N-72026-2027 GRA Appendix 8A-G -Depreciation Study - Redacted
83 passages
REDACTED (CONFIDENTIAL INFORMATION REMOVED) 340.99 OTHER PRODUCTION PLANT OTHER PRODUCTION - GAS TURBINES BURNSIDE 12-2049 75 - S0.5 a (10) 43,645,266 14,071,208 33,938,585 1,440,687 3.30 23.6 TUSKET 12-2049 75 - S0.5 a (11) 17,461,600 6,8...
AI summary The text provides financial and operational data for gas turbine production plants at Burnsidge, Tuskett, and Victoria Junction, including details on costs, revenues, and efficiency metrics.
AD 12-2035 90 - S0.5 a (2) 24,785,573 13,165,184 12,116,101 1,031,094 4.16 11.8 TOTAL OTHER PRODUCTION - WIND 314,100,795 141,206,954 178,996,752 13,208,959 4.21 TOTAL OTHER PRODUCTION PLANT 492,589,726 184,208,655 336,433,567 22,666,476 4...
AI summary The document presents financial data related to production costs, including figures for total other production from wind and other production plants, along with various financial metrics such as totals, percentages, and other numerical indicators.
0.4 367.00 UNDERGROUND CONDUCTORS AND DEVICES 42 - R3 (25) 75,012,364 33,657,017 60,108,439 2,408,318 3.21 25.0 368.00 LINE TRANSFORMERS 35 - R1 (25) 555,455,934 237,671,905 456,648,012 23,881,410 4.30 19.1 369.00 SERVICES 48 - S2.5 (65) 1...
AI summary The text presents financial data for various categories including underground conductors, line transformers, services, meters, and street lighting, with details on costs, revenues, and other metrics.
370,570 5,108,660 5,108,660 (179,498,344) (3) INTERNATIONAL COAL PIER 2029 17,885,000 19,746,485 19,746,485 (11,479,941) (172) TOTAL STEAM PRODUCTION PLANT 208,443,570 288,335,282 190,084,838 (2,123,890,000) (9) HYDRO PRODUCTION PLANT AVON...
AI summary The text presents financial data and figures related to various energy production facilities, including international coal pier, total steam production plant, and hydro production plants such as Avon, Bear River, Black River, and Dickie Brook. The data includes amounts related to costs and revenues for different years.
COST OF GROSS NET REGULAR REMOVAL SALVAGE SALVAGE YEAR RETIREMENTS AMOUNT PCT AMOUNT PCT AMOUNT PCT 1993 299,338 0 142 0 142 0 1994 2,461 0 0 0 1995 32,151 25,848 80 14,439 45 11,409- 35- 1996 27,997 52,984 189 11,179 40 41,805- 149- 1997...
AI summary The text provides a table detailing the cost of retirements, gross amounts, net amounts, and salvage values over various years, from 1993 to 2010. It includes data on percentages and specific figures for each year, highlighting the financial aspects of retirements and salvage values.
COST OF GROSS NET REGULAR REMOVAL SALVAGE SALVAGE YEAR RETIREMENTS AMOUNT PCT AMOUNT PCT AMOUNT PCT THREE-YEAR MOVING AVERAGES 99-01 682,778 732 0 0 732- 0 00-02 671,611 0 0 0 01-03 590,023 0 0 0 02-04 513,236 705 0 0 705- 0 03-05 266,092...
AI summary The document presents a table with data on cost of retirements, gross amounts, net amounts, and salvage values over a period of years, showing trends and percentages related to asset management and financial considerations.
ments. Potential sediment management costs based on known or suspected contamination and the nature of the sediments in the various reservoirs. A comparison of the results of the 2018 and 2024 estimates is provided in Table ES-1. Table E...
AI summary The text compares 2018 and 2024 estimates for system decommissioning costs, showing increases in infrastructure removal, environmental, and sediment management costs, with a notable exception of no sediment management required at Wreck Cove.
y “Hydro System Decommissioning Cost Estimate for Nova Scotia Power Inc’s Control Structures” [1] resulted in the generation of cost estimates which included: Infrastructure removal costs, including powerhouse, substation and equipment r...
AI summary The document discusses the decommissioning cost estimate for Nova Scotia Power Inc.'s hydroelectric facilities, including infrastructure removal, environmental costs, and sediment management. An updated estimate was conducted in 2024, building on the 2018 study by Hatch.
Financing costs. Costs driven by revisions/changes to laws and regulations. Soil and sediment decontamination and disposal costs. Compensation to landowners related to depreciated land values and altered uses. Lost or altered rec...
AI summary The text outlines various costs associated with a decommissioning project, including financing, legal changes, decontamination, landowner compensation, and grid-related work. It also discusses the use of Producer Price Indexes (PPIs) to calculate escalation factors for project costs, with specific weightings assigned to workforce, construction equipment, fuel, and materials.
H374195-0000-21A-249-0001, Rev. 0 Page 5 © Hatch 2024 All rights reserved, including all rights relating to the use of this document or its contents. REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2026-2027 GRA Direct Evidence Appendix 8B Pag...
AI summary The document discusses the calculation of composed escalation factors using the Producer Price Indexes (PPIS) for the year 2024, based on a formula that considers the relative weighting of each component. It also outlines the index series used for decommissioning projects in Canada, including workforce and construction equipment.
commissioning projects in Canada: 1. Workforce: Average hourly rate for construction 2. Construction equipment: Equipment and machinery 3. Fuel: Annual average retail prices for gasoline and fuel oil in cents per liter 4. Structural compon...
AI summary The document discusses commissioning projects in Canada, focusing on factors such as workforce rates, construction equipment, fuel prices, structural components, and concrete costs, with detailed data provided in Appendix A and Figure 3-1. It also includes a hydroplant asset study update by Nova Scotia Power Inc. regarding hydro system decommissioning.
3.50 3.00 Escalation Factor 2.50 2.00 1.50 1.00 0.50 1990 1995 2000 2005 2010 2015 2020 2025 Year Workforce Const. Equip. Fuel Structural components Concrete Composed factor Figure 3-1: Canadian Escalation Factors per Year Referred to 2024...
AI summary The text discusses escalation factors for decommissioning projects in the USA, including workforce, construction equipment, fuel, structural components, and concrete, with data from 1991 to 2024. It references Appendix A for detailed PPI breakdowns and Figure 3-2 for composed escalation factors.
The resulting composed escalation factors per year, as well as the escalation factor per cost component, are shown in Figure 3-2. . H374195-0000-21A-249-0001, Rev. 0 Page 7 © Hatch 2024 All rights reserved, including all rights relating to...
AI summary The document presents a graph showing escalation factors per year and per cost component, including workforce, construction equipment, fuel, and structural components, with data referenced to 2024.
For the Annapolis, Gaspereau, St. Margaret’s Bay and Tusket systems, Hatch had performed decommissioning estimates for environmental costs as part of other project scopes. These estimates were site specific and likely more accurate than ap...
AI summary The document discusses environmental cost estimates for decommissioning four systems (Annapolis, Gaspereau, St. Margaret’s Bay, and Tusket) based on site-specific data from a 2018 study, which were escalated to 2024 CAD using a 1.23 Canada escalation factor. Table 4-2 provides the adjusted costs for each system.
1.23 $13,018,175 Mersey $15,500,000 1.23 $19,065,000 4.3 Sediment Management Costs Each system’s sediment classification from 2018 was checked against any new information. No information was found that conflicted with the 2018 assumptions....
AI summary The text discusses sediment management costs for various systems, noting that classifications from 2018 remain unchanged except for Wreck Cove, which was re-evaluated from 10% to 0% due to a misassignment. It also references a hydroplant asset study update by Nova Scotia Power Inc.
The infrastructure removal, environmental, and sediment management estimated cost results are described in more detail in Sections 5.2, 5.3, and 5.4, respectively. 5.2 Infrastructure Removal Costs The updated infrastructure removal cost es...
AI summary The document details infrastructure removal costs for NSPI’s hydroelectric portfolio, noting increases due to inflation and updated data on dam removal costs. Environmental and socio-economic costs are excluded from the estimates.
sting) or precedent (based on the environmental costing matrix). Main drivers of cost increases were inflation and new information regarding contamination. H374195-0000-21A-249-0001, Rev. 0 Page 14 © Hatch 2024 All rights reserved, includi...
AI summary The document discusses cost increases driven by inflation and new contamination information, referencing a hydroplant asset study update and a hydro system decommissioning study from December 11, 2024.
$33,577,731 Wreck Cove $55,946,550 $131,159,862 0.0% $ 8,913,745 - 6. References [1] Hatch Ltd., "Hydro System Decommissioning Cost Estimate Final Report. Report No. H357345- 00000-200-230-0001," 2018. [2] N. Pansic, R. Austin and M. Finis...
AI summary The document outlines a hydro system decommissioning study update by Nova Scotia Power Inc. (NSPI), referencing cost estimates, sediment management, and producer price indexes. It includes citations from various reports and studies, including a 2024 email from NSP regarding the hydro study update.
Hydro Asset Archaeology Study consisted of background research, the creation of GIS-based models of pre-dam landscapes and archaeological potential modeling and serves as a companion to this document. In 2024, NSPI requested Boreas Heritag...
AI summary The document outlines the Hydro Asset Archaeology Study, including background research, GIS-based modeling of pre-dam landscapes, and archaeological potential modeling. In 2024, NSPI requested Boreas Heritage to update the 2018 Hydro Asset costings due to increased expenses, updated field methods, and evolving regulations.
evelopment or decommissioning areas included in the Asset List are clear of archaeological concerns. As a result, any changes, recommendations or requirements by CCTH may affect the final costs. There are many unknown factors that may cont...
AI summary The text discusses the potential impact of archaeological concerns on the costs of development and decommissioning projects, emphasizing the challenges in estimating costs due to unknown factors. Boreas Heritage recommends a staged approach to manage and mitigate these concerns.
e 2018 Hydro Asset Archaeology Program. The following recommendations and costings for the Sheet Harbour Hydro System are based on the results of that study and are summarized in Table 13. Table 13. Summary of costings for individual asset...
AI summary The text discusses the 2018 Hydro Asset Archaeology Program and provides costings for archaeological assessments at various locations in the Sheet Harbour Hydro System, including Governor Lake Dam and Governor Lake, highlighting the need for reconnaissance and monitoring due to high archaeological potential.
etailed Decommissioning Opinion of Probable Cost). The Detailed Opinion of Probable Cost consists of line items developed in 2010 and is consistent with the NSPI plant system Work Breakdown Structure. 2.1 Cost Categories Revised probable c...
AI summary The document outlines the methodology for estimating the probable costs of decommissioning NSPI power production sites, including the use of updated price indices and industry benchmarks, as well as the classification of estimates based on AACE guidelines.
2026-2027 GRA Direct Evidence Appendix 8D Page 8 of 189 NSPI Power Production Sites Remediation Study Update August 26, 2024 Table 1 AACE Estimate Classifications Level of Project Estimating Level of Accuracy Estimate Class End Usage Defin...
AI summary This document provides an update on the NSPI Power Production Sites Remediation Study and includes a table outlining AACE Estimate Classifications, detailing levels of project estimation, methodologies, and accuracy ranges.
50% to 100% Check Estimate Deterministic 50%: -10% to +15% or Bid/Tender 100%: -3% to +3% To determine the class of estimate required to achieve an accuracy of 25%, the level of definition for the decommissioning, demolition and remediatio...
AI summary The document discusses cost estimation for decommissioning, demolition, and remediation projects, noting a 23% escalation factor due to rising labor and material costs. It also outlines the use of Class 4 estimates and contingency rates based on site-specific conditions.
2026-2027 GRA Direct Evidence Appendix 8D Page 9 of 189 NSPI Power Production Sites Remediation Study Update August 26, 2024 2.5 Variation in Cost Estimates 2.5.1 Asbestos Abatement The feedback received from site operations at Trenton was...
AI summary The document discusses variations in cost estimates for the NSPI Power Production Sites Remediation Study, highlighting increased asbestos abatement costs at the Trenton site, challenges with salvage and material scrap value estimates, and the absence of detailed air monitoring data.
Item Description Estimated Cost July 2024 Assumptions / Notes: Code 500's ELECTRICAL: 50&51 ON SITE DISTRIBUTION LINES REMOVALS 109,360 56 ELECTRICAL POWER SYSTEMS REMOVAL 169,508 57 OlliER AUXILIARY SYSTEMS AND EQUIPMENT REMOVALS 58 ELECT...
AI summary The document outlines various costs associated with the removal and decommissioning of electrical, water, and building systems, including on-site distribution lines, electrical power systems, water systems, and building ventilation. It also includes administrative expenses not included in the demolition phase.
,544 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS 44,455 SUB-TOTAL (excluding contingency): 22,092,248 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 25% 5,523,062 GRAND TOTAL: 27,615,310 NOTE: The Demolition Estimate is based...
AI summary The document provides a demolition and environmental remediation estimate with a total cost of $27,615,310, including a 25% contingency allowance. The estimate is based on previous site visits, limited drawings, past experience, and consultation with a contractor, without actual quotes or field data.
4 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS $ 44,455 SUB-TOTAL (excluding contingency): $ 31,365,613 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 25% $ 7,841,403 GRAND TOTAL: $ 39,207,016 NOTE: The Demolition Estimate is b...
AI summary The document provides an estimate for demolition and environmental remediation costs, including a 25% contingency allowance. The estimate is based on previous site visits, limited drawings, past experience, and consultation with a contractor, but no actual quotes were obtained. Environmental remediation costs are based on site size, brownfield development, and potential contamination levels.
85 ADMINISTRATION EXPENSES $ 1,458,134 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS $ 54,680 SUB-TOTAL (excluding contingency): $ 23,136,602 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 25% $ 5,784,150 GRAND TOTAL: $ 28,920,7...
AI summary The document provides an estimate for administration expenses and includes a contingency allowance. The demolition estimate is based on limited data and past experience, while environmental remediation costs are estimated based on site size and potential contamination, with a 25% contingency factor applied.
Y FOR FINANCIAL DEPRECIATION COST STUDY 2024 LOCATION: BURNSIDE GAS TURBINE SITE DATE: Julv2024 Account Estimated Cost: Item Description Assumptions / Notes: Code July 2024 1.23 Factor for Up-dating from July 2010 to July 2024 100"s SllE R...
AI summary The document outlines estimated costs for financial depreciation related to site remediation and building structures at the Burnsides Gas Turbine Site in July 2024. It includes costs for site remediation issues, site access removals, and site services removals, along with an updating factor from July 2010 to July 2024.
$ - 77 Plant Operating Equipment Removals $ - 800's GENERAL AND UNDISTRIBUlED: 82 Field Facilities and Decommissioning $ 9,113 85 Administration Evftllnses $ 296 627 ()stantec. \\ca0213-ppfss01\work_graup\1214\aclive\121418266\05_report_de...
AI summary The document presents a summary of site decommissioning estimates for the Financial Depreciation Cost Study 2024, focusing on the Burnsides Gas Turbine Site. It includes line items for plant operating equipment removals, field facilities and decommissioning, and administrative expenses.
DATE: Jul-24 Account Item Description Estimated Cost July 2024 Assumptions / Notes: Code 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS $ 31,699 SUB-TOTAL (excluding contingency): $ 6,523,061 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATI...
AI summary The document provides an estimate for demolition and environmental remediation costs, including a contingency allowance of 25% due to limited data and reliance on past experience and consultations with contractors.
,232 85 ADMINISTRATION EXPENSES $ 78,923 900's SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS $ 24,600 SUB-TOTAL (excluding contingency): $ 4,325,920 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 25% $ 1,081,480 GRAND TOTAL: $ 5,407,4...
AI summary The text presents an estimate for demolition and environmental remediation costs, including a contingency allowance of 25% due to limited data and reliance on previous experience and consultations. The total estimated cost is $5,407,400.
83 GRAND TOTAL: $ 5,939,913 NOTE: The Demolition Estimate is based on previous site visit, limited drawings, past experience and consultation \\4th an experienced contractor, no actual qoutes to complete the Demolition v.ork were obtained....
AI summary The text provides a demolition estimate for a site, noting that it is based on previous site visits, limited drawings, and consultations with an experienced contractor, without actual quotes. Environmental remediation costs are estimated based on site size and contamination potential. A 25% contingency factor is included, and scrap value for rail cars is not considered.
$ 58 ELECTRICAL CONTROL AND COMMUNICATION $ 700"8 COMMON SERVICES: 71 WATER SYSTEMS REMOVAL $ 73 BUILDING VENTILATION AND HEATING REMOVALS $ 75 COMPRESSED GAS SERVICES REMOVAL (EXCLUDING FUEL GAS) $ 77 PLANT OPERATING EQUIPMENT REMOVALS $...
AI summary The document outlines various categories of costs associated with electrical control and communication, water systems removal, building ventilation and heating removals, compressed gas services removal, plant operating equipment removals, field facilities and decommissioning, administration expenses, and schedules and general drawings, with specific monetary figures listed for some items.
$ 52,112 82 ADMINISTRATION EXPENSES $ 156,336 SUB-TOTAL (EXCLUDING contingency): $ 3,682,576 CONTINGENCY ALLOWANCE FOR MARGIN OF ESTIMATING ERROR: 20% $ 736,515 SUB-TOTAL (INCLUDING contingency): $ 4,419,091 900's EQUIPMENT SALVAGE AND REC...
AI summary The text presents a financial summary with line items such as administration expenses and equipment salvage and recovery, including a contingency allowance. It also references a redacted document related to a 2026-2027 GRA Direct Evidence Appendix.
aoolv inflation factor. Removal and Disposal of Materials and Residues 1,100,000 Assume $200,000 for chemical residue removals from piping systems and disposal, and $800,000 for cleaning and removal of liquids in caustic tanks, water treat...
AI summary The text discusses the costs associated with the removal and disposal of materials and residues at the Lingan Generating site, including chemical residue removal from piping systems, cleaning and removal of liquids in caustic tanks, and the decommissioning of a large HFO tank. The estimate includes an increase in costs compared to previous years due to higher MW capacity and associated infrastructure.
diation. Costs include presentation of final reports, Record of Site Condition, legal costs, etc. No sianificant chanaes to the 2020 estimate· therefore aoolv inflation factor. Long Term Monitoring 451,800 Cost for semi-annual groundwater...
AI summary The text outlines costs related to long-term monitoring and liability for the LGS and LAMS sites, including groundwater monitoring, reporting, and communication regarding impacts. The estimates are based on updated unit rates from 2024 and assume monitoring over 5 and 10 years respectively.
- •-:�:.. COST STUDY ?n?A LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 100's SITE REMEDIATION ISSUES: 12 SITE REMEDIATION ISSUES 11,989,017 120 Gene...
AI summary The document outlines estimated costs for site remediation issues at the Point Aconi Generating Station, including $11,989,017 for site remediation issues and $232,360 for general preparation activities such as planning, permitting, and coordination with regulators and NSPI. An inflation factor is applied to the 2020 estimate.
No significant change from 2020 estimate; therefore, apply inflation factor. Removal and Disposal of Materials and Residues 246,000 Costs associated with chemical residue removals from piping systems and disposal, and for cleaning and remo...
AI summary The text discusses the removal and disposal of materials and residues, including chemical residue removals from piping systems and disposal costs, as well as cleaning and removal of liquids in caustic tanks, water treatment systems, and fuel systems.
No significant change to 2020 estimate; therefore, apply inflation factor. (j Stantec \\ca0213 ppfss01\work_group\1214\active\121418266\05_report_deliverable\draft_doc\Revised_Draft\Site2_2024 Estimate-Point Aconi Generating Site.xis 2 of...
AI summary The text discusses an estimate for the Point Aconi Generating Site, referencing a cost study and applying an inflation factor to a 2020 estimate. It is part of a larger document related to a regulatory proceeding.
Costs include presentation of final reports, Record of Site Condition, legal costs, etc. No sicnificant chance from 2020 estimate· therefore aoolv an inflation factor. Long Term Monitoring 540,000 Cost for semi-annual groundwater monitorin...
AI summary The text outlines the costs associated with long-term monitoring and liability assessments, including legal costs, groundwater monitoring at specific sites, and communication related to monitoring results. Inflation factors and updated unit rates from 2024 are applied to 2020 estimates.
- •-:�:.. COST STUDY ?n?A LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 15 SITE SERVICES REMOVALS 191,212
AI summary The document provides an estimate of $191,212 for site services removals at the Point Aconi Generating Station as of July 2024.
275 Dyke/ Containment Berm removal 14,514 Dyke/ Containment Berm removal around fuel tanks 300's BOILERS AND AUXILIARIES: 33 BOILER PLANT - REMOVALS 1,188,380 330 General 331 Boiler 1,093,601 332 Draft Plant (including Air & Gas and Magnes...
AI summary The document outlines costs associated with the removal of dykes and containment berms around fuel tanks, as well as various components of boiler plants, including boilers, draft plants, precipitators, and auxiliary systems. It provides a detailed breakdown of expenses related to these removal and replacement activities.
LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 SOO's ELECTRICAL: 50&51 ON SITE DISTRIBUTION LINES REMOVALS 72,907 504 Supporting Structures 505 Framin...
AI summary The document outlines the estimated costs for the removal of electrical infrastructure at the Point Aconi Generating Station, including on-site distribution lines and electrical power systems, with specific line items and notes on equipment and assumptions.
no PCB transformers onsite (equipment all certified) 56 ELECTRICAL POWER SYSTEMS REMOVAL 127,587 560 General -Electrical (including Junction and Terminal Boxes) 54,680 561 Medium Voltage Systems (4 kV to 15 kV) 18,227 562 Low Voltage Syste...
AI summary The text outlines the costs associated with the removal of various electrical power systems and auxiliary equipment, including medium voltage systems, low voltage systems, and control cable systems, with specific line items and amounts provided.
LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 S00's GENERAL AND ADMINISTRATION: 82 FIELD FACILITIES AND DECOMMISSIONING 127,587 825 Demolition Contra...
AI summary The document outlines estimated costs for general and administration expenses at the Point Aconi Generating Station in July 2024, including demolition, environmental engineering, and field supervision costs, with specific line items and assumptions provided.
No significant change since 2020 estimate; therefore, apply inflation factor. 0 Stantec \\ca0213-ppfss01\work_group\1214\active\121418266\05_report_deliverable\draft_doc\Revised_Draft\Site5_2024 Estimate-Tufts Cove Generating Station - R1...
AI summary The text indicates that there has been no significant change since the 2020 estimate, and an inflation factor is being applied. It references a cost study for Tufts Cove Thermal Generating Station.
sume on-site water treatment system can be used during excavation for water control. The cost to remediate sediment impacts have not been induded as a previous investigation conduded that sediments in the area of the site are not expected...
AI summary The text discusses remediation measures for a site, including on-site water treatment systems and fill materials, seeding, fencing, and grading. It notes that sediment remediation is not expected due to background concentrations in Halifax Harbour and applies an inflation factor to cost estimates from previous years.
d. No significant change since 2020 estimate; therefore, apply inflation factor. In-Program Contaminant Monitoring 364,534 Environmental consulting, site coordination/supervision, Project management issues, soil and water sampling during e...
AI summary The text discusses the costs associated with various phases of a decommissioning project, including in-program contaminant monitoring, phase 6 activities, and miscellaneous considerations. It notes that estimates have not changed significantly since 2020 and suggests applying an inflation factor.
.TION COST STUDY ?n?A LOCATION: TUFT'S COVE THERMAL GENERATING STATION DATE: Jul-24 Account Item Description Assumptions/ Notes:2024 Code 36 BOILER STEAM AND WATER SYSTEMS REMOVALS 346,307 360 General 363 Boiler Vents, Drains and Slowdown...
AI summary The document presents a cost study related to the removal of boiler steam and water systems at the Tufts Cove Thermal Generating Station, with specific line items and associated costs listed for various components of the system.
2026-2027 GRA Direct Evidence Appendix 8D Page 104 of 189 SITE ;- - - ·- 11\JINt:: �;:-••••-i; ,. �"-IEETS:nD �111.1 A.11.lr'IAI -,_ :IATION COST STUDY ?n?A LOCATION: BURNSIDE GENERATING STATION (COMBUSTION TURBINE) DATE: July 2024 Estimat...
AI summary This document is part of a cost study related to site remediation issues at the Burnsides Generating Station, dated July 2024. It includes an estimated cost of $1,145,315 for site remediation, with a factor for updating costs from July 2020 to 2024.
sampling for PHCs, estimate indudes reporting and coordination with regulators. Used same methodoloav as 2020 but with uodated 2024 unit rates. Liability 127,587 Potential impacts in the wetland north of the site. No sionificant chanoe sin...
AI summary The text provides estimates for liability and future land use controls related to a site in Burnside, using updated 2024 unit rates and applying an inflation factor due to no significant changes since 2020. The document is part of a revised draft for a cost study.
584 Relaying, Metering, Control and Recording 585 Data Acquisition and Annunciator Systems (When not part of DCS System 341) 586 Time Standards () Stantec \\Ca0213-ppfss01\work_group\1214\active\121418266\05_report_deliverable\draft_doc\Re...
AI summary The document contains a cost study for the Bumside Generating Station, focusing on estimated costs for common services in July 2024. It includes account codes and item descriptions, with assumptions and notes for the estimates.
·- SITE -,;::,,- - :�lnNINI':: ;::_:::;.T;,_:.,TE WO- . i:n � CIIJAl.lt'IAI -, .. _ :1.1\TION COST STUDY ?n?.t TUFTS COVE LM6000 Units (2) Plus WHR Boiler and LOCATION: Steam Turbine Generator DATE: Julv 2024 Account Estimated Cost: Item D...
AI summary The document outlines the removal costs for electrical power systems and auxiliary systems at a site in Tufts Cove, including details on various voltage systems and equipment. The estimated cost for auxiliary systems and equipment removal is listed as $2,460.
2026-2027 GRA Direct Evidence Appendix 8D Page 119 of 189 ·- . i:n � CIIJAl.lt'IAI -, .. _ :1.1\TION COST STUDY ?n?.t SITE -,;::,,- - :�lnNINI':: ;::_:::;.T;,_:.,TE WO- TUFTS COVE LM6000 Units (2) Plus WHR Boiler and LOCATION: Steam Turbin...
AI summary This document provides a cost study for the removal of compressed gas services, excluding fuel gas, at the Tufts Cove LM6000 Units (2) Plus WHR Boiler and Steam Turbine Generator site as of July 2024. The estimated cost for this service is $4,354.
STUDY ?n?.t LOCATION: TUSKET GENERATING STATION (COMBUSTION TURBINE) DATE: 7/15/224 Account Estimated Cost: July Item Description Assumptions/ Notes: 2024 Code 2024 1.23 Factor for Up-dating from July 2020 to July 2024 1DO's SITE REMEDIATI...
AI summary The text outlines a site remediation issue at the Tusket Generating Station, with an estimated cost of $716,490 for the year 2024. The cost includes an updating factor of 1.23 from July 2020 to July 2024.
2026-2027 GRA Direct Evidence Appendix 8D Page 121 of 189 SITE •- - �"',lnNINt: · •,TE wn - 1 �nR Clt.lAt.lt"IAI • :lATION COST STUDY ?n?.t LOCATION: TUSKET GENERATING STATION (COMBUSTION TURBINE) DATE: 7/15/224 Account Estimated Cost: Jul...
AI summary This document is a page from a cost study related to the Tuskett Generating Station, outlining site access and services removal costs for the year 2024. It includes estimated costs and assumptions for various site-related removal activities.
,925 828 Decommissioning Costs 85 ADMINISTRATION EXPENSES 205,199 850 Demolition Studies covered above 851 Consultant Service 29,028 852 Field Supervision 145,140 Includes trailers trucks etc. 853 Head Office Engineering - Salaries and Exp...
AI summary The text outlines various expenses related to decommissioning and administration, including consultant services, field supervision, and engineering costs, as well as final site drawings. These costs are associated with NSPI's involvement in the project.
n of Decommissioning and Clean-up Plans 7,925 One UST removal and two oil/water separator removals. No significant change since 2020; therefore, apply inflation factor.
AI summary The text discusses the costs associated with decommissioning and clean-up plans, including the removal of one underground storage tank and two oil/water separators. It notes that there has been no significant change in costs since 2020 and suggests applying an inflation factor.
s. Includes reporting and coordination with regulators. Used same methodology as 2020 but with updated 2024 unit rates. Liabilitv 27 060 No sianificant chanae since 2020· therefore aoolv inflation factor. Future Controls of Land Use 27 060...
