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ORDER NUMBER G-265-25
IN THE MATTER OF the Utilities Commission Act, RSBC 1996, Chapter 473
and FortisBC Inc. 2025 Cost of Service Allocation and Revenue Rebalancing
BEFORE: E. B. Lockhart, Panel Chair E. A. Brown, Commissioner
WHEREAS:
on November 13, 2025 ORDER
A. On February 14, 2025, FortisBC Inc. (FBC) filed with the British Columbia Utilities Commission (BCUC), pursuant to sections 58 to 61 of the Utilities Commission Act, its 2025 Cost of Service Allocation study (2025 COSA) and application for approval of revenue rebalancing, as well as approval to establish a new rate base deferral account to record the regulatory proceeding costs associated with the review of the application, effective January 1, 2026 (Original Application);
B. By Order G-60-25, the BCUC established the regulatory timetable for the proceeding, which included public notice of the Original Application, intervener registration, one round of information requests (IRs), and final and reply arguments;
C. On May 15, 2025, FBC filed an update to the Original Application to correct for errors discovered in the 2025 COSA, to present new rebalancing options in light of the updated revenue-to-cost ratios, and to amend its approvals sought to reflect a new preferred rebalancing option and updated transformation discounts, as well as a new non-rate base deferral account titled the Irrigation Rebalancing Phase-in deferral account, effective January 1, 2026 (Application);
D. By Order G-127-25, the BCUC amended the regulatory timetable for the proceeding, which included a second round of information requests, and final and reply arguments;
E. On July 4, 2025, FBC filed Exhibit B-13-1 in response to IR No. 2 on a confidential basis as it contains private customer information for which FBC does not have the authority or permission to disclose; and
F. The BCUC has reviewed the Application, evidence, and arguments filed in the proceeding and makes the following determinations.
Final Order
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Order G-265-25
NOW THEREFORE pursuant to sections 58 to 61 of the Utilities Commission Act and for the reasons outlined in the decision accompanying this order, the BCUC orders as follows:
1. FBC is approved to make the following rate changes, effective January 1, 2026: a. Rebalance all billing-determinant-related rate components of Rate Schedule (RS) 20 Small Commercial Service and RS 22 Commercial Service – Secondary – Time of Use such that revenues are decreased by 2.4 percent;
b. Rebalance all billing-determinant-related rate components of RS 31 Large Commercial Service - Transmission and RS 33 Large Commercial Service – Transmission – Time of Use such that revenues are decreased by 0.3 percent;
c.
Rebalance all billing-determinant-related rate components of RS 40 Wholesale Service – Primary and RS 42 Wholesale Service – Primary – Time of Use such that revenues are increased by 1.1 percent; and
d. Rebalance all billing-determinant-related rate components of RS 60 Irrigation and Drainage and RS 61 Irrigation and Drainage – Time of Use such that revenues are increased by 3.7 percent each year for four years, with the in-season irrigation rate from April to October increasing by 4.8 percent each year for four years.
2. FBC is approved to establish a new non-rate base deferral account, titled the Irrigation Rebalancing Phase-in deferral account, to capture the revenue deficiency resulting from the phase-in for RS 60 customers, attracting FBC’s weighted average cost of capital, to be amortized over four years, effective January 1, 2026, and recovered from all customers through FBC’s general rate increases.
3. FBC is approved to provide the following transformation discounts effective January 1, 2026: a. For RS 21 Commercial Service, $0.4841 per kilowatt ($0.4357 on a kilovolt-ampere [kVA] basis) of Billing Demand;
b. For RS 30 Large Commercial Service – Primary, $5.980 per kVA of Billing Demand; and c. For RS 40 Wholesale Service – Primary, $3.780 per kVA of Billing Demand and under the Energy Charge $0.00926 per kilowatt-hour.
4. FBC is approved to establish a new rate base deferral account, titled the 2025 COSA deferral account, to record the costs associated with the regulatory review of the Application, and to amortize it over one year, commencing January 1, 2026.
