 in plant additions associated with Project No. PRJ-003394, "UI – Net Metering Changes," for "information technology (IT) development and implementation necessary to d...
AI summary The Company requests $2,226,469 for IT development related to new net metering tariffs under the Residential Renewable Energy Solutions program. The OCC recommends disallowing the full amount, arguing that the Authority ordered UI to recover such costs through the Rate Adjustment Mechanism (RAM), not base rates, citing previous decisions.
support future capacity and reliability needs, as well as to avoid later work that would disrupt traffic on the bridge and include costly roadway repairs. Late Filed Ex. 67; Hr'g Tr., 1101:5–1102:15. OCC recommends a disallowance of $1,776...
AI summary The Office of the Chief Counsel (OCC) recommends disallowing $1,776,064 related to 12 unused duct lines installed during the Barnum Avenue Bridge Replacement Project, arguing that the Company provided insufficient evidence justifying their necessity or benefit to customers.
i. Rider LIDR (PRJ-003494) The Company seeks to recover net plant additions of $944,477, related to the Rider LIDR Project (PRJ-003494). Late Filed Ex. 1, Att. 3 ("3-GrossPlant" and "4.1- PlantAdditionsDetail Update" tabs). The Company sta...
AI summary The Company requests to recover $944,477 in costs related to the Rider LIDR Project, which involves SAP upgrades for implementing the Low-Income Discount Rate. However, this request conflicts with a prior Authority order that estimated LIDR implementation costs between $0 and $700,000 and directed the Company to seek recovery through the applicable Rate Adjustment Mechanism (RAM) proceeding.
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.
b. Lead/Lag Study For purposes of calculating its proposed cash working capital allowance in the instant proceeding, UI relied on a lead-lag study that was originally developed for Docket 28 The Authority applied the adjustments consecutiv...
AI summary The document discusses a lead-lag study used by UI to calculate its cash working capital allowance, referencing a study from Docket No. 22-08-08. The study explains the lag period for revenues and the lead period for expenses, with the lag measured in days between service delivery and payment receipt, and the lead measured between receipt of goods/services and payment.
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.
iii. Payment Lag Similar to the Collections Lag, the payment processing lag is a component of the Company's proposed revenue lag computation. Interrog. Resp. RSR-266, Att. 1. For purposes of the Company's calculation, UI assumed a payment...
AI summary The Authority rejects the Company's proposed payment lag adjustment of $734,365 due to a lack of evidentiary support. The Company assumed a one-day payment lag without justification, and this assumption is inconsistent with the data, particularly for 'Wires/ACH' payments described as same-day.
3-01-19 Decision), pp. 174–175 (Order No. 14). UI further argues that its deferral of infrastructure replacement programs and projects will create another large bubble of projects in future years. Id. Importantly, the Company has an ongoin...
AI summary The document discusses the Company's obligation to prudently invest in infrastructure and comply with regulatory decisions, while highlighting concerns about deferred projects creating future costs. It also references the need for reasonable returns on investments and the importance of ensuring that ratepayers are not unfairly burdened with future capital costs.
a. Company's Financial Risk The Authority considers the financial risk of the Company as it compares to the Authority Proxy Group to determine if there are unique financial risks or risk mitigations to consider when establishing an ROE. Th...
AI summary The Authority evaluates the financial risk of the Company compared to the Authority Proxy Group and finds that UI's risk profile does not warrant special consideration in determining ROE. Bond ratings and risk mitigation mechanisms such as RAM and C&LM programs reduce financial risk, leading to the conclusion that UI's risk is comparable to other companies in the proxy group.
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.
e. Contact Center Services The Company proposes $57,163 in contact customer services expenses for the Rate Year, which is the Company's $62,832 Test Year, with a ($9,975) pro forma adjustment, and a $4,306 inflation adjustment. Late Filed...
AI summary The Company requests $57,163 for contact center services for the Rate Year, but the Authority approves $52,857, rejecting the inflation adjustment due to the lack of measurable cost drivers based on per unit pricing contracts.
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.
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.
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.
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.
ii. Interim Period FTEs The Authority finds that the Company's proposed 141 Interim Period FTEs are reasonable. The Company explained that its projection of 69 Interim Period FTEs in its rate application was an accurate estimate at the tim...
AI summary The Authority deems the Company's proposed 141 Interim Period FTEs reasonable but expresses concern about employee transfers between UI and service companies, fearing ratepayers may be compensating UI for temporary transfers. The Company is directed to submit regular compliance filings detailing employee transfers until the next rate amendment.
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.
iii. Life Insurance The Company requests that it recover $53,168 in life insurance expenses for the Rate Year, which is the Company's $49,163 Test Year expense plus a $4,005 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch...
AI summary The Company seeks to recover $53,168 in life insurance expenses for the Rate Year, including a $4,005 generic inflation adjustment. The Authority disallows the adjustment due to the lack of historical data demonstrating a correlation between life insurance expenses and inflation.
es not only its base distribution "profit center," but also rate mechanisms recovered outside of base distribution rates: the SBC, GSC, REI, RDR, C&LM, and NBFMCC. [92](#page-152-2) Hr'g Tr., 1775:17– 90 Corporate Services include human re...
AI summary The text outlines various rate mechanisms recovered outside of base distribution rates, including the SBC, GSC, REI, RDR, C&LM, and NBFMCC. It also details the components of Corporate Services and Technical Services, and references the Authority's annual Rate Adjustment Mechanism (RAM).
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.
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.
f. Training The Company proposes $160,864 in the Rate Year for training expenses, which is the Company's $148,745 Test Year amount plus a $12,119 generic inflation adjustment. Late Filed Ex. 1, Att. 2 Supp., Sch. WP C-3.19. The Company, ho...
AI summary The Company proposed $160,864 in training expenses for the Rate Year, including a generic inflation adjustment. However, it failed to justify this adjustment as reasonable and measurable, leading to the approval of only $148,745, the Test Year amount, without the 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.
c. OPEB The Authority approves an OPEB credit of ($1,175,847), which is to be amortized over a three-year period, resulting in a Rate Year credit of ($391,949). The Company reported a $1,576,130 deferred OPEB liability accrued as of August...
AI summary The Authority approves an OPEB credit of $1,175,847 to be amortized over three years, resulting in a Rate Year credit of $391,949. This follows the Company's reported deferred OPEB liability of $1,263,859 as of October 31, 2025, and adjustments made to remove $200,322 in net carrying credits.
e. Isaias Deferral and Customer Credit The Company proposes that it recover a $127,918 regulatory asset in connection with a penalty imposed on the Company following Tropical Storm Isaias that was not returned to customers as of the Compan...