AI summary The text outlines liability calculations and site access removals, including updated unit rates and inflation factors applied since 2020. It references a spreadsheet and a confidential document related to a 2026-2027 GRA Direct Evidence Appendix.
2026-2027 GRA Direct Evidence Appendix 8D Page 131 of 189 lnNINt:: ESTIM4TE - - IEE'T FOR FI ... AIJl"IAI -,_ SITE ni::- - •-:nN COST STUDY ?n?A LOCATION: VICTORIA JUNCTION GENERATING STATION (COMBUSTION TURBINE) DATE: July 2020 Account Es...
AI summary This document provides a cost study for the Victoria Junction Generating Station, focusing on boiler plant removals. The study was conducted in July 2020 and outlines assumptions and notes related to the estimated costs for 2024.
1.23 Factor for Up-dating from July 2020 to 2024 1oo·s SITE REMEDIATION ISSUES: 12 SITE REMEDIATION ISSUES 1,724,076 120 General Preparation (Planning, Pennits, Co-ordination with Regulators etc.) 15,849 Costs associated with overall plann...
AI summary The text discusses site remediation issues, including costs for general preparation, Phase 1 site information assessment, and associated activities. It references a 2017 Phase 1 ESA completed by EXP for specific sites and outlines additional costs for a HAZMAT survey.
nth duration of the project. Used same mathodology as 2020 but with updated 2024 unit rates. 126 Phase 6 - Confinnatory Sampling and Completion Reporting 95,096 Environmental consulting, site coordination/supervision, Project Management is...
AI summary The text discusses Phase 6 of a project involving confirmatory sampling and completion reporting, including environmental consulting, site coordination, and risk assessments. It also mentions miscellaneous considerations such as regulatory approvals and legal costs associated with decommissioning, using updated 2024 unit rates and an inflation factor.
LOCATION: MARINE TERMINAL POINT TUPPER DATE: 15-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 SOO's ELECTRICAL: 50&51 ON SllE DISlRIBUTION LINES REMOVALS 504 Supporting Structures 505 Framing and Ha...
AI summary The document outlines the estimated costs for the removal of electrical infrastructure at the Marine Terminal Point Tupper location, including distribution lines, power systems, and associated components such as transformers and conduits.
Assumptions / Notes: 2024 Code July 2024 1.23 Factor for Up-dating from July 2020 to 2024 100'5 SITE REMEDIATION ISSUES: 12 SITE RE MEDIA11ON ISSUES 2,376,850 120 General Preparation (Planning, Permits, Co-ordination ""1th Regulators etc.)...
AI summary The document outlines site remediation issues, including costs related to planning, permits, and coordination with regulators and entities like NSPI and NSE. The costs are adjusted using an inflation factor from July 2020 to 2024.
lators etc.) 24,600 Costs associated Ytlith overall planning, permitting, coordinating with regulators, coordinating with NSPI, NSE, etc. No change since 2020; apply inflation factor. 121 Phase 1 -Site Information Assessment 49,200 Previou...
AI summary The text outlines costs related to planning, permitting, and coordination with NSPI and NSE, noting no change since 2020 and the application of an inflation factor. It also discusses the need for a comprehensive Phase 1 ESA and a HAZMAT survey due to previous incomplete assessments and the potential presence of asbestos-containing material.
vey. No change since 2020; therefore, apply inflation factor.
AI summary The text indicates that there has been no change since 2020, and suggests applying an inflation factor.
site; therefore, it is anticapted that this cost 1Nill be much lov.er than other NSPI sites. No change since 2020; therefore, apply inflation factor. Excavation of Contamminated Soils and Sediments 526,500 As mentioned above, it is assumed...
AI summary The text discusses the anticipated costs for excavating and disposing of contaminated soils and sediments at an NSPI site, noting that the cost is expected to be lower than at other NSPI sites. It references the use of an inflation factor and updated 2024 soil disposal rates, with assumptions about sediment depth and volume based on previous experiences at similar sites.
l be similar to the PTMT cost since both sites are similar in size and have similar features. No change since 2020; therefore, apply inflation factor. 127 Miscellaneous Considerations: Regulatory Agencies Approval of Decommissioning Comple...
AI summary The text discusses costs associated with site remediation, including regulatory approval, meetings with NSE, and long-term groundwater monitoring. It assumes costs will be similar to PTMT due to comparable site sizes and features, and applies an inflation factor from 2020.
long-term monitoring reporting. Assume groundwater monitoring will be conducted for 5 years. Used same methodoloav as 2020 but 1Nith uodated 2024 unit rates. Liability 61,500 Cost associated with assessing impacts/concems in the adjacent w...
AI summary The text discusses long-term groundwater monitoring, liability estimates for assessing impacts on adjacent properties, and future land use controls. It includes assumptions about monitoring duration, inflation factors, and maintenance costs for fencing. The liability estimate is based on communication costs related to long-term monitoring results.
carried for ongoing fence assessments/maintenance. Assume $50,000 fence maintenance costs. ()stantec. \\ca0213-ppfss01\work_graup\1214\aclive\121418266\05_report_deliverable\draft_doc\Revised_Drafl\Site11_2024 Estimate-Sydney international...
AI summary The text provides an estimate for site decommissioning costs at the Sydney International Coal Pier, including $50,000 for fence maintenance and referencing a spreadsheet with cost details. The document is part of a financial depreciation cost study for 2024.
2 Metering 513 Transfonners (May Contain PCB's) 58 ELECTRICAL POWER SYSTEMS REMOVAL 104,550 560 General -Electrical (including Junction and Tenninal Boxes) 104,550 Lights/ Transfonner/AG-cables/ MCC buildings/ Sub stations 561 Medium Volta...
AI summary This document outlines the costs associated with the removal of electrical power systems, including transformers, junction boxes, and various voltage systems. It references a specific Excel file and includes a redacted section indicating confidential information has been removed.
EET FOR FINANCIAL DEPRECIATION COST STUDY 2024 SYDNEY INTERNATIONAL COAL PIER Account Estimated Cost: Item Description Assumptions / Notes: 2024 Code July 2024 77 PLANT OPERATING EQUIPMENT REMOVALS 15,375 770 Environmental - Monitoring Equ...
AI summary The text provides an estimate of costs related to the removal of plant operating equipment and decommissioning activities at the Sydney International Coal Pier in 2024, including direct labor and equipment costs, as well as general and administration expenses.
AND RAILCAR MAINTENANCE CENTRE DATE: DATE: 30-Jul-24 Account Estimated Cost: Estimated Cost: Item Description Assumptions / Notes: 2024 Code July 2020 July 2024 1.2300 Factor for Up-dating from July 2020 to July 2024 100's SITE REMEDIATION...
AI summary The document outlines the estimated costs for site remediation issues, including general preparation and coordination with regulators and organizations such as NSPI and NSE, with an inflation factor applied to update costs from July 2020 to July 2024.
eporting. Assume groundwater monitoring WII be conducted for 5 years. Used same methodoloav as 2020 but with uodated 2024 unit rates. Liability 50,000 61,500 Cost associated Wth assessing impacts/concerns in the adjacent water bodies or pr...
AI summary The text discusses groundwater monitoring over 5 years, liability estimates for assessing impacts on adjacent water bodies and properties, and future land use controls under NSPI ownership. It includes assumptions about inflation, remediation, and fence maintenance costs.
Costs carried for ongoing fence assessments/maintenance. Assume $30,000 fence maintenance costs. ()stantec \D0213-ppfn01\work_group\1214\aclive\121418268\0S_report_deliverable\draft_dac\Revi&ed_Draft\Si\1112_2024 Estima\11-Sydney Transport...
AI summary The text discusses the estimation of costs for ongoing fence assessments and maintenance, assuming $30,000 for fence maintenance. It also references a site decommissioning estimate worksheet for a financial depreciation cost study related to the Sydney Transportation and Railcar Maintenance Centre.
Estimated Cost 2024 Action Account Item Description Assumptions / Notes: By Code 2024 Escalation 2024 1.23 1oo•s SITE REMEDIATION ISSUES: For this estimate we have assumed the follov,,ina: Comolete demolition of the farm as it stands todav...
AI summary The text provides an estimated cost of $279,825 for site remediation issues in 2024, assuming complete demolition of the farm, no salvage value for equipment, and continued use of the overhead crane until the demolition is complete.
Estimated Cost 2024 Action Account Item Description Assumptions / Notes: By Code 2024 BOO's GENERAL AND ADMINISTRATION: 81 FIELD FACILITIES AND DECOMMISSIONING 57,180 811 Demolition Contractor Site trailers / Facilities 57,180 1.5% ofTDREC...
AI summary The document outlines estimated costs for field facilities, administration, and equipment salvage in 2024, with figures based on percentages of TDREC. These costs are associated with BOO's activities and include demolition, consultant services, supervision, and engineering expenses.
p in 2021. This area historically had scrap metals and minor items (overhead doors, conveyor structure, metal lighting mast, complete with fixtures and roof trusses) stockpiled here, which have been removed from the site. Applied inflation...
AI summary The text discusses the historical removal of scrap metals and minor items from a site, the application of an inflation factor to 2021 estimates, and the reduction of annual capital costs for progressive reclamation activities from 2021 through 2024, adjusted based on the published CPI and the higher costs associated with smaller programs.
Chemistrv/metals. Estimate includes reportina and coordination with reaulators. Liability Future Controls of Land Use (j Stantec V:\1214\active\121418266\05_report_deliverable\deliverable\Site17_2024 Estimate-LS Quarry_rev01.xlsx Page 1 of...
AI summary The text outlines an estimate for site access removals at Glen Morrison Quarry, including reporting and coordination with regulators. It is part of a cost study for a finalization process, dated July 2024.
387 Gypsum Handling and Storage (off-site) 400's TURBINES, GENERATORS AND AUXILIARIES: N/A (j Stantec V:\1214\active\121418266\05_report_deliverable\deliverable\Site17_2024 Estimate-LS Quarry_rev01.xlsx Page 3 of 5 REDACTED (CONFIDENTIAL I...
AI summary The text provides a portion of a cost estimation document for a project at Glen Morrison Quarry, including sections on gypsum handling and storage, as well as electrical components. It includes a table with account codes, item descriptions, and estimated costs for the year 2024.
Assumptions/ Notes: 2024 Code Cost2024 500's ELECTRICAL: 50 & 51 ON SITE DISTRIBUTION LINES REMOVALS 56 ELECTRICAL POWER SYSTEMS REMOVAL 25,200 560 General -Electrical (including Junction and Terminal Boxes) 561 Medium Voltage Systems (4 k...
AI summary The document outlines costs associated with the removal of electrical systems and water systems in 2024. Specific line items include the removal of low voltage systems, fire fighting systems, and an overflow structure at a selling pond, with associated costs provided.
N-92026-2027 GRA Appendix 12 A-C - Cost of Service Study Process - Redacted
312 passages
Cost of Service Study Redacted 1 TABLE OF CONTENTS 2 3 1.0 INTRODUCTION 5 4 2.0 SUMMARY OF STAKEHOLDER PROCESS 7 5 3.0 SUMMARY OF COSS 10 6 3.1 The COSS Framework 10 7 3.2 Developments in the Company's Power System Impacting COS 11 8 4.0 O...
AI summary The document outlines the structure and contents of a redacted Cost of Service Study (COSS) being presented in a regulatory proceeding. It includes sections on the stakeholder process, proposed changes to the COSS, and a line loss study. Key topics include classification of generation and transmission costs, treatment of battery systems, and proposed changes to the DSM rider.
- 4 to be consultative in nature, undertaken through a comprehensive stakeholder process facilitated - 5 by an expert COS consultant. NS Power retained Elenchus Research Associates Inc. (Elenchus) as - 6 its expert consultant at the end of...
AI summary NS Power conducted a consultative process in 2024 with stakeholders to address the Cost of Service (COS) treatment, facilitated by Elenchus and mediated by Bruce Outhouse. The process included technical conferences, resolution sessions, and extensive data exchange, resulting in multiple appendices with models, DR responses, and other supporting documents.
decks provided by NS Power and its consultants, - 25 appended as Appendix 12A(3) , jurisdictional scans, appended as Appendix 12A(4) , and - 26 memorandums, appended as Appendix 12A(5) . 27 - 28 At the outset of the COS process, NS Power p...
AI summary The document references decks provided by NS Power and its consultants, including jurisdictional scans and memorandums, as part of the Cost of Service Study (COSS) process. NS Power presented background information on the COSS to stakeholders, including a review of general principles and a detailed walkthrough of the current COSS approved in 2013.
1 4.0 OVERVIEW OF NS POWER'S PROPOSAL 2 3 NS Power has identified several areas within the existing COSS that can be updated to respond to 4 changes such as increased renewables being brought online, as was ordered by the Board, and to 5 b...
AI summary NS Power proposes updates to the Cost of Service Study (COSS) to align with changes in the electricity market, including increased renewables, and a principled approach focusing on justified changes. They consider cost causation, alignment with Canadian jurisdictions, and seek to simplify the COSS based on stakeholder feedback, using Elenchus' expertise.
11 5.5 Removal of Distinction Between EHV and HV 12 13 NS Power proposes that the distinction between Extra High Voltage (EHV) and High Voltage 14 (HV) within the current COSS model be removed and replaced with a single sub-function for EH...
AI summary NS Power proposes removing the distinction between Extra High Voltage (EHV) and High Voltage (HV) in the COSS model, arguing that their integrated systems justify a single sub-function. This aligns with OATT methodology and is supported by the Elenchus Report, which cites practices in other Canadian jurisdictions.
(WACC) and transmission rate base.
AI summary The text refers to the Weighted Average Cost of Capital (WACC) and transmission rate base, which are key financial and regulatory considerations in utility rate-making processes.
2 3 NS Power is proposing that the treatment of General Plant be refined to more consistently allocate 4 General Plant with a clear and identifiable function. General Plant that is found to have a strong 5 relationship with a category, wil...
AI summary NS Power proposes refining the allocation of General Plant to better reflect its function, focusing on projects over one million dollars. A 'dual allocation' approach is suggested for certain costs, such as vehicle expenses, which would be split between transmission and distribution using allocators like OM&G and rate base.
1 6.0 PROPOSED MAINTENANCE OF STATUS QUO 2 - 3 Through the detailed stakeholder sessions, NS Power and stakeholders comprehensively reviewed 4 each component of the current COSS. Through this review, NS Power identified areas of interest
AI summary This section outlines the proposed maintenance of the status quo, noting that NS Power and stakeholders have reviewed the current Cost of Service Study (COSS) and identified areas of interest during detailed stakeholder sessions.
9 6.1 Classification of Distribution Costs – Minimum System Study 10 11 NS Power currently uses Minimum System Study to classify distribution costs and proposes that 12 continued use of minimum system study to classify distribution costs b...
AI summary NS Power proposes continuing to use the Minimum System Study to classify distribution costs between customer and demand, supported by the Concentric Minimum System Study and the Elenchus Report. This approach allocates system build-out costs based on customer count rather than consumption.
19 6.3 Transmission Links to Other Systems – Maritime Link 9 at a number of system peaks rather than a single peak event. 20 21 The current approach to functionalization of the Maritime Link (ML) between transmission and 22 generation is t...
AI summary NS Power's analysis supports the current approach of fully functionalizing all Maritime Link costs to generation, as transmission costs are minor and not explicitly included in purchase prices. Separating transmission components from generation costs is deemed impractical due to their secondary nature.
- 1 As a reference point, BBA initially adopted an industry benchmark of 1.2 percent for non-technical - 2 losses. This value was then adjusted to 0.9 percent based on refined modelling results. 3 - 4 Non-technical demand losses were estim...
AI summary The document discusses non-technical demand losses, initially set at 1.2 percent and later adjusted to 0.9 percent based on refined modelling. The average non-technical demand loss across classes is estimated at 2.3 percent, calculated using the ratio of technical demand to energy losses and aligned with total system coincident demand.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 1 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Exhibit Reference Cells Modification formulae revised to receive no classification Exh 6 D172:M194 Allocations of transmission energy ex...
AI summary The document outlines modifications to the 2026-2027 GRA Direct Evidence Appendix 12A(1), including adjustments to transmission energy expense allocations, updates to values using the BCF file, and reclassifications to avoid division-by-zero errors in calculations.
1 Request for COSS Model Runs: Run # NSP Position Model Run Description 1 Yes NSP's positions in aggregate. This model includes the changes from model runs #2-5 below. 2 Yes New Intermediate Generation sub-function classified to demand and...
AI summary The document outlines a request for Cost of Service Study (COSS) model runs to evaluate various NSP positions, including the classification of generation and transmission, and the inclusion of specific rate classes and allocation methods.
3 Notes on COSS Model Runs: - 4 All changes to the model cells are denoted with orange highlighting. - 5 Model runs 1, 2, 4, 10a, 10b, and 11 require updates to the Base Cost Fuel ("BCF") file that is an - 6 input into the COSS. Revised ve...
AI summary The document discusses updates to the Base Cost Fuel (BCF) file in the COSS model runs, noting that changes create a mismatch between ATL revenues and costs, which is addressed by adjusting the Profit/Loss figures for BTL classes in specific model runs.
15 COSS Model Run #2, New Intermediate Generation Sub-Function: - 16 New balances are included in the Input Data tab for intermediate generation (Tufts Cove 1,2, and - 17 3). An explanation of the selection of the three Tufts Cove units is...
AI summary The document discusses the inclusion of new balances for intermediate generation units (Tufts Cove 1, 2, and 3) in the COSS Model Run #2. These units are currently categorized under the Steam generation subfunction, and their capacity factors are being analyzed. The explanation for selecting these units is referenced in PHP DR-1.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 7 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process under matter number NSUARB M11475, which is part of the 2026-2027 General Rate Application (GRA) direct evidence. The study is likely related to determining the cost of service for utility providers in Nova Scotia.
11 COSS Model Run #4, PHP is Included as a Separate Class: 12 This model follows the same methodology as PHP DR-12.
AI summary This section describes COSS Model Run #4, which includes PHP as a separate class and follows the same methodology as PHP DR-12.
14 COSS Model Run #5, Classify Grid Scale Storage by ELCC Factor: - 15 Grid Scale Storage is not yet operational and is fully CWIP in 2023 so there are no operating and - 16 maintenance expenses or depreciation functionalized to batteries....
AI summary Grid Scale Storage is not yet operational and is fully CWIP in 2023, resulting in no operating or maintenance expenses or depreciation being functionalized to batteries. Only Interest, Return (Profit/Loss), and Corporate Taxes are functionalized to batteries, with a 62% ELCC provided in CA DR-22.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 8 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the Nova Scotia Utility and Regulatory Board (NSUARB) proceeding numbered M11475. It is part of the 2026-2027 General Rate Application (GRA) direct evidence, specifically Appendix 12A(1), and is marked as confidential.
CONFIDENTIAL 1 COSS Model Run #6, Transmission Subfunctionalized to EHV and HV: 2 The current COSS includes subfunctionalization between EHV and HV but both subfunctions use 3 the same allocators. The allocators applicable to the HV subfun...
AI summary The document outlines various COSS model runs that adjust how costs are allocated across different subfunctions and classifications. These include changes to transmission subfunctionalization, distribution cost allocation, service allocation based on meter costs and customer count, and reclassification of generation based on capacity factors.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 9 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the Nova Scotia Utility and Regulatory Board (NSUARB) matter M11475. It is related to the 2026-2027 General Rate Application (GRA) and includes direct evidence from the appendix.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 10 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This section of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix references the Cost of Service Study Process as outlined in the Nova Scotia Utility and Regulatory Board (NSUARB) matter M11475.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 11 of 46 Cost of Service Study Process (NSUARB M11475)
AI summary This document is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(1), discussing the Cost of Service Study Process under NSUARB matter number M11475.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 12 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the Nova Scotia Utility and Regulatory Board matter M11475. It outlines the process involved in analyzing the cost of service for utility providers in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 13 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the 2026-2027 General Rate Application (GRA) and cites the Nova Scotia Utility and Regulatory Board (NSUARB) matter number M11475.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 14 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding. It outlines the methodology and considerations involved in conducting a cost of service study, which is a key component in determining appropriate rates for utility services.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 15 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document references the Cost of Service Study Process under the NSUARB M11475 proceeding, indicating that it is part of a broader regulatory analysis related to cost of service studies.
CONFIDENTIAL - 1 classes that used to reduce the Profit/Loss allocated to ATL classes (Exh 4 Detail cell H184). In - 2 models 1, 4, and 11 the mismatch as attributed to the new rate class. 3 - 4 COSS Model Run #1, NSP Positions: - 5 This m...
AI summary The text discusses changes in profit/loss allocation for ATL classes and references COSS Model Run #1 and #2, which include NSP's positions and a new intermediate generation sub-function. It outlines adjustments to intermediate generation capacity factors and the classification of Tufts Cove and Lingan units.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 16 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 matter, indicating that the study is a key component in the regulatory proceeding related to the 2026-2027 General Rate Application.
CONFIDENTIAL 1 COSS Model Run #3, Transmission Classified as 100% Demand: 2 The classification of a portion of Transmission as Energy is removed so all rate base and costs are 3 classified as 100% Demand. The sections of the COSS that allo...
AI summary The document outlines various COSS model runs that adjust the classification and allocation of costs related to transmission, grid-scale storage, and distribution. These changes include reclassifying transmission as 100% demand, separating PHP as a class, and adjusting allocators for EHV and HV subfunctions.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 17 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process as part of the NSUARB M11475 proceeding, indicating it is related to the analysis of costs associated with utility services in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 18 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document refers to the Cost of Service Study Process under the NSUARB M11475 matter. It is part of the 2026-2027 GRA Direct Evidence Appendix 12A(1), which includes redacted confidential information.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 19 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary The document refers to the Cost of Service Study Process under NSUARB M11475, which is part of the 2026-2027 General Rate Application (GRA) Direct Evidence Appendix 12A(1). The study is likely related to analyzing the costs associated with service delivery for regulatory proceedings.
1 COSS Model Run #15 Transmission clean import-enabling assets classified by SLF: - 2 This model functionalizes transmission costs associated with enabling clean imports and classifies - 3 these costs by the SLF, with remaining transmissio...
AI summary This section describes COSS Model Run #15, which categorizes transmission costs related to enabling clean imports by SLF, with remaining costs classified as demand. The model includes tabs showing variances between the scenario and the current COSS and Model #3.
8 COSS Model Run #16 Equivalent Peaker Method: - 9 This model run classifies non-fuel generation costs using the equivalent peaker method. NSP does - 10 not build new CT or coal units so the cost per kW of capacity is based on Capital Cost...
AI summary This section describes the use of the equivalent peaker method in the COSS Model Run #16 to classify non-fuel generation costs. Nova Scotia Power uses capital costs from the U.S. Energy Information Administration to determine the cost per kW of capacity, with calculations detailed in the BCF file.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 20 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary This document references the Cost of Service Study Process under matter number NSUARB M11475, indicating that it is part of a regulatory proceeding related to the analysis of service costs.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 23 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475)
AI summary The document references a Cost of Service Study Process under NSUARB M11475, which is part of the 2026-2027 GRA Direct Evidence Appendix 12A(1). The content is redacted, indicating that confidential information has been removed.
THEORY UNDERPINNING THE MINIMUM SYSTEM STUDY - Dr. Pavlovic claims that the Minimum Size Method has no theoretical, practical or empirical basis to - classify a portion of the distribution system cost as customer-related.[1](#page-59-0) Th...
AI summary Dr. Pavlovic argues that the Minimum Size Method (MSS) lacks theoretical, practical, or empirical support for classifying distribution system costs as customer-related. This contradicts industry practice and NARUC endorsement, as well as findings by Concentric showing widespread use of MSS by Canadian utilities.
Description of the MSS - Distribution system costs are incurred to move electricity from generation and transmission facilities - to individual customers that are distributed geographically throughout the service territory of a - utility....
AI summary The document discusses the Minimum Size Method (MSS) for allocating distribution system costs between demand-related and customer-related components. It explains that distribution costs are influenced by both the number of customers and the peak load, and references the NARUC Manual for methodology. An example of the MSS application by Concentric is provided.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 32 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - the system. The minimum system cost represents the customer-related costs, whereas the total c...
AI summary The text discusses two methods for allocating distribution costs: the Zero Intercept Study and the Minimum Size Selection. The Zero Intercept Study uses regression analysis to estimate customer-related costs, but it is criticized for potential statistical unreliability. The Minimum Size Selection method involves selecting the smallest currently installed assets for cost allocation. These methods are outlined in the NARUC Manual.
2 PRIOR COSS - 3 The Board has approved the prior Cost of Service Study (COSS), which classified distribution cost as - 4 both demand and customer-related. Figure 1 above shows the customer and demand classification - 5 utilized in prior C...
AI summary The Board has approved the prior Cost of Service Study (COSS), which classified distribution costs as both demand and customer-related, following established practice in Nova Scotia.
2026-2027 GRA Direct Evidence Appendix 12A(1) Page 36 of 46 REDACTED (CONFIDENTIAL INFORMATION REMOVED) CONCENTRIC EVIDENCE: GRA COSS ELEMENTS 100% demand-related.[7](#page-64-0) This assertion, however, fails to recognize the fact that a...
AI summary The text argues that a portion of distribution system costs is not demand-related, as some infrastructure is required regardless of peak demand. The Minimum Size Method (MSS) is used to calculate non-variable distribution costs, which should not be allocated based on demand due to their fixed nature.
CONCENTRIC EVIDENCE: GRA COSS ELEMENTS 1 Minimum level of load-carrying capacity is appropriate under a minimum sized system 2 The Resource Insight evidence claims that if the minimum size used in the MSS has some load 3 carrying capacity,...
AI summary The text discusses the allocation of minimum system costs and the relevance of the NARUC Manual. It argues that minimum system costs should be treated as equally beneficial to all customers and highlights the continued relevance of the NARUC Manual in cost allocation, despite its last revision in 1992.
POLES SUB-FUNCTIONALIZATION - Secondary customers do not pay twice when combination poles are allocated between - primary and secondary. - The Resource Insight evidence asserts that Concentric's treatment of combination poles (i.e., poles...
AI summary The document discusses the allocation of costs for combination poles in the sub-functionalization study, clarifying that secondary customers are not double-charged. Concentric Energy Advisors explains that the allocation is based on unit costs, ensuring costs are appropriately distributed between primary and secondary functions.
Inclusion of Forecasted Costs - Mr. Briggs disputes the use of forecasted costs in the derivation of net book value and depreciation - expense associated with poles. [29](#page-73-2) It is appropriate to use both capital and O&M forecasted...
AI summary Mr. Briggs disputes the use of forecasted costs in calculating net book value and depreciation expense for poles. The NSUARB argues that both capital and O&M forecasted costs should be used in calculating the pole attachment rate, as the GRA revenue requirement is based on forecasted rate years. The prudency of these costs will be reviewed as part of the GRA.
NON-CONFIDENTIAL 1 Request DR-1: 2 3 Regarding use of ELCC factors in generation COS treatment, please clarify whether NS 4 Power's proposal is for average or marginal ELCC factors, and whether NS Power's 5 proposal is to use ELCC factors...
AI summary The document discusses NS Power's proposal regarding the use of Effective Load-Carrying Capacity (ELCC) factors in the classification of intermediate generation for cost-of-service (COSS) treatment. NS Power prefers using capacity factors over ELCC factors and suggests that if ELCC factors are used, average ELCC factors based on a prospective test year would align with their current COSS approach.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 6 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This section of the document outlines the Cost of Service Study Process referenced in NSUARB M11475, specifically detailing NSPI's responses to CA Data Requests. It is part of a larger, partially confidential proceeding related to the 2026-2027 GRA.
NON-CONFIDENTIAL 1 Request DR-12: 2 3 Please provide the hourly operating cost, including fuel, purchased power, and any other 4 relevant variable costs (transmission fees, environmental control inputs, disposal costs, etc.) 5 for the 2019...
AI summary The company does not track actual hourly operating costs and only provides monthly and quarterly cost data through FAM reports, in response to a request for detailed hourly operating cost information from 2019 to 2023.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests 1 Request DR-14: 2 3 Please provide current transmission costs associated with the extra-high voltage 4 transmission system (EHV, 138 kV and greater) and the...