5. FBC is directed to file revised tariff pages reflecting the determinations and directives set out in the decision accompanying this order with the BCUC for endorsement at the same time FBC files tariff pages for the general rate changes effective January 1, 2026.
6. Unless otherwise ordered by the BCUC, Exhibit B-13-1 will be held confidential. 7. FBC must comply with all other directives and determinations set out in the decision accompanying this order.
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DATED at the City of Vancouver, in the Province of British Columbia, this 13 BY ORDER Electronically signed by Blair Lockhart E. B. Lockhart Commissioner
Final Order
th
Order G-265-25
day of November 2025.
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FortisBC Inc. 2025 Cost of Service Allocation and Revenue Rebalancing
DECISION
Table of Contents
Page no.
Executive Summary ........................................................................................................................................ i 1.0 Introduction .......................................................................................................................................1 1.1 Background .......................................................................................................................................1 1.2 Approvals Sought .............................................................................................................................1 1.3 Legislative Requirement and Rate Design Principles .......................................................................2 1.4 Regulatory Process and Participants ................................................................................................3 1.5 Structure of this Decision .................................................................................................................3 2.0 2025 Cost of Service Allocation Study and Methodology ......................................................................3 2.1 Data Inputs to the 2025 Cost of Service Allocation Study ................................................................5 2.1.1 Load Forecast Data ..............................................................................................................5 2.1.2 Rate Base Data ....................................................................................................................7 2.1.3 Customer Class Load Factors ...............................................................................................8 2.2 Cost of Service Allocation Study Methodology Changes..................................................................9 2.2.1 Rate Schedule 38 Large Commercial Service – Interruptible Service .................................9 2.2.2 Input Assumptions for the Lighting Rate Class ................................................................. 11 2.3 Other Cost of Service Allocation Study Methodology Issues ........................................................ 13 2.3.1 Use of the Minimum System Study Approach ................................................................. 13 2.3.2 Rate Schedule 37 Large Commercial Service – Stand-by and Maintenance Service ....... 15 2.3.3 Net Metering Data............................................................................................................ 17 2.3.4 Demand Metering Interval ............................................................................................... 19 2.4 Overall Panel Determination on the 2025 Cost of Service Allocation Study ................................ 20 3.0 Range of Reasonableness, Revenue Rebalancing, and Phase in .......................................................... 20 4.0 Other Matters and Approvals Sought ................................................................................................ 26 4.1 Transformation Discounts ............................................................................................................. 26 4.2 2025 Cost of Service Allocation Deferral Account......................................................................... 27 4.3 Timing of Next Cost of Service Allocation Study ........................................................................... 28
APPENDICES APPENDIX A APPENDIX B
LIST OF ACRONYMS EXHIBIT LIST
Order G-265-25
Executive Summary On February 14, 2025, FortisBC Inc. (FBC) filed its 2025 Cost of Service Allocation study (2025 COSA) and application for approval of rate changes and transformation discounts as a result of revenue rebalancing, as well as approval to establish a new rate base deferral account to record the regulatory proceeding costs associated with the review of the application, effective January 1, 2026. On May 15, 2025, FBC updated its application to correct for errors discovered in the 2025 COSA, to present new rebalancing options, and to amend certain approvals sought to reflect the corrections (Application). FBC also seeks approval of a non-rate base deferral account titled the Irrigation Rebalancing Phase-in deferral account to phase in the proposed revenue rebalancing option for rate schedule 60 (Irrigation).
FBC last rebalanced its rates as part of its 2017 COSA and Rate Design Application. In 2020, FBC submitted an updated COSA study that did not result in any adjustments to rates. FBC retained a third-party expert to develop the 2025 COSA with inputs provided by FBC. FBC explains that the 2025 COSA follows the three-step, industry-standard practice used for COSA studies to allocate the cost of service: functionalization, classification, and allocation. When looking at rebalancing, FBC uses a range of reasonableness of 95 to 105 percent to assess which customer class’s revenue-to-cost ratios need to be rebalanced.
