Topic:"Capacity Costs" in M12661

Evidence of Colin T. Fitzhenry and Michael P. Gorman Page 11 12 13  NS Power's proposed design of the ELID Tariff and proposed charges and credits are imbalanced and over-charge PHP for its cost of providing service. 14 15 16 17 18  PHP...

AI summary The evidence provided by Colin T. Fitzhenry and Michael P. Gorman critiques NS Power's proposed ELID Tariff design, arguing that it is imbalanced and over-charges PHP. They recommend that the ELID Tariff should include a capacity charge for firm demand service and recover non-firm power supply costs through the energy charge.

2 Q PLEASE DESCRIBE NS POWER'S PROPOSED ELID TARIFF FOR PHP. 3 A NS Power is requesting approval of an Extra Large Industrial Dispatchable ("ELID") 4 Tariff for PHP, to be available on, or before, January 1, 2027, following the termination...

AI summary NS Power proposes an ELID Tariff for PHP, replacing the expiring ELIADC Tariff. The ELID includes a Dispatchable Rider allowing NS Power to curtail PHP's load above 8 MW to reduce system costs and ensure reliability. PHP retains 8 MW firm demand rights, with NS Power prioritizing other customers during curtailments.

1 Q PLEASE DESCRIBE THE NON-FUEL SAVINGS CREATED BY THE DR 2 COMPONENT OF THE ELID. 3 A NS Power's ability to dispatch PHP load allows it to curtail PHP's demands above the 4 8 MW firm demand when it does not have the system resource capac...

AI summary NS Power avoids investing in additional generating/transmission capacity by curtailing PHP's demand above 8 MW during peak periods and emergencies. This creates non-fuel savings through capacity cost avoidance, which are partially allocated to other customers under the ELID Tariff design rather than fully reflected in rate charges.

3 Q HOW SHOULD THE ELID TARIFF BE CHANGED TO MORE EQUITABLY REFLECT 4 PHP'S FIRM AND INTERRUPTIBLE SUPPLY? 5 A The ELID provides both firm service and interruptible service to PHP. The cost of firm 6 service is based on NS Power's COS, whi...

AI summary The ELID tariff should reflect PHP's firm and interruptible supply by allocating capacity costs based on NS Power's cost of service (COS), including the Planning Reserve Margin (PRM). Interruptible demand beyond firm levels does not incur additional capacity costs as it can be curtailed during shortages.

1 Q IF NS POWER'S PROPOSED ELID TARIFF RATE DESIGN IS PREFERRED BY THE 2 BOARD, HOW SHOULD IT BE MODIFIED TO REFLECT NS POWER'S COST OF 3 PROVIDING SERVICE TO PHP? 4 A If NS Power's structure of the ELID is adopted, PHP will pay for NS Pow...

AI summary If NS Power's ELID tariff is adopted, PHP's interruptible demand should be credited at NS Power's marginal capacity cost ($13.107/KVA) to reflect the avoided cost of adding new peaking resources. This aligns PHP's interruptible load with NS Power's capacity needs during peak periods, ensuring fair cost allocation between PHP and firm customers.

13 III. DEMAND COST ALLOCATION 14 Q PLEASE DESCRIBE NS POWER'S PROPOSED DEMAND-RELATED COST 15 ALLOCATION UNDER THE ELID. 16 A The proposed resource capacity cost to the ELID Tariff is based on NS Power's system 17 embedded COSS methodolog...

AI summary NS Power proposes allocating demand-related costs under the ELID Tariff using a COSS methodology based on contribution to Three Coincident Peaks (3-CP) during winter months. PHP's 3-CP demand includes both firm (8 MW) and interruptible loads, with the Settlement Agreement assuming a 65 MW figure for 2026-2027 modeling purposes.

8 Q PLEASE PROVIDE YOUR UNDERSTANDING OF HOW THE 65 MW 3-CP DEMAND 9 LEVEL WAS DETERMINED BY NS POWER. 10 A During the General Rate Application Settlement Discussions that took place in 2024 11 and 2025, it was determined that PHP's averag...

AI summary NS Power determined the 65 MW 3-CP demand level based on PHP's average metered demand during 2022 and 2023, as established during the 2024-2025 General Rate Application Settlement Discussions. Historical data on CPs is detailed in Table 2.

5 Q DOES THE NATIONAL ASSOCIATION OF REGULATORY UTILITY 6 COMMISSIONERS ("NARUC") ELECTRIC UTILITY COST ALLOCATION MANUAL 7 SUPPORT THESE COST-CAUSATIVE PRINCIPLES? 8 A Yes, the NARUC Electric Utility Cost Allocation Manual is regarded as...

AI summary The NARUC Electric Utility Cost Allocation Manual supports cost-causative principles by emphasizing cost allocation based on customer-driven infrastructure needs. NS Power excludes interruptible demands from capacity planning, arguing they don't cause incremental costs. The manual allows flexibility in cost allocation methods, such as the 3-CP approach, to ensure fairness for customers like PHP.

14 Q DOES THE ELID PROVIDE PHP FULL CREDIT FOR SYSTEM RESOURCE 15 CAPACITY SAVINGS CREATED BY ITS INTERRUPTIBLE OR 'NON -FIRM' LOAD 16 TO PHP? 17 A No, it does not provide a full credit for PHP's willingness to be interruptible above its 1...

AI summary The ELID does not provide PHP full credit for capacity savings from its interruptible load. NS Power's avoided production and transmission costs range between $14.310/KVA and $13.107/KVA, with outdated benchmarks (e.g., $160.44/kW) used for capacity cost calculations, which no longer reflect current costs since 2020.

13 Q IS NS POWER'S NEED FOR RESOURCE CAPACITY TO SERVE PEAK DEMAND 14 EXPECTED TO CHANGE GOING FORWARD? 15 A Yes. The obligation for NS Power to retire its remaining coal-fired generation by 2030 16 is a primary driver for an anticipated i...

AI summary NS Power anticipates increased capacity costs due to retiring coal plants by 2030, creating a 'capacity gap.' To address this, investments in natural gas, battery storage, and transmission are required. Operating reserves and dispatchable capacity are critical for reliability, with PHP's interruptible demand becoming increasingly valuable during the energy transition.

11 Q PLEASE SUMMARIZE YOUR CONCLUSIONS AND RECOMMENDATIONS? 12 A In conclusion, Mr. Fitzhenry and Mr. Gorman recommend several modifications to Nova 13 Scotia Power Inc.'s proposed ELID Tariff to better align with cost-causation principles...

AI summary Mr. Fitzhenry and Mr. Gorman recommend modifying Nova Scotia Power Inc.'s ELID Tariff to align with cost-causation principles. Key changes include adjusting the capacity charge to reflect PHP's 8 MW firm demand, setting the interruptible credit to $13.107/kVA, applying a 1.0 revenue-to-cost ratio, and updating 2026/2027 energy sales forecasts post-Goose Harbour Lake Wind Farm integration.

REDACTED 1 LIIR class and PHP, they would have been different from those currently proposed as based 2 on LIIR usage which does not include load of PHP. As a result, Tables 2 and 3 provide 3 limited insight/comparability. 4 5 (f) Please re...

AI summary The text discusses the limitations of comparing LIIR class and PHP due to differences in load considerations, and references a table for simplicity assuming a demand power factor of 1, excluding wind generation from the Goose Harbour Lake Wind Farm.

NSPI Responses to BW Information Requests 1 Request IR-9: 26 system is capacity deficient at PHP current output level, then PHP can be interrupted under 27 the Interruptible Rider by the System Operator. 28

AI summary NSPI responds to a Board Work information request regarding the PHP Deferral, noting that if the system is capacity deficient at the current output level, PHP can be interrupted under the Interruptible Rider by the System Operator.

PARTIALLY CONFIDENTIAL (Attachment Only) 1 Request IR-2: 2 3 (a) Please provide COSS and resulting tariff reflecting all parameters proposed by PHP 4 in its evidence, including: 5 6 (i) designing the capacity charge to reflect PHP's actual...

AI summary The document outlines a request for the provision of a COSS and resulting tariff that reflects specific parameters proposed by PHP, including adjustments to the capacity charge, interruptible credit, revenue-to-cost ratio, and updated forecast energy requirements for 2026 and 2027. The response refers to a partially confidential attachment containing the requested information.

EXHIBIT 3 PAGE 1 OF 5 (1) DEMAND CLASSIFICATION (2) (3) GENERATION FUNCTION (4) STEAM PLANT $380,098 $250,776 $12,802 $69,471 $7,919 $7,116 $9,148 $14,200 $1,441 $5,410 $1,815 D-3A (5) HYDRO PLANT 313,963 207,142 10,575 57,383 6,541 5,878...

AI summary The text presents a detailed table of financial and operational data related to various generation plants and infrastructure, including steam, hydro, wind, and gas turbine plants, as well as generation batteries and transmission lines. It includes costs and classifications for different demand and generation categories.

EXHIBIT 3 PAGE 2 OF 5 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) BUTU (10) (11) MUNICIPAL UNMETERED (12) ALLOCATION FACTOR (15) DEF. CH...

AI summary The document presents a table with various financial and operational data categorized under different headings such as 'DEF. CHG FCR', 'DEF. CR ARO Trans', 'Transmission - EHV', and 'Distribution Function'. It includes figures related to different customer classes and allocation factors, with some entries referencing exhibits and other documents.

EXHIBIT 3 PAGE 3 OF 5 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL INDUSTRIAL (7) MEDIUM (8) INDUSTRIAL LARGE (9) (10) (11) ELI 2P-RTP MUNICIPAL UNMETERED (12) ALLOCATION FACTOR (36) (...

AI summary This exhibit presents a detailed breakdown of various financial and operational categories, including transmission functions, working capital, and deferred charges. It includes allocation factors and references to specific exhibits and pages, such as E-1B and P-11A, indicating the complexity of the regulatory proceeding.

DEMAND CLASSIFICATION (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (9) (10) (11) ALLOCATION (15) (16) TOTAL TRANSMISSION 139,549.91 92,047 4,706 25,534 2,905 2,616 3,355 5,208 528 1,984 666 (17) (18) DISTRIBUT...

AI summary The document presents a table detailing various costs and revenues related to demand classification, including operating and maintenance expenses, depreciation, interest, taxes, and revenue from pole services and other sources. It includes allocations and references to exhibits and pages.

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

AI summary The table presents investment and responsibility percentages across various categories, including small, general, and industrial sectors, with allocations and factors indicated for different investment types such as substituted investment, meter investment, and demand-related investments.

EXHIBIT 8B PAGE 2 OF 3 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (10) (11) COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL INDUSTRIAL INDUSTRIAL ELI 2P-RTP MUNICIPAL UNMETERED (12) ALLOCATION FACTOR (39)...

AI summary The exhibit presents a table with total engineering expenses and their distribution across various categories, including small, general, medium, large, and industrial segments. The data is categorized under different responsibility percentages, with specific allocations for different types of companies and utilities. The table includes references to Board Orders O-11, O-12A, and O-12B.

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

AI summary The document presents a detailed table of energy sales, losses, and demand metrics categorized by customer class for April 2026. It includes data on energy sales losses, energy line losses, demand losses, and system peak demand factors across various customer segments such as domestic, industrial, and municipal. The data is presented in a structured format with multiple columns, including system coincident demand and load factor.

ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 (35) LINE LOSSES - REAL TIME PRICING (36) LINE LOSSES - EBS/RTR (37) LINE LOSSES - EXPORT SALES 0 0 0 0 0 0 0 0 0 0 0 0 - (38) CLASS NON-COINCIDENT DMD DOMESTIC 1,567,908 1,440,...