AI summary NSPI responded to a data request regarding transmission costs for EHV and HV systems in Nova Scotia. The response included spending figures for 2023 and details about the system configuration, noting that both mesh and radial structures are present, with HV lines supplying approximately 25% of the load capacity.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines the Cost of Service Study Process as part of the NSUARB M11475 proceeding, with NSPI providing responses to data requests from the Commission. It focuses on the methodology and data required for the study.
13 Response DR-17: 14 15 (a) The following table provides a list of each distribution region with the transformer 16 nameplate capacity and peak load by transmission supply voltage. The transmission supply 17 voltage refers to the high-sid...
AI summary The text references a table listing distribution regions with transformer nameplate capacity and peak load by transmission supply voltage, with peak load data from 2023. It also mentions a Cost of Service Study Process under NSUARB M11475 and NSPI responses to data requests.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 718 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-22 Attachment 1 Page 1 of 1
AI summary This document is a partially confidential appendix from the 2026-2027 GRA Direct Evidence, specifically COSS CA DR-22 Attachment 1. It is part of a larger regulatory proceeding and contains information related to the Cost of Service Study (COSS).
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 723 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document pertains to the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to CA data requests. The context involves a regulatory proceeding related to the 2026-2027 GRA, with some information redacted.
COSS CA DR-27 Attachment 1 Page 9 of 9 Name Section Title 4 class, differentiating among (1) customer-classified distribution costs (poles and conductors), 5 (2) customer-classified line transformers, and (3) other customer-classified cost...
AI summary The document requests detailed information on customer-classified distribution costs, including line transformers, hookups, and meter-related expenses, by customer class and year, with specific attention to residential classifications and cost classification accuracy.
9 (d) 10 (i) NS Power's COSS tracks meter, service drop, and line transformer costs only by 11 operating and depreciation expense categories. The breakdown of other costs 12 associated with these assets such as interest, taxes, return, or...
AI summary NS Power's COSS tracks meter, service drop, and line transformer costs only by operating and depreciation expense categories. It does not provide costs specifically under a 'customer account' category, but instead includes a variety of customer service-related costs for the Retail Service Area.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study Process under NSUARB M11475. It provides information relevant to the regulatory proceeding on cost of service studies.
NON-CONFIDENTIAL 1 Request DR-38: 2 3 Please identify how NS Power allocates land, easements, survey, and other similar costs and 4 explain the reasoning for this choice. 5 6 (a) For land/easements, please provide any available data (i.e.,...
AI summary NS Power explains that land, easements, and survey costs are allocated based on the relative shares of demand and customer services of the combined investment in substations and poles and wires. These costs account for 11% of total distribution plant investment and are classified 47.3% to Demand and 52.7% to Customer. This method has been used for many years and is considered complementary to the operation of substations and power lines.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 753 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study (COSS) process under the NSUARB M11475 proceeding. It provides insights into the GRA (General Rate Application) for the 2026-2027 period.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 754 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document outlines NSPI's responses to data requests related to the Cost of Service Study Process under NSUARB M11475, as part of the 2026-2027 GRA Direct Evidence Appendix 12A(2).
2013 Cost of Service Study NSPI Responses to Consumer Advocate Data Requests 1 Request DR-6: 2 3 Derivation of "line losses," "demand line-loss adjustment," and "requirements" in "Input 4 Data Two" 5 6 Response DR-6: 7 8 The forecast of li...
AI summary The response to DR-6 explains how line losses are forecasted and assigned to rate classes based on historical patterns from prior COSS studies. Line losses are higher during peak demand hours and are scaled hourly to match annual energy targets. 'Requirements' refers to the total generation needed to meet customer demand, including both customer demand and losses.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document outlines NSPI's responses to data requests from the Cost of Service Study (COSS) process under NSUARB M11475, focusing on providing information relevant to the regulatory proceeding.
11 (g) NS Power does not have specific data related to the percentage of small commercial 12 customers served off shared service drops, as in office buildings and shopping centers. PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appen...
AI summary NS Power does not have specific data on the percentage of small commercial customers served off shared service drops in office buildings and shopping centers. This information is part of the Cost of Service Study Process under NSUARB M11475, with NSPI responding to data requests.
NS Power 2022-2024 General Rate Application (NSUARB M10431) NSPI Responses to Consumer Advocate Information Requests 2 3 Please provide the most recent analysis of weighted meter costs, including all Excel 4 spreadsheets (with formulas int...
AI summary NSPI provided a detailed explanation of how weighted meter costs are calculated, referencing the COSS spreadsheet and updated AMI meter deployment costs. The analysis includes formulas, data, and assumptions from the exhibit provided in the rate application.
Nova Scotia Power Cost of Service Study Methodology January 2022 2022-2024 GRA SR-01 Attachment 1a Page 2 of 12 COSS CA DR-53 Attachment 1 Page 2 of 62 PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 792 of 1218 R...
AI summary The document outlines the methodology for the Cost of Service Study (COSS) used by Nova Scotia Power for the 2022-2024 GRA. It discusses the allocation of costs to Above-the-line (ATL) customer classes after subtracting Below-the-line (BTL) costs, with the aim of identifying inter-class inequities through revenue/cost (R/C) ratios.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 793 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 3 of 12 COSS CA DR-53 Attachment 1 Page 3 of 62 Nova Scotia Power Cost...
AI summary This document outlines the methodology used in the Nova Scotia Power Cost of Service Study from January 2022, as part of the 2022-2024 GRA and related appendices. It is part of a partially confidential submission in a regulatory proceeding.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 798 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 8 of 12 COSS CA DR-53 Attachment 1 Page 8 of 62 Nova Scotia Power Cost...
AI summary The text discusses the methodology used in the Nova Scotia Power Cost of Service Study, including the allocation of energy, demand, and customer factors, as well as the detailed breakdown of investments in distribution poles, overhead and underground wires, and the allocation of line transformers and services based on demand and customer classes.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 800 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 10 of 12 COSS CA DR-53 Attachment 1 Page 10 of 62 Nova Scotia Power Co...
AI summary The document outlines the methodology for the Nova Scotia Power Cost of Service Study, including the classification and allocation of expenses into demand, energy, and customer categories. It details how various costs, such as distribution, service, and communication expenses, are allocated based on factors like rate base, meter investment, and customer numbers.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 801 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 11 of 12 COSS CA DR-53 Attachment 1 Page 11 of 62 Nova Scotia Power Co...
AI summary The document outlines the methodology used in the Nova Scotia Power Cost of Service Study, detailing how various costs such as bad debt, depreciation, and interest are allocated across customer classes. The allocation is based on factors like gross write-off experience, number of customers, and total rate base. Exhibit 7 is used to verify the accuracy of the cost allocation analysis.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 802 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1a Page 12 of 12 COSS CA DR-53 Attachment 1 Page 12 of 62 Nova Scotia Power Co...
AI summary This excerpt from a Nova Scotia regulatory proceeding discusses the methodology used in the Nova Scotia Power Cost of Service Study, focusing on comparing total allocated costs with revenues for each class to determine revenue to cost relationships, as shown in Exhibit 10 under proposed rates for the test year.
Nova Scotia Power Fuel and Purchased Power Related COS Methodology January 2022 Forecast fuel costs for each test year are first apportioned to above-the-line (ATL) and below-the-line (BTL) classes using procedural step 1: 1. A portion of...
AI summary Nova Scotia Power outlines its methodology for allocating forecast fuel and purchased power costs between above-the-line (ATL) and below-the-line (BTL) classes. The company assigns a portion of fuel-related costs to specific BTL classes and unbundled tariffs, while allocating the remainder to ATL classes using modified procedural steps. Starting in 2023, the BUTU class will use the embedded cost allocation methodology for FAM customers.
2.0 RATEMAKING METHODOLOGY FOR UNMETERED - 9 The ratemaking methodology is comprised of two steps: - 1. Determination of cost responsibilities of the Cost of Service Study (COSS)-based unmetered class, which is comprised of all costs of st...
AI summary The ratemaking methodology for unmetered classes involves determining cost responsibilities based on the Cost of Service Study (COSS), which includes street and area lighting and miscellaneous loads, followed by setting revenue responsibilities and calculating individual service rates.
2.1 Cost of Service Studies (COSS) - From a broad cost treatment perspective, costs of unmetered services can be categorized as those - shared with other COSS classes and those assigned directly to the unmetered class.
AI summary The document discusses the categorization of costs for unmetered services within the context of Cost of Service Studies (COSS), distinguishing between shared costs and those directly assigned to the unmetered class.
2.2 Pricing of Unmetered Services - The Street/crosswalk Lighting Study contained below in Section 3, focuses on determining capital - and maintenance costs. Revenue responsibilities for electricity, fixture maintenance, and fixture - capi...
AI summary This section discusses the pricing of unmetered services, focusing on how costs are allocated between shared and direct categories. It outlines a three-step costing process—functionalization, classification, and allocation—to determine the cost responsibilities of the Unmetered Class based on cost causation and infrastructure utilization.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 814 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1d Page 5 of 11 COSS CA DR-53 Attachment 1 Page 24 of 62 Nova Scotia Power Unm...
AI summary The document discusses the determination of unmetered electricity rates for streetlight fixture maintenance, including the allocation of capital costs using the Cost of Service Study (COSS) methodology. The rates are structured with a demand charge and declining block energy charges, and are subject to changes in GRA proceedings.
Nova Scotia Power Unmetered Services Pricing January 2022 1 3.0 UNMETERED SERVICE STUDY 2 3 Street and crosswalk lighting and area lights represent 95 percent of NS Power's unmetered service 4 units and the total revenue collected from unm...
AI summary The document outlines the methodology and schedules used in the 2022-2024 Unmetered Service Study by Nova Scotia Power, focusing on street and crosswalk lighting inventory levels, maintenance costs, depreciation, and capital-related expenses. It references the Cost of Service Study (COSS) and includes forecasted inventory levels based on actual data from 2021.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 818 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1d Page 9 of 11 COSS CA DR-53 Attachment 1 Page 28 of 62 Nova Scotia Power Unm...
AI summary The document discusses the calculation of capital carrying costs for LED and non-LED fixtures using a tax-adjusted WACC rate, which varied between 8.12% in 2022 and 9.07% in 2024. It outlines a three-step process to determine these costs and references Schedule 5 and 5A for detailed tax-adjusted WACC calculations.
- 3 describes the calculations for the ancillary services. All transmission charges shown are updated - 4 for costs and load determinants forecasted for 2022-2024 test years. The ancillary charges are - 5 based on 2019 operational actual d...
AI summary The text outlines the methodology for calculating ancillary services, noting that transmission charges are updated and based on 2019 operational data, with forecasts for 2022-2024 test years.
Nova Scotia Power Open Access Transmission Update February 2022 1 In 2023, this includes $1,228.3 million of transmission assets plus $144.8 million of General 2 Property assets, plus $113.8 million of other assets such as deferred charges...
AI summary The document outlines the transmission assets and depreciation rates for Nova Scotia Power for the years 2022 to 2024. It details the inclusion of various asset types and adjustments made to the Cost of Service Study for the purpose of the Ontario Annual Transmission Tariff (OATT) revenue requirement.
1 2 3 TABLE E1-1 Nova Scotia Power Inc. 2022 Transmission Tariff WACC Rate Millions of dollars 1) Interest (Carrying Cost) a) Weighted Average Cost of Capital - Pretax Proportion Cost Extended ST Debt 3.80% 0.84% 0.03% LT Debt 57.40% 4.98%...
AI summary The document provides a detailed breakdown of Nova Scotia Power Inc.'s 2022 Transmission Tariff WACC Rate, including components such as interest, weighted average cost of capital, income tax, and grants in lieu of property tax. It outlines financial figures and percentages related to transmission expenses and allocated amounts.
1 Nova Scotia Power Inc. 2023 Transmission Tariff WACC Rate Millions of dollars 1) Interest (Carrying Cost) a) Weighted Average Cost of Capital - Pretax Proportion Cost Extended ST Debt 1.70% 0.90% 0.02% LT Debt 57.00% 4.97% 2.83% Common 4...
AI summary The document presents Nova Scotia Power Inc.'s 2023 Transmission Tariff WACC Rate, detailing the weighted average cost of capital, interest, tax considerations, and financial figures related to transmission costs and grants in lieu of property tax.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines Nova Scotia Power Inc.'s responses to data requests from the Cost of Service Study process, which is part of the NSUARB M11475 proceeding.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study process under NSUARB M11475. It provides insights into the procedural and analytical aspects of the study.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document outlines the Cost of Service Study Process under NSUARB M11475, focusing on NSPI's responses to data requests related to the study.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines the responses provided by NSPI to data requests made by the CA in the context of the Cost of Service Study Process under NSUARB M11475.
INTRODUCTION AND PURPOSE - My name is Bickey Rimal, and I am an Assistant Vice President with Concentric Energy Advisors, Inc. - ("Concentric"). I provided evidence related to class cost of service, pricing and rate design matters - in the...
AI summary Bickey Rimal, an Assistant Vice President with Concentric Energy Advisors, Inc., provides rebuttal testimony in response to evidence filed by intervenors and consultants in the 2022 General Rate Application submitted by Nova Scotia Power Incorporated. The testimony addresses claims regarding the Minimum System Method, the Minimum System Study, pole sub-functionalization, cost allocation methods, and the Pole Attachment Rate calculation.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 893 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 5 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - the system. The minimum syst...
AI summary The document discusses two methods for allocating costs in distribution systems: the Zero Intercept Study and the Minimum Size Selection. The Zero Intercept Study uses regression analysis to estimate customer-related costs but is criticized for potential statistical unreliability. The Minimum Size Selection method relies on current minimum installation standards for distribution assets.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 896 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 8 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS SECTION 3:
AI summary The document is a partially confidential appendix from a regulatory proceeding, focusing on the Cost of Service Study (COSS) and related evidence for the 2026-2027 GRA. It includes a section labeled 'CONCENTRIC EVIDENCE: GRA COSS ELEMENTS' and references 'SECTION 3'.
SYSTEM - Minimum System Costs are Customer-related - Dr. Pavlovic's cites Professor Bonbright's book Principles of Public Utility Rates as a basis for his - criticism of the use of the Minimum System Method to classify a portion of the dis...
AI summary The document discusses the classification of minimum system costs as customer-related versus demand-related, referencing Professor Bonbright's views. It argues that despite Dr. Pavlovic's criticism, Bonbright actually prefers classifying minimum system costs as customer-related. The text also addresses the relationship between distribution system costs and customer additions, emphasizing that some distribution costs are fixed and not directly tied to demand.
Relationship between Feeder Length and Customer Count The Resource Insight evidence, filed on behalf of the CA, conducts regression analysis using length as a dependent variable and customer count as an independent variable and concludes t...
AI summary The Resource Insight evidence, filed on behalf of the CA, uses regression analysis to examine the relationship between feeder length and customer count, concluding there is no correlation. However, it is argued that the analysis fails to consider the location of feeders (urban, sub-urban, rural), which affects the number of customers served.
Figure 2: Relationship between Feeder Length and Customers by Geography Figure 2 illustrates that geographic dispersion of the customers and where they are located and not their peak demand drives the length of the feeder. As stated previo...
AI summary Figure 2 shows that the geographic dispersion of customers influences feeder length. Professor Bonbright prefers classifying minimum-sized distribution costs as customer-related. The Ontario Energy Board (OEB) links customer density to distribution asset costs, with specific percentages for different density ranges. NS Power has low customer density, which would lead to 60% of poles, conductors, and line transformers being classified as customer-related under OEB guidelines.
Application of the minimum sized conductor to the appropriate length - The assertion in the Resource Insight evidence that "Concentric applied the cost of a multiple- - conductor line such as triplex to the sum of the lengths of all the co...
AI summary The text refutes the claim that Concentric overstated the minimum conductor cost by applying the cost of a multi-conductor line to the total length of all conductors. It states that Concentric correctly applied the minimum-sized conductor to the appropriate circuit length, and the calculations are accurate based on the total span length.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 900 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 12 of 19
AI summary This document is a partially confidential appendix from a 2026-2027 GRA Direct Evidence submission, specifically COSS CA DR-61 Attachment 1, page 12 of 19. It includes a redacted image and appears to be part of a regulatory proceeding involving cost-of-service studies and related documentation.
Review of Cost Allocation Methods - Resource Insight requests a review of NS Power's cost allocation methods through a new - collaborative process. Resource Insight reasons that a review of cost allocation methods is needed - due to existi...
AI summary The document discusses the rejection of Resource Insight's proposal to review NS Power's cost allocation methods, citing that these issues are not new or immediate. It references past proceedings and argues that transitions in energy resources are likely to occur gradually, not overnight, and that vague claims about updating allocation methods lack concrete guidance.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 904 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS CA DR-61 Attachment 1 Page 16 of 19 CONCENTRIC EVIDENCE: GRA COSS ELEMENTS - Fourth, Resource Insight do...
AI summary The text criticizes Resource Insight's recommendation for updating cost allocation methodologies, arguing that it lacks logical support and could lead to instability in cost allocation and rate design. The text emphasizes the importance of relying on precedents and the potential negative impact of abandoning them, including rate shocks for customers.
8 Figure 1 9 10 11 (b) Figure 2 provides a list of the selected feeder sections including general characterization 12 of the feeder (e.g., rural/suburban/urban, residential/mixed/commercial/industrial) PARTIALLY CONFIDENTIAL 2026-2027 GRA...
AI summary Figure 1 and Figure 2 are referenced in the document, with Figure 2 providing a list of selected feeder sections characterized by location and usage type. The document also mentions the Cost of Service Study Process (NSUARB M11475) and NSPI responses to CA data requests.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines the Cost of Service Study Process under NSUARB M11475 and includes NSPI's responses to data requests from the Commission. It focuses on the methodology and data analysis involved in the study.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document pertains to the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests from the Canadian Association (CA).
2 (i) NS Power did not collect this information as part of this survey. 3 (ii) Please refer to Figure 2 above for the data related to the Phases in each Feeder 4 Section. 5 (iii) The underground conductor is in conduit. 6 (iv) NS Power did...
AI summary The text discusses the lack of data collection by NS Power in certain areas, and references a Cost of Service Study Process under NSUARB M11475, including responses to data requests by CA.
3 (viii) The height and class of each pole with only secondary conductor is represented in 4 Figure 4 below. PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 914 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED)...
AI summary The text references a Cost of Service Study Process under NSUARB M11475 and mentions NSPI's responses to data requests from the Canadian Association. It also refers to a partially confidential appendix containing information about pole heights and classes.
2 1 3 PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 915 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document is part of a partially confidential appendix from a regulatory proceeding related to the Cost of Service Study Process (NSUARB M11475), containing responses from NSPI to data requests by the Canadian Association.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines Nova Scotia Power Inc.'s responses to data requests from the Canadian Association regarding the Cost of Service Study process under NSUARB M11475.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document pertains to the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests from the Canadian Association.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary The document outlines the Cost of Service Study Process under NSUARB M11475 and includes NSPI's responses to data requests from the Canadian Association. It focuses on the procedural aspects of the study and the information provided by NSPI.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 933 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines NSPI's responses to data requests from the Canadian Association under the Cost of Service Study Process, as part of the NSUARB M11475 proceeding.
NON-CONFIDENTIAL 1 Request DR-73: 2 3 Please provide information on whether it is possible to estimate the difference in the cost 4 per customer by class for service lines, final line transformers, and meters. 5 6 Response DR-73: 7 8 It is...
AI summary The response to DR-73 explains that NS Power lacks detailed data to estimate cost differences per customer by rate class for service lines and final line transformers. However, it is possible to estimate meter costs per customer by class, as this information is provided in Exhibit 3(i) of the COSS.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 946 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines NSPI's responses to data requests from the Canadian Association as part of the Cost of Service Study Process under NSUARB M11475. It is part of the 2026-2027 GRA Direct Evidence Appendix.
NON-CONFIDENTIAL 1 • Section 7.13.3 of the NSUARB Decision on NS Power's 2022-2024 GRA (M10431) which 2 approves the proposed changes to the interruptible credit. 3 - 4 Under the current 2023 COS, the interruptible credit costs of $11.796...
AI summary The text discusses the approval of changes to the interruptible credit under the 2022-2024 GRA (M10431) by the NSUARB, referencing the 2023 COS and the methodology used in the COSS. It also refers to how demand charges are determined and how they are set to match approved revenues.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 947 of 1218 Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines the Cost of Service Study Process under NSUARB M11475, detailing NSPI's responses to data requests from the Canadian Association. It is part of the 2026-2027 GRA Direct Evidence Appendix 12A(2).
1 2 3 Date Filed: October 25, 2024 NSPI (CA) DR-77 Page 3 of 3 Not all groups of interruptible customers are necessarily interrupted during each interruption event. COSS CA DR-77 Attachment 1 Page 1 of 3 PARTIALLY CONFIDENTIAL 2026-2027 GR...
AI summary The document references a Cost of Service Study (COSS) and a General Rate Application (GRA) related to a Direct Evidence Appendix in a regulatory proceeding. It notes that not all interruptible customers are interrupted during each event, and includes a partially confidential attachment.
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.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to CA Data Requests
AI summary This document outlines the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests from the Commission (CA).
NON-CONFIDENTIAL 1 • effectiveness of DSM Programs designed for individual ate classes in reducing their 2 electricity usage. 3 4 Option Two: 5 6 The system cost benefit for each individual class was defined as the cost savings a class wou...
AI summary The text discusses the effectiveness of DSM programs for different electricity rate classes, analyzing the system cost benefits and changes in cost distribution when one class does not participate. The split of cost savings shifted from 75/25 to 93.2/7.2, with changes in non-fuel embedded costs impacting participating and non-participating classes differently.
Criteria - Cost Causation defined by proximity of arithmetic average of multipoint peaks under various CP methods to annual system peak (or 1CP) - Cost Redistribution Effect among rate classes measured as % change in annual revenues - Stab...
AI summary The text outlines criteria for evaluating cost causation and redistribution effects in rate-making processes, referencing proximity of arithmetic averages to annual system peaks, stability of cost allocation results, and precedents from other Canadian jurisdictions. It also references a partially confidential attachment from a proceeding.
Findings - The winter peak methods provide for more stable cost allocation results from year to year but rank worse under cost causation criterion than corresponding unconstrained methods. - oIt takes as many as 88CP to match stability off...
AI summary The winter peak methods provide more stable cost allocation results but perform worse under cost causation criteria. The average cost redistribution effects on the Domestic class are minor, while effects on other classes are more significant. Analysis using ANL yields more volatile results.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests 1 Request DR-1: 2 3 Please provide 3-5 years of historical hourly load data for total system and by customer class 4 (that aligns with CP allocator input data...
AI summary NSPI provides responses to data requests regarding historical hourly load data for different customer classes. The data is available for large customer classes but estimated for others using load research samples. The response also outlines the methodology used in the Cost of Service Study (COSS) process.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1022 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests
AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study process under NSUARB M11475. It provides information relevant to the regulatory review of NSPI's cost structures and service delivery.
NON-CONFIDENTIAL - 1 Capital costs match 2022 Evergreen assumptions. 2 • All dollar amounts in the table are in 2021 dollars. 2022 Evergreen IRP assumptions were - 3 adjusted from 2022 dollars to 2021 dollars using an inflation rate of 4.0...
AI summary The document discusses capital costs aligned with the 2022 Evergreen IRP assumptions, adjusted for inflation, and highlights differences between the current interruptible credit and levelized cost calculations based on updated capital costs from the 2022 Evergreen IRP.
COSS IG DR-10 Attachment 1 Page 1 of 6 Determination of Unit Avoided Marginal Annual Cost of Load Served ($/kW, in 1994 Annual Cost of Load Served ($/kW, in 1994 Annual Avoided Cost rounded to nearest dollar in 1996 % Change from 1996 Benc...
AI summary The document presents calculations related to interruptible credit and annual cost of load served for different years, including comparisons between 1996 and test years 2022-2024. It includes figures on avoided costs, revenue credits, and demand coincident with system peaks. These calculations are used to evaluate financial impacts and system reliability.
Input Assumptions - 1. Capital costs are for a 50MW combustion Turbine (Frame) from E3 Resource Option Study using 2021 nominal values; - 2. Fixed Operating costs are derived from E3 Resource Option Study using 2021 nominal values - 3. Scr...
AI summary The input assumptions outline capital and operating costs for a 50MW combustion turbine based on 2021 values from the E3 Resource Option Study. Assumptions include the incorporation of AFUDC into system costs, no administrative overhead, and annual escalation of FO&M costs at 2%.
Peaker Deferral Method Summary Outputs Updated 7/12/2021 Year Equivalent Escalating Series ($/kW-Yr) Levelized ($/kW-Yr) 2021 $ 101.44 $ 130.98 2022 $ 103.47 $ 130.98 2023 $ 105.54 $ 130.98 2024 $ 107.65 $ 130.98 2025 $ 109.81 $ 130.98 202...
AI summary The document presents a table showing the Equivalent Escalating Series and Levelized costs per kW-year from 2021 to 2045, with the Levelized cost remaining constant at $130.98 throughout the period. The Equivalent Escalating Series cost increases annually.
Resource Cost, Performance, & Financing Performance Inputs Financing Performance Inputs Financing System Depreciable Lifetime 35 % Financed w/ equity % Financed w/ debt Ongoing Costs Debt Interest rate Fixed O&M Costs ($/kW-yr) $17.69 Cost...
AI summary The document presents a table outlining performance inputs and financing details for a system, including system cost, depreciation lifetime, financing percentages, interest rates, tax assumptions, and levelized costs. It includes data on capital costs, O&M expenses, and PRM adjustments.
r>$1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 $1,597,251 CCA Schedule 3.06% 2.81% 2.59% 2.38% 2.19% 2.02% 1.85% 1.71% 1.57% 1.44%...
AI summary The text contains a series of financial figures and percentages, likely related to depreciation, tax savings, revenue, expenses, and operating profit over multiple years. The data appears to be part of a financial schedule or report, possibly from a regulatory proceeding.
CONFIDENTIAL (Attachments Only) 1 Response DR-18: 2 3 4 (a) Written Responses: 5 (i) For the effect of MEU proposal to align OATT methodology with COS, please refer 6 to Attachment 1. The effect on individual rate class costs is around 0.0...
AI summary The response discusses the effect of aligning OATT methodology with COS, noting a negligible impact of 0.01 percent on individual rate class costs. It also references model requests and spreadsheet files related to NSP's unbundled service proposal and PHP ATL/BTL analyses, while indicating that certain analyses have not yet been conducted due to resource constraints.
CONFIDENTIAL (Attachments Only) 1 (iv) Please refer to the following spreadsheet uploaded to the FTP site on October 31, 2 2024: 3 • 00-GRA 2023 COSS 2. Inter Gen (Lingan TC) CONF 4 • 00-GRA 2023 BCF 2. Inter Gen (Lingan TC) CONF PARTIALLY...
AI summary This document references a Cost of Service Study Process (NSUARB M11475) and NSPI's responses to data requests from an Independent Generator (IG). It also mentions spreadsheet files uploaded to an FTP site on October 31, 2024, related to a GRA (Generation Resource Assessment) for 2023 and a BCF (Balancing Contract Framework).
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1053 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to MEU Data Requests
AI summary This section of the document outlines the Cost of Service Study Process under NSUARB M11475 and includes NSPI's responses to data requests from the Market Efficiency Unit (MEU). The content is part of the 2026-2027 GRA Direct Evidence Appendix.
NON-CONFIDENTIAL 1 Fixed-generation BUTU and RtR rates are calculated by the same COSS-based embedded 2 cost methodology, however, there is a phase-in adjustment applied to the BUTU rates in 3 2023 to limit the forecast revenue increase to...
AI summary The text explains the methodology for calculating BUTU and RtR rates using a COSS-based embedded cost approach, with a phase-in adjustment in 2023 to limit revenue increases. It also outlines how demand and energy charges are calculated, and summarizes the basis for FAM and non-FAM costs in different rate categories.
BUTU RtR Municipal FAM-related – "Energy-related Purchased Power and Fuel Cost" "Fuel Cost" "Energy Charge" Energy Allocated MWh Marginal/Avoided Cost Allocated MWh "Energy-related Fixed Generation Cost" "Fixed Cost Adder" "Energy Charge"...
