Topic:"Capacity Costs" in M12451

The minimum period for which this service is available from the Transmission Provider is one day. 2026 Delivery Period Charge ($) Yearly: One twelfth of $10,910.36 /MW of Reserved Capacity per year Monthly $909.20 /MW of Reserved Capacity...

AI summary The text outlines the minimum service period for a transmission service, which is one day, and provides a table of charges for reserved capacity across different delivery periods in 2026 and 2027.

int Tupper, Trenton and Tufts Cove Generating Stations, Tufts Cove Combined Cycle Plant and NS Power's Combustion Turbine Fleet. REDACTED Appendix 7A – OM&G Costs by Group Figure 7A-3: Power Production 2024 Actuals vs. 2025 Budget ($ Milli...

AI summary The document outlines the forecasted increase in operating and maintenance (OM&G) costs for power production in Nova Scotia, including factors such as increased contract expenses at Tufts Cove, regulatory requirements, and environmental costs. It also notes cost reductions due to the transfer of certain expenses to other categories, with forecasts for 2025, 2026, and 2027.

(in Thousands of $) 2024 Compliance 2026 Forecast vs 2024 2026 Forecast vs 2024 2026 Forecast vs 2025 2027 Forecast vs 2026 Information Technology Overview 50 642 2026 Forecast vs. 52 494 2027 Forecast vs. 46 048 2026 Forecast vs. 40 493 2...

AI summary The document outlines changes in Information Technology costs from 2024 to 2027, highlighting increases in labour, contracts, and subscription/software expenses, as well as decreases in consulting costs. Factors include cyber security initiatives, technology upgrades, and cloud-based service transitions.

Power Production Forecast Forecast Actual Compliance Restated

AI summary The table presents forecast and actual data for Power Production under the Forecast column, with Compliance Restated as a category. The data appears to be related to financial or operational planning.

Biomass (in Thousands of $) > Materials decrease due to reduced unit shutdown requirements. (252) > Contracts decrease due to reduced unit shutdown requirements. (91) > Other variances (30) ın ı housand IS OF 3 2024 2026 Forecast 2026 Fore...

AI summary The text presents a table detailing financial variances and forecasts related to biomass, including changes in materials and contracts due to reduced unit shutdown requirements, along with various labour and expense categories across different years and budgets.

Transmission & Distribution Contractor Management 2024 Compliance 2026 Forecast vs 2024 2026 Forecast vs 2024 2026 Forecast vs 2025 2027 Forecast vs 2026 2026 Forecast vs. 2024 Compliance Restat d (Thousands of $) Contracts increase due to...

AI summary The text presents a table outlining changes in contractor management costs for Transmission & Distribution in 2024 and forecasts for 2026 and 2027. Key factors include increased maintenance on aging vehicles, inflation, and reclassification of expenses, with some offsets from staff reductions and reorganization.

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.

) (5,991,808) (606,102) (20) (121,220) (6,113,028) (35,156,805) (17) PORT HAWKESBURY BIOMASS (179,498,344) (3) (5,108,660) (32,674,687) (20) (6,534,937) (11,643,597) (212,173,030) (5) INTERNATIONAL COAL PIER (11,479,941) (172) (19,746,485)...

AI summary The text presents financial figures related to various energy production facilities, including Port Hawkesbury Biomass, International Coal Pier, and the Total Steam Production Plant, with details on costs, revenues, and other financial metrics.

STEAM PRODUCTION PLANT LINGAN 2049 48,429,000 79,452,908 55,118,780 (407,345,807) (14) POINT ACONI 2029 32,123,000 35,466,388 26,435,832 (546,201,297) (5) POINT TUPPER 2048 30,354,000 48,822,504 29,922,697 (149,864,128) (20) TRENTON 2029 3...

AI summary The document presents data on various steam production plants in Nova Scotia, including their names, years, and associated financial figures. It includes information on costs, revenues, and other financial metrics for each plant.

cription Estimated Cost July 2024 Assumptions / Notes: Code 500's ELECTRICAL: 50&51 ON SITE DISTRIBUTION LINES REMOVALS 72,907 56 ELECTRICAL POWER SYSTEMS REMOVAL 127,587 57 OTHER AUXILIARY SYSTEMS AND EQUIPMENT REMOVALS 58 ELECTRICAL CONT...

AI summary The text lists various cost estimates for different categories of removal and decommissioning activities, including electrical systems, water systems, building ventilation, and administrative expenses, with specific figures provided for each item.

Item Description Assumptions / Notes: Code 12 SITE REMEDIATION ISSUES $ 7,000,625 13 SITE ACCESS REMOVALS $ 240,491 15 SITE SERVICES REMOVALS $ 196,680 200's BUILDINGS AND STRUCTURES: 21 POWERHOUSE AND AUXILIARY STRUCTURES REMOVALS $ 10,43...

AI summary The text outlines various costs associated with site remediation, building removals, and decommissioning activities, including specific figures for different categories such as powerhouse removals, coal handling plant decommissioning, and ash handling plant decommissioning.

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.

Item Description Estimated Cost: July 2024 Assumptions/ Notes: Coda 100's SITE REMEDIATION ISSUES: Factor for Up-dating from July 2020 to July 2024: = 1.23 12 SITE REMEDIATION ISSUES $ 590,624 13 SITE ACCESS REMOVALS $ - 15 SITE SERVICES R...

AI summary The text outlines estimated costs for various site remediation and decommissioning activities at a power plant, including site services removals, powerhouse and auxiliary structures removals, and coal handling plant decommissioning, with an inflation factor applied to update costs from July 2020 to July 2024.

ription Estimated Cost July 2024 Assumptions/ Notes:2024 Code 100'8 SITE REMEDIATION ISSUES: 12 SITE REMEDIATION ISSUES $ 2,376,850 13 SITE ACCESS REMOVALS $ - 15 SITE SERVICES REMOVALS $ - 200's BUILDINGS AND STRUCTURES: 21 POWERHOUSE AND...

AI summary The text outlines estimated costs for site remediation and removal of structures and buildings associated with a power plant, including costs for site remediation, powerhouse removal, coal handling plant removal, and auxiliary buildings. Some items have no estimated cost.

Estimated Cost July 2024 Assumptions/ Notes: Code 100's SITE REMEDIATION ISSUES: 12 SITE REMEDIATION ISSUES $ 2,818,600 13 SITE ACCESS REMOVALS $ 15 SITE SERVICES REMOVALS $ 200's BUILDINGS AND STRUCTURES: 21 POWERHOUSE AND AUXILIARY STRUC...

AI summary The document outlines estimated costs for various remediation and removal activities related to a site and associated infrastructure, including site remediation, building removals, and boiler and auxiliary system decommissioning. Specific line items include costs for powerhouse removals, coal handling plant decommissioning, and ash handling plant decommissioning.

134 Wharves and Mooring Facilities 108,855 15 SITE SERVICES REMOVALS 223,235 150 Site Services 153 Raw Water Supply 23,695 capping and removal of water line at main line 154 Sewage Systems 23,695 same trench as water line removal 155 Storm...

AI summary The text provides a detailed breakdown of costs associated with various site services and infrastructure removals at the Lingan Generating site, including raw water supply, sewage systems, storm water drainage, retaining walls, lighting, and sediment control. The document is part of a cost estimate and includes a file path and page reference.

359 Natural Gas Systems (Station Gas, Unit Gas and Propane Fuel Gas) 36 BOILER STEAM AND WATER SYSTEMS REMOVALS 464,780 360 General 363 Boiler Vents, Drains and Slowdown System 72,907 364 High Pressure Steam System (Main Steam, Hot & Cold...

AI summary The text outlines the removal costs associated with various systems related to boiler steam and water systems, as well as ash and water treatment systems. Specific systems and their removal costs are listed, including a new sewage treatment plant added since 2002.

July 2024 15 SITE SERVICES REMOVALS 191,212 150 Site Services 153 Raw Water Supply 36,453 154 Sewage Systems 36,453 155 Storm Water and Floor Drainage Systems 36,453 156 Retaining Walls, ,Fences, Gates, Railways 18,227 157 Miscellaneous Im...

AI summary The document provides a detailed breakdown of costs associated with site services removals and building structures removals, including raw water supply, sewage systems, storm water systems, retaining walls, lighting, and sediment control, as well as powerhouse and auxiliary structures removals.