AI summary The Company seeks to recover a $127,918 regulatory asset related to a penalty from Tropical Storm Isaias not returned to customers in its 2022 rate case. The Authority allows amortization of $121,308 over three years, with a $40,436 annual expense, and requires the Company to refund an additional $33,909 by October 31, 2025.
torm reserve accrual. See Ex. UI-RRP-22C, p. 2. The Authority previously determined that carrying costs on deferred expenses are not permissible without explicit prior Authority approval, and allowing carrying charges to accrue on deferred...
AI summary The Authority disallows a credit of $80,343 of carrying charges calculated by the Company, as it was based on deferred expenses and the reserve accrual. The Authority recalculates the Storm Deferral Refund balance to include carrying charges on the storm reserve but excludes them on deferred expenses and mutual aid reimbursements. The resulting carrying charge balance is a credit of $374,911.
h. Fee Free Program The Company proposes to amortize a ($1,852,863) credit related to the difference between its actual credit card transaction fee costs and the amount embedded in distribution rates for such costs as ordered in the 22-08-...
AI summary The Company seeks to amortize a $1,852,863 credit related to credit card transaction fees, as ordered in the 22-08-08 Decision. The Authority adjusted this credit by $308,376 and added a carrying credit of $228,227, resulting in a $2,389,466 deferred credit to be amortized over three years, representing a $796,489 Rate Year credit.
j. Water Heater Rental Program The Company proposes to recover $12,019,711 in expenses related to phase-out costs of its Water Heater Rental Program, amortized over 36 months, resulting in a Rate Year amortization expense of $4,006,570. La...
AI summary The Company seeks to recover $12 million in phase-out costs for its Water Heater Rental Program over 36 months. The Authority allows recovery of $10.18 million over three years, including carrying charges, resulting in a $3.75 million annual amortization expense. The Authority previously ordered the phase-out of the program by September 1, 2025, and the Company selected the most cost-effective option to retire the fleet.
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.
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.
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.
a. Terms and Conditions The Authority reviewed the Terms and Conditions and Billing Glossary in UI's proposed tariff, which are not rate-impacting. Application, Ex. E 1.0, pp. 1–16. The Company made no revisions to those tariff pages, whic...
AI summary The Authority reviewed and accepted UI's Terms and Conditions and Billing Glossary, which are not rate-impacting and were previously approved. No revisions were made by the Company.
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.
f. Adjustment for Allowed Rate of Return The Authority allows the use of UI's ROR in the FCC formula using the full approved ROR (pre-ROE reductions) in this Decision, 7.142%. The FCC formula utilizes UI's allowed ROR to help determine pol...
AI summary The Authority allows the use of UI's Rate of Return (ROR) in the FCC formula without applying ROE reductions, as approved in the 22-08-08 Decision. This ROR is used to determine pole attachment rental fees and was previously applied in prior rate cases without ROE adjustments.
3. Special Contract Policy The Authority approves UI's proposed special contract policy, with modification, and finds that, as modified, the policy meets the just and reasonable standard, providing sufficient flexibility while limiting the...
AI summary The Authority approves United Illuminating's special contract policy with modifications, ensuring it meets the just and reasonable standard. The policy outlines customer eligibility, bill discount components, and a price floor. CIEC recommended several changes, including adjusting discount thresholds, expanding eligibility, and clarifying local commerce restrictions.
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.
5. Late Payment Charges The Company collects a late payment charge (LPC) or interest fee of 1.25% per month for residential and non-residential customers for bills not fully paid within 28 days. Application, Sch. E-1.0, pp. 23–24; see Deci...
AI summary The Company collects a late payment charge (LPC) of 1.25% per month for customers who do not fully pay their bills within 28 days. Due to the pandemic, LPCs were suspended in March 2020 and partially resumed in October 2022, with further adjustments made in May 2023. The Authority has not modified the LPC practices but requires the Company to file relevant data in annual energy affordability reviews.
1. Customer Service Performance Despite significant prior Authority direction to the Company, customer service performance over the period since UI's last rate case, while showing recent signs of improvement, has remained below the level e...
AI summary The document highlights persistent customer service issues at the Company despite prior regulatory guidance, citing deficiencies in live energy affordability calls, oversight of third-party call centers, and outdated information provided to customer service representatives, as outlined in the 22-08-08 Decision.
3. Customer Experience Initiatives In its Application, the Company detailed several completed customer experience initiatives and proposed initiatives to enhance the customer experience. Application, Ex. UI-CSP-1, pp. 36-48. As of the date...
AI summary The Company outlined completed and proposed customer experience initiatives, including digital improvements and new services, and requested $4.6 million for these projects. However, the Authority declined to pre-approve the initiatives or recovery of associated costs, as none met the 'used and useful' standard for capital projects.
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
28 passages
Cost Allocation The Board will analyze the cost allocation filings to identify with greater certainty the actual share of costs for serving different classes of customers. Distributors with significant variations between class costs and re...
AI summary The Board will review cost allocation filings to determine the actual share of costs for serving different customer classes. Distributors with significant discrepancies between class costs and revenues may be required to address the issue in a 2007 rate application.
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.
1.2.1 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.
1.2.3 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.
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.
6.2.4 Adjustments Staff proposes that certain technical adjustments be made to the demand allocator factors.
AI summary Staff proposes technical adjustments to the demand allocator factors as part of the regulatory proceeding.
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.
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.
9.4 Inputs to the Model The inputs to the OEB cost allocation review filing model will be discussed as the modeling proceeds. Final recommendations will be made in the third phase of the consultations. To assist users, it is anticipated th...
AI summary The OEB cost allocation review filing model will incorporate standardized features like direct assignments and customer allocators based on Board-approved methodologies. Distributors may need to file utility-specific data, including trial balances and load profiles, to support the revenue requirement and rate class calculations.
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.
9.7 Use of OEB Model The purpose of the present cost allocation informational filings is to gather detailed costbased information. Consistency in the filings received from distributors is a crucial goal. The need to review approximately ni...
AI summary The Board is proposing a standard cost allocation filing model to ensure consistency among distributors. The model will be based on approved methodologies and principles, with mandatory use unless an exemption is granted. Distributors using their own models must align with the Board's standards and produce equivalent outputs.
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.
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.
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.
14.2.3 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.
ad data. An Appendix contains a specific Province-wide joint load data collection proposal from over 40 distributors ("the Ontario Load Data Research Group") serving the majority of Ontario customers. The Working Group's Report focused on...