AI summary The document presents a table with allocation factor information, specifically focusing on line losses and non-coincident demand across various classes and months. The data includes figures for different categories such as domestic, small general, general demand, and industrial sectors.

(20) MAT. & SUPPLIES - OTHER 16,874 8,903 613 3,712 596 435 703 1,143 431 206 132 (21) DEF. CHG Financing 4,646 2,451 169 1,022 164 120 194 315 119 57 36 (22) DEF. CHG Tax 5,142 2,713 187 1,131 182 133 214 348 131 63 40 (23) DEF. CHG Pensi...

AI summary The text presents a detailed breakdown of various financial line items related to Nova Scotia Power Inc., including expenses, financing, tax, pension, and other charges, as well as deferred charges and liabilities. It includes figures for different years and categories, such as fuel deferral, asset retirement obligations, and cost of removal liabilities.

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

AI summary The exhibit presents a detailed breakdown of various costs and allocations associated with generation and demand classification, including fuel, purchases, imports, and capacity credits. The data is categorized by company, domestic, general, and industrial segments, with references to BCF files for additional details.

NON-CONFIDENTIAL 1 Request IR-5: 2 3 In their evidence, Brubaker & Associates state: 4 5 If the ELID capacity charge is designed to include the cost of firm demand 6 service for a 65 MW tariff capacity, then the interruptible credit should...

AI summary Brubaker & Associates argue that the ELID capacity charge should account for the interruptible credit applied to 57 MW of the 65 MW service, priced at NS Power's estimated marginal cost of capacity. NS Power confirms the proposed ELID tariff aligns with this position.

PARTIALLY CONFIDENTIAL 1 The fact that it is expressly confirmed that "NS Power and PHP shall reflect the foregoing in a 2 written tariff;" and it is open to Parties to take a position that the tariff filing is "inconsistent with 3 the loa...

AI summary The document discusses the ELID Tariff Application by NS Power, addressing PHP's concerns about the capacity charge and energy requirements. NS Power explains that the capacity charge is based on PHP's actual 8 MW firm demand and the forecasted 65 MW load, considering the Goose Harbour Lake Wind Farm's contribution.

PARTIALLY CONFIDENTIAL 1 The Company provides the following in response to parts (a) and (b) of this IR. 2 3 (a) Confirmed. The 2026-2027 GRA was prepared in accordance with the SA. Changes to this 4 to align with PHP's Evidence will resul...

AI summary NS Power confirms the 2026-2027 GRA aligns with the SA but notes PHP's evidence will cause cost reallocations and price increases. NS Power opposes PHP's proposal to include 8 MW peak demand in capacity cost allocation, citing inconsistency with the GRA settlement agreement. The Board's Decision M12451 avoids re-opening COSS and rate design matters.

br>203,799 118,081 0 85,718 (40) TOTAL PLANT IN SERVICE 1,753,988 1,016,258 0 737,730 (41) (42) Working Capital & Deferred Charges/Credits: (43) CASH - FUEL 0 0 0 0 (44) CASH - OTHER 0 0 0 0 (45) MAT. & SUPPLIES - FUEL 0 0 0 0 (46) MAT. &...

AI summary The text presents a table with various financial and asset-related line items, including total plant in service, working capital, deferred charges and credits, and classifications related to energy, demand, and customer-related plant. It provides numerical data across multiple categories and periods.

FOR THE YEAR ENDING DECEMBER 31, 2026 (1) TOTAL (2) PROD. (3) TRANS. (4) DIST. (5) RETAIL (6) DIRECT (7) (25) LEGAL SERVICES (26) EXTERNAL RELATIONS & ENVIRONMENT 1,882 1,746 3,161 2,021 5,043.0 3,766.6 0.373 0.463 3,743 1,620 369 461 853...

AI summary The text presents a detailed financial summary of various departments and services for the year ending December 31, 2026, including legal services, regulatory affairs, finance, procurement, IT, human resources, and generation services, with specific figures for different categories and subcategories.

DETAILED LISTING OF C.O.S.S. INPUT INFORMATION (197) POWER PRODUCTION (261) GENERAL PROPERTY Adj ,2026

AI summary The text presents a detailed listing of C.O.S.S. input information, including categories such as power production and general property, with some entries indicating years like 2026. The content appears to be part of a regulatory proceeding involving data inputs for analysis.

FOR THE YEAR ENDING DECEMBER 31, 2026 (IN THOUSANDS OF DOLLARS) (262) GENERATION 0.0 (263) DISTRIBUTION 6,892.9 0.0 6,893 (264) TRANSMISSION 396.6 0.0 397 (265) DISTRIBUTION/ TRANSMISSION COMMUNICATION 2,394.2 0.0 2,394 (266) DISTRIBUTION/...

AI summary The document presents a financial summary for the year ending December 31, 2026, detailing various costs and allocations across generation, distribution, transmission, and retail operations. It includes depreciation, interest charges, corporate taxes, and various rider allocations such as interruption costs and power factor adjustments.

NOVA SCOTIA POWER INC. FUNCTIONALIZATION OF OPERATING EXPENSES FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) (1) (2) SHORE GEN.REPL POWER LOAD FOLL. ELIADC BUTU SPILL PRICING (3) (4) (5) (6) REAL TIME (7) EBS (8) RTR (7)...

AI summary The document presents the functionalization of operating expenses for Nova Scotia Power Inc. for the year ending December 31, 2027, categorized into various expense types such as fuel, purchased power, and maintenance costs for different energy sources including thermal, hydro, wind, and biomass.

CLASS : ELI 2P-RTP CLASS : ELI 2P-RTP 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 Generation (1) Usage (Energy) $43,222 $19,199 $2...

AI summary This document presents a detailed breakdown of costs related to generation, transmission/distribution, and retail for a Nova Scotia regulatory proceeding. It includes figures for fuel, operating, capital, and return costs, along with unit costs and total expenses categorized by different segments of the energy system.

FOR THE YEAR ENDING DECEMBER 31, 2027 (1) TOTAL (2) COMPANY DOMESTIC GENERAL GENERAL (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM LARGE INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) PHP (10) (11) MUNICIPAL UNMETERED (12) ALLOCATION FACT...

AI summary The document presents a detailed breakdown of demand, responsibility percentages, and energy generation and purchase data across various customer categories for the year ending December 31, 2027. It includes tables with figures and percentages, as well as references to different demand and generation categories.

ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 January February March April May June July August September October November December Total (22) LINE LOSSES - GENERAL LARGE 1,588 1,506 1,573 1,394 1,367 1,411 1,632 1,501 1,51...

AI summary The text presents a table detailing line losses across various categories and calendar months in Nova Scotia. It includes data for different types of line losses, such as general large, industrial, municipal, and unmetered, with monthly figures and totals provided.

CLASSIFICATION OF AVERAGE RATE BASE (1) (2) (3) (4) (5) (6) (7) (8) (9) (9) MAT. & SUPPLIES - FUEL 0 0 0 0 0 0 0 0 0 0 0 D-3A (10) MAT. & SUPPLIES - OTHER 14,219 9,135 466 2,530 288 259 333 517 426 197 66 P-8B (11) DEF. CHG Financing 4,186...

AI summary The document presents a classification of the average rate base, detailing various cost categories such as materials and supplies, deferral charges, and transmission and distribution functions. It includes financial data across multiple columns and references exhibits and pages.

DEVELOPMENT OF ALLOCATION FACTORS (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (10) (11) (12) ALLOCATION (23) ENERGY - GEN. PLANT (24) % RESPONSIBILITY $1,025,084 100.00% $511,896 49.94% 3.38% $34,670 $217,055...

AI summary The document presents a table detailing the development of allocation factors across various categories, including energy generation, transmission, and distribution plants, as well as customer-related distribution plants. The table shows the total costs and percentages of responsibility allocated to different categories, with specific allocations labeled as P-10, P-11A, P-11B, and P-12.

ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 January February March April May June July August September October November December Total (111) REQUIREMENTS - INDUST. 250-3999 KVA (112) REQUIREMENTS - INDUSTRIAL LARGE 62,63...

AI summary The text presents an allocation factor information table, detailing energy requirements across different categories for various calendar months. It includes data for industrial, municipal, and unmetered requirements, with specific figures for each month and a total column.

2 34 - 14 2 1 61 417 9 541 (1) (2) (3) (4) (5) (6) (7) (8) (7) (8) SHORE GEN.REPL POWER LOAD FOLL. ELIADC BUTU SPILL REAL TIME PRICING EBS RTR OATT TOTAL BTL (1) FUEL (2) PURCHASED POWER: - - - - - - - - - - (3) OTHER THAN BIOMASS AND WIND...

AI summary This table outlines various operational and maintenance costs for different energy sources and systems, including thermal, hydro, wind, solar, biomass, and combustion turbines. It includes details on fuel procurement, power production, and capacity credit, providing a breakdown of expenses across multiple categories.

FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) (1) TOTAL DMD.RELATED (2) TOTAL ENG.RELATED (3) UNIT COST ENG.RELATED (4) TOTAL CUST.RELATED (5) TOTAL OPER. (6) TOTAL RATE (7) % REVENUE VARIANCE CALC (6) HYDRO PLANT - CWIP...

AI summary The document presents financial data for various generation plants and related costs for the year ending December 31, 2027, including figures for different types of plants such as hydro, wind, solar, gas, and LM6000, along with their capitalized works in progress (CWIP) and total generation costs.

-1A (13) OPER. & MAINT OTHER CT's 0 0 0 0 0 0 0 0 0 0 0 E-1A (14) OPER. & MAINT GENERATION BATTERIES 0 0 0 0 0 0 0 0 0 0 0 E-1A (15) OPER. & MAINT RADIAL TO GENERATION TRANS. 1,549 774 52 328 52 38 64 99 114 18 11 E-1A (16) DSM 0 See DSM A...

AI summary The document presents a financial breakdown of various operational and maintenance costs, including depreciation, interest, corporate taxes, and non-operating revenue for Nova Scotia Power Inc. It includes allocations for DSM, FCR deferral, and other expenses, with some figures referencing external files and exhibits.

DEVELOPMENT OF ALLOCATION FACTORS (1) TOTAL (2) PROD. (3) TRANS. (4) DIST. (5) RETAIL (6) DIRECT (7) EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES ALLOCATOR (33) GENERATION SERVICES 9,186 2,723 11,909.6 0.771 11,910 0 0 0 11,909.6...

AI summary The text outlines the development of allocation factors, including distribution, transmission, and communication expenses, with percentages and totals for various categories such as generation services, other expenses, and subtotal overhead. Allocation percentages and responsibilities are detailed for different expense types.

CLASSIFICATION OF OPERATING EXPENSES (1) TOTAL COMPANY (2) DEMAND EXPENSES (3) ENERGY EXPENSES (4) CUSTOMER EXPENSES (29) INTEREST NET OF AFUDC 64,274 26,257 38,017 - (30) PREFERRED DIVIDENDS 0 0 0 - (31) CORPORATE TAXES 4,592 1,876 2,716...

AI summary The text presents a classification of operating expenses for Nova Scotia Power Inc. for the year ending December 31, 2027, including categories such as interest, taxes, and revenue from steam and ash sales, along with a detailed breakdown of transmission and depreciation expenses.

DEMAND CLASSIFICATION (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (9) (10) (11) ALLOCATION (15) (16) TOTAL TRANSMISSION 159,119.76 105,193 5,577 28,940 3,308 3,033 3,489 5,931 604 2,264 782 (17) (18) DISTRIBU...