AI summary The table compares different cost allocation methods across BUTU, RtR, and Municipal categories, including energy-related and demand-related costs. It outlines various cost components such as 'Energy-related Fixed Generation Cost,' 'Demand-related Purchased Power,' and 'Average NS Power Unit Cost.' The document is part of a confidential appendix in a regulatory proceeding.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests 1 Request DR-1: 2 3 With reference to NS Power's initial position document Issue # 1a please indicate which 4 specific generation assets NS Power believes wi...
AI summary NSPI responds to a data request regarding the classification of generation assets in the Cost of Service Study. It states that only steam units operating below future system load factors and not retiring before 2030 (Tufts Cove 1, 2, and 3) will be classified based on annual capacity factors. Other units, like LM6000 and combined cycle units, will retain their current classification.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1059 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document relates to the Cost of Service Study Process (NSUARB M11475) and includes NSPI's responses to PHP Data Requests. It is part of a partially confidential appendix in a regulatory proceeding.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1060 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines the Cost of Service Study Process under NSUARB M11475, with NSPI providing responses to data requests related to Peak Hour Pricing (PHP). The content highlights the procedural and analytical aspects of the study.
NON-CONFIDENTIAL exceed the number of operating hours typically expected from a peaking unit4 1 there remains 2 energy-related cost causation behind investment in these units. However, a significant 3 reduction in operating hours of such u...
AI summary NS Power argues that adjusting the classification method of peaking units from system load factor to individual unit capacity factor better reflects energy-related cost causation. The ELCC approach, which classifies more costs to demand as operating hours increase, is criticized for potentially misrepresenting cost causation for base load units.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1061 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines the Cost of Service Study Process as part of the NSUARB M11475 proceeding, with NSPI providing responses to data requests related to Peak Hour Pricing (PHP).
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1062 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 and includes NSPI's responses to PHP Data Requests, indicating a regulatory proceeding focused on cost analysis and data provision.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document pertains to the Cost of Service Study Process under NSUARB M11475, focusing on NSPI's responses to data requests related to Peak Hour Pricing (PHP).
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1068 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document discusses the Cost of Service Study Process under NSUARB M11475 and outlines NSPI's responses to PHP Data Requests, which are part of the 2026-2027 GRA Direct Evidence Appendix 12A(2).
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1069 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines NSPI's responses to PHP data requests in the context of the Cost of Service Study Process under NSUARB M11475. It provides information relevant to the regulatory analysis of Nova Scotia Power Inc.'s operations and financial considerations.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines NSPI's responses to data requests related to the Cost of Service Study Process under NSUARB M11475, focusing on PHP (Peak Hour Pricing) data.
REDACTED COSS PHP DR-13 Attachment 1 Page 1 of 2 Date Hour NSR without PHP NSR with PHP Residential Residential TOU Small General General Large General Small Industrial Medium Industrial Large Industrial Interruptible Large Industrial Firm...
AI summary This table provides data from a cost of service study (COSS) related to the Public Health Program (PHP) in Nova Scotia. It includes various metrics such as NSR (Net Service Revenue) values, residential time-of-use (TOU) rates, and other industrial and general rate categories across different dates and hours.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines NSPI's responses to data requests from the Public Health Program (PHP) related to the Cost of Service Study Process under NSUARB M11475.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1089 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary This document outlines NSPI's responses to data requests from the PHP as part of the Cost of Service Study Process under NSUARB M11475. It is part of the 2026-2027 GRA Direct Evidence Appendix.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1094 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document refers to the Cost of Service Study Process under NSUARB M11475 and outlines NSPI's responses to data requests from the Public Health Program. It is part of the 2026-2027 GRA Direct Evidence Appendix.
NON-CONFIDENTIAL 1 Request DR-19: 2 3 Please provide a detailed description of the current functionalization, allocation, and 4 classification of the Maritime Link in the current COSS. 5 6 Response DR-19: 7 8 The Maritime Link (ML) imports...
AI summary The response to DR-19 explains that the Maritime Link imports are divided into firm, capacity-backed energy, and non-firm Surplus Energy. Import costs are functionalized to Generation and classified based on system load factors and energy demand. Allocation methods are detailed, with demand costs distributed according to coincident contribution to system peaks and energy costs based on annual or monthly energy requirements.
15 4. COST OF SERVICE CLASSIFICATION OF THE MARITIME LINK 16 The CA proposes, supported by MEUNSC, the following: - 17 (a) For the purposes of setting the Base Cost of Fuel for each year of the Rate 18 Stability Period, the Maritime Link c...
AI summary The CA proposes classifying Maritime Link costs as NS Power-owned hydro generation for the Base Cost of Fuel during the Rate Stability Period. The Parties agree to a consultative process to address cost allocation and will file a report with the Board by March 31, 2017. Disagreements will be resolved by the Board, and any changes to classification will not be retroactive and will not be implemented before January 1, 2020.
Cost of Service Classification of the Maritime Link Strawman Report 1 The purpose of this Report is to summarize the various options available with respect to the Cost 2 of Service allocation of the Maritime Link for the purposes of facili...
AI summary This report outlines the cost of service classification options for the Maritime Link, aiming to facilitate consensus among stakeholders. The report emphasizes that cost of service studies do not affect revenue recovery but focus on fair revenue apportionment among customer classes. NS Power seeks input by January 27, 2017, and plans to discuss the matter in a February 2017 meeting.
Cost of Service Classification of the Maritime Link Strawman Report 1 The Company also proposed that the Nova Scotia Block be treated in the same manner as NS 2 Power-owned hydro generation. This means that its costs would be classified to...
AI summary The document discusses the proposed cost of service classification for the Nova Scotia Block, suggesting it be treated similarly to NS Power-owned hydro generation. Energy and demand costs would be allocated based on system load factors and coincident system peaks, aligning with NS Power's COSS practices.
Cost of Service Classification of the Maritime Link Strawman Report 1 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.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document outlines NSPI's responses to data requests from the Public Health Program (PHP) related to the Cost of Service Study Process (NSUARB M11475).
Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests
AI summary The document outlines NSPI's responses to data requests from the Public Health Program (PHP) related to the Cost of Service Study (COSS) process under NSUARB M11475.
REDACTED 1 Request DR-30: 2 3 Provide a model run that incorporates all of NSPI's lastest changes to its proposed COSS 4 positions that would apply post 2030 (ie. incorporating all currently planned plant fuel 5 conversions and all plant r...
AI summary A request (DR-30) is made for a model run that incorporates NSPI's latest changes to its proposed Cost of Service Study (COSS), including post-2030 plant fuel conversions, retirements, and the treatment of PHP load as an above-the-line customer. The response refers to confidential attachments that have been removed due to confidentiality.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to SBA Data Requests 1 (M10431) and shared carrying cost and taxes are functionalized and allocated to customer 2 classes using the COSS model provided as SR-01 Att 03 PCON UPDAT...
AI summary The document discusses the Cost of Service Study (COSS) process as part of the NSUARB M11475 proceeding, with NSPI providing responses to data requests from the SBA. The COSS model is referenced in the context of allocating shared carrying costs and taxes to customer classes.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to SBA Data Requests
AI summary This document outlines Nova Scotia Power Inc.'s responses to data requests from the SBA related to the Cost of Service Study Process under NSUARB M11475. It provides insights into the regulatory proceedings and data submission requirements.
Cost of Service Study Process (NSUARB M11475) NSPI Responses to SBA Data Requests
AI summary The document outlines NSPI's responses to data requests from the Stakeholder Board of Appeal (SBA) regarding the Cost of Service Study Process (NSUARB M11475). It focuses on the procedures and data provided in response to the SBA's inquiries.
NON-CONFIDENTIAL 1 Request DR-4: 2 3 How are the costs of primary vs secondary distribution classified, to demand or energy? 4 5 Response DR-4: 6 7 Please refer to page 3 of Exh 5 of 2023 COSS1 for the distribution cost classification resu...
AI summary The response to DR-4 explains that NS Power classifies distribution costs exclusively to demand, customer, or both, but not by primary vs. secondary voltage levels. Classification factors are based on investment in poles and wires, and specific percentages are provided for OM&G costs.
NON-CONFIDENTIAL - 1 Lines, are classified to demand and customer as determined in Exh 3c, Exh 3e, and Exh 3g. Please - 2 refer to section "3. Distribution system sub-functionalization and classification" of the evidence - 3 filed by Conce...
AI summary The document discusses the classification of various infrastructure investments into demand and customer categories, based on evidence provided in the 2023-2024 GRA. Specific classifications include poles and wires, substations, and streetlights, with references to attachments and exhibits for detailed breakdowns.
MEMORANDUM TO: Nova Scotia Power, Inc. FROM: Bickey Rimal, Concentric Energy Advisors DATE: January 2022 RE: GRA Allocated Cost of Service and Miscellaneous Charges Matters The purpose of this memorandum is to provide the results of: - Con...
AI summary This memorandum from Concentric Energy Advisors to Nova Scotia Power Inc. reviews the company's allocated class cost of service (CCOS) model, concluding that it is reasonable, follows industry-accepted methodology, and produces accurate results. The model uses a three-step process: cost functionalization, classification, and allocation, which are described in detail.
2. Review of certain deferred matters from 2013 COSS Proceeding When NS Power updated its COSS as a part of the compliance filing after the NSUARB issued its decision on the 2013 COSS Proceeding, several items were slated for further revie...
AI summary The document reviews deferred matters from the 2013 COSS Proceeding, including the classification of Lingan Units 1 and 2 as base load units and the treatment of miscellaneous revenues. NS Power continues to treat the units as base load due to their operational limitations and provides a report on the allocation of miscellaneous revenues, which is deemed reasonable.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1149 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-4 Attachment 1 Page 4 of 7 Concentric first calculated the replacement costs of all poles at eac...
AI summary Concentric calculated the replacement costs of poles and conductors in feeder sections by voltage level, allocating costs between primary and secondary based on cost ratios. This approach was applied to both overhead and underground conductors using data provided by the Company.
PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 1151 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) COSS SBA DR-4 Attachment 1 Page 6 of 7 The underlying data used to calculate the fee are cost based and the...
AI summary The document outlines the methodology for calculating pole attachment fees by NS Power, based on cost considerations. The fee is determined by allocating indirect and direct costs associated with poles between NS Power and third-party attachers. The allocation is based on the proportion of usable space occupied by non-power attachments, with a final adjustment for the average number of non-power attachments per pole. The fee is deemed reasonable and minimizes cross subsidization.
COSS SBA DR-6 Attachment 1 Page 16 of 24 536700 RELOCATION EXPENSE 560050 GRANTS IN LIEU OF TAXES 562050 DEPRECIATION EXPENSE 562100 ACCRETION EXPENSE 563050 AMORTIZATION OF DEFERRED TAXES 563100 REGULATORY AMORTIZATION UNUSUAL ITEMS DEFER...
AI summary The document presents a list of expense and income categories, including depreciation, interest, taxes, and grants, as well as a line of business segment description. It appears to be a financial statement or related regulatory filing, with some sections redacted due to confidentiality.
COST CENTRE SEGMENT Cost Centre Segment Value Cost Centre Segment Description 000 DEFAULT 001 MAINTENANCE 002 OPERATIONS 003 ADMINISTRATION 004 ENVIRONMENT 005 SAFETY 006 PROCUREMENT 007 CUSTOMER CARE CENTRE 008 HUMAN RESOURCES 009 BILLING...
AI summary The document presents a table listing cost centre segments and their descriptions, including categories such as maintenance, operations, administration, and others. This information is part of a partially confidential appendix in a regulatory proceeding.
Agenda - Introduction of Elenchus as an expert subject to the duties of an expert - Preliminary Discussion - Board Directive GRA - Meeting Objectives - Consultant Overview of Electric Utility Cost of Service Processes
AI summary The agenda includes the introduction of Elenchus as an expert, a preliminary discussion involving a Board Directive and meeting objectives, and an overview of electric utility cost of service processes by a consultant.
Board Directive - GRA The 2022-2024 GRA Settlement Agreement provided as follows regarding the Line Loss Study and COSS: NS Power must file a Cost of Service Study and a Line Loss Study prior to filing its next GRA or December 31, 2025, wh...
AI summary The 2022-2024 GRA Settlement Agreement requires NS Power to file a Cost of Service Study and Line Loss Study, with stakeholder engagement, prior to the next GRA or December 31, 2025. The NSUARB directed semi-annual progress reports starting January 31, 2024. Costs may be deferred and recovered through future rates with Board approval.
The GRA Decision provided as follows: [361] In this proceeding, several concerns were raised about NS Power's cost of service methodologies applied in this GRA. These concerns included the use of the minimum system study for the classifica...
AI summary The GRA Decision addresses concerns about NS Power's cost of service methodologies, including the use of the minimum system study and LF/3CP method for cost classification. The Board agrees to update the COSS and Line Loss Study to reflect recent system developments and directs semi-annual progress reports starting in 2024.
Meeting Objectives - Introduce experts - Develop a shared understanding of industry practices re: cost of service - Share information - Collaborate with intent to develop initial issues list and identify topics requiring further examinatio...
AI summary The meeting objectives focus on introducing experts, discussing industry practices related to cost of service, sharing information, and collaborating to develop an initial issues list. The meeting will take place on a without prejudice basis and will not be recorded without consent.
Agenda - 1. Introduction and Project Description - 2. Generic Background on Cost Allocation Methodologies - 3. NS Power's Existing COSS Methodology - 4. Effect of Transitional and Technological Changes on COSS - 5. Survey - 6. Next Steps
AI summary The agenda outlines the topics to be discussed in a regulatory proceeding, including an introduction, background on cost allocation methodologies, NS Power's existing cost of service study (COSS) methodology, the impact of transitional and technological changes on COSS, a survey, and next steps.
Elenchus Research Associates Inc. ("Elenchus") - John Todd, President - Founded 1980 - Andrew Blair joined Elenchus in 2016 - Transferred to Power Advisory in 2023 - Elenchus has conducted Cost of Service/Cost Allocation and Rate Design (C...
AI summary Elenchus Research Associates Inc., founded in 1980, has conducted various regulatory and utility-related reviews. Key personnel include John Todd, President, and Andrew Blair, who joined in 2016 and transferred to Power Advisory in 2023. Elenchus has worked with multiple regulators and utilities, including NB Power and ENMAX, and has assisted with rate impact and bill analysis for E1, integrating with NSP's COS model. A strategic alliance was formed with Power Advisory in 2021.
Elenchus Approach to the Review - Facilitate NS Power's Stakeholder Process ‐ technical sessions, with goal being to: - Assist in clarifying and understanding the concerns and views of all parties - Distinguish between interest‐based and p...
AI summary The Elenchus Approach to the Review outlines a structured process to facilitate NS Power's stakeholder engagement, clarify stakeholder concerns, and review NS Power's cost allocation methodologies. It also includes a survey of utility practices in Canada and the US, and the preparation of evidence for filing with the Nova Scotia Utility and Review Board.
Purpose of the January 18th Session (Kick-off) - Canvass stakeholders to determine the parts of NS Power's COSS methodology that need to be explained in greater detail in future tech sessions. Future technical sessions will assist stakehol...
AI summary The January 18th session aims to engage stakeholders in reviewing NS Power's Cost of Service Study (COSS) methodology, identify areas requiring updates due to developments since 2013, and determine the implications of proposed changes on allocated costs. The session will also establish a timeline for future discussions.
Reference Documents - As baseline, NARUC, Electric Utility Cost Allocation Manual, January 1992. What has changed in the last 30 years? Comments invited. - Cost Allocation Modernization references, such as: - Electric Cost Allocation for a...
AI summary The document references historical and modern cost allocation practices, including the NARUC Electric Utility Cost Allocation Manual and recent stakeholder suggestions. It also cites previous Nova Scotia Power evidence, NSUARB decisions, and discussions from past COSS projects, including the Maritime Link Project and deferred projects from 2014–2016.
Cost Allocation Methodologies – Conceptual Overview - Directly allocated costs Exclusive use by class (rare) - Shared Utility Assets and Expenses - > We all benefit from sharing - > Electrons flow through common infrastructure - Cost Causa...
AI summary This section provides an overview of cost allocation methodologies, emphasizing the use of cost causality as the main criterion for allocating shared utility assets and expenses. The goal is to achieve fair and reasonable rates, with rate design being a subsequent step that may incorporate policy considerations.
Classification - > Demand-related costs - > Facilities determine CAPACITY of energy flows - Higher capacity requires larger "pipe" - > Energy-related costs - More energy consumed means more fuel to produce - > Customer-related costs - ➤ Mo...
AI summary The text discusses different types of costs related to energy systems, including demand, energy, and customer-related costs. It highlights that higher capacity requires larger infrastructure, more energy consumption increases fuel needs, and more customers require additional meters and service. There is also a question raised about the definitions of capacity/demand (MW) versus energy (kWh).
Allocation - Costs allocated to customer classes (cost drivers correspond to cost classifications) - Primary Allocators (costs shared by proportionate use) - ➤ kWh (energy including losses) - > kW (demand including losses) - > # of custome...
AI summary The document discusses the allocation of costs to customer classes based on various cost drivers, including kWh, kW, number of customers, and direct assignments such as streetlights. It outlines methods for allocating shared costs proportionally and compares total allocated costs to class revenue to assess revenue/cost ratios.
Functionalization - > Approach very standardized in the electricity industry - > NS Power's functions are consistent with industry standard definitions - ➤ Main functions include generation, transmission, distribution and retail - > Costs...
AI summary The document discusses the functionalization approach used by NS Power in the electricity industry, aligning with standard definitions. It outlines main functions such as generation, transmission, distribution, and retail, and explains that costs are assigned to these functions based on the utility's system of accounts. Some allocation between functions is required, such as between transmission and distribution substation costs.
Generation Classification Methodologies - Variable costs (per MWh) are energy related - > Such as fuel costs - > How to classify capital and other fixed costs? - ➤ NARUC Manual (January 1992) identifies many acceptable options to use for t...
AI summary The text discusses methods for classifying variable and fixed costs in generation, referencing the NARUC Manual and exploring implications of modernization on cost allocation and rate design, particularly in relation to the 4D's (Decentralization, Decarbonization, Democratization, Digitization).
NS Power's Generation Method - ➤ NS Power uses the System Coincident Load Factor to determine energy-related and capacity-related generation costs, though there are differences among types of generation - > Energy-related generation costs:...
AI summary NS Power determines energy and capacity-related generation costs using the System Coincident Load Factor. Energy-related costs are allocated based on energy (MWh), while demand-related costs are allocated using three winter month peaks and annual class peaks for distribution costs.
Transmission Classification / Allocation Methodologies - ➤ Transmission is treated as an extension of generation and is classified to energy and demand based on the system load factor - ➤ Illustrative example: - > Allocation same as genera...
AI summary The document discusses transmission classification and allocation methodologies, treating transmission as an extension of generation and classifying it based on system load factor. It also raises questions about the implications of modernization and the 4D's impact on cost allocation and regulatory decisions.
Distribution Classification / Allocation Methodologies - > NS Power is consistent with standard practices - > Typical approach across utilities: - ➤ Use Minimum System Method for classification of lines and transformers - ➤ Multiple-CP for...
AI summary The text discusses NS Power's use of standard classification and allocation methodologies in distribution, including the Minimum System Method, Multiple-CP, and NCP allocation. It raises a question about the implications of modernization, specifically whether the 4D's impact on CA or RD is causal or driven by policy.
Above-the-Line / Below-the-Line - In NS Power's methodology, costs are allocated Above‐the‐Line after determining the cost responsibility of Below‐the‐Line customers - This review will focus on Above‐the‐Line rate classes
AI summary The document discusses NS Power's methodology for allocating costs Above-the-Line after determining the cost responsibility of Below-the-Line customers. The review will focus on Above-the-Line rate classes.
Agenda - 1. Introduction and Project Description - 2. Generic Background on Cost Allocation Methodologies - 3. NS Power's Existing COSS Methodology - 4. Effect of Transitional and Technological Changes on COSS - 5. Survey - 6. Next Steps
AI summary The agenda outlines the topics to be discussed in a proceeding, including the introduction of a project, background on cost allocation methodologies, NS Power's existing cost of service study methodology, effects of transitional and technological changes on the methodology, a survey, and next steps.
Baseload Generation Classification to Demand Table 6: Classification of Base Load Steam generation costs to demand Percent Classified as demand Number of Utilities Percent of Utilities 90 - 100 3 27 70 - 90 0 0 50 - 70 0 0 35 - 50 3 27 Bel...
AI summary The table classifies the percentage of base load steam generation costs attributed to demand by Nova Scotia utilities. It shows that 27% of utilities classified between 90-100% and 35-50% of costs as demand, while 35% of utilities reported 'NA' for this classification.
Transmission Classification to Demand Table 7: Classification of transmission costs to demand Percent Classified as demand Number of Utilities Percent of Utilities 90 - 100 7 63 70 - 90 0 0 50 - 70 0 0 35 - 50 2 18 NA 2 18 Totals 11 \ Nova...
AI summary The document presents a table classifying the percentage of transmission costs attributed to demand by various utilities. Nova Scotia Power is noted as being in the 35-50% range, while other utilities are categorized into different ranges, with 63% of utilities falling into the 90-100% range.
Recap the identified issues: - Review the aspects of the COSS methodology that need to be explained in future sessions - Review the issues to focus on in future sessions - What other matters need to be addressed in future sessions? - Pleas...
AI summary The document outlines the need to review aspects of the COSS methodology and identify issues to focus on in future sessions. It also asks for other matters to be addressed and requests closing comments on the process and potential improvements for future sessions.
Cost Allocation The amount of total costs to be allocated to individual rate classes.
AI summary The document discusses the allocation of total costs to individual rate classes, focusing on how costs are distributed among different customer categories for the purpose of rate setting.
NS Power's COS Spreadsheet Calculation Process - Data Input Collection: Input Data, Input Data Two - Class Usage: Exh 9a 9c - o Usage based allocator factors in Exh 8a - Rate Base apportionment to rate classes - o Functionalization: Exh 2...
AI summary This document outlines NS Power's Cost of Service (COS) spreadsheet calculation process, including data input collection, class usage, rate base apportionment, cost apportionment, and cost summaries. Exhibits and external sources are referenced for methodology and analysis.
Changes to COS Methodology since 1995
AI summary This section discusses changes to the Cost of Service (COS) methodology since 1995, focusing on evolving regulatory approaches and practices in Nova Scotia's energy sector.
1995 COS Generic Hearing (NSPI864) - Classification of generation and transmission should reflect the intent of the asset: - o All generation costs associated with environmental compliance and fuel conversion to be classified as energy-rel...
AI summary The document discusses the classification of generation and transmission costs, emphasizing the need to align them with the intent of the assets. It suggests that environmental compliance and fuel conversion costs should be energy-related, while fixed costs of Steam and Hydro generation and transmission should be based on annual system load factor. The Equivalent Peaker method was rejected due to inconsistent calculations, and transmission is treated as an extension of generation. Fuel costs are to be allocated on a monthly basis to reflect seasonality.
2013 COS Generic Hearing (M05473) - Upheld status quo regarding the most significant elements of the 1995 COS design - SLF-based classification and 3CP Allocation of non-fuel costs of base load generation and transmission was favored over...
AI summary The 2013 COS Generic Hearing (M05473) upheld the 1995 COS design's core elements, including SLF-based classification and 3CP allocation, but noted pending decisions on distribution costs. Adjustments were made to better align with cost causation and asset utilization, including sub-functionalizing purchased power costs and using a formulaic approach for billing and call center costs.
COS Treatment of Maritime Link - 2017-2019 Fuel Stability Plan (M07348) UARB approves Settlement Agreement wherein parties agree to conduct consultations to address COS treatment of ML costs. - Following stakeholder consultations NS Power...
AI summary The document outlines the treatment of Maritime Link (ML) costs within the Cost of Service (COS) framework. A 2017-2019 Fuel Stability Plan (M07348) led to consultations, resulting in a strawman report recommending that Nova Scotia Block costs be classified as NS Power-owned hydro based on the SLF. Surplus energy, representing non-firm imports, was fully classified to energy, and all approved FAM rates reflect this treatment.
Overview - DSM Cost Recovery Process - 2023-2025 DSM Resource Plan - Regulatory Background behind Cost Allocation Methodology - DSM Cost Allocation Methodology
AI summary The text outlines an overview of topics including the DSM Cost Recovery Process, the 2023-2025 DSM Resource Plan, and the regulatory background and methodology for DSM cost allocation.
Regulatory background behind current DSM Cost Allocation Approach - The current cost allocation methodology was approved by the Board in its 2010 DSM Plan and 2010 DSM Rider Decision (NSUARB-NSPI-P-884(2). Board's findings were as follows....
AI summary The current DSM cost allocation methodology was approved by the Board in its 2010 DSM Plan and 2010 DSM Rider Decision. It recognizes three types of cost benefits from DSM: System, Class, and Participation. The recovery of DSM costs is based on the level of benefit received by customer classes, with 75% of costs directly assigned to rate classes and 25% apportioned via the COSS methodology.
Cost Allocation The amount of total DSM costs E1 budgets and tracks its costs by Rate classes. However, 25% of these costs are reapportioned by NS Power.
AI summary E1 budgets and tracks DSM costs by rate classes, but 25% of these costs are reapportioned by NS Power.
Allocation of DSM Program Costs - All DSM Costs are budgeted and tracked by Rate Classes (See Slide 10) - System benefits are allocated to all applicable customer classes in accordance with the COS methodology reflecting allocation of gene...
AI summary The document outlines how Demand Side Management (DSM) program costs are allocated by rate classes. System benefits are distributed based on the Cost of Service (COS) methodology, with 0.7% of NS Power's revenue requirement allocated to system benefits in 2024. Remaining costs are distributed proportionally among participating classes based on their investments in DSM programs.
DSM Cost Allocation Results # Tabi e 3: 2024 PCR - Anocation 01 2024 prog grann costs annong rate Classes COLUMN Α В С D E F G Н I FORMULA Table 1 Column H Table 2 Column K A + C E/G E / 12 System Ben expenditure C d to classe c ucina Part...
AI summary The document presents a table detailing the allocation of demand-side management (DSM) costs across various rate classes in 2024. It includes breakdowns of system benefits expenditure, participating costs, and PCR riders, with percentages and monetary figures for each category. The data highlights the distribution of costs among residential, industrial, and municipal classes, along with associated charges and payments.
Non-fuel generation cost classification in COS - Generation rate base, broken down by types of generation, is initially classified to demand with the exception of investments for environmental or fuel economy reasons, which are classified...
AI summary The document outlines the classification of non-fuel generation costs within the Cost of Service (COS) framework. It details how generation rate base is classified to demand or energy based on factors like System Load Factor (SLF), Effective Load Carrying Capability (ELCC), and other apportionment methods. Wind, Steam, Hydro, and Natural Gas Turbines are specifically addressed in their classification.
Methods considered in the past proceedings In its 1993 COS Application (NSPI864), in response to UARB's earlier directive to propose a methodology which would classify costs associated with fuel conversion and environmental compliance to e...
AI summary In past proceedings, NSPI proposed the Equivalent Peaker (EP) method for classifying generation costs, but it was rejected by the Board as impractical. The SLF-based method was adopted instead. In 2013, NS Power proposed maintaining the SLF method but also presented alternate methods like PD, EP, and TD, which were rejected due to complexity and lack of industry use.
Evolving and adaptive nature of NS Power's COS In response to changing operating environment NS Power proposed various refinements to the COS methodology for stakeholders' review and Board's approval in GRA and Base Cost of Fuel (BCF) proc...
AI summary NS Power has proposed several refinements to its Cost of Service (COS) methodology in response to changes in the operating environment. These include the addition of new generation types, separation of fuel cost allocation, and changes to costing treatments for various energy sources and services, as discussed in various regulatory proceedings.
Challenges lying ahead - The pace of changes in NS Power's generation and power purchase mix is about to accelerate in the coming years. - The share of NSPI owned generation in total system energy requirement will continue to decline falli...
AI summary NS Power's generation mix is expected to change significantly, with a decrease in fossil fuel generation and an increase in renewable energy. This shift will impact cost classification and redistribution of generation costs among different rate classes.
Discussion - Material changes in operating environment require reviews of costing methodology to ensure proper alignment with cost causation and asset utilization. - It is also important to be mindful of established ratemaking principles,...