AI summary The document outlines the Board's 2003 Load Data Collection Directions, which were developed based on a proposal from the Ontario Load Data Research Group. The directions focus on the collection of load data for cost allocation studies related to 2006 rates. The Board received feedback from various stakeholders, including Hydro One, Guelph Hydro, and others, and has issued final directions on the matter.
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 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.
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.
N-64N-64.pdf
57 passages
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.
1.5.5 Alternative to Current Transformer Ownership Allowance The filings will include a common cost-based alternative to the current transformer ownership allowance. New substation and secondary transformation ownership allowances will be...
AI summary The filings propose a cost-based alternative to the current transformer ownership allowance, including new substation and secondary transformation ownership allowances and the gathering of relevant costs.
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.
2.1.2 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 Run 1 of the Filings Run 1 of the filings should generally reflect the distributor's approved rate classifications, including any rate classifications approved on an interim basis. Distributors should consider the items listed below wh...
AI summary Run 1 of the filings should reflect the distributor's approved rate classifications, including interim approvals. Distributors are advised to consider specific items when completing Run 1 of the model.
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.
2.3.2 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.
2.3.4 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.
2.4 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.
3.4.2 Directions – Weather Normalization of Load Data The Board directs that the Hydro One methodology be used for weather normalizing the load data used in the cost allocation filings. A summary of the load data weather normalization meth...
AI summary The Board mandates the use of the Hydro One methodology for weather normalizing load data in cost allocation filings, as outlined during the June 15th Phase Three Technical Workshop.
Step 2) CATV Battery Mats For CATV power supplies (excluding any battery mat component), a flat load shape must be used for the present filings. A separate load shape must be applied to the weather-normalized consumption of CATV power supp...
AI summary The document outlines requirements for load shapes related to CATV battery mats in rate filings. Distributors must use a flat load shape for CATV power supplies and a separate load shape for battery mats. Adjustments may be needed for revenue requirement figures if battery mats were not considered in prior filings. A flexible approach is encouraged, with explanations provided in the Filing Summary.
4.1.2 Direction – Distributors that used a historical test year in the EDR 2006 application For distributors that used a historical test year in their 2006 EDR applications, the underlying 2004 trial balances will be the basis of the cost...
AI summary Distributors that used a historical test year in their 2006 EDR applications must use 2004 trial balances as the basis for cost data, with specific adjustments. Costs related to non-utility operations and non-recurring regulatory accounts should be excluded. Adjustments to distribution rates for smart meters are excluded, and proper cost allocation is emphasized, including moving costs between accounts.
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.
4.1.6 Direction - Adjustments to the Trial Balance Except where may be specifically required in this Report, pro forma adjustments to the revenue requirement and cost structure supporting the approved 2006 rates are not to be made in the c...
AI summary The document specifies that pro forma adjustments to the revenue requirement and cost structure for the approved 2006 rates should not be made in cost allocation filings, except in cases where significant operational changes impact the revenue requirement and rates, which must be disclosed and discussed in the Filing Summary.
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.
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.
7.3.2 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.
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.
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.
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.
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.
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.
11.3.1 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.
11.4.1.1 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.
11.4.2.1 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.
11.5.1 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.
11.5.3.1 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.
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.
11.5.5.5 Filing Questions - i) If a distributor has an approved administrative charge in respect of standby rates, then it should explain the basis and components of this charge. - ii) If the distributor incurs other extraordinary costs to...
AI summary The document outlines questions for distributors regarding administrative charges, recovery of extraordinary costs for load displacement generators, and methods for estimating distribution benefits and costs from load displacement facilities.
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.
11.5.7 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.
11.6 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.
12.1.2.2 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.
12.2.2.1 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.
N-91-(v)N-91-(v).pdf
49 passages
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the Tariff for the current rate year as specified in the Demand Side Management Cost Recovery Rider.
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 Tariff for the current rate year, in addition to the energy charge.
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 document outlines the Demand Side Management Cost Recovery Rider, specifying that a charge in cents per kilowatt-hour applies to the Tariff for the current rate year, in addition to the energy charge.
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 Tariff for the current rate year, in addition to the energy charge.
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 of green energy at $5 per month, providing 125 kWh per month from renewable sources and displacing fossil fuel energy.
DOMESTIC SERVICE TIME OF USE TARIFF Page 4 of 4 (2) Service under this rider may be limited at the discretion of the Company, based on the expected level of green energy available.
AI summary The Domestic Service Time of Use Tariff rider may be limited by the Company based on the expected level of green energy available, indicating potential restrictions on service under this tariff.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the Tariff for the current rate year as specified in the Demand Side Management Cost Recovery Rider.
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 Tariff for the current rate year, in addition to the energy charge.
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.
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).
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the bulk power transformer. At the option of the Company, supply may be at distribution voltage. Meter readings shall be increased by 1.1% for each transformatio...
AI summary This section outlines special conditions for metering and service agreements under a tariff. It includes provisions for metering locations, adjustments for transformer losses, capital contributions for primary metering, minimum load requirements, service agreements, and operational standards to maintain power supply integrity.
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.
This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...
AI summary This rider outlines the terms for interruptible billing demand service, including customer obligations to reduce load promptly, penalties for non-compliance, and conditions for converting between interruptible and firm service. The customer must maintain a dedicated phone system and respond to interruption notices, with penalties based on residual demand and performance.
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 Tariff for the current rate year, in addition to the energy charge.
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 This schedule applies as a mandatory rider to all electric rate schedules, with specific exceptions. FAM adjustments apply to certain tariffs, including the Standard Energy Charge of the Extra Large Industrial 2P-RTP tariff and Additional Energy under the Mersey System Agreement when priced at applicable tariffs.
(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 a customer transitions from a non-FAM class to a FAM class, outstanding FAM balances are settled outside the Fuel Adjustment Rider on terms acceptable to the customer and NS Power, with NSEB approval required.
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 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.
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.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the Tariff for the current rate year as specified in the Demand Side Management Cost Recovery Rider.
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 the maximum per kWh charges and minimum bills will remain consistent with the tariffs for NS Power Bundled Service for each Rate Class listed above.
SPECIAL CONDITIONS The same Special Conditions will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above, saving and excepting the Interruptible Rider to the Large Industrial Tariff (Rate Code 25) which...
AI summary The Special Conditions outlined apply to NS Power Bundled Service rate classes, with the exception of the Interruptible Rider for the Large Industrial Tariff (Rate Code 25), which does not apply.
ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...
AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs exceeding those included in its revenue requirement, as approved by the Nova Scotia Energy Board. Any underspend is tracked until a $2.5 million threshold or three consecutive years, after which it is returned to customers. Eligible storm costs are capped at 2% of annual forecast retail revenues.