AI summary The document presents a detailed breakdown of costs and revenues associated with demand classification, including transmission, distribution, depreciation, interest, taxes, and corporate expenses, along with corresponding exhibit and page references.

FOR THE YEAR ENDING DECEMBER 31, 2027 (IN THOUSANDS OF DOLLARS) (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL (7) MEDIUM INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) ELI 2P-RTP (10) (11) MUNICIP...

AI summary The document presents financial data for the year ending December 31, 2027, including purchases from wind energy sources, imports, and operational and maintenance costs for steam and hydro facilities. The data is categorized by different customer segments and includes allocations and factors for various line items.

EXHIBIT 6 PAGE 4 OF 6 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (10) (11) (12) ALLOCATION (12) Subtotal (13) Non-Operating Revenue Credit (14) Subtotal $159,437 ($317) $159,120 $105,402 ($210) $105,193 $5,5...

AI summary The text presents a table with various financial figures, including revenue credits, subtotals, and distribution costs categorized by different segments such as small, general, medium, and large. It also includes non-operating revenue credits and operating costs for retail and other segments.

NOVA SCOTIA POWER INC. DEVELOPMENT OF ALLOCATION FACTORS FOR THE YEAR ENDING DECEMBER 31, 2027 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL COMPANY DOMESTIC GENERAL GENERAL LARGE INDUSTRIAL INDUSTRIAL INDUSTRIAL ELI 2P-RTP MUNICIPAL U...

AI summary The document presents allocation factors for various categories of responsibility related to pole and wire infrastructure investments and customer responsibilities for the year ending December 31, 2027. It includes percentages and dollar amounts allocated across different customer segments and categories.

REVENUE TO EXPENSE COMPARISON (1) TOTAL DMD.RELATED (2) TOTAL ENG.RELATED (3) UNIT COST ENG.RELATED (4) TOTAL CUST.RELATED (5) TOTAL OPER. (6) TOTAL RATE (7) % REVENUE VARIANCE CALC (229) PURCHASED POWER - WIND (ERIS) (230) PURCHASED POWER...

AI summary The document presents a revenue to expense comparison table, including various cost categories such as purchased power, depreciation, generation, and grants. It highlights expenses related to demand-side management, energy-related classes, and other overhead expenses, as well as adjustments and variances in costs.

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

AI summary The document presents a detailed table of various generation and plant-related costs, including hydro, wind, LM6000, gas turbine, and battery plants, along with their respective allocations across different categories such as small, general, and industrial. It also includes information on working capital and deferred charges.

DEMAND CLASSIFICATION (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (9) (10) (11) ALLOCATION (30) Streetlights: (31) OPERATING & MAINT. 814 0 0 0 0 0 0 0 0 0 814 EXH 6A (32) GRANTS IN LIEU OF TAXES 327 0 0 0 0...

AI summary The table presents demand classification data, including operating and maintenance costs, depreciation, interest, and other financial figures, along with allocations and references to exhibits and pages. It outlines total demand and distribution figures for various categories such as small, general, medium, and large.

DEVELOPMENT OF ALLOCATION FACTORS (1) TOTAL (2) PROD. (3) TRANS. (4) DIST. (5) RETAIL (6) DIRECT (7) (11) SUB-TOTAL 10,344,803 7.3% 11,094,903 2,667,050 78.6% 2,094,930 12.5% 2,356,954 53.73636% 6,777,270 100.0% (12) SHORE POWER (13) GEN.R...

AI summary The text presents a table detailing the development of allocation factors, including totals and percentages for production, transmission, distribution, and retail categories. It includes subtotals and specific line items such as shore power and real-time pricing, with references to various services and customer rate classes.

F (1) TOTAL EXPENSES (2) PROD. EXPENSES (3) TRANS. EXPENSES (4) DIST. EXPENSES (5) RETAIL EXPENSES (6) PROD. WEIGHTS (7) TRANS. WEIGHTS (8) DIST. WEIGHTS (9) RETAIL WEIGHTS (47) HYDRO (48) WIND 16,630 12,843 16,630 12,843 - - - - - - 3.7%...

AI summary The document presents a table outlining various expenses and weights associated with different energy generation and distribution components, including hydro, wind, solar, and transmission and distribution infrastructure. The data includes total expenses, production, transmission, and distribution expenses along with corresponding weights for each category.

NOVA SCOTIA POWER INC. (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL (7) MEDIUM INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) ELI 2P-RTP (10) (11) MUNICIPAL UNMETERED (12) ALLOCATION FACTOR (18)...

AI summary The document presents a detailed financial breakdown for Nova Scotia Power Inc., including various expense and revenue categories such as advocacy expenses, depreciation, interest, taxes, and non-operating revenue. Specific line items and allocations are provided across different customer segments and business areas.

r>5,514 9,395 14,500 12,471 2,581 1,672 E-1A (20) MAT. & SUPPLIES - OTHER 18,259 9,290 629 3,939 620 452 770 1,189 1,022 212 137 P-10 (21) DEF. CHG Financing 5,375 2,735 185 1,160 182 133 227 350 301 62 40 P-10 (22) DEF. CHG Tax 5,778 2,93...

AI summary The text presents a detailed breakdown of various financial categories, including materials and supplies, financing, tax, pension, and fuel deferral charges, as well as asset retirement obligations and other related costs, with corresponding figures across multiple years and periods.

(IN THOUSANDS OF DOLLARS) (1) TOTAL EXPENSES (2) PROD. EXPENSES (3) TRANS. EXPENSES (4) DIST. EXPENSES (5) RETAIL EXPENSES (6) DIRECT EXPENSES (7) ALLOCATION FACTOR (1) FUEL 443,215 419,642 - - - 23,572.9 (2) PURCHASED POWER: (3) OTHER THA...

AI summary The document presents a detailed breakdown of expenses in thousands of dollars across various categories such as fuel, purchased power, and operating and maintenance costs for different energy sources including thermal, hydro, wind, and biomass. Allocation factors are also included for each expense category.

NOVA SCOTIA POWER INC. (1) TOTAL COMPANY (2) DOMESTIC (3) SMALL GENERAL (4) GENERAL (5) GENERAL LARGE (6) SMALL (7) MEDIUM INDUSTRIAL INDUSTRIAL INDUSTRIAL (8) LARGE (9) ELI 2P-RTP (10) (11) MUNICIPAL UNMETERED (12) ALLOCATION FACTOR (8) B...

AI summary The document presents a detailed breakdown of various operational and maintenance costs across different categories and customer segments for Nova Scotia Power Inc., including specific line items such as capacity credit, hydro, wind/biomass, biomass, and other generation-related expenses, along with references to allocation factors and related documents.

ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 (76) TOTAL COINCIDENT DEMAND AT GENERATOR 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 2,188,591 2,413,470.3 (77...

AI summary The text presents a table with data on total coincident demand and interruptible coincident demand at the generator for various calendar months, highlighting peak demand figures and their distribution across different periods.

DEVELOPMENT OF ALLOCATION FACTORS FOR THE YEAR ENDING DECEMBER 31, 2027 (1) TOTAL (2) (3) SMALL (4) (5) GENERAL (6) SMALL (7) MEDIUM (8) LARGE (9) (10) (11) (12) ALLOCATION (37) TOT. EXP DMD. ( DIST.) $140,786 $92,707 $5,057 $25,531 $1,681...

AI summary The document outlines the development of allocation factors for the year ending December 31, 2027. It includes tables with various expense categories, percentages of responsibility, and allocation factors for different segments such as small, medium, and large.

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

AI summary The text presents a table with various metrics related to energy sales, losses, demand, and system factors for September 2027. It includes columns such as energy sales, energy losses, energy requirement, demand factors, and system peak demand. The table appears to be part of a regulatory proceeding related to energy billing and real-time pricing.

NOVA SCOTIA POWER INC. ALLOCATION OF AVERAGE OVERHEAD WIRE INVESTMENT (1) TOTAL PLANT (2) PRIMARY DEMAND (3) PRIMARY CUSTOMER (4) SECONDARY DEMAND (5) SECONDARY CUSTOMER ( 1) DOMESTIC $135,025 $56,557 $47,437 $4,159 $26,871 ( 2) SMALL GENE...

AI summary The document presents a table detailing the allocation of average overhead wire investment by category, including total plant, primary and secondary demand, and primary and secondary customer segments. The table includes figures for various classifications such as domestic, small general, and industrial, along with allocation factors for different categories.

ANALYSIS OF AVERAGE UNDERGROUND WIRE INVESTMENT (1) TOTAL PLANT (2) PRIMARY DEMAND (3) PRIMARY CUSTOMER (4) SECONDARY DEMAND (5) SECONDARY CUSTOMER (1) FACTORS 1.000 0.056 0.011 0.171 0.762 (2) TOTAL NET WIRE COST $61,773 $3,459 $679 $10,5...

AI summary This exhibit presents a breakdown of total net wire costs across different demand and customer categories, with primary and secondary demand and customer segments showing varying proportions of the total investment.

ALLOCATION FACTOR INFORMATION ALLOCATION FACTOR INFORMATION (162) Distribution BP Substation LIR (163) Distribution BP Substation - Municipal (164) Distribution Primary Voltage - LIR (165) Distribution Primary Voltage - Municipal (166) (15...

AI summary The document provides allocation factor information related to distribution substations, voltage levels, and loss factors under the ELIADC. It includes data on revenue-to-expense ratios and the functionalization and classification of average rate bases.

REVENUE TO EXPENSE COMPARISON (1) TOTAL DMD.RELATED (2) TOTAL ENG.RELATED (3) UNIT COST ENG.RELATED (4) TOTAL CUST.RELATED (5) TOTAL OPER. (6) TOTAL RATE (7) % REVENUE VARIANCE CALC ECEI Batteries Plant ECEI Batteries CWIP Generation-relat...

AI summary The document presents a revenue-to-expense comparison, including figures related to generation, transmission, and distribution plants, as well as associated costs and adjustments. It includes details on capital works in progress (CWIP), total expenses, and variance calculations.

NOVA SCOTIA POWER INC. FUNCTIONALIZATION OF OPERATING EXPENSES POWER PRODUCTION (1) FUEL $443,215 $381,985 $0 $0 $0 $61,230 (2) PURCHASED POWER: (3) OTHER THAN BIOMASS AND WIND 18,478 18,416 0 0 0 62 (4) BIOMASS 20,303 20,234 0 0 0 69 (5)...

AI summary The document presents a detailed breakdown of Nova Scotia Power Inc.'s operating expenses, including fuel costs, purchased power, and maintenance expenses across various energy production and distribution categories. It highlights specific line items such as thermal, hydro, wind, and biomass operations, as well as corporate groups and customer operations.

NOVA SCOTIA POWER INC. FUNCTIONALIZATION OF OPERATING EXPENSES (1) TOTAL EXPENSES (2) PROD. EXPENSES (3) TRANS. EXPENSES (4) DIST. EXPENSES (5) RETAIL EXPENSES (6) DIRECT EXPENSES POWER PRODUCTION (1) (2) FUEL PURCHASED POWER: $363,514 $29...

AI summary This table outlines the functionalization of operating expenses for Nova Scotia Power Inc., breaking down costs into production, transmission, distribution, and retail expenses. It includes costs related to fuel, biomass, wind, imports, and maintenance for various power generation sources such as thermal, hydro, and combustion turbines.