The Panel finds that the 2025 COSA methodology employed by FBC is an appropriate basis for setting rates that are just and reasonable. The Panel notes that the 2025 COSA methodology generally follows approved methodologies as established in the 2017 COSA and Rate Design Application and the 2020 COSA. The Panel is satisfied the limited changes in the 2025 COSA have been adequately explained and justified. The Panel also addresses certain issues and recommendations raised by interveners in the decision.
The Panel finds that FBC’s proposed revenue rebalancing option with a phase-in period to mitigate rate shock for rate schedule 60 (Irrigation), strikes the best balance between the relevant Bonbright rate design principles. This option limits the rebalancing to the rate schedules outside the range of reasonableness, yet brings rate schedule 60 (Irrigation) to a revenue-to-cost ratio as close as possible to the range of reasonableness while still maintaining revenue neutrality.
The Panel directs FBC to implement the rate changes of all billing-determinant-related rate components of its rate schedules as proposed, effective January 1, 2026, as a result of revenue rebalancing, with the exception of rate schedule 60 (Irrigation). The Panel directs a four-year phase-in period, instead of the FBC proposed five-year period, for rate schedule 60 (Irrigation) to achieve a quicker rebalancing of its revenue-to-cost ratio while minimizing the annual rate increases to a reasonable level. Accordingly, the Panel approves the establishment of the Irrigation Rebalancing Phase-in deferral account as proposed by FBC, but with an amortization period of four years.
The Panel approves updating the transformation discounts as sought by FBC. The changes are based on costs that FBC updated in the 2025 COSA, which follows a methodology that the Panel found to be an appropriate basis for setting rates that are just and reasonable.
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The Panel approves FBC to establish a new rate base deferral account, titled the 2025 COSA deferral account, to record the actual costs associated with the regulatory review of the Application, and to amortize the deferral account over one year, commencing January 1, 2026. The Panel considers that a one-year amortization period is reasonable because of the relatively small impact to ratepayers.
The Panel is satisfied that FBC will file its next COSA study when there is a significant change in its operations, structure, or rate design and that a new or updated COSA study is necessary following such event. Given the cost and effort involved in preparing this COSA, the Panel does not see the need at this time to direct FBC to file a COSA study by a certain deadline and expects FBC will file the next COSA study when it is practicable and appropriate to do so.
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1.0 Introduction On February 14, 2025, FortisBC Inc. (FBC) filed its 2025 Cost of Service Allocation (2025 COSA) study and application for approval of rate changes and transformation discounts as a result of revenue rebalancing, as well as approval to establish a new rate base deferral account to record the regulatory proceeding costs associated with the review of the application, effective January 1, 2026 (Original Application). 1
On May 15, 2025, FBC filed an update to the Original Application to correct for errors discovered in the 2025 COSA, to present new rebalancing options, and to amend its approvals sought to reflect a new preferred rebalancing option and updated transformation discounts effective January 1, 2026 (Application). FBC also seeks approval of a non-rate base deferral account titled the Irrigation Rebalancing Phase-in deferral account to phase-in the proposed revenue rebalancing option for one of its rate schedules. 2
This decision addresses FBC’s approvals sought in the Application, as well as the appropriateness of the 2025 COSA for setting rates.
1.1 Background FBC explains that a COSA study is a fundamental component of the design of a utility’s rates. It provides important contextual information to assess how rates and rate structures perform against the relevant rate design principles, the effectiveness of the utility’s rates to recover its cost of service, the fairness of cost apportionment among customer classes, and the potential for any undue discrimination or revenue instability due to the rate design. 3
FBC last rebalanced its rates as part of its 2017 COSA and Rate Design Application (2017 COSA and RDA). 2020, FBC submitted an updated COSA (2020 COSA) 5 that did not result in any adjustments to rates. 6
4 In
1.2 Approvals Sought FBC seeks approval of the following: 7 1. To implement the following changes of all billing-determinant-related rate components as a result of revenue rebalancing for the following rate schedules (RS), effective January 1, 2026:
a. RS 20 Small Commercial Service and RS 22 Commercial Service – Secondary – Time of Use such that revenues decrease by 2.4 percent;
1 Exhibit B-1, pp. 2–3. 2 Exhibit B-1-2, pp. 2–3. 3 Exhibit B-1-2, p. 5. 4 FortisBC Inc. 2017 COSA and Rate Design Application. 5 The 2020 COSA was filed as Exhibit B-4 to this proceeding. 6 Exhibit B-1-2, p. 1. 7 Exhibit B-1-2, pp. 2–3; FBC Final Argument, pp. 2–3.