SCRR RATES FOR 2026 Tariff Storm Riders in cents per kWh1 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use, Small General Cr...
AI summary The document outlines the SCRR rates for 2026, showing zero storm riders across all tariff categories. The company intends to submit an SCRR application by April 30th if required, to take effect in the following year.
RESPONSIBILITIES OF FRANCHISE HOLDER It is the responsibility of the holder of the electric efficiency and conservation franchise granted under Section 79C of the Public Utilities Act (Franchise Holder) to apply to the NSEB to seek approva...
AI summary The Franchise Holder is responsible for seeking NSEB approval for all DSM activities, plans, and programs, including related costs. NS Power must apply for approval of the DSM Cost Recovery Rider amounts by October 1 of the year before program implementation and pay the approved amount monthly to the Franchise Holder.
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) is divided into two parts: BA1, which reconciles revenue discrepancies from two years prior, and BA2, which adjusts for differences between approved DSM funding and actual expenditures, ensuring customers are charged or refunded based on real 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 composed of BA1 and BA2, with BA being updated annually to reflect BA1 and at the end of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR will be implemented in bills starting from the effective date of the change.
2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including its components, Program Cost Recovery (PCR), and Balance Adjustment (BA).
Special Terms and Provisions - (1) Green Power, as defined for the purposes of this rider includes energy produced from renewable resources that have minimal impact on the environment, and could be independently certified by third party en...
AI summary This section defines 'Green Power' as energy from renewable sources with minimal environmental impact, potentially certifiable by third parties. The Company may limit service based on the availability of green energy.
CRITICAL PEAK EVENT PROCEDURE - (1) In the Winter Period, Critical Peak Events exclude all hours on the following holidays: January 1, Nova Scotia Heritage Day, Good Friday, Easter Monday, November 11, December 25 and December 26. If Janua...
AI summary The Critical Peak Event Procedure outlines how Nova Scotia Power Incorporated (NSPI) schedules and notifies customers of critical peak events during the winter period, excluding certain holidays and weekends, to manage high energy usage and costs.
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.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the Tariff for the current rate year as specified in the Demand Side Management Cost Recovery Rider.
AVAILABILITY CONDITIONS - (a) The customer must commence service under this tariff on November 1st, unless NSPI grants a waiver. - (b) The customer must be equipped with a standard Smart Meter. - (c) The customer must be on electronic bill...
AI summary The availability conditions for a tariff require customers to start service on November 1st, have a Smart Meter, use electronic billing, and maintain a MyAccount profile. NSPI may restrict enrollment and customers cannot be on seasonal or Net Metering service under specific regulations.
Effective November 1, 2025, in accordance with the Nova Scotia Energy Board (NSEB, Board) Decision[1](#page-131-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energy Charge applies in al...
AI summary This document outlines the effective dates and terms of the Interim Energy Charge and Time-varying Pricing (TVP) Tariffs as per the Nova Scotia Energy Board's decision on NS Power's application. It specifies billing procedures, customer notifications, and the conditions under which TVP rates will be restored.
DEMAND CHARGE per month per kilowatt of maximum demand Effective February 2, 2023 $10.554 Effective January 1, 2024 $10.554 Effective upon the date of the Board's Order $9.809 Effective January 1, 2027 $10.697 32 cents per kilowatt reducti...
AI summary The document outlines the demand charge rates effective from February 2023 to January 2027, with a reduction of 32 cents per kilowatt for customers who own transformers predating February 1, 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-137-0) on NS Power's Application for 2025/26 Time-varying Pricing (TVP) Tariffs (M12499): - The Interim Energ...
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. NS Power must notify customers once functionality is restored, with specific grace periods depending on the restoration date.
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 outlines charges or credits in cents per kilowatt-hour that apply to the Tariff for the current rate year, in addition to the energy charge.
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 customers who qualify 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.
reduction per kilovolt ampere reduction in demand charge Effective February 2, 2023 $7.486 Effective January 1, 2024 $7.486 Effective upon the date of the Board's Order $7.638 Effective January 1, 2027 $7.667 AVAILABILITY
AI summary The document outlines the reduction per kilovolt-ampere reduction in demand charge at different effective dates, including February 2, 2023, January 1, 2024, the date of the Board's Order, and January 1, 2027.
(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 a customer moves from a non-FAM class to a FAM class, any outstanding FAM balances must be paid or reimbursed outside the Fuel Adjustment Rider on terms acceptable to the customer and NS Power, with NSEB approval required.
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.
8. RTR CUSTOMER RESPONSIBILITIES The RtR Customer shall be responsible for: - (a) payment of all fees and charges arising in connection with the Distribution Tariff; - (b) compliance with the terms and conditions of the Distribution Tariff...
AI summary The RtR Customer is responsible for paying fees related to the Distribution Tariff, complying with its terms and conditions, obtaining renewable low-impact electricity from an LRS, and managing contractual arrangements with an LRS for such electricity.
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 are used to determine charges for Distribution System Access. Interval meters with remote polling capability are required, and all metering equipment remains the property of NS Power, complying with relevant regulations.
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.
AVAILABILITY The same Availability conditions will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above, saving and excepting the Interruptible Rider to the Large Industrial Tariff (Rate Code 25) which w...
AI summary The Availability conditions for NS Power Bundled Service will remain consistent with existing tariffs, except for the exclusion of the Interruptible Rider under the Large Industrial Tariff (Rate Code 25).
Tariff Storm Riders in cents per kWh1 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use, Small General Critical Peak Pricing...
AI summary The document outlines the Storm Cost Recovery Rider (SCRR) application process, specifying that the Company will submit applications by April 30th to recover actual Level 3 and Level 4 storm costs and compare actual SCRR recoveries with forecasted ones. The table lists various tariff categories with zero storm riders in cents per kWh.
BA = Balance Adjustment The BA is comprised of two components: Effective: January 1, 2025January 1, 2026 - (1) BA 1 = Annual Volume Variance Adjustment is calculated for each rate class separately on a previously completed calendar year ba...
AI summary The Balance Adjustment (BA) consists of two components: BA1, which reconciles revenue differences based on actual class load from the previous year, and BA2, which adjusts for differences between approved DSM program costs and actual expenditures. Both are applied with a lag to ensure accurate billing.
2026 DSM Cost Recovery Rider Charges Effective: January 1, 2025January 1, 2026 The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of Jan...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the period from January 1, 2026, to December 31, 2026, including the Program Cost Recovery (PCR) and Balance Adjustment (BA) components. It also explains that the BA is calculated in 2027 and applied over the remaining years of the 2027-2031 term.