EXHIBIT 6.1 PAGE 6 OF 11 CLASS : MEDIUM INDUSTRIAL COSTS (Source Exh 6) (11) DeliveryTrans.(Dmd) - HV (12) DeliveryTrans.(Dmd) - EHV 0 43,215 0 0 0 1,296 0 3,156 0 1,499 0 5,952 0 5,952 1,148,007 1,148,007 $0.000 $5.185 (13) Total Transmis...

AI summary This table presents costs related to transmission and distribution for medium industrial customers, including delivery, transmission, distribution, and retail costs, with details on various line items and unit costs.

Background – Justifications & Cost Allocation for Priority Interruptibility

AI summary This section provides background on the justifications and cost allocation for priority interruptibility, focusing on the rationale behind the allocation of costs associated with this mechanism.

NON-CONFIDENTIAL 1 • Row 32 (cost of priority interruptible credit to PHP ATL): $20,300 Date Filed: April 10, 2026 NSPI (PHP) IR-6 Page 2 of 2

AI summary A cost entry of $20,300 for the priority interruptible credit to Port Hawkesbury Paper (PHP) ATL is listed in a filing by Nova Scotia Power Inc. (NSPI) dated April 10, 2026.

NSPI Responses to Synapse Energy Economics, Inc. Information Requests 1 Request IR-1: 4 Interruptible Rider (LIIR). 5 6 (a) Please explain how the LIIR credit of $7.638 per kVA and $7.667 per kVA of 7 interruptible service for 2026 and 202...

AI summary The document outlines information requests and responses related to the Large Industrial Interruptible Rider (LIIR) credit, including requests for explanations of the credit rates, associated workpapers, and load reduction data for NS Power and PHP from 2022 to 2025.

NSPI Responses to Synapse Energy Economics, Inc. Information Requests 1 Request IR-7: 2 firm load from PHP during the winter peak, as well as the PHP firm load amount 3 that the asset was designed to serve. 4 5 (g) What firm load from PHP...

AI summary The document outlines NSPI's response to information requests regarding the Port Hawkesbury Biomass plant's design capacity and the methodology used for identifying investments in generation, transmission, and distribution. The response includes details on load forecasting and system reliability criteria.

NON-CONFIDENTIAL - Customers to reduce their load as directed by the System Operator (SO) within 10 minutes of notice. A recent innovation to the LIIR Tariff offering allows customers who provide the Company with visibility to their load a...

AI summary The LIIR Tariff requires customers to reduce load rapidly under NSPSO direction, with penalties for non-compliance and strict interruption limits. Customers must provide load visibility and accept potential removal from IR service. A five-year notice period is required for converting to firm service, ensuring adequate time for capacity adjustments.

REDACTED 1 (ii) Holding interruptible load as operating reserve does not, in and of itself, allow NS 2 Power to build less generation capacity. Capacity planning is driven by the long 3 term firm load forecast plus planning reserve margin...

AI summary The document discusses capacity planning, emphasizing that holding interruptible load as reserves does not reduce generation capacity. It highlights the necessity of overriding interruption orders for reliability, and notes that PHP's load, equipped with T&C, can replenish reserves without interruption. NSPI responds to Synapse's information requests regarding ELID and LIIR tariffs.

PLANT 1,550,189 0 0 1,550,189 0 0 (35) (36) 4,480,567 2,097,475 831,618 1,550,189 0 1,285 SUB-TOTAL DIST. PLANT (37) (38) SUB-TOTAL TRANSMISSION AND DISTRIBUTION 2,381,807 831,618 1,550,189 (39) (40) DIRECT GEN. PROPERTY PLANT 86,819 0 2,9...

AI summary The document presents a detailed breakdown of various financial and asset-related categories, including plant values, working capital, deferred charges, and credits. It includes figures for different types of plant, such as distribution, transmission, and generation, along with associated costs and credits.

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

AI summary The document presents a detailed breakdown of various costs and allocations related to energy generation, purchases, and other related factors. It includes data on fuel, purchases from different sources like biomass and wind, maritime link costs, and operational and maintenance steam expenses. The data is categorized by different demand classes and sizes.

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

AI summary The document presents a detailed breakdown of allocation factors related to demand, generation, and purchase across various categories such as small, general, and industrial sectors. Percentages of responsibility are calculated for each category, with specific values and exhibits referenced for further details.

NOVA SCOTIA POWER INC. DEVELOPMENT OF ALLOCATION FACTORS FOR THE YEAR ENDING DECEMBER 31, 2026 (1) TOTAL (2) PROD. (3) TRANS. (4) DIST. (5) RETAIL (6) DIRECT (7) EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES EXPENSES ALLOCATOR (37) GENERALP...

AI summary Nova Scotia Power Inc. is developing allocation factors for the year ending December 31, 2026. The table shows the distribution of expenses across production, transmission, distribution, retail, and direct categories, with a focus on communication expenses related to distribution and transmission.

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

AI summary This table presents data related to energy sales, losses, and demand factors across various customer classes for June 2026. It includes metrics such as MWH sales losses, energy line losses, demand losses, and system coincidence factors. The data is categorized by customer type, including domestic, industrial, and municipal classes, and includes subtotals and totals for different categories.

ALLOCATION FACTOR INFORMATION Calendar Month of System Peak 1 January February March April May June July August September October November December Total (113) REQUIREMENTS - ELI 2P-RTP (114) REQUIREMENTS - MUNICIPAL 8,343 31,866 8,322 33,...

AI summary The document presents a table with allocation factor information, detailing requirements across different categories for various months. It includes data for ELI 2P-RTP, municipal requirements, unmetered, shore power, generation replacement, ELIADC, BUTU, RTP, and EBS/RTR. The table provides monthly data and totals for each category.

BUTU Capacity Credit Calc. Installed Capacity Capacity Credit Approved Contract Demands (kWs) FAM-related Demand Charge Gross Demand Payment Net Demand payment bfr Credits Capacity Credit Ellershouse Imports 23,500 20.5% 0% 7,549 $6.219 $6...

AI summary The text presents a capacity credit calculation table for Ellershouse Imports, including installed capacity, capacity credit percentages, demand charges, and net demand payments. A total net demand payment of -300,185 is shown, indicating a refund or credit.

Annual Peak of ATL 2,297,508 Annual Energy Requirement of ATL 11,303,785,142 System Coincident Load Factor 56.164608% Rate Base Average 2025 2026 Steam Plant $ 481,584 $ 543,265 $ 419,903 Steam Plant - CWIP $ 4,559 $ 4,744 $ 4,374 Steam En...

AI summary The document presents key metrics for a utility system, including annual peak demand and energy requirements, along with detailed financial data for various plant types and their associated costs over multiple years.

REDACTED ELID Tariff Synapse IR-30 Attachment 2 Page 14 of 15 REDACTED (CONFIDENTIAL INFORMATION REMOVED) Category Usage Data Medium Industrial 37,761,228 34,388,307 37,154,644 34,300,556 36,745,594 38,469,740 38,399,377 35,849,667 35,276,...

AI summary The text presents a table containing usage data categorized by different industrial and municipal sectors, including figures for Medium Industrial, Large Industrial (FIRM and INT), PHP, and Municipal. The data spans multiple years and includes totals for each category.

r>0 4,103 4,655 (23) DEF. CHG Tax 9,693 0 0 -5,152 5,152 0 4,541 5,152 (24) DEF. CHG Pension 42,525 46,107 0 0 0 0 42,525 46,107 (25) DEF. CHG Steam Assets 0 0 0 0 0 0 0 0 (26) DEF. CHG Fuel Deferral 0 3,900 0 0 0 0 0 3,900 (27) DEF. CHG O...

AI summary The text presents a detailed breakdown of various deferred charges and credits, including tax, pension, steam assets, fuel deferral, and other categories, along with their respective financial impacts across different periods.

FOR THE YEAR ENDING DECEMBER 31, 2027 (1) MWH (2) ENERGY LINE (3) ENERGY SALES LOSSES REQUIREMENT DMD. (KW) (4) CLASS NON- SYSTEM (5) COINCIDENT COINCIDENT COINCIDENT FACTOR (6) SYSTEM DEMAND SYSTEM (7) LINE (8) DMD. (KW) LOSSES DMD. (KW)...

AI summary The document provides a summary of energy data for the year ending December 31, 2027, including metrics such as MWH, energy losses, demand factors, and contribution percentages across various service categories like HV transmission, large industrial, and municipal.

REDACTED ELID Tariff Synapse IR-30 Attachment 4 Page 9 of 15 REDACTED (CONFIDENTIAL INFORMATION REMOVED) BUTU Capacity Credit Calc.

AI summary The document presents a capacity credit calculation under the BUTU (Board of Utility and Transportation Users) for the ELID Tariff Synapse IR-30 Attachment 4. A figure is referenced, though the content is redacted and confidential.

Annual Peak of ATL 2,288,527 Annual Energy Requirement of ATL 10,656,168,727 Annual Energy Requirement of ATL 10,656,168,727 Generation-related Trans Assets CWIP $ - $ - $ - Total Generation $ 1,888,883 $ 2,065,526 $ 2,165,402 DISTRIBUTION...

AI summary The text presents detailed financial and operational data regarding the Annual Peak and Annual Energy Requirement of ATL, including various categories of generation, distribution, transmission, and retail costs. It also outlines the classification of generation rate base for different types of plants.

$3,627,090 $2,521,417 $2,850,490 $2,534,080 $2,191,956 $1,916,096 $2,250,818 $2,157,931 $3,711,916 $3,788,118 $33,418,031 Purchased Power Wind $ 13,164,243.69 $ 14,283,765.76 $ 16,273,457.62 $ 13,857,420.27 $ 12,582,203.02 $ 10,596,475.95...

AI summary The text presents a series of financial figures related to energy costs, including purchased power, wind generation, and operational and maintenance costs. These figures are likely part of a regulatory proceeding analyzing financial data from a utility or energy provider in Nova Scotia.

Request IR-1: In their evidence, Brubaker & Associates state: The interruption demand service will not impose resource capacity cost on NS Power because this demand will be served only on an as-available basis. Hence, NS Power can avoid in...

AI summary Brubaker & Associates argue that interruptible demand service will not require capacity charges for NS Power as it is served on an as-available basis, avoiding resource capacity costs. Costs will be recovered via the ELID energy charge, which covers fuel/energy and non-fuel service costs, without requiring an interruptible credit above PHP's 8 MW firm demand.

And further PHP firm demand service will contribute 8 MW to NS Power firm ATL peak demand. Hence, the firm 8 MW demand charge should reflect the PHP allocated cost of including its 8 MW peak demand in NS Power's 3-CP capacity cost allocati...

AI summary PHP's 8 MW firm demand service contributes to NS Power's capacity costs, with ELID energy rates covering interruptible demand beyond this. The text clarifies that no interruptible credit is needed under this ELID structure, as non-fuel costs in the rate cover excess demand. Questions seek clarification on ELID design and PHP's proposal to exclude interruptible credits above 8 MW.

1 Response IR-1: - (a) If the Board adopts an 8 MW demand allocator, the resulting rates will only reflect the costs of providing firm service. In this scenario, because PHP is not being charged for the system capacity required to serve it...

AI summary The response discusses the implications of adopting an 8 MW demand allocator on rates and interruptible credits for PHP, contrasting scenarios where the allocator exceeds 8 MW. It also rejects the proposed ELID tariff, citing inconsistencies with PHP's position on cost causation and credit pricing. The analysis centers on tariff design, demand-side management, and cost recovery mechanisms.