AI summary The discussion highlights the need to review costing methodologies in response to changes in the operating environment, emphasizing the importance of aligning with cost causation and asset utilization. It also addresses the balance between ratemaking principles and the simplicity of the SLF method, while noting the complexity of alternative methods like LOLP and Probability Dispatch.
Why is Transmission classified on SLF? On pages 20 and 23 of its 1995 COS Decision (NSPI864) the UARB provided as follows. Regarding transmission line rate-base assets, it is the Board's opinion that these assets cannot be totally separate...
AI summary The UARB classified transmission costs based on energy and demand factors, stating that transmission cannot be fully separated from generation. Energy-related costs are determined by the annual system load factor, while remaining costs are classified as demand-related.
MidAmerican collects a substantial portion of non-energy generation costs during lowdemand hours • This is not consistent with cost-causation principles
AI summary MidAmerican collects a significant portion of non-energy generation costs during low-demand hours, which is inconsistent with cost-causation principles.
Retain System Load Factor (SLF) method for allocating legacy generation resource costs to energy - Existing coal and combined cycle unit costs split between capacity and energy - All thermal unit energy costs (not fuel, but also including...
AI summary The document proposes retaining the System Load Factor (SLF) method for allocating legacy generation resource costs to energy. It outlines how existing coal and combined cycle unit costs are split between capacity and energy, and how energy costs are allocated equally on an hourly basis. The premise is that all customers consuming energy in the same hour should pay the same rate for that energy.
Comments on NB Power COSS Filings Prepared for the NS Power COSS Stakeholder Consultation (M11475) April 11, 2024 John D. Wilson, Grid Strategies LLC
AI summary This document provides comments on NB Power's COSS Filings, prepared for the NS Power COSS Stakeholder Consultation (M11475) by John D. Wilson of Grid Strategies LLC on April 11, 2024.
2026-2027 GRA Direct Evidence Appendix 12A(3) Page 146 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Comments on NB Power COSS Filings (April 11, 2024) Page 2 of 4
AI summary This document contains comments on NB Power's Cost of Service Study (COSS) filings submitted on April 11, 2024. The text is part of a larger regulatory proceeding and includes redacted confidential information.
2. Definition of POD Method The NB Power evidence defines the POD method as allocating "the energy classified costs by looking at the cost of providing energy in each hour instead of assuming that each kilowatt-hour served throughout the y...
AI summary The document defines the POD method, which allocates energy classified costs based on hourly dispatch and probability of dispatch. E3 suggests improvements, such as including operating reserves and excluding dispatch for exports and interruptible loads. The method requires significant data and process changes for full implementation.
3. Application of POD Method The NB Power POD method analysis assigns generation capacity (non-fuel) costs equally to all hours in which they are used. (Exh. NBP2.03, p. 15) The cost-of-service workbook provided by NB Power does not includ...
AI summary The NB Power POD method assigns non-fuel generation capacity costs equally across all hours of use. The analysis compares the POD method to the variable energy method and suggests they are similar to a class energy allocation, though verification is not possible due to incomplete supporting calculations in the provided workbook.
A. Energy (Fuel) Costs There is at least one substantial difference between the POD and HCM methods for allocating fuel costs. NB Power's POD method uses "forward-looking dispatch and costs of individual generators," while MidAmerican's HC...
AI summary The document discusses differences between the POD and HCM methods for allocating fuel costs, noting that NB Power's method is based on forward-looking dispatch while MidAmerican's uses historical data. However, NB Power's exhibits lack supporting workpapers, making verification difficult. The methods are considered similar if forecast data is reasonable.
2026-2027 GRA Direct Evidence Appendix 12A(3) Page 148 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Comments on NB Power COSS Filings (April 11, 2024) Page 4 of 4 using forecast data while the HCM method is challenged for application...
AI summary The text discusses challenges in applying the HCM method to NS Power due to the lack of hourly LMP data, requiring NS Power to calculate hourly generation costs using fuel cost, purchased power costs, and other dispatch cost inputs.
2.2 Average and Peak with Time of Use (TOU) Method - 7 The average and peak with time of use method increases the granularity of the data used in - 8 allocation of the energy classified costs by looking at the cost of providing energy in e...
AI summary The average and peak with time of use (TOU) method provides a more granular approach to allocating energy classified costs by considering hourly generation costs and loss of load probability (LOLP). However, it requires additional data not currently available in NB Power's systems and raises confidentiality concerns that may impact transparency in cost allocation.
2.3 Probability of Dispatch Method - The probability of dispatch method allocates variable production costs the same way as the - average and peak with TOU method. All fixed production costs are classified and allocated based - on the hour...
AI summary The probability of dispatch method allocates variable production costs based on hourly dispatch probabilities rather than separating costs between demand and energy. It is argued to be more accurate in assigning costs directly to the classes that use resource output, though it shares data needs and confidentiality concerns with other methods.
2.4 Marginal Cost Method 5 During the procedural conference of June 28, 2023, the final approved scope listed the marginal 6 cost allocation model as optional. Marginal cost modeling has the advantage of being relatively 7 simple to implem...
AI summary The marginal cost allocation model is deemed unsuitable for NB Power's class cost allocation study due to its volatility, inaccuracy in reflecting long-term costs, and confidentiality concerns. E3's analysis highlights discrepancies between marginal costs and actual costs, and no vertically integrated Canadian utility uses this method for CCAS.
2026-2027 GRA Direct Evidence Appendix 12A(3) Page 151 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Excerpt from Exh. Overview of Cost Allocation Methodologies
AI summary The excerpt provides an overview of cost allocation methodologies relevant to the 2026-2027 GRA Direct Evidence Appendix 12A(3). It outlines approaches used to distribute costs among different service categories or customer groups.
2026-2027 GRA Direct Evidence Appendix 12A(3) Page 152 of 310 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Overview of Cost Allocation Methodologies included in this analysis however, it would be appropriate to include them in future analys...
AI summary The document discusses cost allocation methodologies, highlighting the inclusion of fixed costs for generators dispatched for exports and interruptible load in customer class allocations. It notes that this approach may not accurately reflect the reason for dispatch and suggests that future analyses should consider excluding such data for better accuracy.
Table 4: Pros and cons of Probability of Dispatch method Pros Cons Removes a layer of subjectivity because it removes the need to classify overall fixed costs to energy and capacity. Potentially more accurate in assigning costs of resource...
AI summary The Probability of Dispatch method has pros such as reducing subjectivity in cost classification and potentially more accurate cost assignment. However, it has cons like high data requirements, not considering the rationale for investments, and volatility due to system changes. The method assigns generator costs equally across usage hours, potentially misrepresenting investment rationale.
Transmission Allocator - Functional Classification - Demand is the appropriate allocation for transmission. - Transmission facilities are sized to handle peak electricity demand. - The majority of NS Power's transmission system is networke...
AI summary The document discusses the functional classification of transmission facilities based on demand and the need for further investigation into 3-CP versus 12-CP allocation methods to align cost with causation. It also notes that winter peaks influence system demand and that the majority of NS Power's transmission system is networked.
Timing of COS Transition - § Now is the time to make changes to reflect rapidly evolving NS Power system. - § ELCC generating resource cost functionalization is both more forward looking and more dynamic than current methodologies. - § COS...
AI summary The document emphasizes the need for updating the Cost of Service (COS) model to better reflect the current and evolving NS Power system, advocating for a more dynamic and forward-looking approach that focuses on cost-causation and the role of assets rather than ownership.
1. Introduction 1. SBA Objectives for COSS The SBA believes that the timing is excellent for a fresh, comprehensive, and forward-looking review of the methodologies and assumptions used to establish the cost of service including allocation...
AI summary The SBA advocates for a comprehensive review of cost of service methodologies to ensure fair allocation of costs as electrification and decarbonization policies reshape energy usage and customer load profiles in Nova Scotia.
2. Underlying Principles for COSS The SBA has participated in the COSS stakeholder process hoping to see a process that: - 1. Closely examines cost causation for all the functions, generation, energy production, transmission, distribution,...
AI summary The SBA participated in the COSS stakeholder process to ensure cost causation is thoroughly examined across all functions, align cost causation with allocation factors, and avoid resisting COSS methodology improvements for rate stability, advocating for alignment with Bonbright principles and recognizing the evolving system structure.
Issuelb - Should the use ofllourly Production Costing for Cost Allocation? SBA View - The SBA would like this to be examined carefully and quickly in this process to ultimately propose changes in COSS methodology to the UARB. Issue 1 c - I...
AI summary The SBA recommends careful and quick examination of hourly production costing for cost allocation to propose changes in COSS methodology to the UARB. It also believes its preferences from Issue 1a will capture the effects of a more diverse generation portfolio on cost allocation methodology.
Issue 2d - New Transmission Resources (including grid scale battery, ancillary service technologies)? SBA View-The SBA refers to the discussion oflssue la(i) above for Grid Scale Batteries. Regarding Ancillary Services, the SBA agrees with...
AI summary The SBA references a prior discussion on grid scale batteries and agrees that ancillary service costs should be fully demand-related, but emphasizes the need to examine the cost allocation factor in comparison to resource adequacy cost causation.
Issue 3c - Classification between customer and demand costs SBA View – The SBA strongly believes that any application of a Minimum System Study to classify distribution system costs on a customer basis is inappropriate and highly hypotheti...
AI summary The SBA argues that applying a Minimum System Study to classify distribution system costs on a customer basis is inappropriate and highly hypothetical. They also suggest that NSP should separate and allocate service drop costs on a customer basis, though they have not fully addressed remaining issues and plan to file supplemental comments.
Purpose of Minimum System Study - The Minimum System Study is used in the COSS for the classification of distribution costs between customer-related and demand-related. - The need to classify distribution costs is described in NARUC Electr...
AI summary The Minimum System Study is used in the COSS to classify distribution costs between customer-related and demand-related. This classification is based on the NARUC Electric Utility Cost Allocation Manual, which emphasizes that distribution costs are driven by both reaching customers and maintaining capacity to meet peak demands.
Minimum System Study Methodology - The Minimum System Study methodology compares the cost of a hypothetical minimum system to the total cost of the distribution system. The cost of the hypothetical minimum system is classified as customer-...
AI summary The Minimum System Study methodology evaluates the cost difference between a hypothetical minimum distribution system and the actual system, classifying costs as either customer-related or demand-related. This approach is used by SaskPower, Hydro Quebec, and NL Power, and similar analyses are used by NB Power and Ontario distributors.
Zero-Intercept Methodology The Zero-Intercept Methodology relies on actual cost data to determine the relationship between installed costs and load carrying capacity. A regression analysis provides a formula for the cost of an asset based...
AI summary The Zero-Intercept Methodology uses regression analysis to calculate unit costs based on installed costs and load carrying capacity, with a formula that includes an intercept and a coefficient multiplied by load carrying capacity. This method separates costs associated with zero demand from those related to load carrying capacity.
COSS Model Exhibit Purpose 1 Summary of Existing and Proposed Revenue to Expense Ratio Ratios 2 Rate Base Functionalization & Classification 3 Rate Base Allocation 4 Operating Expense Functionalization 5 Operating Expense Classification 6...
AI summary The COSS Model is being analyzed through various runs, with specific changes to classifications and allocations of expenses and revenue. Key changes include the classification of PHP as a separate rate class, grid-scale storage by ELCC factor, and adjustments to transmission and generation classifications.
Overview of COSS Model Runs - ➤ We will begin with the model runs with less complex modifications and move toward the more complex models and NSP's Positions - ➤ Each COSS model includes a Summary tab that provides rate base and costs by f...
AI summary The document outlines the approach to reviewing COSS model runs, starting with less complex modifications and moving to more complex ones, with a focus on NSP's positions. Each model includes a Summary tab showing rate base and costs by function and classification, along with variance data and changes in the Revenue to Expense Ratio.
6. Sub-functionalize Transmission into EHV and HV - ➢ Purpose: Analyse the impact of removing the allocation of HV Transmission costs to EHV-connected customers. - ➢ Model Notes: The COSS already separates Transmission into EHV and HV, but...
AI summary This section discusses the purpose and model notes of sub-functionalizing transmission into EHV and HV. It explains that the COSS model separates transmission into EHV and HV, but uses the same loads for allocators. Adjusting the HV allocator by removing EHV-connected customers shifts cost responsibility from EHV to remaining classes.
10b. Classify All Generation that is Currently Classified by SLF by Capacity Factor - ➢ Purpose: Analyse the impact of allocating all generation costs that are currently classified by the SLF by the weighted average capacity factor of that...
AI summary This section discusses the analysis of allocating generation costs based on the weighted average capacity factor rather than the Steam Load Factor (SLF). The change shifts cost classifications from energy to demand, with lower load factor classes bearing more cost responsibility.
11. MEUs Included as an ATL Rate Class - ➢ Purpose: Provide an indication of the costs that would be allocated to MEUs that take OATT service if they are included in the COSS as an ATL rate class. - ➢ Model Notes: The four municipal custom...
AI summary This section outlines the inclusion of MEUs as an ATL rate class in the COSS, noting that four municipal customers taking OATT service are instead included in the 'Municipal OATT' rate class. Transmission costs for OATT service are allocated to all rate classes, while revenues include only OATT revenues.
2. New Intermediate Generation Sub-function Classified to Demand and Energy by Weighted-Average Capacity Factor - ➢ Purpose: Identify "Intermediate Generation" assets and costs and classify by the weighted-average capacity factor instead o...
AI summary This section discusses the classification of 'Intermediate Generation' assets, specifically Tufts Cove units 1, 2, and 3, using a weighted-average capacity factor instead of the Steam Load Factor (SLF). This change results in a shift of classified costs from energy to demand, with a relatively small overall impact due to the 10% contribution of intermediate generation to total steam generation.
3. Transmission Classified 100% as Demand - ➢ Purpose: Classify all Transmission as 100% demand instead of using the SLF as peak demands are the primary cost driver of Transmission costs. - ➢ Model Notes: The classification factors that sh...
AI summary This section discusses reclassifying all Transmission costs as 100% demand, removing classification factors that shift costs to energy. This change shifts cost responsibility from classes with high load factors to those with low load factors, with adjustments made to avoid cell definition errors in the model.
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.
5. Classify Grid Scale Storage by ELCC Factor Change in Total Allocated Costs ($000) Revenue to Expense Ratio Demand Energy Cust. Total Approved 2023 Scenario Change ( 1) DOMESTIC 645 -528 -0 117 97.63 97.62 -0.01 ( 2) SMALL GENERAL 34 -36...
AI summary The document presents a table analyzing the change in total allocated costs and revenue to expense ratios across various customer classes and scenarios, with a focus on the classification of grid-scale storage by ELCC factor.
1. NSP Positions - ➢ Purpose: Combine the changes made in COSS model runs 2, 3, 4, and 5. - ➢ Model Notes: The classification of Transmission 100% to demand is not applied to grid scale storage. - ➢ Overall Impact: There is an overall shif...
AI summary NSP is proposing to combine changes from multiple COSS model runs, noting that transmission costs classified as 100% demand impact cost classification, with some offset from increased generation costs due to changes in SLF and the inclusion of PHP.
DSM Model Scenario - ➢ NSP was asked to model the impact of changing the classification of DSM costs attributable to the MEUs to be 100% based on direct customer costs. - ➢ Currently 75% of costs are assigned directly to rate classes and 2...
AI summary NSP was asked to model the impact of changing the classification of DSM costs attributable to the MEUs to be 100% based on direct customer costs. Currently, 75% of costs are assigned directly to rate classes, while 25% is classified as System Benefit and allocated using the COSS methodology. The four OATT municipalities currently receive 100% customer-related costs and no System Benefit allocation. BUTU costs are classified as 100% customer-related.
Transmission Cost Comparison Recap - 2024 Blended unit transmission costs (c/kWh) are lower under the OATT than the Municipal Tariff over a broad range of load factors starting at LF of 35%. - MEUs pay currently less for transmission under...
AI summary The 2024 blended unit transmission costs under the OATT are lower than the Municipal Tariff for load factors starting at 35%. However, the current OATT is capped at a 1.8% increase, and bundled service costs to OATT MEUs are higher than in the 2023 COSS. These findings may need reassessment after the costing methodology is revised as part of this proceeding.
Differences in Transmission Revenue Requirements Expense (In thousands of 2013 2014 dollars) OATT COSS % Var OATT COSS % Var Operating, Maintenance and General OM&G) $26,586 $26,104 2% $26,762 $26,286 2% Depreciation $24,072 $26,167 -8% $2...
AI summary The text presents tables comparing transmission revenue requirements for different years, highlighting changes in expenses such as operating, maintenance, depreciation, and fixed cost recovery deferral between OATT and COSS for 2013, 2014, and 2023. The data shows significant variations in expense percentages and amounts over time.
OATT COSS Control CentreOther Total Direct 2,978 12,109 15,087 Corporate OH 2,682 10,909 13,591 Total 5,660 23,018 28,678 Source: OMG Calc tab Source: Exh 4.1 Direct 15,087 Corporate OH 13,662 Total 28,749 - The discrepancy between Corpora...
AI summary The text presents a discrepancy in Corporate OH calculations, noting that the OATT value is determined based on the share of transmission in above-the-line classes rather than the system total, which includes below-the-line classes.
(Source: 2023 COSS and OATT spreadsheets) EXHIBIT 4.1 NOVA SCOTIA POWER INC. TRANSMISSION OPERATING EXPENSES FOR THE YEAR ENDING DECEMBER 31, 2023 (IN THOUSANDS OF DOLLARS) ABOVE-THE LINE RATE CLASSES BELOW-THE LINE RATE CLASSES TOTAL OPER...
AI summary The document provides a detailed breakdown of Nova Scotia Power Inc.'s transmission operating expenses for the year ending December 31, 2023, including operating and maintenance costs, depreciation, taxes, interest, and retained earnings. The data is presented in thousands of dollars and includes comparisons between OATT and COSS figures, showing no significant variance.
Proposed Amendment to OATT Revenue Req - In general, a direct application of transmission cost requirement, as a data input into transmission rate under the OATT, would have the following effects. - It would help eliminate differences in t...
AI summary The proposed amendment to the OATT revenue requirement aims to align transmission revenue requirements between OATT and COSS by using transmission cost requirements as a data input. The amendment would only slightly alter the computation process, primarily changing entry-level costs in the 'Revenue' tab and removing the redundant O&M tab.
Hypothesis includes greater level of complexity vs. accuracy/precision - Annual losses, 8760 Data vs. load factor calculations - Non-Technical Losses, assumption vs. calculations - Secondary Configurations, sampling vs assumptions - Distri...
AI summary The text discusses the evaluation of annual energy losses and load factor calculations, comparing assumptions with actual data. It highlights the importance of accurately allocating losses per customer type by analyzing energy sold and network segment performance.
Step 02 : Calculation of loss allocation factors - Losses are calculated for each customer class across all network segments using a defined formula. Segment Losses = Customer Class Contribution % x Total Annual Energy Losses for the segme...
AI summary This section outlines the methodology for calculating loss allocation factors, where segment losses are determined by multiplying the customer class contribution percentage by total annual energy losses for each segment, and total energy loss for each class is obtained by summing losses across all segments.
Table 4 – Overall Classifications The following table summarises the share of each utility's total costs classified by each demand, energy, and customer. The shares excluding energy are also provided. In addition to classification methodol...
AI summary Table 4 summarizes the share of each utility's total costs classified by demand, energy, and customer. It also provides shares excluding energy, with variations based on generation type and classification methodologies.
3. Review of Treatment of General Plant During discussion in the COSS Stakeholder Engagement Session 2, held on February 22, 2024, intervenors noted that when looking at the COSS, General Plant costs had grown significantly. Intervenors we...
AI summary The document discusses the treatment of General Plant in the Cost of Service Study (COSS), noting significant growth in General Plant costs. General Plant includes NS Power's investments in facilities, vehicles, and IT infrastructure, with its Net Book Value (NBV) tracked separately and apportioned among generation, transmission, and distribution service areas for rate base and depreciation purposes.
2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 7 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) November 1, 2024 Memo to Participants in COSS Stakeholder Process - Func�onalized among the four service areas of genera�on, transmiss...
AI summary This memo outlines the methodology for func�onalizing and classifying costs across different service areas and rate classes as part of the 2026-2027 GRA Direct Evidence Appendix 12A(5) process.
November 1, 2024 Memo to Participants in COSS Stakeholder Process Pros Cons Would be consistent with fuel conversion Does not align with the view that the DDA and emission reduction classification. is a rate stabilization tool and was esta...
AI summary The memo outlines a debate on the classification of the Decarbonization Deferral Account (DDA) and its alignment with rate stabilization tools. It also details the inclusion of regulatory amortization in corporate taxes and the apportionment of regulatory assets and expenses to rate classes based on their responsibilities for the rate base.
3. Review of Treatment of General Plant During discussion in the COSS Stakeholder Engagement Session 2, held on February 22, 2024, intervenors noted that when looking at the COSS, General Plant costs had grown significantly. Intervenors we...
AI summary The document discusses the treatment of General Plant in the Cost of Service Study (COSS), noting significant growth in General Plant costs. It explains that General Plant includes NS Power's investments in buildings, communication equipment, transportation, and IT infrastructure, and that its Net Book Value is tracked separately and apportioned among generation, transmission, and distribution service areas.
General Plant Category 2025 2026 2027 2028 Computer Hardware 4.0 4.5 5.3 4.6 Computer Software 15.6 22.6 23.7 21.8 Vehicles 21.4 20.2 17.3 17.8 Telecommunication 15.2 15.3 15.3 4.3 Other 9.2 9.1 9.0 9.1 Total 65.4 71.7 70.6 57.7 2026-2027...
AI summary The table presents projected costs for various general plant categories from 2025 to 2028, with a notable decrease in telecommunication costs in 2028 and an overall decline in total costs by 2028. This data is part of a GRA Direct Evidence Appendix, indicating its relevance to regulatory proceedings.
2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 13 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Status Quo CTD Referen ce NS Power Position (Pre Resolution Session) NS Power Updated Position (Following Resolution Session) Justifi...
AI summary The document discusses NS Power's proposal to classify all generation assets based on SLF, eliminating the need to subfunctionalize generation assets. This approach is justified as it aligns with industry practices, supports system stability, and provides a simpler and more consistent method for cost-of-service classification.
3. Review of Treatment of General Plant During discussion in the COSS Stakeholder Engagement Session 2, held on February 22, 2024, intervenors noted that when looking at the COSS, General Plant costs had grown significantly. Intervenors we...
AI summary The discussion during the COSS Stakeholder Engagement Session 2 highlighted significant growth in General Plant costs and the need for analysis of its impact on the COSS. General Plant includes NS Power's investments in buildings, communication equipment, transportation, and IT infrastructure. The NBV of General Property is tracked separately and apportioned among generation, transmission, and distribution based on relative NBV shares.
2026-2027 GRA Direct Evidence Appendix 12A(5) 1 Page 31 of 31 REDACTED (CONFIDENTIAL INFORMATION REMOVED) December 6, 2024 Memo to Participants in COSS Stakeholder Process are secondary. As a result, IT Work and Asset Management Investment...
AI summary This memo discusses the functionalization of IT Work and Asset Management Investment to distribution, noting that while professional judgment is required, NS Power considers this method more accurate than the previous one.
The five-year forecast within the 2024 ACE plan shows that the investment level in general plant, which includes IT software and communication investments continues to be an area of significant investment and warrants a refinement in its C...
AI summary The 2024 ACE plan highlights ongoing significant investment in general plant, including IT software and communication, and suggests the need for a refinement in the COS approach. This is supported by a referenced table.
• Session 4: April 10, 2024 - o Half-day session - o Topics: Generation (part 1) pros/cons of continued use of system load factor (SLF), consistency of generation and transmission treatment/classification between energy and demand - o Summ...
AI summary This session focused on generation topics, including the classification of fuel and non-fuel costs in the Cost of Service Study (COS), the rationale behind using the system load factor (SLF) for classification, and an alternative approach presented by John Wilson. NS Power and intervenors discussed these topics.
2026-2027 GRA Direct Evidence Appendix 12A(6) Page 5 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - o Topic: Review of Models - o Summary: In this session, NS Power's third-party COSS consultant, Elenchus Research Associates Inc. (Elen...
AI summary This document outlines a series of sessions related to the 2026-2027 GRA Direct Evidence Appendix 12A(6). NS Power presented updates on the Cost of Service Study model, discussed bundled vs. unbundled service alignment, and provided a Line Loss Study update. Resolution sessions were held to address stakeholder concerns and find common ground.
2026-2027 GRA Direct Evidence Appendix 12A(6) Page 6 of 6 REDACTED (CONFIDENTIAL INFORMATION REMOVED) that NS Power and its expert consultant could also support. Although a resolution of all issues was not ultimately reached during these s...
AI summary NS Power held a final session in December 2024 to review updated Cost of Service Study (COSS) proposals following stakeholder engagement. The session allowed stakeholders to provide feedback and clarification on NS Power's updated positions and modeling related to the 3CP and other issues.
1 EXECUTIVE SUMMARY 2 Nova Scotia Power Inc. ("NS Power") retained Elenchus Research Associates 3 ("Elenchus") in December 2023 to assist the company during its cost of service study 4 ("COSS") review process. The goal of this process was...
AI summary NS Power retained Elenchus Research Associates to assist with its cost of service study review process. The goal was to refine NS Power's methodology in light of developments since the 2013 COSS, including increased renewable integration, gas-fired generation, and grid-scale battery storage. Elenchus provided context on ratemaking principles and cost allocation practices.
2026-2027 GRA Direct Evidence Appendix 12B Page 6 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1000000 Onc :hus .i ius -6- NSP COSS Consultation Report Draft April 25, 2025
AI summary The document provides a redacted excerpt from a consultation report by NSP related to the Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B, which contains confidential information.
2026-2027 GRA Direct Evidence Appendix 12B Page 7 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -7- NSP COSS Consultation Report Draft April 25, 2025 - 1 responsibility because they typically support multiple functions and aren't drive...
AI summary NS Power has proposed refinements to its Cost of Service Study (COSS) to better align cost allocation with current operational realities and customer classes. These include adjustments for PHP's rate class, DSM benefits, and line loss studies. Elenchus supports these changes, stating they improve cost recovery and alignment with industry evolution.
2026-2027 GRA Direct Evidence Appendix 12B Page 8 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -8- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B and contains redacted confidential information.
1.1 OVERVIEW - 3 Nova Scotia Power Inc. ("NS Power") retained Elenchus Research Associates - 4 ("Elenchus") in December 2023 to assist the company during its COSS review process. - 5 The goal of this process was to refine NS Power's existi...
AI summary NS Power engaged Elenchus Research Associates to assist with updating its Cost of Service Study (COSS) in 2023, considering recent developments such as renewable integration, gas generation, and grid storage. The process involved stakeholder sessions in 2024 to discuss proposed changes and their alignment with regulatory principles.
2026-2027 GRA Direct Evidence Appendix 12B Page 9 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The second second Le enc hus -9- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix 12B, which includes a consultation report draft from NSP's Cost of Service Study (COSS) dated April 25, 2025. The content is partially redacted and contains limited information.
2026-2027 GRA Direct Evidence Appendix 12B Page 10 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -10- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study, dated April 25, 2025, and is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is marked as confidential and redacted.
1 1.2 THEORY OF COST ALLOCATION - 2 In the electricity industry, electricity is generated, primarily in large power plants, then - 3 transmitted over high voltage transmission lines, after which it is transformed to lower - 4 voltages and...
AI summary This section outlines the theory of cost allocation in the electricity industry, explaining how shared assets and expenses are distributed among customer classes using a cost allocation study. The methodology relies on principles such as cost causality, benefit derived, government policy alignment, timing of recovery, simplicity, and acceptability.
2026-2027 GRA Direct Evidence Appendix 12B Page 11 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -11- NSP COSS Consultation Report Draft April 25, 2025 - 1 More than one criterion may also be used in developing an acceptable cost alloc...
AI summary The text discusses the development of a cost allocation study methodology, emphasizing criteria such as cost causality, simplicity, and acceptability in the context of the NSP COSS Consultation Report Draft from April 25, 2025.
Cost-related Attributes: - 4. Static efficiency of the use of rate classes and rate blocks in discouraging wasteful use of the service, while promoting all justified types and amounts of use. - 5. Reflections of all of the present and futu...