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b. RS 31 Large Commercial Service - Transmission and RS 33 Large Commercial Service – Transmission – Time of Use such that revenues decrease by 0.3 percent;
c.
RS 40 Wholesale Service – Primary and RS 42 Wholesale Service – Primary – Time of Use such that revenues increase by 1.1 percent; and
d. RS 60 Irrigation and Drainage and RS 61 Irrigation and Drainage – Time of Use such that revenues increase by 3.0 percent each year (with the in-season irrigation rate from April to October increasing by 3.9 percent each year) over a five-year phase-in period.
2. To establish a new non-rate base deferral account, titled the Irrigation Rebalancing Phase-in deferral account, attracting FBC’s weighted average cost of capital, to be amortized over five years, effective January 1, 2026, and recovered from all customers through FBC’s general rate increases to facilitate the phase-in for RS 60 and 61.
3. To update the transformation discount offered to customers under RS 21 who choose to take service at the primary distribution voltage, as well as RS 30 and 40 customers who choose to take service at the transmission line voltage level:
a. For RS 21 Commercial Service, from $0.409 to $0.4841 per kilowatt (from $0.371 to $0.4357 on a kilovolt-ampere basis) of Billing Demand;
b. For RS 30 Large Commercial Service – Primary, from $6.727 to $5.980 per kilovolt-ampere of Billing Demand; and
c.
For RS 40 Wholesale Service – Primary, from $3.390 to $3.780 per kilovolt-ampere of Billing Demand for Wires Charge, and from $0.00985 to $0.00926 per kilowatt-hour for Energy Charge.
4. To establish a new rate base deferral account, titled the 2025 COSA deferral account, to record the costs associated with the regulatory review of the Application, and to amortize the deferral account over one year, commencing January 1, 2026.
1.3 Legislative Requirement and Rate Design Principles The Panel reviews this Application pursuant to sections 58 to 61 of the Utilities Commission Act as well as accepted rate design principles. Pursuant to sections 60(1)(a) and (b) of the Utilities Commission Act, when setting rates, the BCUC must consider all proper and relevant matters affecting the rate and must have due regard to setting a rate that is just and reasonable and not unduly discriminatory or unduly preferential. As stated in Sections 59(4) and (5) of the Utilities Commission Act, it is a question of fact, that the BCUC determines, whether a rate is unjust or unreasonable, whether there is undue discrimination, preference, prejudice or disadvantage, or whether a service is offered under substantially similar circumstances and conditions. The BCUC makes these findings of fact based upon the evidence filed.
The Panel also considers the eight rate design principles identified by Dr. James C. Bonbright (Bonbright Principles), 8 which FBC discusses when assessing revenue rebalancing options in the Application. FBC states that it has not applied the eight Bonbright Principles in any priority or with any particular weighting. FBC further states that revenue rebalancing is a complex process of assessing multiple, and sometimes conflicting, principles
8 The Principles of Public Utility Rates, James C. Bonbright, Albert L. Danielsen, David R. Kamerschen (Second Edition, 1988) Public Utilities Reports, pp. 383–384.