Request IR-3: In their evidence, Brubaker & Associates state: Q IF THE ELID INTERRUPTIBLE CREDIT WAS SET AT NS POWER'S AVOIDED CAPACITY COST OF $13.107/KVA, WOULD PHP PAY ANY CAPACITY COST FOR ITS INTERRUPTIBLE SERVICE? A Yes. The proposed...

AI summary Brubaker & Associates explain that even if the ELID interruptible credit equals NS Power's avoided capacity cost ($13.107/KVA), PHP would still pay capacity costs. The ELID 2027 energy charge ($0.1124/KWh) exceeds NS Power's fuel cost ($0.08299/kWh), generating non-fuel margins. PHP would also pay the difference between the demand charge ($14.310/kVA) and the credit.

Response IR-3: PHP's primary position is that the 3-CP demand allocator should be set at 8 MW to reflect only its firm demand, as interruptible load does not drive system capacity investment costs. Including the 57 MW of interruptible dema...

AI summary PHP argues the 3-CP demand allocator should be set at 8 MW to reflect only firm demand, excluding interruptible load. It proposes a $13.107/KVA interruptible credit as a secondary alternative if the 8 MW allocator is rejected, ensuring economic neutrality for firm customers regarding NS Power's generation investment decisions.

interruptible load is three-fold: - 1. It is based on PHP's historic contribution to winter month system coincident demand when PHP was operating on a different tariff that was subject to dispatch by NS Power and not intended nor anticipat...

AI summary PHP argues that using historic interruptible load data for capacity cost allocation is inappropriate, as it was based on a different tariff and could lead to over-allocation of costs. PHP proposes using 0 kW for winter month system coincident demand under the proposed ATL tariff, as interruptible load is subject to NS Power dispatch.

Request IR-4: - Reference: N-2, Evidence of C. Fitzhenry and M. Gorman, Interruptible Credit, page 12. - (a) Provide all workpapers, source documents, and derivation steps underlying BAI's recommended interruptible credit of $13.107/kVA-mo...

AI summary The proceeding requests documentation on BAI's interruptible credit calculation, including capital costs and methodology, and a comparison with NSPI's approach in the GRA. The reference cites evidence from C. Fitzhenry and M. Gorman regarding interruptible credit mechanisms.

Response IR-4: (a) BAI has not performed the requested analysis. The recommend interruptible credit of $13.107/kVA-month was derived from NS Power's Application, Attachment 1 Extra Large Industrial Dispatchable Tariff, Page 8 of 19, footno...

AI summary BAI did not perform the requested analysis for IR-4 and IR-5. The interruptible credit calculation for ELID class uses winter coincident peak and avoidable peaker costs. Reducing PHP's demand determinant from 65 MW to 8 MW is estimated to reduce revenue requirements by $6.5M (2026) and $9.4M (2027), though BAI has not confirmed reallocation details or secondary cost impacts.

Request IR-8: - Reference: N-3, Evidence of PHP, pages 9-10 (PHP consumption forecast and PHP Wind forecast). - (a) Provide the full workpapers, assumptions, and inputs underlying PHP's 2026 and 2027 consumption forecasts (approximately 77...

AI summary Request IR-8 seeks detailed workpapers and assumptions behind PHP's 2026-2027 energy consumption and PHP Wind production forecasts, reconciliation with NSPI's COSS figures, and analysis of revenue and cost risks from forecast variances. It also asks for modeling of financial responsibilities for discrepancies.

Response IR-9: (a) PHP is currently seeking approval of the ELID tariff modified to address the concerns raised in its Evidence, Exhibit N-3, at page 8, lines 18-31. (b) Please refer to PHP's response to CA IR-5. (c) Generally a below-the-...

AI summary PHP seeks approval for a modified ELID tariff, emphasizing a cost-based ATL rate. The response addresses concerns about tariff impacts on financial sustainability and references prior submissions. Request IR-10 questions PHP about dispatch events, load curtailment, and the rationale for setting the 3CP value at 8 MW despite a recorded low of 9 MW.

Response IR-10: - (a) Real time schedules are sent out in advance of the next several hours, and do not account for any immediate system disturbances. NS Power sends out real time dispatches that are informed by the best available system i...

AI summary NS Power clarifies that real-time dispatches do not account for immediate system disturbances, citing specific dispatch examples for PHP. It argues that interruptible demand does not require incremental capacity, as NS Power reserves capacity only for PHP's 8 MW firm demand. Dispatch records from 2020-2025 show load adjustments during peak periods, with some instances showing significant load reductions.

Request IR-11: - Reference: N-3, Evidence of PHP, pages 12-13. - Preamble: PHP states that there are aspects of PHP's load flexibility that are not being - captured in the ELID filing, and that the benefits from the February 13, 2026, Mari...

AI summary PHP argues that its load flexibility and the February 13, 2026, Maritime Link event's ancillary service value are not fully captured in the ELID filing. It seeks compensation for this value beyond ADC and priority interruptible, requesting a tariff mechanism and cost allocation. PHP also asks to quantify the system value of off-protocol curtailments under ELIADC, including methodology.

Response IR-3: (a) PHP cannot confirm the average number used in the question as it does not have the method used for calculation. PHP confirms that the MWh for 2026 filed in the 2026 AAR Appendix G2 under "PHP Load" Total is stated as 774...

AI summary PHP responds to IR-3 by stating it cannot confirm average load calculations but provides 2026 MWh data (774,456). It outlines forecast submission practices and mentions potential parameter adjustments. IR-4 requests confirmation that transmission facilities can accommodate PHP's maximum load under normal conditions.

omponent of the ELID tariff. PHP acknowledges a BTL alternative "may" have embedded cost-based, non-fuel components. It also may not. Request IR-6: Reference: NS Power Application, pages 8-9 of 19. With respect to the SA priority interrupt...

AI summary NS Power argues that maintaining priority interruptible service provisions in the SA is justified due to system reliability benefits, low annual costs (~$500,000), and potential risks from discontinuation during system transformation. The company proposes retaining the service until the next GRA for further review.

Response IR-8: BAI agrees that the application of the interruptible credit, that is that the per unit credit would be multiplied by a fixed, agreed upon, interruptible demand level, in the same manner as the LIIR class. However, that is wh...

AI summary BAI agrees with the interruptible credit structure for ELID but highlights differences in calculation methods compared to LIIR. ELID load is prioritized for interruption, potentially leading to more interruptions. NS Power argues that interrupting PHP load above 8 MW reduces system costs and supports reliability by using interruption as operating reserves.

Refer to M12661, Exhibit N-2, Evidence of Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, page 18, lines 5-23 and page 19, lines 1-6. specifically, the use of three coincident peak ("3-CP") and cost-causation principle guidance...

AI summary The text references a regulatory proceeding (M12661) and requests information from PHP regarding the application of NARUC guidelines on interruptible capacity, cost-causation principles, and 3-CP allocation methods. It also asks about performance obligations, penalties for non-performance, and statistical methods for allocating capacity.

- (b) The NARUC manual is clear that shifting load can assist the utility to avoid adding new capacity cost. The Manual is also clear that costs should be allocated to the load that causes the cost to be incurred. The interpretation of the...

AI summary The text discusses the NARUC manual's guidance on load shifting to avoid capacity costs and cost allocation. It outlines the ELID Tariff's interruptibility provisions, requiring PHP to reduce load upon NS Power's request, with penalties for non-compliance. The Dispatchable Rider clarifies interruption procedures, and the ELID Tariff mirrors the ELIADC Tariff's penalty structure for non-compliance.

Request IR-6: Refer to M12661, Exhibit N-2, Evidence of Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, regarding the non-fuel savings created by the Dispatchable Rider ("DR"), please answer the following: a) Does PHP believe th...

AI summary The document requests PHP's position on the Dispatchable Rider (DR) component, including its inclusion of avoided transmission and production costs, potential overlap with interruptible credit, and whether DR benefits are fully passed to PHP, along with a table of credit attributes.

Response IR-6: (a) No, avoided transmission and production capacity costs should primarily be captured through the interruptible credit or through an appropriate demand allocation. (b) No. While PHP believes that the Dispatchable Rider doe...

AI summary PHP responds to questions about capacity cost recovery, stating that avoided transmission and production costs should be captured through the interruptible credit or demand allocation. It disagrees with NS Power's proposed DR credit, which would not include capacity cost savings. PHP has not reviewed a finalized methodology for calculating DR benefits related to energy dispatch savings.

(d) Please see the table below: Value Attribute Associated Credit / Component System Energy Savings Dispatchable Rider (DR) Credit Generation Capacity Interruptible Credit Transmission Capacity Interruptible Credit Priority Interruption Pr...

AI summary The document references a table outlining value attributes and associated credits, including Dispatchable Rider (DR) Credit and Interruptible Credit. It also references a request (IR-7) and directs to evidence provided by Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, regarding the utilization of the marginal cost of capacity at $13.107/kVa for the interruptible credit.

Response IR-7: - (a) Confirmed. PHP's estimate would likely be higher as a result of dated peaker capacity cost included in the NS Power estimate. - (b) No, PHP's load must be moved in large increments per approved operating modes. - (c) N...

AI summary Response IR-7 addresses five points: PHP's estimate may be higher due to outdated peaker capacity costs, load must be moved in large increments, no calculation was performed, DR credits capture energy savings beyond capacity costs, and PHP provides priority interruptible service to NS Power.

Request IR-8: Refer to M12661, Exhibit N-2, Evidence of Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, regarding the transmission avoided costs, please answer the following: - a) Identify the NS Power studies relied on to claim...

AI summary Request IR-8 seeks clarification on PHP's transmission avoided costs claims, including studies supporting their demand impact, high-voltage upgrade triggers for varying winter peak contributions, and whether PHP recommends additional transmission capacity credits.

4.1 INCLUSION OF INTERRUPTIBLE LOAD IN 3CP CALCULATION NSP's application includes a provision for PHP interruptible load in the 3CP calculation. PHP's consultants state their view that "PHP's interruptible demands are served on an as-avail...

AI summary NSP proposes excluding PHP's interruptible load from 3CP calculations, arguing it doesn't impact system capacity costs. The Consumer Advocate counters that this would avoid transmission cost responsibility, while InterGroup supports NSP's position but notes alternative allocation methods could address concerns. The debate centers on cost causation and transmission planning implications.

clear why derivation of an interruptible credit rate to PHP would use the same kW demand figure for both coincident and non-coincident PHP peaks, which is not supported by PHP's historical peak load. 2. The proposed cost-based demand charg...

AI summary The text critiques the methodology for deriving an interruptible credit rate for PHP, arguing that using the same kW demand figure for coincident and non-coincident peaks is unsupported by historical data. It highlights that the proposed interruptible credit rate exceeds cost-based demand charges for 2026 and 2027, which is deemed unreasonable. PHP responds that its position aligns with the 2026-2027 GRA SA and references the Board's decision on M12451 regarding a deferral account.

se to Information Request Synapse-7. Exhibit N-10. transmission and generation costs allocated to PHP in accordance with the Cost of Service (as is the case with other ATL customers).[26](#page-11-0) Note however that the ELIADC Tariff, in...

AI summary The text discusses the proposed ELID Tariff, contrasting it with the ELIADC Tariff, particularly the absence of a Variable Capital Charge (VCC) component. It highlights concerns that PHP's DR credit ratio change may not adequately account for VCC payments, which could exceed 20-30% of DR benefits. InterGroup argues the proposal's complexity warrants further reasonableness testing.

ble notification processes and penalties for non-compliance.[33](#page-12-3) NSP explains the value and difference of the PHP Interruptible Credit Rider compared to the Dispatchable Rider as follows: - Interruptible rider reduces the Compa...