AI summary The text discusses principles of public utility rates, emphasizing the static efficiency of rate classes and rate blocks in discouraging wasteful use while promoting justified usage, and the reflection of present and future private and social costs and benefits of service provision, referencing a 1988 publication by Bonbright, Danielsen, and Kamerschen.
2026-2027 GRA Direct Evidence Appendix 12B Page 12 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 1 enc hile ıwə -12- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a consultation report draft from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025. It is part of the 2026-2027 GRA Direct Evidence Appendix 12B, which contains redacted confidential information.
1.3.1 REVENUE RELATED Meeting revenue requirement implies that customer rates should be set so as to yield sufficient revenues for the utility to recover its approved costs. The recoverable costs that make up the company's revenue requirem...
AI summary Setting customer rates to meet the utility's revenue requirement ensures the recovery of approved costs, including operating expenses, maintenance, administration, amortization, and the cost of capital, which includes debt interest and return on equity.
2026-2027 GRA Direct Evidence Appendix 12B Page 13 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -13- NSP COSS Consultation Report Draft April 25, 2025 1 Stability and predictability are criteria that deal with the need to use cost all...
AI summary The text discusses the importance of stability and predictability in cost allocation and rate design, emphasizing the need to avoid sudden and significant changes in customer bills. It suggests that when necessary changes occur, they should be phased in to mitigate impacts on consumers.
11 1.3.2 COST RELATED - 12 Fairness and equity are understood to mean that the utility's assets and expenses have - 13 been apportioned to the customer classes in a manner that has cost causality as the main - 14 criterion. The methodologi...
AI summary The text discusses the principles of fairness, equity, and economic efficiency in utility cost apportionment. It emphasizes cost causality as a key criterion for allocating assets and expenses to customer classes, and highlights the importance of rate design in promoting operational and dynamic efficiency, as well as resource conservation.
2026-2027 GRA Direct Evidence Appendix 12B Page 14 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -14- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, part of the 2026-2027 GRA Direct Evidence Appendix 12B, with confidential information redacted.
1 1.3.3 PRACTICAL RELATED - 2 Simplicity and administrative ease are criteria that address the need to use cost allocation - 3 and rate design methods that are understandable by stakeholders and customers and - 4 are implementable by the u...
AI summary The text emphasizes the importance of simplicity and administrative ease in cost allocation and rate design methods, highlighting the need for these methods to be understandable by stakeholders and customers, as well as implementable by the utility based on its available capabilities and resources.
2026-2027 GRA Direct Evidence Appendix 12B Page 15 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -15- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, and is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information.
1 2 OVERVIEW OF STAKEHOLDER PROCESS - 2 From January to December 2024, NS Power held fifteen meetings with stakeholders to - 3 discuss COSS matters. These meetings are summarized below. - 4 Eight stakeholder sessions - 5 Two mini sessions...
AI summary NS Power conducted fifteen stakeholder meetings from January to December 2024 to discuss COSS matters, including eight sessions, two mini sessions, a modeling review, a pre-resolution position session, a two-day in-person resolution session, and a post-resolution session.
10 Table 1 – Stakeholder Session Summary Date Session Length 18-Jan-24 Initial COSS Stakeholder Engagement Session 2 Hours 22-Feb-24 2nd COSS Stakeholder Session Full Day 13-Mar-24 3rd COSS Stakeholder Session Half-Day 10-Apr-24 4th COSS S...
AI summary The document outlines a series of stakeholder sessions related to the Cost of Service Study (COSS) conducted by Nova Scotia Power (NS Power) over multiple dates and durations, indicating ongoing engagement and discussion around cost-related matters.
2026-2027 GRA Direct Evidence Appendix 12B Page 16 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -16- NSP COSS Consultation Report Draft April 25, 2025 - 1 with the current methodology, and present alternative methodologies. In additio...
AI summary NS Power conducted stakeholder consultations and discussions to refine the Cost of Service Study methodology, responding to 152 data requests and providing 31 model scenarios to assess alternative approaches.
2026-2027 GRA Direct Evidence Appendix 12B Page 17 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -17- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, which is part of the 2026-2027 GRA Direct Evidence Appendix 12B. The content is redacted and contains confidential information.
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.
1 4.1.1.2 NSP PROPOSED APPROACH - 2 NS Power is proposing to classify all generation by the same methodology. This is further - 3 discussed in section [4.2.1.2.](#page-79-2) This proposed change in methodology will eliminate the - 4 need t...
AI summary NS Power proposes to classify all generation using the same methodology, eliminating the need to sub-functionalize rate base and OM&A by type of generation, while continuing to track costs separately within the Cost of Service Study model.
7 4.1.1.3 ELENCHUS OPINION - 8 Elenchus agrees it is appropriate to continue to maintain the current sub-functionalization - 9 of rate base and OM&A by type of generation. The primary purpose of sub-functionalizing - 10 accounts is to sepa...
AI summary Elenchus supports maintaining the current sub-functionalization of rate base and OM&A by type of generation, arguing that it provides greater clarity and transparency in the cost of service study model compared to consolidating into a single generation function.
2026-2027 GRA Direct Evidence Appendix 12B Page 20 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) The second second On IC en -20- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a redacted page from the 2026-2027 GRA Direct Evidence Appendix 12B, which includes a consultation report draft from NSP's Cost of Service Study (COSS) dated April 25, 2025.
2026-2027 GRA Direct Evidence Appendix 12B Page 22 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -22- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, as part of the 2026-2027 GRA Direct Evidence Appendix 12B. It includes redacted confidential information and is part of a regulatory proceeding.
2026-2027 GRA Direct Evidence Appendix 12B Page 23 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -23- NSP COSS Consultation Report Draft April 25, 2025 1 part of its proposal, NS Power will remove the initial classification of environm...
AI summary NS Power proposes to classify all generation rate base, including environmental and fuel conversion, using the system load factor rather than discrete classification factors. This approach is consistent with practices in other Canadian jurisdictions and aims to align cost allocation with customer load profiles and regulatory requirements.
2026-2027 GRA Direct Evidence Appendix 12B Page 24 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -24- NSP COSS Consultation Report Draft April 25, 2025 - 1 would be primarily classified to energy and combustion turbines would be classi...
AI summary This excerpt from the NSP COSS Consultation Report Draft discusses the classification of assets, noting that certain classifications would be primarily energy-related, while others would be fully classified to demand, potentially leading to different rate impacts based on when investments in those assets occur.
4.2.1.3 ELENCHUS OPINION 5 The system load factor method is a simple and pragmatic approach to classifying costs 6 that are functionalized as generation costs as energy- and demand-related in a manner 7 that ignores the cost difference acr...
AI summary The Elenchus opinion critiques the system load factor method for allocating generation costs, noting that it oversimplifies by ignoring differences between supply resources. It raises concerns about the impact of new facilities on cost allocation and suggests that a more granular approach may not be equitable in the short term. The opinion emphasizes the need for a methodology that balances cost causality and fairness.
2026-2027 GRA Direct Evidence Appendix 12B Page 25 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -25- NSP COSS Consultation Report Draft April 25, 2025 - 1 reasonable rates that ultimately determines whether the methodology is appropri...
AI summary The text discusses the system load factor approach used in NS Power's cost allocation process, emphasizing that embedded costs are determined by historic decisions and not current use, highlighting the diversity of assets resulting from long-term capital investment.
2026-2027 GRA Direct Evidence Appendix 12B Page 27 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 10000 On IC en ш U > -27- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a consultation report from Nova Scotia Power's Cost of Service Study (COSS) draft dated April 25, 2025, which is part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information and appears to be part of a regulatory proceeding.
2026-2027 GRA Direct Evidence Appendix 12B Page 28 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -28- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a consultation report from Nova Scotia Power's Cost of Service Study (COSS) draft dated April 25, 2025, part of the 2026-2027 GRA Direct Evidence Appendix 12B. It is redacted and contains confidential information.
4.3.1.3 ELENCHUS OPINION - 2 The allocation of demand-classified costs using the 3CP method is consistent with the - methodologies that are generally used in other jurisdictions in Canada.[10](#page-85-1)
AI summary The document discusses the allocation of demand-classified costs using the 3CP method, noting its consistency with methodologies used in other Canadian jurisdictions.
4.3.2.2 NSP PROPOSED APPROACH - NS Power is proposing to change the method to allocate the non-fuel, energy related - costs of purchases to rate classes from an annual to a monthly based allocation method. - The allocation of other costs i...
AI summary NS Power proposes changing the allocation method for non-fuel, energy-related costs from annual to monthly. Other costs will remain unchanged. The text references allocation methods used by NB Power, BC Hydro, and SaskPower.
16 4.3.3.3 ELENCHUS OPINION - 17 NS Power's proposed allocators for radial-to-generation and storage are reasonable as - 18 they are consistent with the allocators used for other generation sub-functions.
AI summary NS Power's proposed allocators for radial-to-generation and storage are deemed reasonable as they align with allocators used for other generation sub-functions.
2026-2027 GRA Direct Evidence Appendix 12B Page 30 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -30- NSP COSS Consultation Report Draft April 25, 2025
AI summary This document is a draft consultation report from Nova Scotia Power's Cost of Service Study (COSS) dated April 25, 2025, as part of the 2026-2027 GRA Direct Evidence Appendix 12B. It contains redacted confidential information.
5.1.1.2 NSP PROPOSED APPROACH - NS Power is proposing to maintain the current practice of classifying and allocating EHV - and HV transmission by the same factors. The separation of EHV and HV within the cost - of service study model is no...
AI summary NS Power proposes to maintain current classification practices for EHV and HV transmission, eliminate sub-functionalization in the cost of service study model, and continue refunctionalizing bulk power substations from Transmission to Distribution.
5.1.3.3 ELENCHUS OPINION - 2 Creating a transmission storage sub-function is prudent at this time given developments - 3 in the electricity sector since NS Power's last cost of service study review. Storage can - 4 be used for many purpose...
AI summary The text discusses the prudence of creating a transmission storage sub-function, citing developments in the electricity sector since NS Power's last cost of service study review. It notes that storage can serve multiple purposes and that NS Power is likely to develop storage with a transmission function.
- 1 interconnections, all other transmission is classified as 100% demand in all other - 2 jurisdictions in Canada. This is appropriate because the quantum of costs incurred to - 3 provide transmission service is caused by forecasted capac...
AI summary The text discusses the classification of transmission costs, including radial-to-generation and storage, within the context of cost causality and system load factors. Elenchus supports NS Power's proposal to reclassify transmission rate base, depreciation, and OM&A as 100% demand while maintaining classification based on the system load factor.
5.3 ALLOCATION - 5.3.1 GENERAL TRANSMISSION - 5.3.1.1 NSP CURRENT APPROACH - Demand-classified EHV and HV transmission is allocated to rate classes using the same - 3CP allocator used to allocate demand-classified generation costs. - Energ...
AI summary NS Power proposes maintaining the current method of allocating demand-classified transmission costs using the 3CP allocator, while eliminating the energy classification of transmission costs. Elenchus supports this approach, aligning with NS Power's proposal to use a single sub-function for EHV and HV transmission costs in the revised cost of service study model.
5.3.2 RADIAL-TO-GENERATION & STORAGE - 5.3.2.1 NSP CURRENT APPROACH - 3 Radial-to-generation and storage costs are embedded within EHV and HV transmission - 4 costs so they are implicitly allocated using the same demand and energy allocato...
AI summary The document discusses Nova Scotia Power's (NSP) current and proposed approaches to allocating radial-to-generation and storage costs. NSP currently embeds these costs within transmission costs, while proposing to refunctionalize radial-to-generation away from transmission and apply the 3CP demand allocator to transmission storage. Elenchus supports the use of the 3CP allocator for transmission storage costs.
12 6.1.1.3 ELENCHUS OPINION - 13 NS Power's functionalization of Distribution to sub-functions is reasonable and - 14 consistent with the sub-functions used by other vertically-integrated utilities across - 15 Canda. This level of sub-func...
AI summary The text argues that NS Power's division of Distribution into sub-functions is reasonable and consistent with other utilities in Canada. It also suggests that creating a distribution storage sub-function is prudent, even without current facilities, due to future developments in the electricity sector and potential cost savings.
6.2.1.3 ELENCHUS OPINION - Elenchus agrees that the classifications applied to each sub-function are appropriate. The - cost of substations and line transformer costs are driven by demands and peak times so - it is appropriate for those co...
AI summary Elenchus agrees with the classification of sub-function costs, stating that substation and line transformer costs are demand-driven and customer-related costs vary with the number of customers served.
6.2.2.1 NSP CURRENT APPROACH - The minimum system methodology is used in the cost of service study for the - classification of poles & fixtures and overhead & underground lines between customer- - related and demand-related. The need to cl...
AI summary NSP uses the minimum system methodology in its cost of service study to classify distribution costs as either demand-related or customer-related, following guidelines from the NARUC Electric Utility Cost Allocation Manual.
6.2.2.2 NSP PROPOSED APPROACH - 8 NS Power is proposing to maintain the minimum system methodology for the purpose of - 9 classifying poles & fixtures and overhead & underground lines. This methodology - appropriately considers the two pri...
AI summary NSP is proposing to maintain the minimum system methodology for classifying poles, fixtures, and overhead and underground lines, emphasizing that this approach appropriately considers customers and demand as the primary cost drivers.
6.2.2.3 ELENCHUS OPINION - The minimum system method is appropriate for classifying poles & fixtures and overhead - & underground lines between demand and customer. These costs have two clear cost - drivers: the sprawl of the distribution...
AI summary The minimum system method is deemed appropriate for classifying distribution costs related to poles, fixtures, and overhead and underground lines. It accounts for two cost drivers: the sprawl of the distribution system and peak demand. This method is used by multiple utilities and is considered the most common approach in Canada for classifying distribution costs.
2026-2027 GRA Direct Evidence Appendix 12B Page 41 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -41- NSP COSS Consultation Report Draft April 25, 2025 - 1 load can create counterintuitive and controversial results that are detached fr...
AI summary The document discusses the limitations of the basic customer method for cost allocation, highlighting inconsistencies with cost causality. It compares this method to the minimum system and zero-intercept methods, noting that the latter two are used by some Canadian utilities but not universally. The zero-intercept method, while used by some, can produce counterintuitive results.
2026-2027 GRA Direct Evidence Appendix 12B Page 42 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -42- NSP COSS Consultation Report Draft April 25, 2025 - 1 In Elenchus' view the minimum system method is the method most aligned with cos...
AI summary The document discusses NS Power's current and proposed methodologies for classifying and allocating distribution storage and demand-classified distribution. Elenchus supports NS Power's approach, arguing that using a weighted average classification aligns with cost causality principles and appropriately allocates distribution storage costs.
15 7.1.1 CURRENT RETAIL METHODOLOGY - 16 Retail costs include expenses like meter reading, customer service, and billing & - 17 collection. These costs are classified fully as customer-related.
AI summary The current retail methodology classifies retail costs, such as meter reading, customer service, and billing and collection, as fully customer-related expenses.
4 7.1.3 ELENCHUS OPINION - 5 Meter reading, call centre, and billing services costs are allocated by a weighted allocation - 6 factor that consider the costs of these sub-functions are largely driven by the number of - 7 customers but ther...
AI summary The text discusses the allocation of meter reading, call centre, and billing services costs using a weighted factor that considers both the number of customers and class revenues, with an 85%/15% weighting based on resource analysis.
2026-2027 GRA Direct Evidence Appendix 12B Page 46 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -46- NSP COSS Consultation Report Draft April 25, 2025 - judgement. 1 [11](#page-103-2) Allocating these costs typically relies on judgeme...
AI summary The text discusses the allocation of costs related to customer experience, solutions, and meter data services, emphasizing the use of direct allocations and adjustments for seasonal customers. Elenchus supports these methods as reasonable.
7.2.3 ELENCHUS OPINION - General plant provides support to the generation, transmission, and distribution functions - and there generally is no clear cost driver for these costs. The overall approach to - classifying and allocating general...
AI summary The opinion discusses the classification and allocation of general plant costs, emphasizing the need for periodic reviews to ensure accurate cost assignment. It supports breaking out computer software and communications equipment for more precise allocation and highlights the importance of aligning with Canadian methodologies.
7.3.2 NSP PROPOSED APPROACH - 7 NS Power has refined the COSS to facilitate scenarios that allocate costs to PHP as a - 8 separate rate class PHP's loads and customer characteristics would be included in the - 9 derivation of allocators as...
AI summary NSP has refined the COSS to allocate costs to PHP as a separate rate class, ensuring its loads and customer characteristics are included in the derivation of allocators. PHP, being a transmission-connected customer, will not receive any allocation of distribution costs.
7.4.2 ELENCHUS OPINION - 4 The study conducted by BBA is consistent with, or in many cases more detailed, than line - 5 loss studies used in other jurisdictions across Canada. In Elenchus' view the results - 6 produced by BBA are appropria...
AI summary The Elenchus opinion supports the use of BBA's study in NS Power's cost of service analysis, noting its consistency and detail compared to other jurisdictions in Canada. The study is deemed appropriate for deriving loss-adjusted energy and demand allocators.
8 CONCLUSIONS 2 As stated in the Introduction the goal of this process was to identify appropriate changes 3 to NS Power's COSS in light of developments including the greater integration of wind 4 and other renewables, the addition of a gr...
AI summary The document discusses the need for refinements to NS Power's Cost of Service Study (COSS) methodology due to changes in technology and generation mix, such as increased renewables and gas-fired generation. It emphasizes that the fundamental principles of cost allocation remain unchanged, but adjustments are necessary to equitably assign costs to customer classes.
2026-2027 GRA Direct Evidence Appendix 12B Page 54 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -54- NSP COSS Consultation Report Draft April 25, 2025 1 with meeting the system's base, intermediate and peak demands. However, the 2 int...
AI summary The document discusses NSP's approach to classifying generation, transmission, and distribution costs in the context of evolving energy technologies and supply portfolios. It highlights the integration of renewable generation, storage, and PPAs, and proposes refining cost classifications to align with operational realities and best practices in ratemaking.
2026-2027 GRA Direct Evidence Appendix 12B Page 55 of 55 REDACTED (CONFIDENTIAL INFORMATION REMOVED) -55- NSP COSS Consultation Report Draft April 25, 2025 1 of the functionalization of projects within general plant will better align suppo...
AI summary This text discusses refinements to NS Power's Cost of Service Study (COSS) to better align support costs with specific functions, address unique costing approaches for PHP, and update DSM rate rider weightings based on customer class. It also highlights a new line loss study conducted by BBA, which provides a more accurate basis for allocating line losses among rate classes.
7.3 Non-coincident demand loss allocation factors NS Power's cost of service methodology considers three categories for non-coincident demand losses: - Secondary voltage: includes service transformer and secondary conductor; - Primary volt...
AI summary NS Power's cost of service methodology categorizes non-coincident demand losses into three types: secondary voltage, primary voltage, and bulk power transformers, each encompassing specific equipment and infrastructure.
N-64N-64.pdf
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COST ALLOCATION REVIEW Board Directions on Cost Allocation Methodology For Electricity Distributors
AI summary The document outlines the Board's directions regarding the methodology for cost allocation among electricity distributors, emphasizing the need for a fair and transparent approach to distributing costs.
1.1 Purpose of Report This Report sets out the Board's common cost allocation methodology to govern the cost allocation review informational filings due from licensed electricity distributors starting in the Fall of 2006. The Board release...
AI summary This report outlines the Board's cost allocation methodology for licensed electricity distributors, following the release of a staff proposal and additional comments in 2006. A filing model and instructions will be issued in October 2006, with distributors required to submit filings as per their licence requirements.
1.5.1 Common Cost Allocation Methodology In this Report the Board has established a common cost allocation methodology for use by Ontario electricity distributors. To assist in the completion and review of the filings, certain default valu...
AI summary The Board has established a common cost allocation methodology for Ontario electricity distributors, emphasizing sound cost causality and using consistent methodology with utility-specific inputs to support cost allocation reviews.
1.5.5 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.
1.5.7 Summary of the Cost Allocation Filing In addition to filing a completed model, all distributors will be required to file an accompanying Summary of the Cost Allocation Review Filing ("Filing Summary"). The Filing Summary should inclu...
AI summary Distributors must file a Summary of the Cost Allocation Review Filing alongside their completed model, including management comments on the interpretation of results and explanations if the approved methodology does not reasonably portray cost causality in their specific circumstances.
1.5.8 Specialized Situations This Report sets out a common cost allocation methodology that is intended to cover the great majority of the situations to be faced by a typical distributor. There may be specialized situations for which the R...
AI summary This section outlines a common cost allocation methodology for distributors, noting that it may not cover all specialized situations. It mentions that including generation assets in the rate base is rare and that distributors should use sound practices and explain any uncovered situations in their Filing Summary.
1.6 The OEB Cost Allocation Filing Model The OEB cost allocation review filing model and accompanying instructions are planned for release to all distributors shortly after the issuance of this Report. All licensed electricity distributors...
AI summary The OEB is planning to release a cost allocation review filing model for electricity distributors, with exceptions for certain entities. Most distributors are expected to use the standard model, while others must create their own with Board approval and ensure consistency with the outlined methodology.
1.9 Filing Process Distributors will be required to submit their cost allocation filings to the Board in one of the four following tranches (for details, see Appendix 1.3): - 1) November 30, 2006 - 2) January 15, 2007 - 3) February 28, 200...
AI summary Distributors must submit cost allocation filings to the Board in four tranches by specific dates. They are encouraged to collaborate with load data service providers and begin background work promptly. The filings will be made public, and additional background work is discouraged.
1.10 Review of Filings Following a review of the cost allocation filings by Board Staff, stakeholders will be provided an opportunity to comment on the results .
AI summary Board Staff has reviewed the cost allocation filings, and stakeholders will be given the opportunity to comment on the results.
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.
2.2.2 Unmetered Scattered Loads ("USL") in Run 1 and USL Metering Credit Certain customer loads have traditionally not been metered by most distributors. Specific examples include such loads as: bus shelters, phone booths, CATV amplifiers,...
AI summary The document discusses the treatment of Unmetered Scattered Loads (USL) in the context of cost allocation filings. It outlines two approaches for allocating costs to USL customers, referencing the 2006 EDR Handbook and rate orders. Distributors are advised to consider the underlying substance of their current USL rates and explain their choice of approach in the Filing Summary.
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.
3. Load Data Requirements The Chapter sets out the Directions on load data requirements for the cost allocation filings.
AI summary This section outlines the Directions regarding load data requirements for cost allocation filings, which are essential for regulatory proceedings related to energy costs and distribution.
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.
3.6 Load Profile for Separate Load Displacement Generation Rate Classification Two different load data approaches may be modeled for these customers in Run 2 and Run 3, as the Board considers it useful to obtain a broad range of informatio...
AI summary The document discusses two different load data approaches for modeling customers in Run 2 and Run 3, aiming to gather a wide range of information on cost allocation for load displacement generation customers. Stakeholders will be given a future opportunity to comment on these approaches.
4.1.1 Background Cost allocation studies are generally performed using data for a one year reference period or "test year". For the purpose of the upcoming filings, the revenue requirement (as defined below) and the data underlying the app...
AI summary Cost allocation studies are based on a one-year reference period, and the 2006 distribution rates will be used for upcoming filings. Adjustments approved by the Board to the 2006 EDR revenue requirement must be reflected in the cost allocation filing.
4.1.2 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.
4.2.2 Direction - Definition of Revenue for Cost Allocation Filings The service revenue requirement on sheet 5-1 of the distributor's approved 2006 EDR model will be the basis of ensuring all the proper costs have been included in the cost...
AI summary The document outlines the definition of revenue for cost allocation filings, specifying that the revenue per rate classification from the approved 2006 EDR model must be used. It details the components of revenue, including base revenue, revenue off-sets, and CDM allocations, while excluding certain adjustments like regulatory asset adders and smart meter adjustments.
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.
6. Functionalization Directions on the process to functionalize costs in the cost allocation filings are presented in this Chapter.
AI summary This section outlines the process for functionalizing costs in cost allocation filings, providing guidance on how to categorize and allocate costs appropriately within regulatory proceedings.
6.1.1 Background The process of functionalization of costs is an important step in the cost allocation process, as it sets up the framework for the categorization and allocation steps. The functionalization step is the process that groups...
AI summary The functionalization of costs is a key step in the cost allocation process, grouping homogeneous costs into functions. The Uniform System of Accounts (USoA) for Ontario distributors is used to standardize this process. Costs are then categorized as demand-related or customer-related based on factors discussed in Chapter 7.
6.1.2 Direction - Grouping of Accounts and Sub-accounts in Cost Allocation Filings In the cost allocation filings, each adjusted 2004 account shown in column P of Sheet 2-4 of the approved 2006 EDR application will be placed into a group t...
AI summary This section provides guidance on grouping accounts and sub-accounts in cost allocation filings, based on the approved common cost allocation methodology. Each adjusted 2004 account from the 2006 EDR application is to be grouped with others sharing a common allocation process, and sub-accounts are also to be grouped accordingly. Appendix 6.1 provides a comprehensive mapping of these groupings.
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.
Functional Approach The bulk, primary and secondary sub-accounts relate to assets associated with performing bulk, primary and/or secondary functions within a distribution system. The key objective of the cost allocation is to allocate cos...
AI summary The document discusses the 'functional approach' for allocating distribution costs based on the functions of bulk, primary, and secondary assets. It emphasizes the importance of cost causality and simplicity in the allocation method, noting that a voltage-based test is not universally applicable. The Board concludes that a functional approach best identifies bulk assets.
Stakeholder Discussions on Bulk Asset Test The Board believes the most appropriate manner to implement a functional approach towards identifying bulk assets involves a separation of the distribution assets to identify any assets that were...
AI summary The Board discusses the implementation of a functional approach to identify bulk assets, emphasizing the need for a clear definition to ensure consistent cost allocation. The approach focuses on system peak considerations and addresses stakeholder concerns about inconsistent application of the bulk asset test.
6.2.2.2 Direction – Definition of Bulk A functional approach must be adopted towards identifying the assets that may serve a bulk delivery function in some distribution systems. The test to determine if any bulk assets exist in a given dis...
AI summary The document outlines a functional approach to identify bulk delivery assets in distribution systems, emphasizing that assets built to support the system's peak, not the customer's peak, should be classified as bulk assets for cost allocation purposes.
6.2.2.3 Implementation Guidance on Application of Bulk Definition For cost allocation purposes, as indicated the test to be applied by distributors in defining bulk assets is to identify those assets that were built to support the distribu...
AI summary This section provides guidance on defining bulk assets for cost allocation purposes. Bulk assets are those specifically built to support the distribution system's peak, and should be allocated using Coincident Peak (CP), while primary and secondary assets are allocated using Non-Coincident Peak (NCP). Factors like voltage level and system configuration are considered in determining the function of assets.
6.2.2.7 Specialized Circumstance When the Technical Advisory Team commenced its discussions of functionalization, participants noted that subtransmission costs had been segregated in a previous application submitted to the Board by Hydro O...
AI summary The Board allows Hydro One to use a subtransmission cost pool in its upcoming cost allocation filing, provided it explains and justifies this approach, including the impact compared to a standard bulk asset cost pool. The Board also expects Hydro One to provide further justification if it uses CP for allocation, considering Chapter 8's guidance on CP and NCP usage.
6.3.1 Direction – Identifying Bulk, Primary and Secondary Costs Once the bulk, primary and secondary assets have been identified based on the above tests and guidance, it is necessary to break out the associated costs. As the accounting gr...
AI summary The document outlines the process for identifying and allocating costs for bulk, primary, and secondary assets. Since detailed accounting data is not available, the distributor must estimate the percentage of costs for each asset type and apply it to the total asset account. The Filing Summary must explain this allocation method, which involves calculating unit installation costs and applying them to the respective asset line lengths.
6.3.2 Direction - Breakout of Bulk, Primary and Secondary Sub-accounts The bulk, primary and secondary sub-accounts should be broken out to the corresponding rate classifications that use those assets. In particular: - Secondary costs will...
AI summary The text outlines how bulk, primary, and secondary sub-accounts should be allocated to rate classifications based on the use of corresponding assets, with specific rules for cost allocation depending on customer and load percentages.