47,896 For Tidal work& Sediment & Erosion Contol 23 COAL HANDLING PLANT - REMOVE TO 1 METER BELOW GRADE 345,503 230 Waste Water / Effluent Treatment System 23,695 231 Dumper House Facilities (incl. Coal Unloading Facilities and Primary Con...

AI summary The text outlines various costs associated with coal handling plant removal and related infrastructure, including wastewater treatment, conveyors, stackers, and temporary facilities, with a total estimated cost of approximately $47,896 for tidal work and sediment erosion control.

- •-:�:.. COST STUDY ?n?A LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description Assumptions/ Notes:2024 Code July 2024 24 ASH HANDLING PLANT DECOMMISSIONING 136,700 240 General 241 Disposal System...

AI summary The text provides a cost study for the decommissioning of the ash handling plant at the Point Aconi Generating Station, with an estimated cost of $136,700 for ash silo demolition and related activities.

7,291 348 Steam Measurement 35 FUEL HANDLING SYSTEMS REMOVALS 244,920 350 General 351 Station Fuel Oil System 352 Unit Fuel Oil System 353 Unit Coal Handling 182,267 removal of coal bunkers during powerhouse demolition 354 Station Coal Han...

AI summary The text outlines various fuel handling systems and their associated removal costs, including coal handling, fuel oil systems, and limestone handling, with specific figures provided for each category. It also mentions the removal of coal bunkers during powerhouse demolition and the shared costs with the coal system.

359 Natural Gas Systems (Station Gas, Unit Gas and Propane Fuel Gas) 36 BOILER STEAM AND WATER SYSTEMS REMOVALS 205,961 360 General 363 Boiler Vents, Drains and Slowdown System 47,389 364 High Pressure Steam System (Main Steam, Hot & Cold...

AI summary The text provides a breakdown of costs related to the removal of boiler steam and water systems, as well as ash and water treatment systems. It includes various sub-systems and their associated costs, such as chemical feed systems, reserve feedwater systems, and waste water treatment systems.

Controls - General 36,453 441 Turbine Generator Automatic Run-up and Loading (when separate) 9,113 (j Stantec \\ca0213 ppfss01\work_group\1214\active\121418266\05_report_deliverable\draft_doc\Revised_Draft\Site2_2024 Estimate-Point Aconi G...

AI summary The document contains a cost study estimate for the Point Aconi Generating Station, including details on turbine generator automatic run-up and loading costs. The text includes a file path and a redacted page reference from a 2026-2027 GRA Direct Evidence Appendix.

2026-2027 GRA Direct Evidence Appendix 8D Page 74 of 189 SITEni= - lnNINr.l ESTIMATE - IEET FOR Fl""A"''"' A.I ·- - •-:�:.. COST STUDY ?n?A LOCATION: POINT ACONI GENERATING STATION DATE: 1-Jul-24 Account Estimated Cost: Item Description As...

AI summary This document provides an estimate for the removal of water systems at the Point Aconi Generating Station, with a cost of $127,810 as of July 2024.

g c11.1ANl":IA1 ni:::pgi:::r:14TION COST STUDY ?n?A LOCATION: TUFT'S COVE THERMAL GENERATING STATION DATE: Jul-24 Account Item Description Assumptions/ Notes:2024 Code Removal and Disposal of Materials and Residues 3,490,191 Costs associat...

AI summary The document outlines the costs associated with the removal and disposal of materials and residues at the Tuft's Cove Thermal Generating Station, noting an increase in costs compared to the 2020 estimate due to the decommissioning of a large HFO tank and an applied inflation factor.

estimate. Costs carried for ongoing fence assessments/maintenance. Assume $50,000 fence maintenance costs. \\ca0213-ppfss01\Yt'Ork_group\1214\active\121418266\05_report_deliverable\draft_doc\Revised_Draft\Site5_2024 Estimate-Tufts Cove Gen...

AI summary The text discusses an estimate for fence maintenance costs at Tufts Cove Generating Station, assuming $50,000 for ongoing fence assessments and maintenance. It references a cost study related to the site and includes a file path and page number from a document.

21,771 15 SITE SERVICES REMOVALS 455,499 150 Site Services 153 Raw Water Supply 154,927 removal and capping water lines 154 Sewage Systems 54,680 removal and capping sewer lines 155 Storm Water and Floor Drainage Systems 54,680 removal of...

AI summary The text outlines the costs associated with the removal of various site services and structures, including water lines, sewer lines, drainage systems, retaining walls, and lighting, as well as the removal of powerhouse and auxiliary structures.

145,140 Due to extent of dismanUing work 42 CONDENSING PLANT AND CIRCULATING WATER SYSTEM REMOVALS 60,148 420 General 421 Condensers and Auxiliaries 29,163 422 Circulating Water System (Screens, Pumps, Piping and Valves) 21,872 426 Seawate...

AI summary The text outlines costs related to the removal of condensing plants and circulating water systems at Tufts Cove Generating Station, including breakdowns for condensers, auxiliaries, and seawater treatment systems. It references a document titled 'Site5_2024 Estimate-Tufts Cove Generating Station - R1 .xlsx' and appears to be part of a confidential submission in a regulatory proceeding.

734 District Heating I Cooling System 75 COMPRESSED GAS SERVICES REMOVAL (EXCLUDING FUEL GAS) 45,567 750 General 751 Plant Service Air System 9,113 752 Nitrogen System 9,113 753 Hydrogen System (when separate from Turbine/Generator Contrac...

AI summary The document outlines costs associated with the removal of compressed gas services and plant operating equipment, including specific line items such as plant service air systems, nitrogen systems, and environmental monitoring equipment, with detailed cost allocations.

ription Assumptions/ Notes:2024 Code S00's GENERAL AND ADMINISTRATION: 82 FIELD FACILITIES AND DECOMMISSIONING 144,048 825 Demolition Contractor Facilities 48,099 827 Decommissioning Costs 18,227 828 Demolition of all exterior buildings 77...

AI summary The document outlines various costs related to field facilities, administration expenses, and drawings. It includes specific line items such as demolition contractor facilities, decommissioning costs, and administration expenses, with detailed breakdowns of costs associated with different activities and departments.

LOCATION: BURNSIDE GENERATING STATION (COMBUSTION TURBINE) DATE: July 2024 Estimated Account Item Description Cost: July Assumptions / Notes:2024 Code 2024 23 COAL HANDLING PLANT - REMOVE TO 1 METER BELOW GRADE does not apply to this site...

AI summary The document outlines the estimated costs for the decommissioning and removal of coal handling and ash handling plant components at the Burnsides Generating Station as of July 2024. It lists various account codes and associated items, noting that certain costs do not apply to the site.

2 903 22 CIRCULATING WATER - REMOVE TO 1 METER BELOW GRADE 39188 220 General 14 514 221 Intake Structure (Source to Pumphouse and Restore Shore Line) 2 903 222 Pumphouse (includina Intake Structure if lntearal) 2 903 223 Intake and Dischar...

AI summary The document contains cost estimates for various construction and infrastructure projects, including intake structures, pumphouses, and outfall structures. It also references a redacted appendix from a proceeding related to 2026-2027 GRA Direct Evidence.

2026-2027 GRA Direct Evidence Appendix 8D Page 116 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 an estimate of costs related to the removal of boiler instruments and controls, as well as fuel handling systems, for the Tufts Cove LM6000 Units (2) Plus WHR Boiler and Steam Turbine Generator project as of July 2024.

87 084 NSPI involvement 856 Environmental Engineering Cost - Salaries and Expenses 900'5 SCHEDULES AND GENERAL DRAWINGS: 90 DRAWINGS 21 771 900 Final Site General Arrangement Drawing 21,771 ()stantec \\ca0213-ppfss01\v...ork_group\1214\act...

AI summary The text contains a portion of a cost study related to the Tuskett Generating Station, including a redacted section and a reference to a location and cost study for a combustion turbine facility.

OST STUDY ?n?.t LOCATION: TUSKET GENERATING STATION (COMBUSTION TURBINE) DATE: 7/15/224 Account Estimated Cost: July Item Description Assumptions/ Notes: 2024 Code 2024 23 COAL HANDLING PLANT· REMOVE TO 1 METER BELOW GRADE does not apply t...

AI summary The text outlines the estimated costs and details for the decommissioning of the coal handling and ash handling plants at the Tusket Generating Station, including specific items and assumptions related to the process.

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 129 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 an estimate of costs associated with site services removals at the Victoria Junction Generating Station, a combustion turbine facility, as of July 2020. The cost for this action is estimated at $38,639 for the year 2024.