AI summary NSP outlines the benefits of the ELID Interruptible Rider, emphasizing reduced firm peak demand, planning relief (avoided generation costs), and reliability during capacity shortfalls. It contrasts this with the Dispatchable Rider, noting mandatory compliance and penalties for non-compliance under the Interruptible Rider.

ation approach focused on a staged analysis, including a baseline financial forecast focusing on utility cash- flow and dividends, with reasonable estimates of future capital spending and rate levels. For Government of Northwest Territorie...

AI summary The text outlines economic/financial analyses for renewable energy projects in the Northwest Territories and Qulliq Energy Corporation's (QEC) initiatives. It includes evaluations of solar, wind, and LNG projects, transmission line extensions, and capacity planning for industrial customers. QEC's work on pricing strategies, IPP programs, and capital project planning is detailed.

Approval of an Above-the-Line Tariff Applicable to Port Hawkesbury Paper (M12661) Bates White Evidence – Confidential Version - at the Goose Harbour facility. The reason for this position is that the P90 level reflected in the COSS (at - t...

AI summary The text argues that the P90 capacity factor of 44% at Goose Harbour is high given Nova Scotia's wind potential, and without operational data, exceeding this with 90% likelihood is unlikely.

II. SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS Q. Please describe your conclusions and recommendations. A. NS Power's proposed tariff is generally reasonable and represents an appropriate transition from a below-the-line to an above-the-li...

AI summary NS Power's proposed ELID tariff is generally reasonable but requires modifications to address concerns about capacity costs and equitable benefit allocation. PHP, the largest electricity customer, has raised issues regarding interruptible credit compensation and demand charge calculations. The ELID tariff aims to replace the expiring ELIADC tariff and ensure PHP pays its incremental costs while allowing NS Power to manage load for system reliability and cost reduction.

1 Q. What are PHP's primary concerns regarding the ELID tariff as proposed by NS 2 Power? 3 A. PHP states that it is concerned about the following components of the proposed tariff: 4 1) Interruptible load of 57 MW; 5 2) The value of the p...

AI summary PHP raises concerns about the ELID tariff proposed by NS Power, focusing on interruptible load, the value of the interruptible credit, the use of a revenue-to-cost ratio exceeding 1.0, and forecast energy requirements for 2026 and 2027. PHP suggests treating demand above 8 MW as non-firm and increasing the interruptible credit by over 50%.

IV. DEMAND CHARGE AND INTERRUPTIBLE CREDIT on PHP's firm load level of 8 MW, with no interruptible credit? A. No. PHP's consultants, Mr. Fitzhenry and Mr. Gorman of Brubaker and Associates (BAI), argue that NS Power's ability to curtail PH...

AI summary The discussion revolves around the appropriate basis for calculating PHP's demand charge and interruptible credit. PHP argues that its interruptible load does not contribute to NS Power's generation and transmission costs, but NS Power counters that transmission costs are driven by both interruptible and firm load, and that PHP's proposal would shift costs to other customers. NS Power also argues that compensating PHP at the full marginal cost would overstate its benefit to other customers.

1.1 Findings and Recommendations - The proposed ELID rate is complicated and unusual in utility rate regulation. No comparable rate could be - identified in Canada, particularly for a major customer on a regulated utility system. - Despite...

AI summary The proposed ELID rate is criticized for being complex and unfair, failing to reflect service costs or value. Recommendations include adjusting capacity values, limiting PHP's DR credits, rejecting interruptibility credits, and ensuring transparency in operating procedures. The ELID's predecessor, ELIADC, is acknowledged as beneficial but requires reforms to address inequities in cost allocation and dispatchability.

- through the Fuel Adjustment Mechanism ("FAM") allocation process as a dollar value credit, and will be allocated so as to be paid for by all ATL customers. - 3. The ELID customer is also proposed to receive an Interruptible Rider ("IR")...

AI summary NSP proposes an ELID tariff with credits via the Fuel Adjustment Mechanism (FAM), Interruptible Rider (IR), and a 10% priority interruptible premium. PHP's wind generation from Goose Harbour Lake is prioritized in energy allocation, with load shaping via DR and potential interruptible demand credits. The proposal outlines a sequence for PHP's energy procurement and system integration.

3.1 Issues in the COS for establishing the ELID ATL Costing (Before Application of the DR) - In the first step of the rate development, PHP is included in the NSP COS study as an ATL customer. - The PHP usage in the COS is intended to refl...

AI summary The document addresses issues in the Cost of Service (COS) study for establishing the ELID ATL Costing for PHP prior to applying the Dispatchable Rider (DR). It emphasizes the need to base capacity inputs on a Constant Base Load (CBL) assumption, recommending a 120 MW capacity value for PHP to align with CBL principles and ensure accurate transmission and generation cost allocation.

re to the high (and uncertain) marginal cost generation, and such costs are now borne by all customers. So the move to ATL is a trade-off for PHP including benefits and costs, not solely a new cost. More substantively, the design of the pr...

AI summary The proposed DR credit risks overcompensating PHP by assuming an unrealistic CBL load profile, potentially harming ATL customers. ELIADC's benefits were overvalued (56% below expectations), as per Bates White's report. Solutions include adjusting CBL to reflect seasonal demand or sharing savings.

30 Added peak demand to 120 MW: $9.4 million (may be less, pending NSP analysis) 1 multiple places, NSP indicates that effectively no PHP is load is typically 12 over 50% larger in capacity than the LI class (120 MW versus 77 MW) and 13 sl...

AI summary The document discusses added peak demand and related costs, noting that NSP indicates no PHP load is typically present. It also outlines the capacity and energy differences between classes and mentions the intent to provide benefits for load shaping activities while maintaining a reasonable ATL rate.

Request IR-3: - Reference: Testimony, page 9, lines 20-23. "The capacity value used in the COS for PHP - should be representative of the expected PHP average demand based on total forecast - energy requirements (prior to non dispatchable w...

AI summary The text discusses a request for clarification regarding the capacity value for PHP in the COS, including whether PHP can operate at the CBL, its impact on costs, and the use of the 'capacity value' in place of the current 3-CP demand allocator. It also asks for the firm and interruptible load parameters Mr. Bowman suggests for PHP.

1 2 wind, PHP will consume 305 GW.h, so that scenario does not appear relevant. 3 4 (b) If PHP operated at 120 MW all year, and consumed 1,051 GW.h of energy, then yes, the system costs would go up. 5 (c) Yes. 6 7 8 9 10 11 (d) No. The 3-C...

AI summary The text discusses the impact of PHP's energy consumption and demand scenarios on system costs and rate-setting. It outlines considerations for determining capacity value, load factors, and the use of different demand approaches, such as 3-CP, for establishing ATL rates, particularly for PHP.

- of PHP loads at times of system constraint, there should be little to no credit via - Interruptiblility Rider ("IR") provided in the ELID tariff." - (a) Does Mr. Bowman agree that the value of interruptibility is currently set to the avo...

AI summary The text presents a series of questions directed at Mr. Bowman regarding the Interruptibility Rider (IR) under the ELID tariff, focusing on how interruptibility credits are calculated, the role of the IR in avoiding capacity costs, and whether operational responses by PHP during system peaks qualify as tangible capacity resources.

26 Response IR-5: 27 (a) This is not clear. Mr. Bowman's understanding is that the interruptibility 28 values are based on $160/kW. In Exhibit N-2, Brubaker and Associates 29 indicate that this value is linked to a dated value of the avoid...

AI summary The response discusses the basis for interruptibility credits, particularly the $160/kW value linked to avoided generation costs. It questions the relevance of using a dated value and highlights that the actual contribution to system capacity avoidance depends on the customer's load during system peaks, not their maximum potential load.

CA Response IR-1: a) The core issue in InterGroup's view is that including only 8MW of PHP's load would under-represent the degree to which PHP makes use of and benefits from the transmission system in its normal course of business. Unreas...

AI summary InterGroup argues that underrepresenting PHP's 8MW load in cost allocation would misallocate costs to other customer classes, citing the FERC's 2020 ER19-1661-002 order. The example highlights how voluntary load reductions during peak events distort transmission usage assessments, leading to inaccurate cost allocations.

PHP Request IR-3: Reference: Testimony, page 6. "The proposed cost-based demand charge is $12.872/kVA for 2026 and $14.310/kVA for 2027. At the rate of $13.107/kVA plus 10% PI premium, the interruptible credit would be $14.42/kVA, thus exc...

AI summary The text discusses the proposed cost-based demand charges for 2026 and 2027, comparing them to an interruptible credit calculation. It raises questions about the regulatory or economic rationale for ensuring that interruptible credits do not exceed embedded cost-of-service demand charges, as well as whether Intergroup agrees that capacity costs are functionalized as energy costs under NSP's COS.

And at p. 16, lines 10-13 and 15-16: Combining both the lower projected PHP gross load, and the higher expected output from Goose Harbour, the net PHP load incorporated in the COSS would more appropriately be 121 GWh rather than the 304 GW...

AI summary The text discusses a discrepancy in PHP's net load projections (121 GWh vs. 304 GWh) and its impact on NSPI's revenue, estimating a $21 million annual shortfall if Energy Charge rates are approved without correction. Questions are raised about Bates White's calculations, the accuracy of the Energy Charge rate, and funding sources for the shortfall.

Request IR-4: Reference : N-20, Bates White Evidence, pp. 16-17: Another issue that is notable, but likely of less significance than proper representation of the Goose Harbour facility capacity, is the fact that the generation of the facil...

AI summary The text discusses the use of P90 versus P50 generation levels in the cost-of-service study (COSS) for the Goose Harbour facility. Bates White argues that while P50 is more appropriate in principle, switching to it without operational data is premature. The questions raised focus on significance, cost impacts, risks, capacity factor calculations, and regulatory mechanisms for updating generation assumptions.

Response IR-4: - (a) We do not believe the use of a P90 value has great significance in part because the assumed capacity factor of 44% is already fairly high, and consistent with historical performance of relatively new and large wind far...

AI summary The response discusses the insignificance of P90 capacity factor estimates for the Goose Harbour wind farm due to high assumed capacity factors, and explains how using P50 estimates would lower PHP net load, increasing ELID Energy Charge rates and shifting system fixed costs to FAM customers.

Issued at Halifax, Nova Scotia, this 22nd day of June 2026. 1 Request IR-1: 15 portion of benefits for other customers (to the appropriate level discussed in (g), 16 above)? 17 18 Response IR-3: 19 20 (a) Not confirmed. Ms. Whited's positi...

AI summary The response discusses the determination of an interruptible credit for PHP, suggesting it should be based on avoided capacity costs and negotiated benefits for other customers, while considering revenue contributions and overall revenue requirements.

l ratepayers if the compensation rate is less than the full avoided cost, but sufficiently high enough to induce participation by those resources, while also accounting for changes in revenue impacts. (c) (i – iii) PHP would be charged for...

AI summary The text discusses compensation rates for PHP, suggesting they should be set below full avoided costs to induce participation while managing revenue impacts. It also proposes charging PHP based on embedded costs to maintain cost causation principles and reduce overall costs to ratepayers.

1 Request IR-4: 2 3 Reference: N-21 – Synapse Evidence, p.9/ pdf p.11, lines 16-17. 4 …[T]here is no above-the-line offering that would serve as a default rate for PHP. 5 (a) Please confirm Ms. Whited's understanding that PHP would meet th...