6.5.2 Direction – Treatment of Line Transformers To properly allocate line transformers assets (Account #1850) and the associated maintenance costs (Accounts #5035, #5055, #5160), the cost allocation model will require customer numbers and...
AI summary The document outlines the need to allocate line transformer assets and their maintenance costs using customer numbers and NCP loads by rate classification to reflect distinct usage patterns, differing from secondary assets.
6.6.2 Background - Determination of Contributions The level of contributions are determined by the net present value of the total costs of a project, offset by the revenue stream generated by the project's new customers. In addition to ext...
AI summary Contributions are determined based on the net present value of a project's total costs, adjusted for revenue from new customers. Upstream growth-related capital costs, such as distribution stations and feeders, may also be included in the project's costs even if they are not directly attributable to the project.
7. Categorization Directions on the process to categorize costs in the cost allocation filings are presented in this Chapter.
AI summary This section outlines the process for categorizing costs in cost allocation filings, providing guidance for proper classification and allocation of expenses.
7.1 Introduction The categorization step, also referred to as "classification", consists of subdividing distribution assets and O& M expenses into the following cost-based groupings: - demand-related, and/or - customer-related. Distributio...
AI summary The categorization step, or classification, involves subdividing distribution assets and operating and maintenance expenses into demand-related and customer-related groupings based on cost causality. Joint costs will be divided into customer and demand-related proportions using generic minimum system results, and allocated to rate classifications using allocators detailed in subsequent chapters.
7.2 Direction – Identification of Accounts For the cost allocation filings, functionalized grouped costs will be ultimately classified into one of the four components: - 100% demand-related - 100% customer-related - joint related (both cus...
AI summary This section outlines the classification of functionalized grouped costs into four categories: 100% demand-related, 100% customer-related, joint related, and pro-rata related. Examples include metering and billing as customer-related, distribution stations as demand-related, and joint costs like poles and transformers. Pro-rata related costs are allocated based on specific methods outlined in Chapter 10.
7.3.1 Background Three principal options for categorizing joint distribution assets and operating expenses were initially identified. Each approach has been approved by various regulators across North America. The minimum system approach i...
AI summary Three principal options for categorizing joint distribution assets and operating expenses were identified. The minimum system approach is preferred for use in filings as the common categorization method, while the basic customer method is used for calculating lower end customer unit costs to assist with future rate design.
Option 2: Minimum System Method The minimum system method assumes that a minimum-size distribution system can be built to serve the minimum load requirements of the customer. The minimum system method involves determining the minimum size...
AI summary The minimum system method assumes a minimum-size distribution system can be built to serve customer load requirements. It classifies costs as either customer-related or demand-related. The method involves determining the minimum size of distribution infrastructure and adjusting for peak load carrying capability to ensure accurate cost allocation.
Option 3: Basic Customer Method This approach categorizes as customer-related costs only those capital and operating expenses that are directly associated with adding another customer. Examples of such costs are the capital and operating c...
AI summary Option 3, the Basic Customer Method, allocates customer-related costs only to those directly tied to adding a new customer, such as meters and service drops. Unlike other methods, it does not consider upstream distribution infrastructure costs. While it will not be approved for cost allocation, it may be useful for providing unit cost information for future reviews of fixed monthly customer charges.
7.3.2 Direction – Use of Minimum System Method and Basic Customer Method in Filings For cost allocation purposes, the minimum system approach will be used as the common categorization method. Generic minimum system results will be set out...
AI summary The document outlines the use of the minimum system method and basic customer method for cost allocation in filings. It specifies that the minimum system approach will be used for calculating revenue to cost ratios and splitting joint costs, with a standard PLCC adjustment. The basic customer method will be used to determine the lower range of unit costs, while the minimum system method will establish the upper range.
7.4.1 Introduction The cost and time to undertake individual minimum system studies is significant. In addition, practitioners have varying judgements on key implementation details. Therefore, on the grounds of both practicality and consis...
AI summary The document discusses the use of generic minimum system results in cost allocation filings, grouping distributors by density and applying these results to specific joint-cost and depreciation accounts, excluding bulk sub-accounts.
7.4.2.3 Background - Stratification of Generic Minimum System Results Technical Advisory Team discussions took place on how to fairly and consistently define density for purposes of the cost allocation filings. The question is of practical...
AI summary The document discusses the technical advisory team's efforts to standardize the definition of density for cost allocation filings. It highlights inconsistencies in how different distributors calculate density and outlines the rationale for using road km instead of circuit km. The Board may be asked to consider refining density definitions or stratum boundaries in the future.
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.
Customer Unit Cost Adjustment Another output of the filing model is customer and demand unit costs by rate classification. These unit costs can be used to help set future distribution rates; however, to reflect the results of the PLCC adju...
AI summary The filing model produces customer and demand unit costs by rate classification, which can be used to set future distribution rates. To reflect the PLCC adjustment, customer-related costs should be moved into demand-related costs before rate determination, though the total cost allocated to the rate classification remains unchanged.
7.7.1 Background The minimum system methodology to be adopted will allocate certain customerrelated costs to individually metered customers in multi-unit complexes. But the multi-unit complexes have sometimes been considered, in past studi...
AI summary The document discusses the allocation of customer-related costs in multi-unit complexes, noting that past studies sometimes treated them as single customers. A stakeholder suggested a multi-unit adjustment based on cost causality, but no such adjustments will be included in current filings due to data challenges. The Board encourages distributors to gather more information for future improvements.
8. Allocation of Demand-Related Costs Directions on how to allocate demand-related costs in the cost allocation filings are presented in this Chapter.
AI summary This section outlines the guidelines for allocating demand-related costs within cost allocation filings, providing a framework for how such costs should be distributed.
8.1 Introduction The accounts/sub-accounts that, following the categorization step, are allocated on demand in total or in part were listed in Appendices 7.1 and 7.3. There are several technical factors to consider when properly allocating...
AI summary This section outlines the allocation of demand-related costs for distributors, introducing CP and NCP as methods for cost allocation. It notes that NCPI was used previously but will not be used in the current filing methodology due to complexity and other allocation methods.
4 NCP A criterion accepted in prior Ontario cost allocation analyses is the importance of choosing a stable cost allocation methodology. 4 NCP will function as a more stable methodology than 1 NCP and so has an important practical advantag...
AI summary The document discusses the use of 4 NCP as a more stable cost allocation methodology compared to 1 NCP and 12 NCP, emphasizing its importance in ensuring accurate cost causality and reliability, particularly in Ontario's distribution systems.
8.6.2 Direction – Treatment of Line Losses in Filings In the cost allocation filings, distributors will use the same loss factors as approved in their 2006 EDR applications when adjusting their metered load data to arrive at the demand all...
AI summary Distributors are directed to use the same loss factors approved in their 2006 EDR applications when adjusting metered load data for cost allocation filings.
8.6.3 Filing Questions A distributor must provide the following information for future reference as part of its Filing Summary: - 1. Provide an estimation of "non-technical" energy losses (e.g. theft of power, billing accruals, metering pr...
AI summary The distributor is required to estimate and report both non-technical and technical energy losses as a percentage of energy purchased, with technical losses further broken down by system components such as >50 kV, bulk, primary, and secondary assets, using definitions from cost allocations filings.
9. Allocation of Customer-Related Costs Directions on how to allocate customer-related costs in the cost allocation filings are presented in this Chapter.
AI summary This section outlines the guidelines for allocating customer-related costs within cost allocation filings. It provides directions on how these costs should be handled in regulatory proceedings.
9.1 Introduction Customer-related costs are commonly allocated by using the number of customers by rate classification, or by using weighted customer allocation factors. The weightings of customer allocation factors are typically developed...
AI summary Customer-related costs are allocated using rate classifications and weighted allocation factors that consider investment costs, service complexity, and customer density. These factors vary by asset type and O&M expenses to reflect specific cost characteristics, such as meter reading frequency and customer distribution.
9.3.1.1 Background A common allocator used to allocate customer-related costs that are related to billing activities is the number of bills issued. The major accounts allocated on this basis are billing, collecting and associated supervisi...
AI summary The document discusses the allocation of customer-related costs based on the number of bills issued, including billing, collection, and customer care costs. Some parties suggested applying weighting factors to account for differences in costs across customer classifications, which the Board agreed to. Flexibility is provided for handling rate classifications not covered in the survey and for using utility-specific factors.
9.3.1.2 Direction – Allocation of Billing Activities The number of bills adjusted by a weighting factor must be used to allocate costs associated with billing activities which include billing, collecting, and associated supervision and cus...
AI summary The document outlines the allocation of billing activities costs using a weighting factor based on the number of bills. It provides guidelines for using default weighting factors, allows for distributor-specific adjustments, and specifies that sentinel lights should be weighted at 0.10 for cost allocation purposes.
9.3.3 Meter Reading Costs 9.3.3.1 Background At present, the meters for most Residential and General Service < 50 kW customers are read manually. The frequency of meter readings may vary by rate classification and by distributor. It is the...
AI summary The document discusses the allocation of meter reading costs, noting that manual readings are more expensive for customers spread out, while electronic readings for larger users are less costly. A weighted factor approach is used to allocate these costs fairly across rate classifications.
9.3.3.2 Direction – Allocation of Meter Reading Costs Default "relationship factors" related to meter reading costs are provided for use when allocating meter reading costs. Details are set out in Appendix 9.3. The cost to read a residenti...
AI summary The document outlines a method for allocating meter reading costs using relationship factors based on a residential urban outside meter as a base. Distributors must input data on installed meters and apply relationship factors to determine relative costs for each rate classification. Flexibility is allowed for up to five additional meter types if their reading costs differ by at least 10% from defaults.
9.3.4.1 Background The installed costs of overhead and underground service drops are included in Account 1855. These costs are customer related and it is appropriate to allocate the costs associated with these services (e.g. depreciation,...
AI summary The document discusses the allocation of costs for overhead and underground service drops, which are included in Account 1855. These costs are customer-related and should be allocated based on the weighted number of customers or connections, with some stakeholders noting that certain rate classifications may have zero costs due to distributor demarcation policies.
9.3.4.2 Direction - Allocation of Services Costs The weighted number of customers or connections will be used to allocate costs related to Services (Account 1855). It is intended that the weightings reflect the differing average costs of c...
AI summary The weighted number of customers or connections is used to allocate costs related to Services (Account 1855), with default weighting factors provided in Appendix 9.4. Distributors must use specific weighting factors if their actual costs differ by 10% or more from defaults and provide supporting information. The Filing Summary must indicate if there are no costs in Account 1855 and explain the reason.
10. Allocation of Other Costs Directions on how to allocate "other" costs in the cost allocation filings are presented in this Chapter. Generally these are costs that are neither customer nor demand-related.
AI summary This section outlines the directions for allocating 'other' costs in cost allocation filings, which are typically not customer or demand-related.
10.1 Introduction Some components of the revenue requirement cannot be directly allocated, or allocated to customer rate classifications by using the functionalization, categorization and allocation process described earlier. Instead other...
AI summary The document discusses methods for allocating revenue requirements when direct allocation is not feasible, including pro rata allocation and detailed analyses. It lists various expenses and capital expenditures that fall into this category, such as administrative expenses, working capital allowance, and conservation costs.
10.2.2 Direction – Allocation of General Plant General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets (average of opening and closing balances for the test year), with no adjustment for con...
AI summary General Plant should be allocated on a pro rata basis using a composite of distribution net fixed assets, with no adjustment for contributed capital. Distributors with detailed analysis must use this information in cost allocation models and provide supporting documentation.
10.3.2 Direction – Allocation of A & G Except for property insurance and community safety program costs, a pro rata allocation of O&M with backing out of A&G will be the common methodology for allocating general expenses. For property insu...
AI summary The document outlines a pro rata allocation methodology for general expenses, excluding property insurance and community safety programs, which are allocated based on distribution net fixed assets. Contributed capital is handled separately as outlined in Chapter 6.
10.6.1 Background Bad debt expense consists of the amounts of uncollectible revenues. Many distributors monitor their bad debt write-offs at the rate classification level. The Accounting Procedures Handbook (Article 220) requires distribut...
AI summary The document discusses the allocation of bad debt expenses to customer rate classifications, recommending a method based on historical write-offs. It notes lack of stakeholder consensus and addresses concerns about normalization periods and fairness. The Board supports the staff's recommendation for cost allocation purposes.
10.6.2 Direction – Allocation of Bad Debt Expense Bad debt expense must be directly allocated to specific customer rate classifications based on their respective contribution to historical write-offs. For historical test year filers, an av...
AI summary The document outlines the allocation of bad debt expense to specific customer rate classifications based on historical write-offs. It specifies the use of average bad debt data from 2002–2004 for historical test year filers and 2003–2005 for future test year filers, excluding extraordinary bad debt. Pro rata allocation is recommended for new rate classifications without historical data.
10.7.1 Background Late payment charges (Account #4225) include the amounts of discounts forfeited or additional charges imposed because of the failure of customers to pay their electricity bills on or before a specified date. Collection ex...
AI summary Late payment charges and collection expenses are discussed in terms of their allocation based on rate classifications. A stakeholder suggested a common approach for both costs, but further data is needed. The allocator for collection expenses is the weighted number of bills, except for embedded distributors. Late payment charges should be allocated based on the three-year average of revenues by rate classification.
10.7.3 Filing Question To determine whether a similar cost allocation treatment of collection expenses and late payment charge revenues is feasible in the future, distributors should indicate whether the records are available to break out...
AI summary The proceeding discusses whether a similar cost allocation treatment of collection expenses and late payment charge revenues is feasible in the future, requiring distributors to indicate if records are available to break out collection costs by rate classification.
gas DSM hearing (EB-2006-0021), it was agreed by all participants that costs should be allocated on the same basis as budgeted spending. This allocation would apply to both direct and indirect costs. Several stakeholders commented on the A...
AI summary The document discusses the allocation of CDM costs in the gas DSM hearing, with stakeholders proposing different methods based on energy use, distribution revenue, and the Global Adjustment Mechanism. Some support the August proposal, while others argue for an 80/20 energy/demand allocation. The Board concludes to maintain the electricity sector status quo for cost allocation.
10.8.2 Direction – Allocation of Conservation and Demand Management Costs For cost allocation purposes, CDM costs must be allocated as follows: - 1. Direct CDM program operating expenses must be allocated to the participant customer classi...
AI summary The document outlines the allocation of Conservation and Demand Management (CDM) costs, specifying that direct program expenses are allocated to participant customer classifications, while indirect and capital costs are distributed proportionally based on composite operating and maintenance costs.
11. Cost Allocation and Unit Cost Calculations for Specialized Rate Classifications Directions on cost allocation and unit cost calculations for the following specialized rate classifications are presented in this Chapter. - Embedded distr...
AI summary This section outlines the directions for cost allocation and unit cost calculations for specialized rate classifications, including embedded distributor, density, seasonal, unmetered scattered loads, and load displacement generation.
11.1.2 Direction – Cost Allocation and Unit Cost Methodology for Embedded Distributor Classification The cost allocation methodology approved elsewhere in this Report must be applied when allocating costs to this rate classification. The s...
AI summary The text outlines the cost allocation methodology for embedded distributor classifications, requiring the use of a two-part customer unit cost calculation. It emphasizes proper account sub-division and references Chapter 6 for subfunctionalization methods. Alternative methodologies are permitted in Run 3 but must be justified and consistent with sound cost allocation practices.
11.2.1 Background It should be recognized that the average density for some currently-approved rate classifications varies significantly. In some cases, "urban" customers have been defined based on an average customer density higher than 6...
AI summary The document discusses the impact of customer density on cost allocation for rate classifications, noting that urban and suburban classifications have different customer densities. It outlines that density is a direct cost driver but may not be linear, and provides guidelines for cost allocation for distributors with approved density-based rate classifications.
11.2.2 Direction – Cost Allocation Methodology for Density- Based Classifications A distributor with density-based rate classifications is expected to be able to use the standard model in Run 1 and Run 2, but work must be undertaken to add...
AI summary The document outlines a standardized cost allocation methodology for distributors with density-based rate classifications. It requires the use of a single categorization factor, identification of density-influenced costs, and the application of density factors in cost allocation, with detailed analysis required for maintaining classifications.
11.3.1 Background The standard cost allocation methodology will apply to any seasonal rate classification as no unique cost allocation issues were identified. There are few distributors with such separate rates currently in place. Adding a...
AI summary The document outlines the standard cost allocation methodology for seasonal rate classifications, noting that no unique cost allocation issues were identified. It emphasizes the need for full supporting data when considering changes to seasonal rates and highlights potential rate impacts from using a single NCP for demand-related cost allocation.
11.3.2 Direction – Cost Allocation Methodology for Seasonal Rate Classification[2](#page-89-1)3 Run 1 and Run 2 of the model must apply the cost allocation and customer unit cost methodology approved in this Report. Distributors wishing to...
AI summary The document outlines the cost allocation methodology for seasonal rate classification, requiring distributors to apply approved methods in Run 1 and Run 2 of the model. Run 3 requires justification for using 12 NCP based on the distribution system's cost characteristics.
11.4 Unmetered Scattered Loads ("USL") In the past, there had been variability in the treatment of unmetered scattered loads across the Province. The present filings are intended to lead to a common cost allocation approach for these custo...
AI summary The document discusses the need for a consistent cost allocation approach for unmetered scattered loads (USL) across the Province, with the same methodology applying to the Farm Rate classification.
11.4.1.2 Direction – Cost Allocation Methodology where Separate USL Rate Classification The cost allocation methodology approved in this Report for all rate classifications must also be applied to this rate classification, subject to any s...
AI summary This section outlines the cost allocation methodology approved in the report, which must be applied to all rate classifications, including this specific rate classification, with any special rules provided below.
Distribution and General Plant Unmetered Scattered Load customers will bear the full allocated costs of distribution facilities (and associated depreciation), with the exclusion of Load Management Controls – Customer Premises (Account 1970...
AI summary Unmetered Scattered Load customers are responsible for the full allocated costs of distribution facilities, excluding Load Management Controls and Meters. Test meters installed on USL as part of a verification program must have their costs allocated to USL.
11.4.2.1 Background The approach below is expected to apply to most distributors in Run 1, including all those whose 2006 USL charges were effectively based on the special rate calculation reached during the 2006 EDR process.[24](#page-91-...
AI summary The text outlines an approach for modeling USL rates for distributors in Run 1, noting that demand costs will be treated as related to the GS<50 kW rate classification. It also discusses the potential implementation of a metering credit and the need to collect revenue from other customers to maintain the distributor's revenue requirement.
11.4.2.2 Direction – Unit Cost for USL Metering Credit The following methodology must be used to determine the metering credit for USL customers in Run 1. The first step is to identify the following items in the cost allocation model. - a)...
AI summary This section outlines the methodology for calculating the metering credit for USL customers in Run 1, specifying the cost allocation model items to consider. It also notes that billing costs will not be included in the filing requirements as they are already reflected in the standard classification.
11.4.3.1 Background Run 2 of the filings will provide the Board with information on costs for USL as a separate rate classification. Once costs have been allocated to this potential rate classification, the question remains whether it is p...
AI summary Run 2 of the filings provides the Board with information on costs for USL as a separate rate classification. The filings will produce standard customer unit cost outputs for this classification, raising the question of whether unit costs should be determined on a per customer or per connection basis.
11.4.3.2 Direction – Modeling Unit Costs Where USL a Separate Rate Classification The cost allocation filing model will calculate a standard two-part unit cost output for USL.
AI summary The cost allocation filing model is designed to calculate a standard two-part unit cost output specifically for USL, treating it as a separate rate classification.
11.5.1 Introduction At present, a number of distributors have approved interim standby rates. In some cases, there is an additional approved administrative charge. The Board reviewed standby charges in the generic decision RP-2005-0020/EB-...
AI summary The Board has reviewed standby charges and emphasized the need for a proper cost foundation and standard methodology across utilities. Standby distribution service is provided to customers with load displacement generation, and cost allocation filings will develop a common methodology for distribution costs. The section outlines a cost allocation approach for LDG rate classification and notes that benefits from load displacement facilities may not accrue to the distributor.
11.5.2.2 Direction - Calculation of total load for LDG classification In the cost allocation filings, the load associated with a LDG customer will be the full measured load of the customer, which includes the load when the load displacemen...
AI summary The document discusses how the total load for LDG (Load Displacement Generation) customers should be calculated for cost allocation purposes. It specifies that the full measured load, including both the load when the generator is running and the standby load, should be considered. Some stakeholders argue that the measured load does not fully capture the distribution system's requirements, leading to a suggestion for an optional Run 3 to adjust the load calculation.
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.
11.5.4.1 Background There have been discussions with stakeholders as to what might be the appropriate threshold at which a customer with load displacement facilities would be defined as a LDG customer for capturing in Run 2 of the cost all...
AI summary Discussions with stakeholders are ongoing to determine the appropriate threshold for defining a customer with load displacement facilities as a LDG customer in Run 2 of the cost allocation modeling. Some stakeholders suggest aligning this threshold with the net-metering threshold of 500 kW.
11.5.4.2 Direction – LDG Rate Classification Threshold For the purpose of modeling the costs to be allocated to the separate LDG rate classification in Run 2, a customer will not be considered to be part of that separate rate classificatio...
AI summary This section outlines the criteria for classifying customers under the LDG rate classification, specifying that a customer must have standby distribution service requirements greater than 500 kW. It also provides steps for separating costs and revenues associated with LDG customers and guidelines for estimating standby requirements when detailed information is not available.
11.5.5.2 Direction – Cost Allocation Methodology Where LDG Rates Modeled as Separate Rate Classification The same cost allocation methodology approved for use with other rate classifications must be applied to this classification (for exam...
AI summary The cost allocation methodology approved for other rate classifications must also be applied to LDG customers. The default load data method is required for Run 2, with an alternative available for Run 3. Distributors must document estimates and address diversity issues. A two-part distribution charge will be generated for all rate classifications, including LDG.
12. Unit Cost Outputs The cost allocation filings will gather customer unit cost information to assist with future discussions on the following rate design areas: - a) Review of the range of monthly customer service charges. - b) Review of...
AI summary This section outlines how cost allocation filings will gather customer unit cost information to support future discussions on rate design areas, including monthly customer service charges and transformer ownership allowance alternatives.
Option 1: Avoided Costs With a strict "avoided cost" approach, only meter related costs, billing and collection costs would be included. This approach has the advantage of focusing on the immediate costs of an additional customer. But no a...
AI summary Option 1, the 'avoided cost' approach, includes only meter, billing, and collection costs, focusing on immediate customer costs but excluding administrative overhead. A stakeholder suggested using this approach to strengthen conservation price signals, while the Board emphasizes that the filings aim to provide comprehensive information for future rate design decisions.
Option 2: Directly Related Customer Costs In this approach, additional costs viewed as directly related to the customer would be included, namely operations performed at the customers' premises. An example would be a disconnect and a recon...
AI summary Option 2 includes directly related customer costs such as disconnect and reconnect operations, with revenue from related services credited back to cost centres. Administration and general overhead are also allocated. This approach is commonly used and will be incorporated into the filing model.
12.2.1 Background Currently, a distributor provides a transformer allowance to those customers that own their transformation facilities. With a few exceptions, the present level of transformer ownership allowance is $0.60 per kW. The amoun...
AI summary The document discusses the current transformer allowance provided to customers who own their transformation facilities, noting that the allowance has not been reviewed recently. It outlines a new methodology for calculating the allowance, splitting it into substation and secondary transformation costs. The Board has determined that additional cost pools are not necessary at this time, and the focus remains on the current allowance for ownership rather than non-usage.
12.2.2 Direction – Updated Unit Cost and Cost Pools Information For the purpose of determining updated unit costs, the starting point will be the standard unit costs that include all costs associated with transformation. The new transforma...
AI summary The document outlines a direction for updating unit costs and cost pools, focusing on transformation ownership allowance calculations and data collection for four specific cost pools by rate classification.
The following outlines the resulting numbers of customers using the various asset groupings, for Example 3: Class Bulk Primary Secondary 1855 Services 1860 Meters 1565 Conservation and Demand Management Expenditures and Recoveries 5065 Met...
AI summary The text presents a table outlining various customer classes and associated costs, including meter expenses, maintenance, billing, and infrastructure-related expenditures, categorized under different asset groupings such as primary and secondary networks.
Filing Question: Load Displacement Customers - Further Potential Distribution Cost Savings or Burdens When completing Run 1 and Run 2 of the filing, all distributors with load displacement customers should review the below list to ascertai...
AI summary The filing question addresses potential distribution cost savings or burdens associated with load displacement customers. It outlines cost reductions and potential burdens, such as deferred asset commissioning, reduced line losses, and increased system flexibility, as well as unknown impacts like voltage stability concerns.
Avoided costs plus administration and general expenses associated with the above direct operation, maintenance, billing and collection costs as well as a proportion of general plant assigned to meter assets.
AI summary The text discusses the avoidance of costs related to direct operation, maintenance, billing, and collection, as well as a proportion of general plant assigned to meter assets, including administration and general expenses.
Proposal - Primary Conductors and Poles Cost Pools Calculation - a) Depreciation on sub-account 1830-4 Poles, Towers and Fixtures Primary - b) Depreciation on sub-account 1835-4 Overhead Conductors and Devices – Primary - c) Depreciation o...
AI summary The proposal outlines the calculation of cost pools for primary conductors and poles, including depreciation, operation and maintenance expenses, rental payments, and allocated general plant and administrative expenses associated with overhead and underground distribution lines and feeders.
N-92Compliance Filing - Standardized Filings - Redacted
63 passages
REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 2 Page 1 of 100 NOVA SCOTIA POWER INC. 2026 COST OF SERVICE STUDY ANALYSIS REFERENCE GUIDE EXHIBIT
AI summary This document is a 2026 Cost of Service Study Analysis Reference Guide from Nova Scotia Power Inc., part of a compliance filing for the GRA (likely the Greenhouse Gas Reduction Act) and includes an exhibit. It outlines the structure and content of the study.
OTIA POWER INC. 2026 COST OF SERVICE STUDY ANALYSIS REFERENCE GUIDE EXHIBIT
AI summary The document is a reference guide for the 2026 Cost of Service Study Analysis by OTIA Power Inc., providing information related to the cost of service study conducted for the year 2026.
(1) RETAIL FUNCTION (2) (3) DISTRIBUTION PLANT: (4) SERVICES 0 0 0 0 (5) METERS 0 0 0 0 (6) TOTAL RETAIL PLANT 0 0 0 0 (7) (8) GENERAL PROPERTY PLANT 42,983 0 0 42,983 (9) TOTAL PLANT IN SERVICE 42,983 0 0 42,983 (10) (11) Working Capital...
AI summary The text presents a financial summary of the retail function, including distribution plant, general property plant, working capital, and deferred charges. It lists various line items such as cash, materials and supplies, and deferred charges, along with their respective values. The total retail function is reported as $206,880, with a total average rate base of $5,563,003.
DEMAND CUSTOMER DEMAND CUSTOMER (1) FACTORS 1.000 0.165 0.471 0.122 0.242 (2) TOTAL NET WIRE COST $399,387 $65,894 $188,116 $48,657 $96,720 (3) FACTORS bfr Adjustment 1.000 0.150 0.486 0.110 0.254 (4) ADJUSTMENT before Zero Cap Restriction...
AI summary The text presents financial data related to demand and customer factors, including net wire costs and adjustments before and after a zero cap restriction. It includes an allocation of average pole investment for Nova Scotia Power Inc. for the year ending December 31, 2026.
ACK OFFICE - (16) (17) TOTAL FINANCE 7,350 5,000 640 1,416 106 189 (18) (19) ENTERPRISE SERVICES (20) PROCUREMENT & FACILITIES 12,284 2,996 2,996 2,996 2,996 298 F - 5 (21) INFORMATION TECHNOLOGY 46,049 19,238 5,324 12,901 7,473 1,114 F -...
AI summary The document presents a financial summary with various expense categories, including procurement, information technology, human resources, and other expenses, along with totals for different divisions and periods. It includes figures for advocacy expenses and deferrals related to FCR.
- - - - 0.0% 0.0% 0.0% 0.0% (14) CORPORATE CONTROLLER 3,433 2,555 246 577 55 0.6% 0.2% 0.2% 0.1% (15) CORP. PERFORMANCE & BACK OFFICE - - - - - 0.0% 0.0% 0.0% 0.0% (16) (17) TOTAL FINANCE 7,161 5,000 640 1,416 106 1.2% 0.5% 0.4% 0.2% (18)...