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.

2026-2027 GRA Direct Evidence Appendix 8D Page 133 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 related to the removal of feedwater heating systems at the Victoria Junction Generating Station, including specific system components and an assumption that this does not apply to the site.

2026-2027 GRA Direct Evidence Appendix 8D Page 134 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 an estimate for the removal of auxiliary systems and equipment at the Victoria Junction Generating Station, including lighting, grounding, cable tray and conduit, control cable systems, and power cable systems, with assumptions and notes for the year 2024.

July 2024 23 COAL HANDLING PLANT. REMOVE TO 1 METER BELOW GRADE 332,835 230 Waste Water / Effluent Treatment System 7,925 mosUy sch 40 PVC pipe 231 Coal Pile Distribution Facilities (incl. Coal Unloading Facilities and Primary Conveyors) 1...

AI summary The text details the costs associated with the decommissioning of coal handling and ash handling plants, including removal of structures, conveyors, and disposal systems. It outlines various components and their associated costs, such as waste water treatment systems, coal pile distribution facilities, and temporary coal handling plants.

RAILCAR MAINTENANCE CENTRE DATE: DATE: 30-Jul-24 Account Estimated Cost: Estimated Cost: Item Description Assumptions / Notes: 2024 Code July 2020 July 2024 23 COAL HANDLING PLANT. REMOVE TO 1 METER BELOW GRADE N/A 230 Waste Water / Efflue...

AI summary The document outlines the estimated costs for decommissioning and removal activities at a railcar maintenance centre, specifically focusing on the coal handling plant and ash handling plant. It includes various account codes and descriptions related to the decommissioning process.

Estimated Cost 2024 Action Account Item Description Assumptions / Notes: By Code 2024 13 SITE ACCESS REMOVALS 130 General 131 Access Roads and Road Bridaes Assumed v.111 be abandoned in Place 132 Access Railwavs and Railwav Bridaes n/a 133...

AI summary The text outlines estimated costs for site access and service removals in 2024, including details on various infrastructure elements such as access roads, railways, airports, and wharves, with some assumptions noted.

removal turbine foundations (1.0m below grade- main core only) 396,000 $15k/unit- demolition to one (1) meter below finished grade-foundation center core= 6.35 m dia x 1.1m high incl rebar

AI summary The text outlines the cost and specifications for the removal of turbine foundations, including the depth of removal, dimensions of the foundation core, and associated costs.

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.

CONFIDENTIAL - 1 is calculated as the weighted average capacity factor (weighted by net plant) of the three Tufts - 2 Cove units. - 3 The current and proposed classification of the Tufts Cove units is summarized in the following

AI summary The text discusses the calculation of a weighted average capacity factor for the Tufts Cove units, as well as their current and proposed classification.

CONFIDENTIAL 8. Services on same basis as Meters Exh 3i Column G New column added in Meter tab to allocate services on same basis as meters Exh 3a D39:M39 Replace allocated rate base with allocations from Exh 3i. This indirectly impacts th...

AI summary The text outlines various adjustments and classifications related to rate base allocations, service basis, and capacity factors in a regulatory proceeding. Changes include adding columns, replacing weighting factors, and updating classifications for Steam and SLF generation based on capacity factors.

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.

2022-2024 GRA SR-01 Attachment 1e Page 18 of 32 COSS CA DR-53 Attachment 1 Page 48 of 62 1 Service. The NS Power grid has integrated a significant amount of variable generation, mostly in 2 the form of wind, which is not usually centrally...

AI summary The text discusses the NS Power grid's integration of variable generation, particularly wind, and the ancillary services required to balance load and generation fluctuations. It outlines the need for specific generation capacities (32 MW for 5-minute fluctuations and 176 MW for hour-to-hour changes) and details the operating reserves required (spinning, 10-minute, and 30-minute reserves). The revenue requirements for these services are calculated based on quantity and cost per unit.

PARTIALLY CONFIDENTIAL 2026-2027 GRA Direct Evidence Appendix 12A(2) Page 851 of 1218 REDACTED (CONFIDENTIAL INFORMATION REMOVED) 2022-2024 GRA SR-01 Attachment 1e Page 31 of 32 COSS CA DR-53 Attachment 1 Page 61 of 62 Nova Scotia Power Op...

AI summary The document discusses changes in NS Power's transmission costs and operational factors from 2014 to 2024, including increased investment in transmission assets, changes in depreciation rates, and the impact of wind generation on ancillary services. Operating costs have decreased, but the overall system usage has increased, affecting OATT service rates.

Approach - NS Power examined 11 CP Methods - 3 winter month methods: 3CP_JFD, 4CP_JFMD and 5CP_JFMND - 8 unconstrained methods: 1CP, 2CP, 3CP, 4CP, 5CP, 10CP, 20CP and 88CP using two alternate hourly system load datasets to determine hours...

AI summary NS Power evaluated 11 capacity planning (CP) methods, including winter month and unconstrained methods, using two system load datasets (NSR and ANL) over a 7-year period from 2016 to 2022 to determine system peak hours and class contributions to these peaks.

COSS IG DR-2 Attachment 1 Page 4 of 4 Capacity Factor Jan-24 Feb-24 Mar-24 Apr-24 May-24 Jun-24 Jul-24 Aug-24 Sep-24 Oct-24 Nov-24 Dec-24 To Date New CT's (450 MW) 4% 5% 2% 5% 5% 9% 6% 6% 10% 4% 3% 4% 5% Total CTs Hydro Wind Tidal Biomass...

AI summary The table presents capacity factors for various energy sources and the New CT's (450 MW) from January to December 2024. It shows fluctuating capacity factors for the New CT's, with values ranging from 2% to 10% across the months.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to IG Data Requests 1 change by an order of magnitude which makes them transition from one type of generation 2 to another, such as from peak load to intermediate load generation...

AI summary The text discusses changes in generation unit classifications based on capacity factors, which can lead to reclassification of costs from demand to energy or vice versa. For example, a peaking unit with a low capacity factor may transition to intermediate load generation, affecting cost classification.

NON-CONFIDENTIAL 1 Request DR-9: 2 3 Based on Figure 5, explain whether the benchmark used for the current interruptible credit 4 - the cost of a combustion turbine (CT) peaking unit - aligns with NSPI's planned capacity 5 additions as per...

AI summary The response to Request DR-9 explains that the benchmark for the interruptible credit, based on the cost of a combustion turbine peaking unit, aligns with NSPI's planned capacity additions as outlined in the 10-year system outlook and Evergreen IRP. It also notes that renewable capacity contributions should not be compared directly to combustion turbine capacity.

1 Request DR-11: 2 (a) Please compare the planning assumptions used in the evaluation of each capacity addition, including how many hours on average each year that each capacity addition is forecast to be in use to meet supply requirements...

AI summary The request asks for a comparison of planning assumptions for capacity additions, including their annual energy supply contribution, and how these assumptions align with the terms and conditions of the Interruptible credit, which allows for up to 1,314 hours of interruption per year.

16 Average System Fossil Fuel Fleet Purchased Power, Cost Top peak demand Demand Generation Cost hours (no PHP) [MW] [$/MWh] [$/MWh] 50 2153 $85.7 $185.9 100 2067 $81.1 $159.7 1000 1768 $74.3 $83.4 PARTIALLY CONFIDENTIAL 2026-2027 GRA Dire...

AI summary The table presents average system demand, fossil fuel fleet generation costs, and purchased power costs at different peak demand levels. It includes data points for 50, 100, and 1000 peak hours, showing variations in demand and costs.

Cost of Service Study Process (NSUARB M11475) NSPI Responses to PHP Data Requests 1 Request DR-23: 2 3 Reference: Verbal request from David MacDougall during July 16, 2024 Modelling Session. 4 5 Provide calculation of capacity factors. 6 7...

AI summary NSPI provided a response to a data request (DR-23) regarding the calculation of capacity factors, referencing Attachment 1. The document includes a partially confidential appendix from the 2026-2027 GRA Direct Evidence, with some pages redacted.

COSS SBA DR-6 Attachment 1 Page 4 of 24 171050 LT DIT ASSET LIABILITY FAM 172050 LT DERIV ASSET HFT 172350 LT DERIV ASSET HFT TREASURY 173050 DEFERRED PENSION RETIREE BENEFIT 180050 LT REG ASSET UNAMORT DEFEASANCE COSTS 180450 LT REG ASSET...