N-92Compliance Filing - Standardized Filings - Redacted
12 passages
BELOW-THE-LINE CLASSES (14) SHORE POWER NA NA 1.000 NA NA 1 NA NA - NA NA - 1 0 1 1 0 1 (15) GEN.REPL./LOAD FOLL. NA NA 1.000 NA NA - NA NA - NA NA - - - - - - - (16) ELIADC NA NA 1.000 NA NA - NA NA - NA NA - - - - - - - (17) BUTU NA NA 1...
AI summary The text presents a table with various below-the-line classes, including Shore Power, GEN.REPL./LOAD FOLL., ELIADC, BUTU, REAL TIME PRICING, and OATT, along with numerical data and labels. It appears to be a financial or operational classification table, possibly related to regulatory reporting.
OINCIDENT LINE COIN. PEAK COINCIDENT SALES LOSSES REQUIREMENT DMD. (KW) FACTOR DMD. (KW) LOSSES DMD. (KW) L/D FACTOR ( 1) DOMESTIC 327,490 7.98% 353,638 763,048 87.6% 668,458 9.28% 730,459 65.07% ( 2) SMALL GENERAL 24,363 7.94% 26,296 50,4...
AI summary The text provides a detailed breakdown of electricity demand, losses, and requirement factors across various customer categories in Nova Scotia, including domestic, industrial, and municipal sectors, along with a sub-total summary of the data.
1,138,878 2,239,337 84.4% 1,889,859 12.72% 2,130,200 71.86% (12) SHORE POWER (13) GEN.REPL./LOAD FOLL. (14) ELIADC (15) BUTU (16) REAL TIME PRICING (17) EBS/RTR (17) SUB-TOTAL 13,254 16.4% 13,650 82,065 271.3% 55,591 18.63% 58,391 0.00% (1...
AI summary The document contains numerical data and a list of terms related to energy systems, including SHORE POWER, GEN.REPL./LOAD FOLL., ELIADC, and others. It also references a compliance filing for the 2026-2027 GRA and an exhibit detailing the determination of class non-coincident KW demand by voltage level for 2026.
3 C/P FIRM LARGE INDUST. DEMANDS 212,880 C/P INTERRUPTIBLE RIDER DEMANDS 66,917 C/P FIRM LARGE INDUST. DEMANDS 10,858 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 2 Page 83 of 100...
AI summary The document presents monthly demand adjustment factors for the standby tariff under Nova Scotia Power Inc. for the year ending December 31, 2026, with ratios of average winter peak demand to monthly peak demand for each month.
8 Oct, Nov 1.35 1.65 1.35 1.20 0.99 1.16 0.96 0.92 0.00 1.33 INSERT TABLE FOR STANDBY SERVICE TARIFF Classes Jan, Feb, Dec Mar, Apr May, June Jul, Aug, Sep Oct, Nov Domestic 1.00 1.34 2.13 2.26 1.65 Small General 1.00 1.24 1.62 1.59 1.35 G...
AI summary The document includes a table with standby service tariff rates for different customer classes across various months, as well as an exhibit summarizing system energy line losses for Nova Scotia Power Inc. for the year ending December 31, 2026.
5) PREFERRED DIVIDENDS 0 Corporate Adjustment 23,800.0 0 Regulatory Amort. 7,420 (677.610) (276) CORPORATE TAXES -10,608 Allowance for Funds (26,086) Costs of Goods Sold 0 (277) RETAINED EARNINGS 200,714 (583.862) Net 141,773 Settlement Ad...
AI summary This chunk outlines various financial and operational adjustments, including corporate taxes, retained earnings, interruption costs, and customer solutions allocators. It includes percentages and figures related to different categories and allocations.
12.00% (292) CUSTOMER SOLUTIONS ALLOCATOR - GENERAL 16.51% 12.00% (293) CUSTOMER SOLUTIONS ALLOCATOR - LARGE GENERAL 2.35% 2.00% (294) CUSTOMER SOLUTIONS ALLOCATOR - SMALL INDUST. 1.80% 9.00% (295) CUSTOMER SOLUTIONS ALLOCATOR - MEDIUM IND...
AI summary The document presents a detailed breakdown of percentage allocations for Customer Solutions and Meter Data Services allocators across various categories, including domestic, industrial, municipal, and unmetered sectors. The data compares two sets of percentages, indicating potential adjustments or discrepancies in distribution.
1,825,306.19 1,825,306.19 1,825,306.19 $37,511 (352) (0.000) #REF! #REF! (353) EXPORT SALES - (354) FX Interest (355) (356) FX COST REVENUE OF BTL RATE CLASSES Var (357) SHORE POWER PROD 19.116 19.116 0.000 (358) SHORE POWER TRANS - - 0.00...
AI summary The text presents a financial table with various line items, including shore power, generation replacement, and ELIADC, with associated costs and revenues across different categories such as production, transmission, distribution, and retail. Some entries show variances and include numerical values, while others are marked as zero or not applicable.
3 C/P FIRM LARGE INDUST. DEMANDS 211,850 C/P INTERRUPTIBLE RIDER DEMANDS 67,170 C/P FIRM LARGE INDUST. DEMANDS 10,214 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 83 of 102...
AI summary The document presents monthly demand adjustment factors under the standby tariff for Nova Scotia Power Inc. for the year ending December 31, 2026, including ratios of average winter peak demand to monthly peak demand for different months.
10,114 Allowance for Funds (17,343) Costs of Goods Sold 0 (294) RETAINED EARNINGS 212,348 (8.277) Net 154,226 Settlement Adj. 0 (295) Normal Interruption Cost 160.44 10,114 (296) Interr. Rider Coincident Demand & CD Losses 69,857 (297) PHP...
AI summary The text presents a financial summary with various line items related to costs, credits, and allocations. Key elements include fuel cost recovery deferrals, customer solutions allocators, and percentages for different customer segments.
y. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing RB-01 Attachment 1 has been filed electronically. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing RB-02-RB-16 Attachment 1 has been...
AI summary The document outlines the submission of various attachments for the 2026-2027 General Rate Adjustment (GRA) Compliance Filing by NS Power, including filings related to rate base, demand-side management, and other regulatory matters.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing OE-01A Attachment 02 has been filed electronically. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Compliance Filing OE-01C Attachment 01 has been filed...
AI summary Multiple compliance filings related to the 2026-2027 General Rate Adjustment (GRA) have been submitted electronically, including various attachments and documents.
101825Board Order
31 passages
- c) To file an updated depreciation study with its next general rate application, with several directives to address a comparison of the ALG and ELG methodologies, including, but not limited to: - The interaction between depreciation expe...