AI summary The document discusses a regulatory inquiry regarding PHP's eligibility for specific tariff rates and its potential uptake based on evidence provided. It confirms PHP's understanding of eligibility but notes that the proposed tariff has not been costed or priced with PHP's demand and energy forecast, nor would it enable the dispatch of PHP load.

M12661 Date Filed: June 22, 2026 Synapse (IG) Page 10 of 14 1 Request IR-5: 2 3 Reference: N-21 – Synapse Evidence, p. 13/ pdf 15, lines 7-10 and 14-19. 4 5 Q. If PHP's proposal to assess the demand charge on only 8 MW of its 6 demand is n...

AI summary The response to Request IR-5 discusses the theoretical net-avoided-cost figure as an upper bound for negotiated outcomes and confirms that the Board should pre-establish this cap as a condition of negotiation. The respondent also acknowledges the need for further calculation using NSPI's capacity cost data.

Request IR-1: Reference: Testimony, page 12, line 20 to page 13, line 2: "Given that transmission costs are driven by both interruptible and firm load, it would not be appropriate to assign PHP a demand charge based solely on its 8 MW firm...

AI summary The text discusses concerns about how PHP's interruptible load may impact transmission costs and whether it should be held responsible for those costs. It requests analyses showing whether PHP's interruptible load has driven or is expected to drive incremental transmission investment or capacity expansion in Nova Scotia.

Request IR-2: Reference: Testimony, page 13, lines 10-19. "First, compensating PHP at the full marginal cost of generation capacity would overstate the value of its interruptible load from the perspective of other customers. While PHP's in...

AI summary The text discusses the compensation of PHP for its interruptible load, arguing that compensation should be capped at the avoided capacity cost net of its expected revenue contribution under firm service. It raises questions about the appropriate value to net from the avoided capacity cost and whether the expected revenue contribution should be limited to portions of PHP's COS for generation.

Response IR-2: (a) The referenced passage was intended to convey the need to compare two different scenarios: (1) a scenario in PHP is not interruptible and receives no interruptible credit, and in which NS Power procures 57 MW of addition...

AI summary The response discusses two scenarios involving interruptible credits and their impact on revenue and capacity costs. It highlights that interruptible credits should be set to ensure other ATL customers are not worse off and emphasizes the need for a rate and bill impact analysis in setting these credits.

Response IR-3: - (a) Yes. NS Power states on page 8 of its ELID application states that it used the Annual Levelized Avoided Peaker Cost of $160.44/kW. - (b) Yes. - (c) Ms. Whited agrees that the assumed price of a peaker is likely underst...

AI summary NS Power used an Annual Levelized Avoided Peaker Cost of $160.44/kW in its ELID application. Ms. Whited agrees that the assumed price of a peaker is likely understated and that the benefits of PHP's interruptibility are likely higher, but notes that the extent to which other classes share these benefits depends on the interruptible credit level.

Q CAN YOU BRIEFLY SUMMARIZE THE RECOMMENDATIONS OF MS. WHITED? A Synapse witness Melissa Whited recommends that the Board approve the proposed ELID tariff, but subject it to specific, targeted modifications to achieve a more equitable allo...

AI summary Melissa Whited recommends approving the ELID tariff with modifications to ensure fair allocation of capacity costs and system benefits. She opposes PHP's proposal to assess demand charges solely on its 8 MW firm load and rejecting pricing interruptible credit at full marginal cost. Instead, she suggests negotiating a revised credit value to balance PHP's participation and benefit other customers.

3.0 CONCLUSION It is encouraging that the evidence submitted in this proceeding is focused primarily on tariff costing and pricing parameters and, in general, seems to accept the new above-the-line ELID Tariff construct. In this regard, Sy...

AI summary The proceeding concludes that NS Power's proposed ELID Tariff is generally reasonable but requires modifications to address capacity costs and benefit allocation. The ELID Tariff is seen as a positive evolution in service to Port Hawkesbury Paper, though challenges related to its complexity and prior bankruptcies of the pulp and paper operation at Point Tupper are noted.

Request IR-2: Refer to M12661, Exhibit N-1, the Application submitted by NS Power, Section 2.4 Interruptible Service, starting at page 8 of 19, and please answer the following: - a) Describe the rationale for the use of the interruptible c...

AI summary This request (IR-2) asks NS Power to explain the rationale, derivation, and changes in the interruptible credit used in the LIIR, the difference between ELID and ELIADC rates, avoided peaker costs, and the implications of redefining the interruptible rider's credit, including the 10% priority credit and its relation to ancillary services.

1. Describe the rationale for the use of the interruptible credit at the same rate as the large industrial interruptible rider (“LIIR”). 2. Describe the derivation of the credit. Is the credit based on a marginal cost of capacity or embedd...

AI summary The text outlines a series of questions directed at NS Power regarding the rationale, derivation, and implications of various credits and rates, including the interruptible credit, LIIR, ELID, ELIADC, and the Dispatchable Rider. The questions focus on cost calculations, fairness, and alignment with established practices.

Request IR-5: Refer to M12661, Exhibit N-2, Evidence of Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, page 18, lines 5-23 and page 19, lines 1-6. specifically, the use of three coincident peak ("3-CP") and cost-causation princ...

AI summary Request IR-5 asks for clarification on the use of NARUC Manual guidance related to interruptible capacity allocation, cost-causation principles, and penalty mechanisms for non-performance by PHP. It also requests a statistical method for a 3-CP allocator and an explanation of why historical peak contributions are inappropriate.

Request IR-7: Refer to M12661, Exhibit N-2, Evidence of Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP, regarding the utilization of the marginal cost of capacity at $13.107/kVa for the interruptible credit, beginning at page 20...

AI summary The text refers to evidence provided by Colin T. Fitzhenry and Michael G. Gorman on behalf of PHP in M12661, Exhibit N-2, concerning PHP's use of NS Power's estimate of the marginal cost of capacity at $13.107/kVa for an interruptible credit. It requests confirmation and explanation on several related questions regarding PHP's position on capacity valuation, interruptibility, and DR credits.

iff would occur? 2. Would it be a new ATL or a below-the-line tariff? 3. Would PHP require interim service if the alternative tariff was not developed prior to January 1, 2027? If so, under what rate? Request IR-5: Refer to M12661, Exhibit...

AI summary The text contains a series of regulatory questions and requests related to the development of an alternative tariff, the use of NARUC Manual guidance for interruptible capacity allocations, and the potential penalties for non-performance during interruptible events. It also asks for statistical methods aligned with NARUC principles and critiques of historical peak contribution metrics.

ed by NS Power is not appropriate. 8. If 65MWs reflects the historical reliance of interruptibility (including suppressed meter readings), why is this not an appropriate allocation? Request IR-6: Refer to M12661, Exhibit N-2, Evidence of C...

AI summary The text contains several requests for information related to the Dispatchable Rider (DR) and interruptible credit, including questions about the allocation of capacity, the appropriateness of the DR component, and the valuation of capacity. These requests are part of a regulatory proceeding and involve NS Power and PHP.

is duplicative if provided the full avoided cost of capacity? Please explain. 5. Does PHP believe that it provides the same interruptible benefit as LIIR customers? Please explain. Request IR-8: Refer to M12661, Exhibit N-2, Evidence of Co...

AI summary The document contains a series of questions and requests related to PHP's capacity contributions and transmission avoided costs. It asks whether PHP believes its interruptible benefit is the same as LIIR customers and requests clarification on studies and transmission upgrades based on different peak load scenarios.

22 Request IR-2: 23 24 (a) Please provide COSS and resulting tariff reflecting all parameters proposed by PHP in its 25 evidence, including: 26 27 i. designing the capacity charge to reflect PHP's actual 8 MW firm demand rather 28 than the...

AI summary The request asks for updated cost-of-service (COSS) and tariff calculations based on PHP's proposed parameters, including adjustments to capacity charges, interruptible credit, revenue-to-cost ratios, and forecast energy requirements for 2026 and 2027. It also requests updated rates for all customer classes and supporting calculations.

29 Request IR-5: 30 In their evidence, Brubaker & Associates state: 31 32 If the ELID capacity charge is designed to include the cost of firm demand service for a 65 33 MW tariff capacity, then the interruptible credit should be applied to...

AI summary Brubaker & Associates argue that the ELID capacity charge should reflect the marginal cost of capacity, and that the interruptible credit should be applied to 57 MW of the 65 MW service. They request confirmation that the ELID tariff aligns with this position, except for the interruptible credit price.

42 Request IR-6: 43 In their evidence, Brubaker & Associates state: 44 45 The interruption demand service will not impose resource capacity cost on NS Power 46 because this demand will be served only on an as-available basis. Hence, NS Pow...

AI summary Brubaker & Associates argue that interruptible demand does not require a capacity charge as it is served on an as-available basis. They suggest that NS Power can recover associated costs through the ELID energy charge. The request asks for an updated ELID tariff design and COSS reflecting this approach.

23 Request IR-9: 24 In its evidence, PHP proposes the following modifications to the proposed ELID tariff: 25 - 26 1. designing the capacity charge to reflect PHP's actual 8 MW firm demand rather than the 27 proposed 65 MW; - 28 2. adjusti...

AI summary PHP proposes modifications to the ELID tariff, including adjusting capacity charges, interruptible credit, revenue-to-cost ratios, and load forecasts. The request asks NSPI to assess whether these changes are consistent with the 2026-2027 GRA settlement agreement and whether they require re-opening of related matters.

ctice for pricing of the interruptible credit? 2. Please explain why PHP’s interruptible credit should differ from the LIIR Tariff (excluding the priority interruptibility premium)? Request IR-2: 1. Please provide COSS and resulting tariff...

AI summary The text outlines several requests related to the pricing of interruptible credit, tariff design, and cost-of-service models for PHP, including adjustments to capacity charges, revenue-to-cost ratios, and implications for deferral account balances. These requests are part of a regulatory proceeding involving Nova Scotia Power Inc.

I’s proposed PHP deferral account balance (annualized for 2027), clearly stating all assumptions and estimates used in quantifying the implications. Request IR-4: As noted in NPSI’s Application: In accordance with this provision, PHP will...

AI summary The document discusses NSPI’s proposed deferral account balance for 2027, including assumptions and estimates. It also raises questions about line losses in sales to PHP and how they are factored into netting energy from the Goose Harbour Lake wind facility. Additionally, it references Brubaker & Associates' explanation of the ELID capacity charge and interruptible credit calculation.

d. This interruptible credit should be priced at NS Power’s estimated marginal cost of capacity of $13.107/KVA, and updated in the next GRA filing to reflect the current cost of capacity. (N-2 page 3) Please confirm that other than the int...

AI summary The document discusses the pricing of an interruptible credit for NS Power, the ELID tariff design, and cost recovery for interruptible demand. It also requests clarification on tariff design, cost allocation differences, and NSPI’s plans if PHP does not accept the ELID tariff post-2026.

be inconsistent with any terms of the 2026-2027 GRA settlement agreement and why. In answering this question, and without limiting the generality of the foregoing, please also address the following: 1. Please confirm that the 2026 and 2027...

AI summary The document asks whether PHP's proposed changes to load forecasts and capacity cost allocations are consistent with the 2026-2027 GRA settlement agreement, and whether these changes would require re-opening of related matters. It also requests an explanation of NSPI's position on these issues.

1 Request IR-1: 2 In their evidence, Brubaker & Associates state: 3 4 The interruption demand service will not impose resource capacity cost on NS Power 5 because this demand will be served only on an as-available basis. Hence, NS Power ca...