AI summary The document presents a list of long-term assets and liabilities, including deferred pension benefits, regulatory deferrals, and various financial instruments, as part of a regulatory proceeding related to cost of capital and other studies.

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).

Classification / Allocation Methods - Generation costs present conceptual challenges - How to separate capacity related from demand related capital (there is no single, valid method) - > Generation assets provide both capacity and energy -...

AI summary The document discusses the conceptual challenges in classifying and allocating generation, transmission, and distribution costs. It highlights that generation costs are difficult to separate into capacity and demand-related components, while transmission is primarily capacity-related and distribution poses definitional challenges. Customer costs are largely based on customer-related allocations.

Generation Classification Methodologies (2) - Peak Demand Methods (five methods identified) - Single Coincident Peak (1-CP) - Summer and Winter Peak (Average of 3 CPs in each season) - ➤ Sum of 12 Monthly Coincident Peaks (12-CP) - ➤ Multi...

AI summary The document outlines various peak demand methods for generation classification, including Single Coincident Peak, Summer and Winter Peak, and Sum of 12 Monthly Coincident Peaks. It emphasizes that generation is built to meet capacity requirements driven by demand, not energy requirements.

COS Generic Hearing (M05473) - Deferred Projects No Project Status 1 &2 Capacity contribution of ERIS and NRIS wind Consistent with Board's directive the COS treatment in BCF and GRA proceedings aligned with NSPI's planning assumption base...

AI summary The document discusses deferred projects under the COS Generic Hearing (M05473), including the capacity contribution of wind projects, treatment of Lingan Units 1 & 2 as base load units, a survey of the distribution system, and class load data collection and analysis. These projects are aligned with planning assumptions and regulatory proceedings.

Capacity value is a key concept for both resource planning and for functionalizing generation costs - In COSS, as the average capacity value of resources on the system decreases, costs are shifted from demand to energy - In resource planni...

AI summary Capacity value is crucial for resource planning and generation cost allocation. Lower average capacity values shift costs from demand to energy, influenced by factors like climate change, gas availability, and interactions between renewable and storage technologies.

Equivalent peaker method will become increasingly challenging - Not currently used in Nova Scotia, but the concept of valuing capacity at the cost of a peaker unit is widely applied - Equivalent peaker method values capacity at the cost of...

AI summary The equivalent peaker method, which values capacity based on the cost of a natural gas peaking plant, is not currently used in Nova Scotia but is widely applied elsewhere. California uses battery storage costs for similar purposes, though it is more complex due to additional services provided by batteries.

Theory: Build Capacity to Peak Demand → Reliability - Resource planning targets a planning reserve margin at a target level of reliability - Allocation of capacity costs to demand is based on coincident peak

AI summary The theory discusses building capacity to meet peak demand for reliability, with resource planning targeting a reserve margin and allocating capacity costs based on coincident peak demand.

Theory: Build Capacity to Peak Demand → Reliability - Resource planning targets a planning reserve margin at a target level of reliability - Allocation of capacity costs to demand is based on coincident peak

AI summary The theory of building capacity to meet peak demand focuses on ensuring reliability through planning reserve margins and allocating capacity costs based on coincident peak demand levels.

Cost-causation for "demand-related" costs includes non-demand elements - Excess fossil generator capacity should be retired as quickly as replacement built in present circumstances (avoiding fixed O&M costs) - Transmission system built to...

AI summary The text discusses the inclusion of non-demand elements in the cost-causation for 'demand-related' costs, suggesting that excess fossil generator capacity should be retired promptly and that transmission systems should be built to address supply-related contingencies.

B. Generation (Capacity or Demand) Costs The POD and HCM method use substantially different methods for allocating the generation revenue requirement. The POD method allocates these costs equally to each MWh generated, although exactly how...

AI summary The document compares the POD and HCM methods for allocating generation revenue requirements, noting that the POD method equally distributes costs per MWh while the HCM method focuses on high-load hours. An s-shaped cost allocation curve is suggested for better representation of grid stress and time-varying rate design.

Issue 1 Generation Issue 1 a - Should the use of System Load Factor (SLF) to allocate generation investment costs between demand and energy continue to be used? Are there alternatives to the use of the 3CP allocation factor? Can AMI data b...

AI summary The SBA proposes replacing the System Load Factor (SLF) with a peaker methodology for allocating generation investment costs, emphasizing reliability, energy cost minimization, and clean energy contributions. They also suggest classifying transmission facilities based on function rather than using SLF, with some classified as generation or energy investments.

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.

Standby Service Tariff Standby Service is a supplemental generation capacity service provided to LRS. The service has two components: - o Capacity Adequacy Service fulfillment of the LRS's obligation to provide or pay for its share of firm...

AI summary Standby Service is a supplemental generation capacity service provided to LRS, consisting of Capacity Adequacy Service, which fulfills the LRS's obligation to provide or pay for its share of firm capacity required to meet adequacy standards of the Nova Scotia electricity system during forced and unforced generation outages.

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.

10a. Classify Steam Generation by Capacity Factor Instead of SLF - ➢ Capacity Factor = Average Hourly Generation / Peak Generation - ➢ Purpose: Analyse the impact of allocating steam generation by the weighted average capacity factor inste...

AI summary This section discusses the proposal to classify steam generation based on capacity factor rather than SLF (Steam Load Factor). It explains that the weighted average capacity factor is lower than SLF, leading to a reallocation of costs from energy to demand, with lower load factor classes bearing more costs.

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.

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.

5.2.1.2 NSP PROPOSED APPROACH - NS Power is proposing to change the classification of transmission costs from the system - load factor to 100% demand. Classifying transmission costs by the system load factor is - not consistent with cost c...

AI summary NS Power proposes classifying transmission costs based on 100% demand rather than system load factor, arguing that this aligns with cost causality principles and practices of other Canadian utilities, as transmission costs are driven by peak demand rather than energy delivered.

- 8 system requires sufficient substation and transformer capacity at peak demands, so the - 9 costs are caused by capacity constraints. - 10 Services and meters are classified 100% as customer because the costs vary by the - 11 number and...

AI summary The text discusses the classification of costs in a distribution system, noting that costs caused by capacity constraints are not customer-related, while costs related to serving customers under minimal demand conditions are considered customer-related.

4.1.4 Deration Factor For each of the units, a Deration Factor will be assigned to recognize the times that the unit is not at its maximum capability. The following are considered for each plant: - Seasonal cooling water temperature fluctu...

AI summary A Deration Factor is assigned to each unit to account for times when the unit is not operating at maximum capability. Factors include seasonal temperature fluctuations, coal conditions, and economic coal blends. These factors are recommended by NS Power operations and engineering personnel and must be approved by NS Power's management.

Plant Performance Ca aci ty Fac tor p Q1 Q2 Q3 Q4 An al nu Ac l tua Ye ar Bu dg et Pri or Ye ar Pla nt Lin Un it 1 g an Lin Un it 2 g an Lin it 3 Un g an Lin it 4 Un g an fts Cv it 1 Tu Un Tu fts Cv Un it 2 Tu fts Cv Un it 3 ( ) Tu fts Cv...

AI summary The text presents a table related to plant performance, including capacity factors and availability definitions. The table appears incomplete or corrupted, with fragmented headers and missing data. The definition of availability is provided as a formula involving operating hours and ABNO outages.

As at June 30, 2025, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Long-term debt principal (1)(2) $ 23 $ 1,257...

AI summary As of June 30, 2025, the document outlines contractual obligations for the next five years and beyond, including long-term debt, interest payments, purchased power, transportation, fuel, capital projects, and other commitments. These obligations are expected to be transferred to the buyer upon the completion of the sale of NMGC.

- (1) Includes $660 million related to NMGC (2026: $95 million and $565 million thereafter). - (2) The Company's $1.2 billion USD and $500 million USD hybrid notes mature in 2076 and 2054, respectively, and these maturity dates have been u...

AI summary The document outlines the Company's financial obligations, including hybrid notes, future interest payments, and commitments related to electricity purchases, fuel transportation, and pension contributions. It also details NSPI's contractual obligation for the Maritime Link and Emera's commitment to transmission rights in New Brunswick.

2026-2027 GRA OP-01 Attachment 4 Page 30 of 37 REDACTED (CONFIDENTIAL INFORMATION REMOVED) As at December 31, 2024 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: Commodity swaps and forwards $ 15 $ 3 $ - $ 18...