AI summary The Board has ordered NS Power to update its depreciation study with specific directives, including comparisons of ALG and ELG methodologies, addressing asset service life accounts, and providing detailed management notes and peer analyses. It also requires addressing cost-of-service concerns raised by Synapse.
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.
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 applied per kilowatt-hour in addition to the energy charge for the current rate year, as part of the Tariff.
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 of green energy at $5 per month, with each block providing 125 kWh of renewable energy per month, displacing fossil fuel energy.
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 document outlines the Demand Side Management Cost Recovery Charge, which is applied in cents per kilowatt-hour on top of the energy charge as part of the Tariff for the current rate year.
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 applied per kilowatt-hour in addition to the energy charge for the current rate year, as part of the Tariff.
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 of green energy at $5 per month, providing 125 kWh of renewable energy and displacing fossil fuel energy. This charge is added to the customer's normal bill under the Domestic Service Critical Peak Pricing Tariff.
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 applied per kilowatt-hour in addition to the energy charge for the current rate year, as part of the Tariff.
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the bulk power transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required...
AI summary The document outlines special conditions related to metering and service agreements. It specifies adjustments to meter readings based on voltage levels, withdrawal of tariff availability for customers not maintaining certain demand levels, and the Company's right to establish separate agreements for specific issues.
DEMAND CHARGE per month per kilovolt ampere of maximum demand Effective upon the date of the Board's Order $10.710 Effective January 1, 2027 $11.269 32 cents per kilovolt ampere reduction in demand charge where the transformer is owned by...
AI summary The document outlines the demand charge rates effective from the date of the Board's Order and January 1, 2027, as well as a rebate of 32 cents per kilovolt ampere reduction in demand charge for customers who own 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.
This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...
AI summary This rider outlines the terms and conditions for interruptible billing demand service, including customer responsibilities, load interruption procedures, penalties for non-compliance, and conversion policies between interruptible and firm service rates. Penalties include threshold and performance components based on demand and compliance during interruptions.
Availability This rate shall be applicable to the supply, operation and maintenance of lighting units not provided for under the Street and Area Lighting rate.
AI summary This rate applies to the supply, operation, and maintenance of lighting units not covered under the Street and Area Lighting rate.
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 This schedule applies as a mandatory rider to all electric rate schedules, with specific exceptions. FAM adjustments apply to certain tariffs and energy supplied under the Mersey System Agreement when Additional Energy is priced at applicable tariffs.
(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.
9. INTERRUPTION OF DISTRIBUTION SYSTEM ACCESS Notwithstanding any term of this Distribution Tariff, NS Power shall have the right to suspend or interrupt, in whole or in part, the provision of Distribution System Access for the purpose of...
AI summary NS Power may suspend or interrupt distribution system access for safety, repairs, or improvements, but customers remain obligated to pay charges during such interruptions and must resume service once it is restored.
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.
AVAILABILITY The same Availability conditions will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above, saving and excepting the Interruptible Rider to the Large Industrial Tariff (Rate Code 25) which w...
AI summary The Availability conditions for NS Power Bundled Service will remain consistent with those in the tariffs, except for the Interruptible Rider to the Large Industrial Tariff (Rate Code 25), which will not apply.
ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...
AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs, subject to approval by the Nova Scotia Energy Board (NSEB). If actual costs exceed or are below the approved amount, specific recovery and return procedures apply. SCRR costs include preparation, response, and restoration expenses, and are allocated based on the Company's Cost of Service Study.
SCRR RATES FOR 2026 Tariff Storm Riders in cents per kWh1 Domestic Service, Domestic Service Time-of-Day, Domestic Service Time-of-Use, Domestic Service Critical Peak Pricing 0.000 Small General, Small General Time-of-Use, Small General Cr...
AI summary The document outlines the Storm Cost Recovery Rider (SCRR) rates for 2026, indicating that no storm riders are applied across various tariff categories. The company intends to submit an SCRR application by April 30th if required, to take effect in the following year.
RESPONSIBILITIES OF FRANCHISE HOLDER It is the responsibility of the holder of the electric efficiency and conservation franchise granted under Section 79C of the Public Utilities Act (Franchise Holder) to apply to the NSEB to seek approva...
AI summary The franchise holder under the Public Utilities Act is responsible for seeking NSEB approval for all DSM activities, plans, and programs, including the DSM Cost Recovery Rider. NS Power must apply for approval by October 1 of the year before implementation and pay the approved amount monthly to fund DSM costs.
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 annual volume variance on a two-year lag, and BA2, which adjusts for discrepancies between approved DSM amounts and actual expenditures, applied over the next DSM term.
2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges and its components, PCR and BA, for the period from January 1, 2026, to December 31, 2026.
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.
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 This document outlines the administration plan for Nova Scotia Power Inc.'s Fuel Adjustment Mechanism (FAM), approved by the Nova Scotia Energy Board. The FAM allows for the recovery of fuel and purchased power costs, with the Base Cost of Fuel being reset through General Rate Applications or Board orders. Stakeholders may challenge the methodology and forecasts in formal proceedings, and the FAM accounts will be subject to audits.
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.
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 This section outlines how Nova Scotia Power should handle load migration between FAM and non-FAM classes, referencing Special Condition 3 of the FAM Tariff.
3.4 Deferrals Effective: May 1, 2026 Page 20 of 33 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 inte...
AI summary NS Power may include prior Fuel Adjustment Mechanism (FAM) deferrals in certain rate classes during the 2026-2027 GRA Period to avoid additional interest charges by deferring these amounts until the end of the period.
Annual Filing Requirements for Base Cost of Fuel Forecast For each year in which NS Power applies to adjust the Base Cost of Fuel, a load forecast, Base Cost of Fuel and net system requirement forecast filing for the upcoming FAM year (Jan...
AI summary NS Power must submit annual, quarterly, and monthly standardized filings related to the Base Cost of Fuel forecast, using templates approved by the Board. The filings include load forecasts, fuel forecasts, and supporting documentation, with stakeholder input required for revisions.
the 'Actual Sales' for the current period. Effective: May 1, 2026 Page 29 of 33 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 other than a Saturday, Sunda...
AI summary This section defines key terms related to NS Power's rate applications and fuel adjustment mechanisms, including the Base Cost of Fuel Component, Compliance Filing, Estimated Sales, Export Sales Costs and Recoveries, and the General Rate Application for the 2026-2027 period.
101354Board Decision
15 passages
e from January 1, 2026, onwards, related to the $704 million in coal-related assets it intends to retire. The amount collected in the deferral is proposed to be added to the total securitized amount. [8] Morrison Park Advisors, a consultan...