AI summary The text presents a table of financial figures, including various departments and their associated costs, with percentages and totals provided for different categories. The data reflects corporate and divisional expenses, including procurement, information technology, human resources, and other expenses, with a focus on cost distribution and percentages.
% 0.6% 0.6% 2.0% (29) (30) TOTAL DIVISIONAL EXPENSES bfr Advocacy Expense 310,044 148,543 36,078 84,449 40,974 34.3% 26.4% 25.6% 68.6% (31) (32) TOTAL DIVISIONAL EXPENSES 311,881 149,910 36,210 84,758 41,003 34.6% 26.5% 25.7% 68.7% (33) (3...
AI summary The text presents a detailed breakdown of divisional expenses, including advocacy expenses, COGS, DSM expenses, FCR deferral, and other expenses. It includes figures for different years and percentages, with some categories showing significant changes over time.
1) EHV and HV STORM EXPENSES 1 8
AI summary The text references expenses related to EHV and HV storm events, indicating a focus on costs associated with high-voltage infrastructure damage due to storms.
(11) THERMAL - OPERATING & MAINT. 59,047.2 57,510 0 0 0 1,538 (12) HYDRO - OPERATING & MAINT. 1,879.3 1,830 0 0 0 49 (13) WIND - OPERATING & MAINT. 8,364.9 8,147 0 0 0 218 (14) WIND - OPERATING & MAINT. 130.2 0 0 0 0 130 (15) BIOMASS - OPE...
AI summary The text presents a table of operating and maintenance costs for various energy generation sources, including thermal, hydro, wind, biomass, and combustion turbines, along with related categories such as energy, fuels, and risk management. It also includes a subtotal for total production operating and maintenance costs.
62,852 23,683 46,485 5,138 3,616 (78) PREFERRED DIVIDENDS 0 0 0 0 0 0 (79) CORPORATE TAXES -10,608 -4,703 -1,772 -3,478 -384 -271 (80) (81) TOTAL EXPENSES $1,706,121 $1,254,384 $102,973 $263,937 $52,435 $32,392 (82) (83) NON-OPERATING REVE...
AI summary The text presents financial figures related to preferred dividends, corporate taxes, and non-operating revenue items such as late payment charges, connection charges, and others. These figures are likely part of a financial statement or expense report.
0 0 6,250.7 (17) INTEREST NET OF AFUDC 5,138 0 0 5,137.9 (18) (19) PREFERRED DIVIDENDS 0 0 0 - (20) CORPORATE TAXES -384 0 0 (384.4) (21) Non-Operating Revenue: (22) LATE PAYMENT CHARGE (5,743.1) 0 0 (5,743.1) (23) CONNECTION CHARGES AND M...
AI summary The text presents a financial summary, including interest, preferred dividends, corporate taxes, and various non-operating revenues and expenses. It includes line items such as late payment charges, connection charges, and retail sales. The total retail revenue and total net expenses are also listed.
0 0 0 0 0 0 0 0 0 0 0 P-14 (23) CORPORATE TAXES -1,862 -1,196 -61 -331 -38 -34 -44 -68 -56 -26 -9 P-14 (24) Non-Operating Revenue: (25) STEAM AND ASH SALES -1,293 -830 -43 -231 -26 -24 -30 -47 -39 -18 -6 O-8 (26) OTHER REVENUE -868 -557 -2...
AI summary The text presents a financial summary with various line items including corporate taxes, non-operating revenue from steam and ash sales, and other revenue. It also includes return (profit/loss), interrider demand adjustment, allocation of interrider demand adjustment, ELI 2P-RTP demand adjustment, and allocation of ELI 2P-RTP demand adjustment with associated figures and codes.
9,862 6,741 374 1,943 119 217 243 104 0 28 92 P-9 (22) DEPRECIATION 67,915 46,426 2,575 13,378 822 1,497 1,671 718 0 195 633 EXH 6D (23) INTEREST NET OF AFUDC 26,243 17,929 995 5,167 319 578 646 279 0 76 255 P-16 (24) PREFERRED DIVIDENDS 0...
AI summary The text presents a series of financial figures and categories, including depreciation, interest, corporate taxes, non-operating revenue, and return on operations, with associated line items and references to pages and exhibits.
$3,350 $411 $526 $294 $695 $118 $173 $855 (26) (27) Total $1,825,306.187 $1,086,335 $65,943 $337,765 $45,582 $38,117 $56,905 $72,635 $81,353 $18,768 $21,903 (28) (29) Costs by Functional Areas (relative shares) (30) Generation 73% 67% 69%...
AI summary The document presents a detailed breakdown of costs across various functional areas, including generation, transmission, distribution, and retail, along with average customer cost calculations. It provides data on distribution and retail costs before non-operating credit adjustments for different periods.
. (Customer) 54 0 2 5 2 9 9 240 $36.218 (16) Total Distribution 12,908 0 366 1,241 454 2,061 2,061 $3.212 - $36.218 (17) Total Transmission/Distribution $32,253 $0 $1,092 $2,596 $1,134 $4,822 $4,822 $7.534 - $36.218 (18) kW.h Sold 358,568...
AI summary The text presents a series of financial figures and costs related to distribution, transmission, and customer-related activities, including total distribution, transmission/distribution costs, unit costs, and marketing expenses. These figures are likely part of a regulatory proceeding analyzing cost structures and financial performance.
RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2026 CLASS : SMALL INDUSTRIAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Ener...
AI summary This document provides a rate class disaggregation analysis for the Small Industrial class for the year ending December 31, 2026. It details the rate base, variable and fixed costs, and unit costs associated with generation, including energy and reliability components.
COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL INDUSTRIAL INDUSTRIAL PHP MUNICIPAL UNMETERED FACTOR (1) POLE&WIRE INV.-DMD. $230,632 $155,449 $8,604 $45,159 $4,056 $5,035 $5,960 $3,284 $0 $964 $2,119 (2) % RESPONSIBILITY 100.00% 67.40%...
AI summary The text presents a table with various cost categories and percentages of responsibility across different customer classes, including Domestic, General, Large, Industrial, Municipal, and Unmetered. The table includes line items such as Pole&Wire Investment - Demand and Customer, Substation, Pole&Wire - Demand and Customer, and associated percentages of responsibility for each category.
DEVELOPMENT OF ALLOCATION FACTORS FOR THE YEAR ENDING DECEMBER 31, 2026 (1) (2) (3) (4) (5) (6) (7) TOTAL PROD. TRANS. DIST. RETAIL DIRECT EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES ALLOCATOR (1) LABOUR O&M excluding HR, IT, PR,...
AI summary The document outlines the development of allocation factors for the year ending December 31, 2026, detailing total expenses, revenue requirement before corporate groups, and net plant in service, along with their respective percentages of responsibility across various categories such as production, transmission, distribution, and retail.
% -0.09% 7.82% 2.43% 4.22% REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 2 Page 88 of 100 EXHIBIT 10 NOVA SCOTIA POWER INC. REVENUE TO EXPENSE COMPARISON FOR THE YEAR ENDING DECEMBE...
AI summary The document presents a revenue to expense comparison for Nova Scotia Power Inc. for the year ending December 31, 2026, showing a variance of -0.8% in total operating expenses compared to the CA IR-001 standard.
(10) Regulatory Amortization (677,610) (677,610) Regulatory Amort. 100.0% K322 (11) Fuel Expense (1,808,772) (1,729,291) ML - NS Block (BCF COSS) 100.0% B8..M8 and B35..M37 (12) FAM Deferral Interest 328,135 343,365 Interest & Other Exp 10...
AI summary The text provides a summary of various financial and regulatory expenses, including regulatory amortization, fuel expense, FAM deferral interest, AMI opt-out charges, and income tax. It outlines figures related to operating expenses and the rate base, indicating financial performance and regulatory considerations.
Line # AVERAGE RATE BASE RATE BASE RATE BASE 2025 2026 (78) WORKING CAPITAL & DEFERRED CHARGES (79) (80) WORKING CAPITAL - CASH FUEL 0 0 0 (81) WORKING CAPITAL - CASH OTHER 162,574 Source: 2014 COSS 187,621 137,527 (82) WORKING CAPITAL - M...
AI summary The text provides a breakdown of working capital and deferred charges for 2025 and 2026, including cash fuel, material and supply fuel, and deferred charges related to financing, tax, and pensions. It includes figures and sources for some line items.
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.
COTIA POWER INC. 2027 COST OF SERVICE STUDY ANALYSIS REFERENCE GUIDE EXHIBIT
AI summary The document is a reference guide for the 2027 Cost of Service Study Analysis by COTIA Power Inc., providing information related to cost of service studies and associated regulatory proceedings.
36,737 0 0 0 0 0 36,737 (44) Working Capital & Deferred (45) Charges/Credits: (46) CASH - FUEL 0 0 0 0 0 0 0 0 0 (47) CASH - OTHER 0 0 126,109 0 0 0 0 0 126,109 (48) MAT. & SUPPLIES - FUEL 0 0 0 0 0 0 0 0 0 (49) MAT. & SUPPLIES - OTHER 0 0...
AI summary The document presents a financial table outlining working capital and deferred charges/credits, including categories such as cash, materials and supplies, and deferred charges related to financing, tax, and pensions. The table includes subtotals and totals for the retail function and average rate base.
SUPPLIES - FUEL 0 0 0 0 0 0 0 0 0 0 0 P-9 (47) MAT. & SUPPLIES - OTHER 15,961 11,086 608 3,034 185 346 349 161 0 44 148 P-9 (48) DEF. CHG. - Financing 4,395 3,052 167 835 51 95 96 44 0 12 41 P-9 (49) DEF. CHG. - Tax 5,309 3,687 202 1,009 6...
AI summary The document presents a detailed breakdown of supply and financing-related costs across multiple categories, including fuel, materials, and various deferred charges such as tax, pension, and others, with specific figures for different periods and categories.
139 - 139 (16) BIOMASS - OPERATING & MAINT. 6,831 6,580 - - - 251 (17) LM6000 OPERATING & MAINT. 656 632 - - - 24 (18) COMBUSTION TURBINE - OPER. & MAINT. 1,728 1,664 - - - 64 (19) FUEL PROCUREMENT 6,858 6,605 - - - 252 (20) GENERATION DEV...
AI summary The text presents a table with various operational and maintenance costs related to biomass, combustion turbines, fuel procurement, and power production, along with corporate and legal expenses. It includes figures for different categories and subcategories, with some entries showing cost differences between periods.
AIL DIRECT ALLOCATION EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES FACTOR
AI summary The text presents a table with headings related to allocation and expenses, including categories such as 'DIRECT', 'EXPENSES', and 'FACTOR'. The content is highly technical and appears to be related to financial or operational allocation mechanisms.
(1) REGULATORY AFFAIRS (2) Advocacy Expense 1,861 1,345 156 334 26 0.3% 0.1% 0.1% 0.0% (3) Other Expenses 7,305 5,280 612 1,310 104 1.2% 0.4% 0.4% 0.2% (4) Subtotal 9,166 6,625 767 1,643 130 1.5% 0.5% 0.5% 0.2% (5) (6) FINANCE GROUP (7) IN...
AI summary The text provides a detailed breakdown of expenses under the Regulatory Affairs and Finance Group categories, including Advocacy Expense, Internal Audit, Investor Relations, and others, with comparisons across different time periods and percentages of total costs.
0.2% 0.2% 0.1% (15) CORP. PERFORMANCE & BACK OFFICE - - - - - 0.0% 0.0% 0.0% 0.0% (16) (17) TOTAL FINANCE 7,284 4,927 752 1,511 95 1.1% 0.5% 0.4% 0.2% (18) (19) ENTERPRISE SERVICES (20) PROCUREMENT & FACILITIES 12,233 3,058 3,058 3,058 3,0...
AI summary The text presents a detailed breakdown of various financial and operational expenses, including corporate performance, enterprise services, human resources, and other expenses, with percentages and figures indicating allocations and changes over time.
EREST NET 154,226 64,106 29,258 51,096 4,136 5,630 (78) PREFERRED DIVIDENDS 0 0 0 0 0 0 (79) CORPORATE TAXES 10,114 4,204 1,919 3,351 271 369 (80) (81) TOTAL EXPENSES $1,765,210 $1,226,710 $117,864 $281,294 $52,682 $86,660 (82) (83) NON-OP...
AI summary The text presents financial data including net earnings, preferred dividends, corporate taxes, and total expenses. It also includes non-operating revenue items such as late payment charges, connection charges, NSF fees, and others. These figures provide insight into the financial operations and revenue streams of the entity.
THERMAL O&M D&E SPLIT $151,867 (36) (37) THERMAL O&M DMD. ALLOC. % 48.19% (38) THERMAL O&M ENG. ALLOC. % 51.81% (39) (40) BIOMASS DEMAND ALLOC % 48.19% (41) (42) BIOMASS ENERGY ALLOC % 51.81% (43) (44) NRIS ERIS (45) WIND O&M DMD. ALLOC. %...
AI summary The text presents a breakdown of operational and maintenance costs allocated between demand and energy for various thermal, biomass, and wind assets, as well as pole and wire allocations. It also includes general property allocations across different voltage levels and customer segments, with totals provided.
0 0 0 0 0 0 0 E-1A (15) OPER. & MAINT. - RADIAL TO GENERATION TRANS. 1,388 730 50 304 49 36 58 94 41 17 11 E-1A (16) DSM 0 See DSM Allocation (17) FCR DEFERRAL 0 0 0 0 0 0 0 0 0 0 0 P-17 (18) REG. AFFAIRS - ADVOCACY EXPENSE 697 339 55 272...
AI summary The text presents a financial summary with various line items including operational and maintenance costs, demand-side management (DSM), fuel cost recovery deferral, regulatory affairs expenses, grants in lieu, depreciation, interest net of AFUDC, and preferred dividends. These figures are organized by category and year, with some entries referencing additional documentation.
$380 $508 $211 $642 $69 $163 $843 (26) (27) Total $1,837,796 $1,136,731 $69,475 $340,440 $45,772 $39,062 $53,522 $72,591 $37,780 $19,652 $22,771 (28) (29) Costs by Functional Areas (relative shares) (30) Generation 71% 66% 68% 80% 87% 79%...
AI summary The text presents financial data, including costs by functional areas and average customer costs. It details distribution and retail costs before non-operating credit, along with percentages of total costs attributed to generation, transmission, distribution, and retail.
RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : GENERAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Custom...
AI summary This document presents a rate class disaggregation analysis for the year ending December 31, 2027, focusing on the General rate class. It details various costs, including fuel, operating, capital, return, and total costs, along with units sold, demand, and energy metrics for generation, reliability, and total generation.
RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : LARGE GENERAL RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy...
AI summary This document presents a rate class disaggregation analysis for the Large General rate class as of December 31, 2027, detailing various costs and units sold related to generation, including energy and demand components.
RATE CLASS DISAGGREGATION ANALYSIS FOR THE YEAR ENDING DECEMBER 31, 2027 CLASS : PHP RATE BASE COSTS (Source Exh 6) (Source Exh. 3) Variable Fixed Unit Cost Fuel Operating Capital Return Total Total Cost Units Sold Demand Energy Customer G...
AI summary This document presents a rate class disaggregation analysis for the PHP rate class ending December 31, 2027. It details the rate base, variable and fixed costs, unit costs, and energy and demand metrics for generation, including MWh sales, energy requirements, and kW demand.
$25 $40 $1,690 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 55 of 102 EXHIBIT 6B NOVA SCOTIA POWER INC. ALLOCATION OF CUSTOMER SERVICE FIELD EXPENSES FOR THE YEAR ENDING DEC...
AI summary The document presents an allocation of customer service field expenses for Nova Scotia Power Inc. for the year ending December 31, 2027, categorized into different customer segments such as domestic, small general, and large industrial, with expenses broken down into meter reading and wiring inspection costs.
0 (10) UNMETERED 487 0 487 (11) TOTAL $10,009 $2,373 $7,636 ALLOCATION FACTOR C-6 C-8 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 56 of 102 EXHIBIT 6C NOVA SCOTIA POWER INC...
AI summary The document presents an allocation of credit services expenses for Nova Scotia Power Inc. for the year ending December 31, 2027, with detailed breakdowns of bad debt expenses across different customer categories.
BILITY 100.00% 64.36% 3.42% 17.72% 2.02% 1.86% 2.13% 3.63% 3.00% 1.38% 0.48% O-8 (33) TOT. EXP. - DMD. ( TRANS. HV) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 (34) % RESPONSIBILITY 100.00% 65.00% 3.46% 17.95% 2.04% 1.88% 2.15% 3.66% 1.98% 1.40% 0.48...
AI summary The text presents a table of percentages and dollar amounts related to expenses and responsibilities across various categories, including transmission and distribution, with references to specific line items and percentages. The data appears to be part of a regulatory proceeding involving cost allocation and responsibility distribution.
D. TRANS. DIST. RETAIL DIRECT EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES ALLOCATOR (1) LABOUR O&M excluding HR, IT, PR, OTHER and direct 201,262 87,649 22,398 57,115 34,100 - (2) % RESPONSIBILITY 100.00% 43.55% 11.13% 28.38% 16....
AI summary The document presents a detailed breakdown of various expense categories, including labour, revenue requirement, and insurance premiums, with percentages of responsibility allocated across different segments. It includes figures related to net plant in service and compliance reporting, along with footnotes for reference.
EMENT 1,727.8 -149 (103) (104) CORPORATE INSURANCE 10,029.1 (105) CORPORATE SECRETARY 1,792.5 (106) CORPORATE SECRETARY & INSURANCE 11,821.6 (107) (108) LEGAL SERVICES 5,177 (109) (110) VP EXTERNAL RELATIONS (111) COMM. & PUBLIC AFFAIRS 1,...
AI summary The document presents a detailed listing of input information for Nova Scotia Power Inc.'s Cost of Service Study (C.O.S.S.) for the year ending December 31, 2027, including various corporate and operational line items.
15,013.7 (138) TOTAL CORPORATE GROUPS 68,025.74 (139) (140) TOTAL LABOUR RELATED 242,597.10 244,779.2 -2,182.1 (141) TRANSMISSION CONTROL CENTER 3,619.3 (142) GENERATION, TRANSMISSION AND DISTRIBUTION (143) TRANSMISSION BEFORE STORM EXPENS...
AI summary The text presents a detailed breakdown of various expenses related to corporate groups, labor, transmission, distribution, and customer service. It includes figures for storm-related expenses, line costs, and customer service expenditures, along with percentages and comparisons.
- (176) BAD DEBT EXPENSE 5,012.9 17.5% 7,503,950 (177) Total 15,047.3 52.6% 22,524,963 Customer Service Total 28,604.7 28,604.7 100.0% 42,819,524 (178) 0 REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing...
AI summary The document presents a detailed listing of the Cost of Service Study (C.O.S.S.) input information for Nova Scotia Power Inc. for the year ending December 31, 2027, including line items such as bad debt expense and total customer service costs.
8,847 $7,602,473 (186) Environmental Services 2,623.4 2023 $418,234 $348,956 $2,871,700 $3,638,890 (187) Project Implementation 1,082.7 2024 $1,360,838 $1,492,826 $10,572,909 $13,426,574 (188) EAM 8,631.4 Total $3,894,405 $4,119,914 $31,46...
AI summary The text presents a financial table with figures related to various departments and programs, including Environmental Services, Project Implementation, and EAM, along with budget and cost data spanning multiple years and categories.
0.0 61 61 61 0 (249) LM6000 7,371.9 0.0 7,372 7,372 7,394 -22 (250) GAS TURBINE - OTHER 3,238.8 0.0 3,239 3,239 3,057 182 (251) TOTAL GENERATION 91,131.6 0.0 91,131.6 0.0 91,131.6 87,310.2 3,821.4 (252) (253) ECEI BATTERIES 8,877.2 8,877 (...
AI summary The text presents a detailed listing of input information from a Cost of Service Study (C.O.S.S.) for Nova Scotia Power Inc. for the year ending December 31, 2027, including various line items related to generation and assets.
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.
NS ALLOCATOR - MEDIUM INDUST. 2.9% 3.00% (312) CUSTOMER SOLUTIONS ALLOCATOR - LARGE INDUST. 4.6% 2.00% (313) CUSTOMER SOLUTIONS ALLOCATOR - PHP 0.0% 0.00% (314) CUSTOMER SOLUTIONS ALLOCATOR - MUNICIPAL 0.3% 2.00% (315) CUSTOMER SOLUTIONS A...
AI summary The text presents allocation percentages and unit meter costs for various customer segments and services, including residential, small general, and general categories, as part of a cost-of-service study (COSS) for the year 2023.
129.17 113.00 (333) Small General 146.15 111.72 (334) General 565.62 392.00 (335) Large General 1,811.88 692.00 (336) Small Industrial 589.45 196.84 (337) Medium Industrial 1,611.77 692.00 (338) Large Industrial 1,891.93 1,106.00 (339) PHP...
AI summary The document presents a detailed listing of input information from the Cost of Service Study (C.O.S.S.) for Nova Scotia Power Inc. for the year ending December 31, 2027, with various categories and associated dollar amounts.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 96 of 102 NOVA SCOTIA POWER INC. DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSA...
AI summary The document is a detailed listing of input information from Nova Scotia Power Inc.'s Cost of Service Study (C.O.S.S.) for the year ending December 31, 2027, presented in thousands of dollars.
REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 97 of 102 NOVA SCOTIA POWER INC. DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSA...
AI summary This document is a detailed listing of input information for Nova Scotia Power Inc.'s Cost of Service Study for the year ending December 31, 2027. It is part of a confidential compliance filing related to the 2026-2027 GRA (likely a regulatory or compliance acronym).
S - DEMAND 0.4819 (580) BIOMASS - ENERGY 0.5181 (581) (582) Bad Debt Direct Cost Allocator (Domestic) 0.84 (583) REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 3 Page 98 of 102 NOVA...
AI summary The document provides a detailed listing of input information for the Cost of Service Study (C.O.S.S.) for Nova Scotia Power Inc. for the year ending December 31, 2027, including allocation factor information and calendar month of system peak data.
50,433 54,239 49,133 55,684 48,648 54,408 45,826 61,953 50,562 63,643.9 (43) CLASS NON-COINCIDENT DMD. - INDUSTRIAL LARGE 92,014 92,756 86,801 88,913 92,902 97,263 97,187 103,959 102,722 99,058 101,792 92,640 103,959.2 (44) CLASS NON-COINC...
AI summary The text provides a detailed listing of input information for the Cost of Service Study (C.O.S.S.) for Nova Scotia Power Inc. for the year ending December 31, 2027, including allocation factor information and various demand class data.
100 of 102 NOVA SCOTIA POWER INC. DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) ALLOCATION FACTOR INFORMATION
AI summary The document provides a detailed listing of input information for the Cost of Service Study (C.O.S.S.) for Nova Scotia Power Inc. for the year ending December 31, 2027, focusing on allocation factor information.
0 0 0 0 0 0 0 0 0 0 0 0 - REQUIREMENTS - EBS/RTR 68,626 78,686 77,113 60,680 52,282 59,439 55,407 53,083 54,246 60,079 60,501 68,303 215,615.6 (113) REQUIREMENTS - EXPORT SALES 0 0 0 0 0 0 0 0 0 0 0 0 - (114) INTERRUPTIBLE COINCIDENT DEMAN...
AI summary The document presents a detailed listing of Cost of Service Study (C.O.S.S.) input information for Nova Scotia Power Inc. for the year ending December 31, 2027, including various financial figures and allocation factors.
33 34 35 36 37 38 39 40 41 42 43 44 Line # Base Cost of Fuel Cost of Service Allocation of Fuel Expenses among Rate Classes 1 2 FOR THE YEAR ENDING DECEMBER 31, 2026 3 4 COLUMN A B C D E F G H I J K L M N O P Q R S T U V W X Y Z AA AB AC A...
AI summary This section presents a table outlining the allocation of fuel expenses among different rate classes for the year ending December 31, 2026. It includes various columns labeled with terms such as 'Base Cost of Fuel,' 'Cost of Service,' and 'Allocation of Fuel Expenses,' suggesting a detailed breakdown of financial data related to fuel costs.
11 Cost Allocation Factors Fuel-related C o s t s f r o m C O S Fuel Costs used for FAM purposes FAM Cost Classification V A R I A N C E FROM CA IR-001 Purchased Power other than Biomass and 12 3 CP Demands Energy Requirement Purchased Pow...
AI summary The text discusses fuel-related costs from the Cost of Service Study (C.O.S.S.) and their classification in the Financial Accounting Manual (FAM), highlighting variances from CA IR-001. It includes categories such as purchased power, biomass, wind, and other energy requirements.
45.3% 100.0% 54.7% 45.3% 100.0% 54.7% 45.3% 100.0% 54.7% 45.3% 100.0% 30 Non-FAM Rate Classes 31 BUTU 100.00% 32 GRLF 100.00% 33 1P - RTP 100.00% 34 ELIADC 100.00% 35 Shore Power EBS /RSS 37 Total Below-the-line 178,670 0.3% 159,281,443 0....
AI summary The text presents a table with percentages and financial figures related to rate classes and cost data. It includes entries such as 'Non-FAM Rate Classes' and 'Total Below-the-line' with associated monetary values and percentages, indicating a focus on financial and regulatory accounting details.
r EBS Total 48,967 56,214 55,044 43,191 38,004 49,486 40,310 41,744 41,957 46,470 46,776 50,842 156,023 48,967 NSR Peak: 2,413,470 2,353,879 2,067,656 1,743,372 1,484,308 1,376,186 1,433,351 1,444,266 1,383,409 1,535,612 1,913,044 2,188,59...
AI summary The text presents a table with data on energy costs and peak demand, including total figures, marginal costs, and incremental costs across different years. It includes values such as total, NSR Peak, Marginal Cost, and Incremental Cost for various years.
11 Cost Allocation Factors Fuel-related C o s t s f r o m C O S Fuel Costs used for FAM purposes FAM Cost Classification V A R I A N C E FROM CA IR-001 Purchased Power other than Biomass and 12 3 CP Demands Energy Requirement Purchased Pow...
AI summary The text discusses fuel-related costs from the Cost of Service Study (C.O.S.S.) and their classification in the Financial Accounting Manual (FAM), highlighting variances from CA IR-001. It includes categories such as purchased power, biomass, wind, and other energy requirements.
Cost Amount Unit Cost (cents per kWh) before BUTU Capacity BUTU Capacity Credit Demand- Energy- Total Fuel-related costs (CA IR-001) Variance % Var 13 Relative Shares of Relative Shares of
AI summary The text presents a table with cost data, including unit costs per kWh, before BUTU Capacity and BUTU Capacity Credit, as well as demand and energy costs. It also references a variance and percentage variance, possibly related to cost analysis or regulatory proceedings.
costs (CA IR-001) Variance % Var 13 Relative Shares of Relative Shares of Imports (allocated on Basic and Supplemental Blocks ERIS NRIS Credit, Export Revenues, (Allocated demand- OM&G costs Demand-related Energy-related Total related rela...
AI summary The text presents a table with cost-related data, including variance percentages, embedded costs, fuel costs, and energy-related and demand-related costs, categorized by rate class and other factors. It appears to be a detailed financial breakdown from a regulatory proceeding.
15 $7,564,672 $30,871,211 $13,394 $0 $0 $0 $30,884,605 $32,279,658 3.7% $32,117,707 9.013 $7,514,672 $23,369,933 $30,884,605 2.109 6.558 8.667 $30,948,722 -$64,117 -0.2% 18 General Demand 104.71% 1,195,401 17.629% 2,335,071,503 21.85% 2,16...
AI summary The text presents financial data and figures related to various categories, including demand, large general, and other unspecified categories, with percentages, monetary values, and other metrics. The data appears to be part of a regulatory proceeding involving cost analysis and financial reporting.
Export Revenues $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $0 OM&G (Solid Fuel Handling) recovered in fuels $0 Foreign Exchange (Fuel-related) $0 ML - NS Block per Appliation $16,990,030 $16,990,030 $16,990,030 $16,990,030 $16,990,030 $16,990...
AI summary The text presents financial data related to export revenues, OM&G costs, foreign exchange, and adjustments for the NS Block under various decisions. It includes figures for total FAM related costs and costs with OATT customers over multiple years.