AI summary The document presents a financial summary of assets and liabilities related to commodity and foreign exchange derivatives as of December 31, 2024. It highlights significant amounts in regulatory deferral and HFT derivatives, with total assets at $166 million and total liabilities at $617 million, resulting in a net liability of $451 million. A note mentions the pending sale of NMGC and its classification as held for sale.

A. Commitments As at June 30, 2025, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted o...

AI summary This section outlines contractual commitments as of June 30, 2025, excluding pensions, long-term debt, and asset retirement obligations, detailing commitments for each of the next five years and in aggregate thereafter.

BEAR SWAMP - 50% joint venture. - 660 MW hydro pumped storage capacity located in western Massachusetts. - Attracts ISO NE capacity revenue.

AI summary The BEAR SWAMP project is a 50% joint venture with a 660 MW hydro pumped storage capacity located in western Massachusetts, designed to attract ISO NE capacity revenue.

Regulatory Arrangements In November 2024, the UARB approved the recovery of ~$158M of Maritime Link Costs for 2025, and an additional ~$42M of financing costs in relation to the $500M of additional Federally guaranteed debt

AI summary In November 2024, the UARB approved the recovery of approximately $158M in Maritime Link Costs for 2025 and an additional $42M in financing costs related to $500M of federally guaranteed debt.

Regulatory Arrangements In November 2024, the UARB approved the recovery of ~$158M of Maritime Link Costs for 2025, and an additional ~$42M of financing costs in relation to the $500M of additional Federally guaranteed debt Note: All figur...

AI summary In November 2024, the UARB approved the recovery of approximately $158M in Maritime Link Costs for 2025 and an additional $42M in financing costs related to $500M of federally guaranteed debt.

Bear Swamp - 50% joint venture. - 660 MW hydro pumped storage capacity located in western Massachusetts. - Attracts ISO NE capacity revenue.

AI summary Bear Swamp is a 50% joint venture with a 660 MW hydro pumped storage capacity located in western Massachusetts, which attracts ISO NE capacity revenue.

Other Total Exh 5 of COSS: 2026 ALLOCATION OF OPERATING EXPENSES Sub-Total Wreck Annapolis Other Total Wind Combustion Combustion Total Lingan Tufts Cove Tufts Cove 6 Trenton Pt. Tupper Pt. Aconi Thermal Gen. Cove Tidal Power Hydro Hydro G...

AI summary The text presents a table detailing generator nameplate capacities and gross plant costs for various locations in Nova Scotia, including Lingan, Tufts Cove, and others, with amounts listed in thousands of dollars.

Table 1 Industry Sector: Electric Nova Scotia Power Inc. Maritime Electric Co. Ltd. Tucson Electric Power Co. Hawaiian Electric Industries Inc. Inc. Ltd. Co. Industries Inc. Ratings as of April 6, 2020 BBB+/Stable/(A-2) BBB+/Stable/ A-/Neg...

AI summary The document presents a financial comparison of Nova Scotia Power Inc. and other electric utility companies, including metrics such as revenue, EBITDA, interest coverage, and debt ratios. The table highlights Nova Scotia Power's financial position relative to its peers, with a focus on key financial indicators and risk assessments.

2026-2027 General Rate Application (M12451) NSPI Responses to GT Information Requests 1 (DDA) - 2024 Annual Report3 Deferral Account . The update in the 2024 DDA report 10 explanations on the increased labour requirements for these matters...

AI summary The document discusses NSPI's responses to information requests related to the 2026-2027 General Rate Application (M12451). It includes explanations for increased labor requirements and material costs at Tufts Cove and Combustion Turbines, citing the 2025 10-Year System Outlook and increased operational demands due to renewable energy integration.

SUMMARY OF CURVE FITTING RESULTS - PCT SURV BALANCED AREAS PLACEMENT BAND 1925-2023 001 EXPERIENCE BAND 1942-2023 SURVIVOR CURVE RESID RANGE OF MEAS FIT SURVIVOR RESID RANGE OF CURVE MEAS FIT 60.2-S0 54.7-S0.5 50.6-S1 47.7-S1.5 45.5-S2 2.9...

AI summary The text presents a summary of curve fitting results for survivor curves across different placement and experience bands, indicating residuals and measurement fits for various segments. The data includes ranges of survivor curves and associated residuals, with some segments marked as not fitted.

As at December 31, 2024, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2025 2026 2027 2028 2029 Thereafter Total Minimum lease payments to be re...

AI summary The text presents a table showing future minimum lease payments to be received by the company for each of the next five years and in aggregate thereafter, as of December 31, 2024. The section title 'RELATED PARTY TRANSACTIONS' suggests that the following content will discuss transactions involving related parties.

Heavy Fuel Oil: NSPI periodically enters into physical and/or financial contracts based on forecast heavy fuel oil purchases to meet load and system security requirements. Volumes exposed to market prices are managed using financial instru...

AI summary NSPI manages heavy fuel oil requirements through physical and financial contracts, using a hedging program to mitigate market price risks. As of December 31, 2024, all forecast heavy fuel oil needs for 2025 are fully hedged.

1 Figure 8 – Project Accountabilities Matrix 2030 Projects Accountability NS Power Key Action Items NS Government Key Action Items Partner Key Action Items 24 • There continues to be constraints in the global electricity industry supply ch...

AI summary The document highlights ongoing supply chain constraints in the global electricity industry, including high demand, inflation, and geopolitical factors, leading to longer lead times and increased costs. It also notes a 2024 trend of reduced risk related to inflationary cost pressures.

- 6 3. Human Resources 2.7 - 7 2024 Trend: No change - The electricity industry continues to face a shortage of talent due to high demand in both the electricity industry and adjacent industries, such as housing and other construction. Thi...

AI summary The document discusses ongoing talent shortages in the electricity industry, project approvals under the 2030 Clean Power Plan, and increasing risks in transition planning due to rising electricity demand and shifting supply costs. These factors are creating cost pressures, staffing challenges, and delays in project timelines.

CA4 – Production Additions as % of Production Plant - On a 5-year average basis, NSPI Production Additions as a Percent of Production Plant are slightly above below the peer group median - NSPI Production Additions as a Percent of Producti...

AI summary NSPI's Production Additions as a Percent of Production Plant are slightly above the peer group median on a 5-year average basis. From 2019 to 2023, NSPI's Production Additions increased by 1 percentage point, while the peer median increased by 0.5 percentage points. NSPI's Production Additions in 2023 were 37% higher than in 2019, compared to a 24% increase for the peer median.

- 19 is the same as customer growth, it shows this information below. Company Percentage Change in Reported Number of Customers 6 depreciation expense basis, and below the peer median in four of the five years studied. 7 8 (v) NS Power's f...

AI summary The text discusses customer growth and compares NS Power's distribution and general plant additions to peer medians, highlighting discrepancies in depreciation expense and investment in system reliability. It also notes higher HR costs per FTE and mentions regulatory processes like the ACE Plan and Five-Year Reliability Plan.

2026-2027 GRA NSEB IR-85 Confidential Attachment 1 has been removed due to confidentiality. 1 Request IR-86: 5 NS Power states it intends to file an application seeking approval to decommission the 6 Annapolis Tidal Generation Facility in...

AI summary NS Power plans to file an application in Q4 2026 to decommission the Annapolis Tidal Generation Facility and recover its remaining net book value over ten years. The application will determine the amortization period and cost recovery, which may differ from the 2027 revenue requirement forecast. Additionally, NS Power removed approximately $700 million from its rate base for DDA assets.

6 charge would be recovered through an increase in the energy charge. Request IR-134: 11 The interruptible credit is $160 kW/year and the most recently calculated levelized avoided costs 12 of capacity is $140 kW/year. Differences between...

AI summary The document discusses the interruptible credit for the Large Industrial Interruptible Rider (LIIR), explaining that the credit is based on the avoided cost of a combustion turbine. The credit reflects the deferral of future generation capacity costs and is designed to mimic the operation of a peaking facility. The updated credit values are supported by SR-01 Attachment 4.

1 Request IR-137: 2 3 Reference: OATT Updates SR-01 Attachment 1e 4 5 On page 32 of 42, NS Power stated: 6 7 However, as part of developing this consensus GRA, it was agreed that 8 for the 2026-2027 test periods the costing approach will u...

AI summary The document discusses a costing amendment related to interruptible loads under the Large Industrial Rate class, specifically the use of 50% of estimated average hourly demand for 10-minute operating reserve. This decision was made through consensus discussions and references a prior Board decision (M10431).