AI summary Brubaker & Associates argue that interruptible demand will not require a capacity charge as it is served on an as-available basis, and that NS Power can recover costs through the ELID energy charge. PHP's firm demand contributes 8 MW to NS Power's peak demand, and any demand above this will be covered by the ELID energy rate without an interruptible credit.

30 Request IR-2: 31 In their evidence, Brubaker & Associates state: 32 33 If the ELID capacity charge is designed to include the cost of firm demand service for a 65 34 MW tariff capacity, then the interruptible credit should be applied to...

AI summary Brubaker & Associates argue that the ELID capacity charge should account for interruptible demand, allowing NS Power to avoid additional resource costs. The interruptible credit should be priced at NS Power's estimated marginal cost of capacity and updated in the next GRA filing. PHP is asked to confirm if the proposed ELID tariff aligns with this position.

3 Request IR-3: 4 In their evidence, Brubaker & Associates state: 5 6 Q IF THE ELID INTERRUPTIBLE CREDIT WAS SET AT NS POWER'S AVOIDED 7 CAPACITY COST OF $13.107/KVA, WOULD PHP PAY ANY CAPACITY COST FOR 8 ITS INTERRUPTIBLE SERVICE? 9 10 A...

AI summary Brubaker & Associates explain that if the ELID interruptible credit is set at NS Power's avoided capacity cost, PHP would still pay capacity costs due to the proposed ELID energy charge exceeding NS Power's average fuel cost, resulting in non-fuel margins being collected by NS Power.

6 Request IR-7: 7 In its evidence, PHP states: 8 9 These events go unnoticed by the public, yet time and again PHP is called upon as a 10 resource for system reliability that is in a grey area between ADC real time dispatches and 11 the NS...

AI summary PHP highlights the need to recognize additional ancillary service value beyond ADC and priority interruptible value in the approval of a new ATL Tariff. It also asks about its proposal for considering this value and its plans beyond 2026 if the ELIADC tariff expires without accepting the ELID tariff.

M12661 NOVA SCOTIA ENERGY BOARD IN THE MATTER OF: The Public Utilities Act , R.S.N.S. 1989, c. 380 as amended -and- IN THE MATTER OF: AN APPLICATION by NOVA SCOTIA POWER INCORPORATED for approval of an Extra Large Industrial Dispatchable A...

AI summary The Consumer Advocate has requested information regarding the ELID tariff for Port Hawkesbury Paper, including claims by Brubaker & Associates that interruptible demand will not require capacity charges and will be recovered through the ELID energy charge.

non-fuel cost of service. Under this ELID design, the ELID will not require an interruptible credit for NS Power interruptible power supply above PHP’s firm demand of 8 MW. (N-2, page 2) And further PHP firm demand service will contribute...

AI summary The text discusses the ELID design and its implications for interruptible credits and capacity costs. It outlines how PHP’s firm demand contributes to NS Power’s capacity costs and how the ELID tariff structure handles interruptible service. Questions are raised about the application of interruptible credits and capacity costs under the proposed ELID tariff.

ir evidence, Brubaker & Associates state: Q IF THE ELID INTERRUPTIBLE CREDIT WAS SET AT NS POWER’S AVOIDED CAPACITY COST OF $13.107/KVA, WOULD PHP PAY ANY CAPACITY COST FOR ITS INTERRUPTIBLE SERVICE? A Yes. The proposed ELID 2027 energy ch...

AI summary The ELID interruptible credit is based on NS Power's avoided capacity cost of $13.107/KVA. PHP would still pay capacity costs due to the difference between the proposed demand charge and the credit. NS Power argues that the credit should reflect the system benefits of PHP's interruptible load, and PHP's position on the coincident peak parameter is requested.

be inconsistent with any terms of the 2026-2027 GRA settlement agreement and why. In answering this question, and without limiting the generality of the foregoing, please also address the following: 1. Please confirm PHP’s understanding th...

AI summary The document asks PHP to explain whether its proposed changes to load forecasts and capacity cost allocations are consistent with the 2026-2027 GRA settlement agreement. It also requests clarification on whether these changes would require re-opening of existing matters. PHP’s evidence highlights its role in system reliability and the need to recognize additional ancillary service value in the approval of a new ATL tariff.

M12661 – NS Power Application for Approval of the ELID Tariff NSPI Information Requests to PHP 1 2 3 site, that includes approximately 4MW that are needed to maintain the shared services required for the NS Power Port Hawkesbury Biomass Pl...

AI summary NS Power is proposing the ELID Tariff for PHP, including a capacity charge based on a 65 MW contribution to the ATL system 3-CP allocation. The proposed interruptible credit rate is significantly lower than the company's established practice, and the ELID interruptible credit may be revisited in the next Grid Reliability Assessment.

ts or procurements for firm load relative to interruptible load? In your response, please also explain whether NS Power assumes that 100% of interruptible load will be available when called, or whether some other value is used, and how tha...

AI summary The text contains a series of questions directed at NS Power regarding the assumptions and planning related to firm and interruptible/dispatchable load, specifically for PHP. It asks about historical data, design assumptions, and asset capacities related to PHP’s firm load.

from PHP during the winter peak, as well as the PHP firm load amount that the asset was designed to serve. 7. What firm load from PHP was the Port Hawkesbury Biomass plant designed to accommodate? 1. Refer to the Application, p. 8, lines 3...

AI summary The document includes questions about the Port Hawkesbury Biomass plant's capacity to serve PHP firm load, the derivation of a 10% credit for priority interruptible service, and the rationale for matching winter month system coincident demand with negotiated firm plus interruptible demand. It also asks for NS Power’s forecast for avoided costs and the comparison of dispatch service to interruptible service for LIIR customers.

r each of the following terms within the proposed Tariff, please describe if the PHPW PPA changes the calculation of the value after it enters service. If it does change the calculation of a value after entering service, please provide a w...

AI summary The text requests clarification on how the PHPW PPA affects the calculation of demand charges, minimum charges, and interruptible/dispatchable riders in the ELID Tariff. It also asks for an explanation of NS Power's conclusion regarding the adequacy of firm supply to accommodate an 8 MW increase in 2026.

f 50 MW is fully ignored. Please break the penalty into the threshold and performance penalty components. 2. How would the firm billing be determined for a single month? In this response, please respond to how the “addition” of incremental...

AI summary The text outlines several questions regarding the ELID Tariff, including how penalties are calculated, how firm billing is determined, and the order of interruptibility. It also requests specific data on penalty payments incurred by PHP and details on the capacity and dispatch order of different tiers within the tariff.

ruptibility be broken into two components 2-A and 2-B with the riders ordered appropriately? 2. Can PHP be dispatched for load reduction prior to the first tier of interruptible load being interrupted, that being Generation Replacement and...

AI summary The text outlines a series of questions related to load management, interruptible load, and operating reserve in the context of energy regulation. It seeks clarification on the dispatch order of PHP, the splitting of load, the meaning of holding load as Operating Reserve, and the derivation of the ELID priority interruptible credit.

during the peak periods of 1/11/2022, 2/15/2022, 12/13/2022, and 12/22/2023? If not, why not? 2. Please provide the date and time of interruptions and direct control actions for PHP for each of 2022, 2023, 2024, and 2025. Please provide an...

AI summary The text includes a series of questions directed at NS Power regarding load interruption events, cost causation related to peak demand, and confidential responses to undertakings and COSS. It focuses on specific dates and the impact of load reduction on resource capacity and grid stability.

under which PHP (or its predecessor owners of the mill) has taken service and specify the applicable tariff in each case. Reference: N-1, ELID Application, page 9 – Priority Interruptible Credit. 1. Please provide all workpapers, calculati...

AI summary The document requests detailed explanations and supporting calculations regarding the priority interruptible credit values, the derivation of the 10% premium, and the distinction between priority interruptibility and DR dispatch. It also seeks clarification on the conditions under which priority interruptibility might be called upon separately from DR dispatch.

14 Request IR-3: - 15 Reference: N-2, Evidence of C. Fitzhenry and M. Gorman, page 3. - 16 Preamble: PHP's consultant, Brubaker & Associates, Inc., states that the current ELID 17 R/C ratio is 1.04373 and recommends an R/C ratio of 1.0 " e...

AI summary The text outlines several requests from a regulatory proceeding, including inquiries about the R/C ratio, interruptible credit calculations, and the impact of reducing PHP's demand determinant on revenue requirements and customer classes. These requests are aimed at ensuring transparency and proper cost allocation.

- 3 Maritime Link trip event and states, "This was neither a real time (RT) schedule dispatch - 4 nor an NSPSO call for interruption." - 5 And Reference: N-2, Evidence of C. Fitzhenry and M. Gorman, page 16, lines 9-11. - 6 Amidst this eve...

AI summary The text references a Maritime Link trip event and questions why PHP concluded it was not a real-time schedule dispatch. It requests a list of load reduction events outside formal protocols, confirmation of dispatch instructions during specific hours, and an explanation of how dispatch control should inform capacity cost allocation under the ELID tariff.

27 1 2 (b) What factors does Ms. Whited believe make a transition appropriate or not appropriate? 13 14 15 16 17 18 19 A. No, for two reasons If PHP were compensated at the full marginal cost without accounting for this avoided contributio...

AI summary Ms. Whited argues that compensating PHP at full marginal cost without accounting for avoided contributions would over-allocate benefits to PHP and shift costs to other customers. The question also asks whether the theoretical net-avoided-cost figure should be used as an upper bound for negotiations and if it can be calculated using NSPI's capacity cost data.

- 31 (f) What annual capacity factor does Bates White believe is more reasonable 32 than the noted 44% annual capacity factor? Please provide the studies or 33 comparables relied upon in answering. 1 (g) In principle, is it appropriate to...

AI summary The document includes questions regarding the annual capacity factor, use of P90 or P50 estimates, and concerns about the predictability of PHP's load and forecast errors. Bates White raises issues about the reliability of assumptions used in setting the ELID Energy Charge and the challenges in forecasting PHP's load due to various operational and external factors.

interruptible load above its 8 MW firm base demand has directly driven, or is forecasted to drive, incremental transmission investment or physical transmission capacity expansion in Nova Scotia. IR-2 Reference: Testimony, page 13, lines 10...

AI summary The document discusses the compensation of PHP for its interruptible load, emphasizing that compensation should be capped at the avoided capacity cost net of its expected revenue contribution under firm service. It raises questions about the calculation and basis of this expected revenue contribution.

osal, would the expected revenue contribution be based on the percentage of PHP's contribution to NSP's planning reserve margin in relation to the total system planning reserve margin? Please explain. (e) Considering that NSP's Application...

AI summary The text discusses the pricing of interruptible credits for large industrial customers, specifically whether the credit should be based on full marginal cost or adjusted to ensure other customers share benefits. It references NSP's established practices and considerations of system costs and avoided capacity.

Application by NS Power for Approval of an Extra Large Industrial Dispatchable Above-the-Line Tariff Applicable to Port Hawkesbury Paper (NSUARB M12661) PHP Information Requests to the IG (Bowman) IR-2 Reference: Testimony, pages 6-7, line...

AI summary The document discusses NS Power's application for an Extra Large Industrial Dispatchable Above-the-Line Tariff for Port Hawkesbury Paper. It includes testimony regarding the ELIADC tariff's contribution to NSP's fixed costs and the use of marginal power costs. Questions are raised about whether marginal power costs are used to fund NSP's embedded cost of service and the appropriate capacity value for PHP's tariff.