AI summary The document discusses the credit rating downgrade of Nova Scotia Power (NSP) to BBB- in 2022 and the risks of further downgrades to 'junk bond' status. Morrison Park Advisors, engaged by Board Counsel, warns that failing to approve both securitization proceeds and rate increases could lead to higher financing costs, potentially adding at least $25 million annually to customer rates.
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.
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 Nova Scotia Power's asset life grouping procedures is criticized for being misleading due to its long-term focus and failure to account for net present value. The ALG procedure is shown to generate more revenue than the ELG procedure, but on a net present value basis, the ELG procedure is more favorable. The analysis also highlights the difficulty in accurately predicting future financial impacts and the importance of using the correct assumptions.
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.
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.
[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.
[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.
this is kind of a middle route. I've acknowledged it's an approximation and that it will be superior to have Nova Scotia Power's analysis when available. [Transcript, January 13, 2026, pp. 1311-1312] [621] In response to Undertaking U-6, N...
AI summary The document discusses the impact of a peak load carrying capability adjustment on distribution system costs, shifting about $7 million in costs from the residential class to other rate classes, particularly the general service class. The adjustment would reduce proposed rate increases for some classes but increase them for others, with some classes still seeing overall rate reductions.
3.9.2 Residential and Small General Customer Charges [649] In its last general rate application, NS Power proposed to increase customer charges for the domestic service and small general customer classes to align those charges with costs u...
AI summary NS Power proposed increasing customer charges for residential and small general customers to align with cost-of-service study findings. Other parties raised concerns, leading to a settlement where charges were set at 75% of the proposed amounts. In the current proceeding, NS Power seeks to increase these charges in line with smoothed non-fuel cost revenue increases.
4.2 Storm Cost Recovery Rider [695] During the 2023-2024 GRA process, participants raised a concern about the asymmetrical nature of the Storm Cost Recovery Rider (SCRR). The current SCRR allows for NS Power to apply to recover Level 3 and...
AI summary During the 2023-2024 GRA process, concerns were raised about the asymmetrical nature of the Storm Cost Recovery Rider (SCRR), which allows NS Power to recover Level 3 and 4 storm costs above those included in the revenue requirement but does not provide a mechanism for returning funds if forecast amounts are not fully spent. NS Power is now requesting approval to continue the SCRR as a pilot in 2026 and 2027 on a symmetrical basis.
[699] The 2026 and 2027 values for the SCRR rider are zero but NS Power's forecast expenditures for OM&G storm restoration costs in 2026 and 2027 are: Level 1 & 2 ($ million) Level 3 & 4 ($ million) 2026 9.6 10.1 2027 9.8 10.3 [Exhibit N-3...
AI summary The SCRR rider values for 2026 and 2027 are zero, but NS Power's forecast expenditures for OM&G storm restoration costs in those years are provided in a table with amounts for Level 1 & 2 and Level 3 & 4.
rts of the settlement agreement. It has made several adjustments in this decision to reduce NS Power's proposed revenue requirement or adjust the allocation of costs among customer classes, including: - A further reduction of $8 million in...
AI summary The Board has made several adjustments to NS Power's revenue requirement and cost allocation, including reducing operating expenses, executive compensation, and denying the deferral of GRA OM&G costs. It also adjusted peak load carrying capability and denied the AMI opt-out fee.
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, which includes cost reductions, adjustments to executive compensation, and tariff changes. The Board also approves the rates for 2026 and 2027, emphasizing the importance of timely filings to avoid confusion for customers.
101825Board Order
37 passages
- 4. NS Power's proposed depreciation rates are approved. - 5. The PHP Deferral account is approved, based on the assumptions in the settlement agreement, to track any variances in revenue in 2026 and 2027 between that which would occur ba...
AI summary The Board approves NS Power's proposed depreciation rates, the PHP and EIFEL deferral accounts, and the inclusion of four Maritime Link transmission projects in the rate base. Approved rates for 2026 and 2027 are based on projected rate base and weighted average cost of capital figures. The FAM Plan of Administration is also approved, effective 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, which are part of the regulatory framework for electricity pricing in Nova Scotia.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the current rate year as part of the Tariff.
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 Tariff for the current rate year, in addition to the energy charge.
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 of green energy at $5 per month, with each block providing 125 kWh of renewable energy per month, displacing fossil fuel energy.
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 Tariff for the current rate year, in addition to the energy charge.
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 of green energy at $5 per month, providing 125 kWh of renewable energy and displacing fossil fuel energy. This charge is added to the customer's normal bill under the Domestic Service Critical Peak Pricing Tariff.
DOMESTIC SERVICE TIME OF USE TARIFF Page 4 of 4 (2) Service under this rider may be limited at the discretion of the Company, based on the expected level of green energy available.
AI summary The domestic service time of use tariff rider may be limited by the company based on the expected level of green energy availability.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the current rate year as part of the Tariff.
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 Tariff for the current rate year, in addition to the energy charge.
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. It also mentions a reduction in the demand charge for customers with transformers owned prior to February 1, 1974, or under Special Condition (2).
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. It also mentions a 32-cent reduction in demand charge for customers with transformers owned prior to 1974 or under a specific special condition.
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 document outlines the application of the Demand Side Management Cost Recovery Charge, which is added to the energy charge in the current rate year as part of the Tariff.
SPECIAL CONDITIONS - (1) Metering will normally be at the low voltage side of the bulk power transformer. Should the customer's requirements make it necessary for the Company to provide primary metering, then the customer will be required...
AI summary The special conditions outline requirements for metering, billing demand maintenance, and service agreements. Customers requiring primary metering must contribute additional capital costs. Adjustments to meter readings are specified based on voltage levels, and the company may withdraw the tariff if billing demand thresholds are not met.
INTERRUPTIBLE RIDER TO THE LARGE INDUSTRIAL TARIFF (RATE CODE 25) Customers who qualify for interruptible service will receive a per month per kilovolt ampere reduction in demand charge for billed interruptible demand, as shown in the tabl...
AI summary The interruptible rider to the Large Industrial Tariff (Rate Code 25) provides a monthly reduction in demand charges based on billed interruptible demand, defined as the difference between contracted firm demand and billing demand. Credits apply only when billing demand is less than contracted demand, with specific rules for calculating billed interruptible demand.
This rider will be applicable to an agreed upon, between the Company and the customer, interruptible billing demand at 90% Power Factor, under the following terms and conditions: - (1) The customer has provided written notice of their desi...
AI summary This rider outlines the terms for interruptible billing demand service, including customer responsibilities, load interruption procedures, penalties for non-compliance, and conditions for converting between interruptible and firm service rates. The customer must comply with load reduction requirements and maintain communication systems for interruptions.