CONFIDENTIAL (Attachment Only) 1 (i) Is NSPI's transmission system designed to function over extended hours of high 2 loading? Explain why or why not. 3 4 (j) In live, unlocked Excel file format with all links and formula intact, please pr...

AI summary NSPI is asked whether its transmission system can function under high loading and to provide an alternate version of the COSS using SLF to classify transmission costs. NSPI explains that the transmission system will transition from radial to network-based, affecting cost classification.

2026-2027 GRA Synapse IR-4 Attachment 1 Page 14 of 24 REDACTED (CONFIDENTIAL INFORMATION REMOVED) - 14- - (a) line loss differences - (b) purchased power fixed costs - (c) grid sales - (d) direct and incrementally costed rates. Mr. Baker s...

AI summary The document discusses methods for allocating seasonal costs to customer classes, with differing opinions on the use of equivalent peaker, loss of load probability, and three coincident peak months. Dr. Chamberlin emphasized the need for further study on seasonal cost variation, while others suggested current methods may be sufficient. The Board noted limited discussion on functionalization.

NON-CONFIDENTIAL 1 Request IR-1: 22 ensure sufficient firm capacity is available to meet the forecast firm demand in the province 23 and maintain a planning reserve margin above the forecast firm demand. Whether in 24 province demand comes...

AI summary The text discusses the obligation to ensure sufficient firm capacity in the province and references the 2025 Ten-Year System Outlook (M12386) for details. It also addresses resource adequacy assessments by NS Power, including consideration of third-party generators. Additionally, it references Exhibit N-3 and Exhibit N-4 and asks about recent engagement with REI.

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

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

Proposed ($) Adjustments ($) Approved ($) Prior Approved (2022) 2,273,831,000 2,273,831,000 Adjustments Test Year Beginning Balance Correction - (265,839) (265,839) Net Metering 2,226,469 (2,226,469) - Municipal Dashboard 900,222 (900,222)...

AI summary The table outlines proposed, adjustment, and approved figures for Test Year Plant-in-Service Adjustments, including items like Net Metering, Municipal Dashboard, and All Other Proposed Plant Additions, with specific dollar amounts and adjustments made.

red 8,574 poles with two (2) single pole administrative analysts and 14 field technicians. Interrog. Resp. RSR-131; Interrog. Resp. RSR-16. While the Company's internal staff engineered fewer poles in 2023 (4,875 poles) and 2024 (4,419 pol...

AI summary The Company's internal capacity to engineer poles has been assessed, and it is determined that the Company could engineer significantly more poles internally than previously estimated, reducing reliance on external contractors.

Capacity per Equipment Type Capacity (kW) Customers Customer (kW) Primary Overhead 138,270 349,495 0.396 Primary Poles 138,270 349,495 0.396 Secondary Overhead 6,396 349,033 0.018 Secondary Poles 6,396 349,033 0.018 Primary Underground 12,...

AI summary Table 81 presents load-carrying capacity adjustments for various equipment types in the rate year, including primary and secondary overhead and underground lines, transformers, and poles, along with customer counts and capacity per customer.

UTILITY RATE PROCEEDINGS IN WHICH TESTIMONY HAS BEEN PRESENTED BY JACOB POUS ALASKA Entergy Guil States, Inc. 34724 JSP, Depreciation, Decommissioning, Entergy Gulf States, Inc. 34800 Amortization, CWC, Franchise Fees, Rate Entergy dun Sta...

AI summary The text lists various utility rate proceedings involving Entergy and Gulf States Utilities Company, detailing case numbers and topics such as depreciation, fuel cost factors, rate case expenses, and capacity factors. These proceedings involve financial and regulatory considerations related to utility operations.

Q DID THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO GIVE ANY INDICATION THAT EXISTING STEAM PRODUCTION SITES IN COLORADO ARE VALUABLE? A Yes. With respect to PSCo, the Colorado Commission stated the following: "We find that Publ...

AI summary The Colorado Public Utilities Commission indicated that existing steam production sites, such as the Comanche 3 expansion of a coal plant, offer cost savings compared to new Greenfield projects due to shared infrastructure and earlier operational dates, which could save ratepayers hundreds of millions of dollars.

l[[email protected]](mailto:[email protected]) Lana Myatt Senior Regulatory Analyst Nova Scotia Power Inc. PO Box 910 Halifax, NS B 3J 2W5 Dear Ms. Myatt: M12316 • Nova Scotia Power Incorporated - Cl C0067023 - LIN2 2024/25 Capacity...

AI summary Nova Scotia Power Inc. (NS Power) has requested regulatory approval for a capital project to refurbish Lingan Unit 2 (LIN2) to ensure safe operation and meet firm capacity requirements during the 2024/2025 winter season. The application includes budgeted and final cost details.

Budgeted Amount Final Cost Variance Cl C0067023 LIN2 2024/2025 Capacity Requirement $1,083,801 $1,257,127 ($173,326) This matter was considered by Roland A Deveau, K.C., Vice Chair.

AI summary The document presents a table showing a budgeted amount of $1,083,801, a final cost of $1,257,127, and a variance of ($173,326) for the capacity requirement of Cl C0067023 LIN2 2024/2025. The matter was considered by Roland A Deveau, K.C., Vice Chair.

N2. Accordingly, the Board directs NS Power to continue to submit for Board approval any LIN2 CI projects, collectively, as a Winter Capacity Requirement project application, until directed otherwise. Further, in response to Board Staff IR...

AI summary The Board directs NS Power to submit LIN2 CI projects as a Winter Capacity Requirement project application until otherwise directed. NS Power provided energy generation data for LIN2 during specific periods in early 2025 and is asked to provide a detailed weekly breakdown and explanation for the increased energy output. The Board also requires NS Power to seek approval for LIN2 operating expenses beyond 2024.

Use of CP in specialized circumstances The 2003 Working Group believed it preferable to use coincident demands (i.e., the customer class demand at the time of the distributor's peak) as a demand allocator where distribution facilities are...

AI summary The 2003 Working Group recommended using coincident peak (CP) demand for allocating costs on distribution facilities that consider load diversity. Higher voltage assets, such as those serving major substations, are typically allocated using CP. Staff will collaborate with the Technical Advisory Team to establish clear rules for CP use in cost allocation filings.

Combination of Methodologies It is recommended that all distributors employ the following combination of methodologies in their filings to allocate joint demand-related costs: - CP may be used to allocate the costs of some substations and...

AI summary The document recommends a combination of methodologies for allocating joint demand-related costs in distribution filings. CP is suggested for certain substations and high-voltage conductors, NCPI for secondary conductors and transformers, and NCPC for remaining distribution assets.

Cost Allocation Adjustment The PLCC in kW per customer or per connection should be multiplied by each rate classification's number of customers or connections. For the purposes of the PLCC adjustment, the model will first consider if there...

AI summary The document outlines a method for adjusting the PLCC (Peak Load Carrying Capability) to allocate a distributor's capital and O&M costs based on the number of customers or connections in each rate classification. It specifies that this adjustment does not apply to bulk delivery facilities, and explains how the demand capacity is calculated and subtracted from non-coincident peak values.

8.3.1 Background CP is the generally preferred demand allocator for distribution assets designed to serve a distributor's system peak. In the cost allocation filings, assets identified as >50 kV and bulk (if any)[1](#page-65-1)2 by a distr...

AI summary CP (Coincident Peak) is the preferred method for allocating demand on distribution assets serving a system's peak. Assets over 50 kV and bulk must use CP for cost allocation. The Federal Energy Regulatory Commission's tests for CP have been adapted for current filings, affecting how costs are allocated to rate classifications, with examples like street lights benefiting from different CP allocations.

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

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

DETAILED LISTING OF C.O.S.S. INPUT INFORMATION FOR THE YEAR ENDING DECEMBER 31, 2027 (227) POWER PRODUCTION - FUEL (228) POWER PRODUCTION - OPERATING & MAINT. 366,094.3 (277) (278) TRANSMSSION (279) Transmission - HV 0 0.0 0.0 0 0 0 0 (280...

AI summary The document provides a detailed listing of C.O.S.S. input information for the year ending December 31, 2027, including various categories related to power production, transmission, and distribution with associated costs and figures.

FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) Calendar Month of System Peak 1 January February March April May June July August September October November December Total (21) LINE LOSSES - GENERAL (22) LINE LOSSES - GENER...

AI summary The document presents line loss data for each month of the year ending December 31, 2027, in thousands of dollars. It includes both general and large line loss figures, with a total of $169,655.6 for general line losses and $17,922.9 for large line losses.

(IN THOUSANDS OF DOLLARS) Calendar Month of System Peak 1 January February March April May June July August September October November December Total (117) REQUIREMENTS - SHORE POWER (118) REQUIREMENTS - GEN.REPL. / LOAD FOLL. (119) REQUIR...

AI summary The table presents monthly requirements related to shore power, generation replacement, load following, PHP, BUTU, and RTP in thousands of dollars, with detailed values for each month and a total. The data includes figures for January through December and highlights the distribution of costs across different categories.

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

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

montants de capacité absorbée pour les an- Y is the total of all amounts, each of nées antérieures à l’année de capacité ab- which is an amount determined by the sorbée, formula Z × Z.1 ÷ Z.2 (II) l’excédent éventuel du montant de capaci-...

AI summary This text discusses the calculation of absorbed capacity amounts for previous years and the potential excess of absorbed capacity for the year of absorbed capacity, relative to reductions under the relevant subsection. It includes a formula involving variables Z, Z.1, and Z.2.

consideration any reductions to that excess de sources situées dans un endroit donné, la capacity under somme obtenue par la formule suivante : I×J 1 this subparagraph, in respect of amounts of transferred capacity for years preceding où :...

AI summary This text discusses the calculation of capacity reductions and transferred capacity amounts, referencing a formula that involves variables I and J. It includes legal terms and conditions related to the transfer year and the calculation of amounts for the transfer year and preceding years.

FO-13 – Average Rate Base – Deferred Charges and Credits 1  RB-01 – Plant In Service Continuity Schedule 2  RB 02-16 – Rate Base Table 3  DA-02 - Accumulated Reserve for Depreciation 4  DA-03 – Amortization Expense 5  OR-01 – Proof of...

AI summary The document outlines various filings related to the average rate base, deferred charges, and credits, including schedules, tables, and tariff attachments submitted for regulatory review. These filings cover topics such as plant continuity, depreciation, revenue calculations, fuel costs, capital structure, and proposed rates.

The minimum period for which this service is available from the Transmission Provider is one day. 2026 Delivery Period Charge ($) Yearly: One twelfth of $6,347.23 /MW of Reserved Capacity per year Monthly $528.94 /MW of Reserved Capacity p...

AI summary The document outlines the pricing structure for Network Integration Transmission Service, specifying charges for reserved capacity based on different delivery periods (yearly, monthly, weekly, and daily) for the years 2026 and 2027.

Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Operating Reserve – Supplemental Reserve will be equal to 8.3 percent of Reserved Capacity for Point-to-Point Tran...

AI summary The document outlines that customer obligations for self-supply or third-party supply of Operating Reserve – Supplemental Reserve are set at 8.3 percent of Reserved Capacity for Point-to-Point Transmission Service and 8.3 percent of Network Load for Network Integration Transmission Service.

Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Operating Reserve – Spinning Reserve is equal to 2.0 percent of the Transmission Customer's reserved capacity for...

AI summary The document outlines that the customer obligation for self-supply or third-party supply of Operating Reserve – Spinning Reserve is set at 2.0 percent of the Transmission Customer's reserved capacity for Point-to-Point Transmission Service and 2.0 percent of the Network Load for Network Integration Transmission Service.

GENERATION FUNCTION (1) FUEL 434,033 $0 $434,033 - (2) PURCHASES - OTHER THAN BIOMASS AND WIND 18,420 $8,334 $10,086 - (3) PURCHASES - BIOMASS 20,238 $5,365 $14,874 - (4) MARITIME LINK 198,036 $89,600 $108,436 (5) PURCHASES - WIND ERIS 33,...

AI summary The document text presents a detailed breakdown of various generation and operational costs, including fuel, purchases from different energy sources, imports, capacity credits, and maintenance expenses. It includes line items such as biomass, wind, hydro, and other generation-related costs.

uirement 274,652 (6) kW 3 CP 123,550 (7) kW 12 NCP 488,281 (8) Unit Cost (cents/kW.h) 8.320 1.199 1.775 0.764 3.738 12.058 Transmission/Distribution (9) Delivery Trans.(Eng) - HV 0 0 $0 $0 $0 $0 $0 255,142 0.000 (10) Delivery Trans.(Eng) -...

AI summary The text provides a detailed breakdown of costs related to transmission and distribution, including line items such as delivery, demand, and customer-related expenses. It includes figures for various voltage levels (HV, EHV) and associated costs in cents per kW.h and dollar amounts.

18,477.9 (215) PURCHASED POWER - BIOMASS (Energy) 14,919.9 (216) PURCHASED POWER - BIOMASS (Demand) 5,382.6 (217) PURCHASED POWER - MARITIME LINK 198,664 86,453.2 85,044.2 (218) PURCHASED POWER - WIND (ERIS) 33,418.0 (219) PURCHASED POWER...

AI summary The text presents a detailed breakdown of purchased power costs and related expenses, including biomass, wind, and imports, along with depreciation and accretion figures for different energy sources. It includes categories such as DSM expenses, grants, and adjustments.

y Requirement 374,976 (6) kW 3 CP 136,936 (7) kW 12 NCP 637,230 (8) Unit Cost (cents/kW.h) 7.651 1.113 1.738 0.714 3.565 11.216 Transmission/Distribution (9) Delivery Trans.(Eng) - HV 0 0 $0 $0 $0 $0 $0 357,053 0.000 (10) Delivery Trans.(E...

AI summary The text provides a breakdown of costs related to transmission and distribution, including line items such as delivery for transmission and distribution, with associated figures in dollars and cents per kilowatt-hour. It lists various components like demand, customer delivery, and total transmission costs.

y Requirement 719,039 (6) kW 3 CP 245,492 (7) kW 12 NCP 1,148,007 (8) Unit Cost (cents/kW.h) 7.447 1.071 0.058 0.690 1.819 9.267 Transmission/Distribution (9) Delivery Trans.(Eng) - HV 0 0 $0 $0 $0 $0 $0 694,582 0.000 (10) Delivery Trans.(...

AI summary The text provides a breakdown of costs related to transmission and distribution, including delivery costs for high voltage and extra high voltage systems, as well as demand and customer-related delivery costs. It outlines various line items such as transmission costs, demand-related delivery costs, and customer delivery costs with corresponding figures and totals.

22,698,943 (8) Unit Cost (cents/kW.h) 8.733 1.460 2.085 0.889 4.434 13.167 Transmission/Distribution (9) Delivery Trans.(Eng) - HV 0 0 $0 $0 $0 $0 $0 9,923,466 0.000 (10) Delivery Trans.(Eng) - EHV 0 0 0 0 0 0 0 9,923,466 0.000 (11) Delive...

AI summary The document presents a detailed breakdown of transmission and distribution costs, including various line items such as delivery costs for high voltage and extra high voltage systems, along with associated unit costs and totals. These figures are presented in a tabular format with specific monetary values and rates.

89,972.5 (232) BUTU CAPACITY CREDIT 393.0 (233) OTHER OVERHEAD EXPENSES 7,886.5 6,978.0 908.6 System Planniing and ECI (234) CURRENT YEAR INCENTIVE PLAN PAYOUT 0 (235) DSM EXPENSES - Demand-related ATL Classes 923,250.7 923,250.7 0.0 (236)...

AI summary This document excerpt presents a detailed breakdown of financial and operational expenses, including capacity credit, overhead expenses, DSM expenses categorized by ATL classes, and depreciation and accretion for various energy generation sources such as steam, hydro, wind, and solar. It includes figures related to the Fuel Cost Recovery (FCR) deferral and grants in lieu of taxes.

FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 January February March April May June July August September October November December Total (148) Distribution BP...

AI summary The text presents allocation factor information for the year ending December 31, 2027, including distribution substation and voltage allocations across different months and entities. Specific figures are provided for LIR and Municipal categories, with notable amounts in January and March.

$2,209,053 $1,774,468 $1,910,905 $338,372 $1,760,529 $1,747,854 $2,221,955 $2,265,821 $1,832,245 $345,941 $1,921,853 $1,973,556 $20,302,553 Maritime Link ML - NS Block (GWh) $13,250,000 $13,250,000 $13,250,000 $13,250,000 $33,082,221 $13,2...