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 This schedule applies as a mandatory rider to all electric rate schedules, excluding specific tariffs such as Generation Replacement and Load Following, and certain Time-of-Use Real Time Pricing tariffs. FAM adjustments apply to specific tariffs and energy supplied under the Mersey System Agreement when applicable.
(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 every two years through the FAM adjustment process or in a General Rate Application. Changes to this cost will affect customer rates according to the Board-approved Cost of Service Methodology.
(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 a customer moves from a FAM class to a non-FAM class, NS Power must calculate the fuel cost imbalance and adjust it in future FAM proceedings. Adjustments require approval from the Nova Scotia Energy Board and must be resolved on terms acceptable to both parties, or as determined by the NSEB.
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, with exceptions for those directly connected to the Transmission System. Transmission-connected customers must arrange access through the LRS under OATT provisions. The tariff outlines terms and conditions for distribution 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 providing distribution system access, processing customer transaction requests, providing billing data, and acting as a contact point for RtR Customers. However, it is not responsible for supplying electricity, monitoring contracts between RtR Customers and LRS, or being liable for the LRS's failures.
8. RTR CUSTOMER RESPONSIBILITIES The RtR Customer shall be responsible for: - (a) payment of all fees and charges arising in connection with the Distribution Tariff; - (b) compliance with the terms and conditions of the Distribution Tariff...
AI summary The RtR Customer is responsible for paying fees related to the Distribution Tariff, complying with its terms, obtaining renewable low-impact electricity from an LRS, and managing contractual arrangements with the LRS.
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 NS Power calculates distribution tariff amounts for RtR Customers based on meter readings and applicable rate schedules. If a customer's operational or consumption characteristics change, NS Power will adjust the tariff rate to match the new classification.
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 costs, 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.
AVAILABILITY The same Availability conditions will apply as stated in tariffs for NS Power Bundled Service for each Rate Class listed above, saving and excepting the Interruptible Rider to the Large Industrial Tariff (Rate Code 25) which w...
AI summary The document states that the same availability conditions as those in the NS Power Bundled Service tariffs will apply, with the exception of the Interruptible Rider to the Large Industrial Tariff (Rate Code 25), which will not be applicable.
ADJUSTMENTS Subject to NS Power making application for recovery of costs through the Storm Cost Recovery Rider (SCRR), this Rider will provide for recovery of actual Level 3 and Level 4 storm costs as defined in the Company's Emergency Ser...
AI summary The Storm Cost Recovery Rider (SCRR) allows NS Power to recover actual Level 3 and Level 4 storm costs from customers, subject to approval by the Nova Scotia Energy Board. If actual costs are below the approved amount, the difference is tracked and returned to customers under certain conditions. The Rider includes specific cost categories and recovery mechanisms based on customer class and market participation.
RESPONSIBILITIES OF FRANCHISE HOLDER It is the responsibility of the holder of the electric efficiency and conservation franchise granted under Section 79C of the Public Utilities Act (Franchise Holder) to apply to the NSEB to seek approva...
AI summary The franchise holder under the Public Utilities Act must seek NSEB approval for all DSM activities, plans, and programs, and itemize related costs. NS Power must apply for DSM Cost Recovery Rider amounts by October 1 each year and pay the approved amount monthly to the Franchise Holder.
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 differences based on actual class load from two years prior, and BA2, which adjusts for discrepancies between approved DSM funding and actual expenditures, ensuring customers are charged or refunded accordingly.
Total BA = BA1 + BA2 The BA shall be updated annually to reflect BA1, and at the conclusion of each Approved DSM Term to reflect BA2. The NSEB-approved DCRR shall be placed into effect with bills rendered on and after the effective date of...
AI summary The Balance Adjustment (BA) is updated annually and at the end of each Approved DSM Term, with the NSEB-approved Demand Side Management Cost Recovery Rider (DCRR) being implemented in bills after its effective date.
2026 DSM Cost Recovery Rider Charges The Demand Side Management Cost Recovery Rider (DCRR) charges, along with its components, (PCR) and (BA), for the period from the approved effective date of January 1, 2026 to December 31, 2026 are as f...
AI summary The document outlines the Demand Side Management Cost Recovery Rider (DCRR) charges for the year 2026, including its components PCR and BA, effective from January 1, 2026, to December 31, 2026.
1 The Approved DSM Term refers to the full DSM Plan period in effect (e.g. 2023-2026, 2027-2031). Applicable Tariff PCR (cents per kWh) BA (cents per kWh) DCRR (cents per kWh) General, General Time of Use, General Critical Peak Pricing, Mu...
AI summary The document defines the Approved DSM Term as the full DSM Plan period in effect, such as 2023-2026 or 2027-2031. It also presents a table outlining various applicable tariffs, including PCR, BA, and DCRR values for different service categories.
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 and those in the Wholesale Market, specifying that the approach applies to classes as a whole or individual customers, respectively, and that it covers total Approved DSM costs.
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, effective May 1, 2026.
al fuel cost incurred by NS Power. The apportioned interest expense or credit is added to the fuel cost variance by class to provide the total fuel and interest (over)/under-recovery amount by class. In order to determine the factor to be...
AI summary This section explains how the Fuel Adjustment Mechanism (FAM) calculates the Actual Adjustment (AA) and Balance Adjustment (BA) components. It describes the process of determining fuel and interest variances by class and how these factors influence the credit or charge applied to customers' bills for the subsequent year.
3.4 Deferrals Effective: May 1, 2026 Page 20 of 33 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 inte...
AI summary During the 2026-2027 GRA Period, NS Power may include prior FAM deferrals for certain rate classes to save additional interest charges by avoiding further deferral to the end of the period.
Annual Filing Requirements for Base Cost of Fuel Forecast For each year in which NS Power applies to adjust the Base Cost of Fuel, a load forecast, Base Cost of Fuel and net system requirement forecast filing for the upcoming FAM year (Jan...
AI summary NS Power must submit annual, quarterly, and monthly standardized filings related to the Base Cost of Fuel forecast, using templates approved by the Board. These filings include load forecasts, fuel forecasts, and supporting reports. Changes to reporting templates require stakeholder and Board approval.
the 'Actual Sales' for the current period. Effective: May 1, 2026 Page 29 of 33 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 other than a Saturday, Sunda...
AI summary This section defines key terms related to NS Power's rate application and fuel adjustment mechanism, including the Base Cost of Fuel Component, Compliance Filing, and General Rate Application. It outlines how fuel costs are recovered and how sales are estimated for rate calculations.