AI summary The text presents a series of numerical figures related to financial and energy data, including costs and energy generation figures, with specific references to Maritime Link and other energy-related blocks and programs.

1.44063% 1.37% 1.28% 1.11% 0.76% 0.77% 0.92% 0.89% 1.00% 1.10% 1.27% 1.28% 1.13% Unmetered BUTU Total 100.00000% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% REDACTED (CONFIDENTIAL INFORMA...

AI summary The document presents various percentages and financial figures related to capacity credits, demand charges, and biomass calculations for the 2026-2027 GRA Compliance Filing. It includes data on installed capacity, fuel costs, and operating expenses for biomass projects.

1.37% 1.36% 1.21% Unmetered BUTU Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% REDACTED (CONFIDENTIAL INFORMATION REMOVED) REDACTED 2026-2027 GRA Compliance Filing - SR-01 Att...

AI summary The document contains redacted data related to capacity credit calculations for Ellershouse and imports, as well as biomass calculations for 2027. These figures include capital, fuel, and operating costs, with references to a compliance filing and an exhibit from a previous proceeding.

l Peak of ATL 2,347,983 Annual Energy Requirement of ATL 10,656,168,727 System Coincident Load Factor 51.81%

AI summary The text provides data on the peak load and annual energy requirement for ATL, along with the system coincident load factor, which is 51.81%. These metrics are key indicators of energy demand and system performance.

REDACTED 2026-2027 GRA Compliance Filing - SR-01 Attachment 6 Page 10 of 13 Data Inputs Category Jan-27 Feb-27 May-27 Jun-27 Jul-27 Aug-27 Sep-27 Oct-27 Nov-27 Dec-27 Annual Plant Fuel Costs $57,665,346 $47,414,297 $17,809,534 $19,048,134...

AI summary The document presents financial data for Plant Fuel Costs and Maritime Link (ML) related expenses across various months from January 2027 to December 2027, including annual totals. The data includes breakdowns for ML - NS Block, ML - Supp Block, and ML - Surplus.

3 $13,608,333 $33,033,866 $13,608,333 $13,608,333 $13,608,333 $13,608,333 $13,608,333 $33,033,866 $13,608,333 $202,151,066 Non-Wind Purchases Purchased Power Regular bfr Biomass $1,912,288 $2,286,050 $2,707,206 $2,536,520 $2,107,445 $1,929...

AI summary The text presents numerical data on non-wind purchases and biomass-related power purchases over multiple years, highlighting variations in costs and totals. The figures suggest fluctuations in spending on these energy sources.

[622] In response to questions from NS Power at the hearing, Ms. Palmer agreed that the peak load carrying capability adjustment used in Connecticut was heavily influenced by the capacity adjustment associated with line transformers. The c...

AI summary NS Power responded to questions about peak load carrying capability adjustments, noting that its methodology allocates transformers as 100% demand-related. NS Power cautioned against implementing such adjustments, citing potential impacts on other rate classes and the lack of evidence to support a 1.5 kW/customer adjustment. Other parties expressed concerns about the impact on non-residential customers.

The minimum period for which this service is available from the Transmission Provider is one day. 2026 Delivery Period Charge ($) Yearly: One twelfth of $6,347.23 /MW of Reserved Capacity per year Monthly $528.94 /MW of Reserved Capacity p...

AI summary The document outlines the pricing structure for the Network Integration Transmission Service, specifying charges per reserved capacity for different delivery periods in 2026 and 2027, with daily, weekly, monthly, and yearly rates provided.

Customer Obligations The customer obligation for reserves is equal to 3.0 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.0 percent of Network Load for Network Integration Transmission Service.

AI summary The document outlines the customer obligation for reserves at 3.0 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.0 percent of Network Load for Network Integration Transmission Service.

price forecasts citing timing of settlement negotiations and their observation that there were no major changes regarding commodity futures prices that would require an update to rates.[18](#page-13-0) Further, when asked whether the 2025...

AI summary Bates White confirmed no major changes in load forecasts or fuel cost-related rate increases. They made two recommendations: confirming the scope of the PHP Deferral Account includes the Goose Harbour Lake wind project and providing more narrative on sustaining capital costs for Lingan Unit 2. NS Power confirmed the inclusion of the wind project in the PHP Deferral Account.

Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Regulation is equal to 3.5 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.5 percent of...

AI summary The document outlines the customer obligations for self-supply and third-party supply under different transmission services, specifying percentages of Reserved Capacity and Network Load for Point-to-Point and Network Integration Transmission Services.

SCHEDULE 5: OPERATING RESERVE – SPINNING RESERVE SERVICE Spinning Reserve Service is needed to serve load immediately in the event of a system contingency. Spinning Reserve Service may be provided by generating units that are on-line and l...

AI summary Spinning Reserve Service is required to address system contingencies and must be provided by online generating units operating below maximum output. The Transmission Provider must offer this service, and the Transmission Customer must either purchase it or make alternative arrangements. Monthly charges for the service are outlined, with costs passed through if the Operating Area operator provides the service.

Customer Obligations for Self-Supply and Third-Party Supply The customer obligation for self-supply or third-party supply of Operating Reserve – Spinning Reserve is equal to 2.0 percent of the Transmission Customer's reserved capacity for...

AI summary The document outlines the customer obligation for self-supply or third-party supply of Operating Reserve – Spinning Reserve, specifying it as 2.0 percent of the Transmission Customer's reserved capacity for Point-to-Point Transmission Service and 2.0 percent of the Network Load for Network Integration Transmission Service.

Customer Obligations The customer obligation for reserves is equal to 3.0 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.0 percent of Network Load for Network Integration Transmission Service.

AI summary The document outlines customer obligations related to reserves, specifying that they are equal to 3.0 percent of Reserved Capacity for Point-to-Point Transmission Service and 3.0 percent of Network Load for Network Integration Transmission Service.

1 Power's direct evidence, so the General Rate Application; 3 the 2026-2027 GRA period. As [Nova Scotia 4 Power] explained in its November'2025 5 Maritime Link Benefits Report', as of 6 August 15, 2022, 'Lingan Unit 2 was laid up 7 and not...

AI summary The text discusses Nova Scotia Power's (NSP) explanation regarding the status of Lingan Unit 2, which was placed in cold reserve to maintain planning reserve margin. NSP also filed a capital application in May 2024 to support safe operations and provide firm capacity. The document includes a question about the accuracy of Bates White's reflection of NSP's estimates and a response confirming the timeframe, with additional context on the 10-year system outlooks.

Cr-ex, (Power) 1 capacity adjustment to the Minimum System in this case is 2 a possibility, but I'm not recommending overturning the 3 parties' Consensus Agreement, with your understanding that 4 they have overcome their own concerns with...

AI summary The text discusses a regulatory proceeding involving the Minimum System Method for capacity adjustments. While the parties have reached a settlement and agreed to revisit the methodology in a future proceeding, there is a recommendation to evaluate the need for precise peak load-carrying capacity adjustments in the interim.

INTERNATIONAL REPORTING INC. CERTIFIED COURT REPORTERS with two very different peak load-carrying capacity adjustments. Ontario uses a 0.4 kilowatt number and then Xcel, which is one utility in Minnesota uses the 1.5 kilowatt number. Is th...

AI summary The discussion revolves around the use of a 1.5 kilowatt figure for peak load-carrying capacity adjustments, as used by Xcel Energy in Minnesota and South Dakota. The expert acknowledges that this figure is an approximation and not based on detailed analysis specific to Nova Scotia Power, suggesting that Nova Scotia Power should determine a suitable number for its jurisdiction.

INTERNATIONAL REPORTING INC. CERTIFIED COURT REPORTERS should be a load-carrying capacity adjustment. So that's my testimony. Q. So your testimony is to take something that requires thoughtful analysis from Nova Scotia Power and stakeholde...

AI summary The testimony discusses the use of an arbitrary number from other jurisdictions for load-carrying capacity adjustment, with the witness defending its use as a temporary measure until a more thorough analysis can be conducted by Nova Scotia Power and stakeholders.

INTERNATIONAL REPORTING INC. CERTIFIED COURT REPORTERS Q. And in speaking with my friend concerning the numbers set by Ontario I believe you said that the number was perhaps dated or old. A. Oh, I just mean simply that I understand this wa...

AI summary The witness discusses the Minimum System used by utilities, noting that it may have evolved over time with the installation of larger equipment. They mention that current systems may use outdated numbers and that the Minimum System could have increased in load-carrying capacity, though this is not confirmed.