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as well as considering the viewpoints from various stakeholders. FBC explains that different rate design principles may have varying levels of importance in different contexts, and this requires the application of experience and judgment to consider the most relevant principles in each unique context. Accordingly, rate design should strive to strike a balance among competing rate design principles based on the specific characteristics of customers in each rate schedule. 9
1.4 Regulatory Process and Participants In accordance with the established regulatory timetable, the BCUC has undertaken a public review of the Application, including the following: 10
• • •
One round of BCUC and intervener information requests (IRs) on the Original Application; One round of BCUC and intervener IRs on the Application; and FBC’s final argument, interveners’ final arguments, and FBC’s reply argument.
The following five parties registered as interveners in this proceeding: • British Columbia Municipal Electric Utilities (BCMEU); • Industrial Customers Group (ICG); • Commercial Energy Consumer Association of British Columbia (the CEC); • British Columbia Old Age Pensioners’ Organization et al. (BCOAPO); and • Residential Consumer Intervener Association (RCIA). 1.5 Structure of this Decision The remainder of this decision is structured as follows: • Section 2.0 discusses FBC’s methodology for the 2025 COSA and whether it provides a reasonable basis for setting rates, in addition to associated issues raised by interveners;
•
•
Section 3.0 assesses FBC’s use of a range of reasonableness in determining which, and to what degree, a customer class’s revenue-to-cost ratio should be rebalanced, as well as FBC’s proposed revenue rebalancing options and associated issues raised by interveners; and
Section 4.0 reviews FBC’s proposed transformation discounts, deferral accounts, and the timing of the next COSA study.
2.0 2025 Cost of Service Allocation Study and Methodology FBC explains that a COSA study allocates the costs of providing utility service to the various customer classes served by the utility based upon the cost-causal relationship associated with specific expenditures. This approach strives to develop a fair and equitable assignment of costs to each customer class so that customers pay for the costs that they cause. 11 In addition, the alignment between rate components and unit costs on an
9 Exhibit B-1-2, p. 6. 10 Orders G-60-25 and G-127-25. 11 Exhibit B-1-1, Section 5, p. 11.
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individual rate basis can diverge and therefore updating COSA studies periodically provides information that can be used to re-establish this alignment. 12 FBC explains that a COSA study is a point in time study with point in time data. 13
FBC retained EES Consulting Inc. (EES), a third-party expert in public utility rate design matters, to develop the 2025 COSA with inputs provided by FBC. FBC explains that EES completed the 2025 COSA following standard utility practice and using inputs and allocation methodologies which are substantially the same as past practice for FBC. 14 The 2025 COSA considered each of the rate schedules associated with Residential, Commercial, Lighting, Irrigation, and Wholesale customers, as well as the impact of FBC’s two market-based rates, Standby and Maintenance Service and the recently approved Large Commercial Interruptible Rate. 15 FBC states that its proposals to rebalance its rates are based on the 2025 COSA, which ensures that rates are fair, equitable and not unduly discriminatory. 16 FBC notes that its target for when it will rebalance rates is when the revenue-to-cost (R/C) ratios in a customer class falls outside of the range of reasonableness (RoR), the endpoints of which are 95 percent and 105 percent. 17 The RoR is discussed further in Section 3.0.
The primary inputs, assumptions and methods included in the 2025 COSA include the following: 18 • The following customer classes, which customers are grouped into, to reflect common usage characteristics or facility requirements:
•
• • • •
The total approved 2024 revenue requirement of $457.2 million, with further adjustments for the revenues of RS 37 and RS 38, as discussed in more detail in Sections 2.3.2 and 2.2.1, respectively, below.
The average of the 2021 and 2022 actual rate base, which totals $1,542.4 million. Average customer count for 2024 of 152,006 and gross load of 3,396 gigawatt-hours. A forecast winter system peak of 777 megawatts (MW) and a forecast summer peak of 629 MW. For Generation, the output from the Kootenay River plants was priced as if it were at the BC Hydro 3808 Tariff rate to determine the equivalent splits in costs between demand and energy, with this split applied to the actual costs of these projects for the purposes of classification.
12 Exhibit B-1-1, Appendix A, Section 1, p. 1. 13 Exhibit B-14, CEC IR 9.2. 14 This includes the 2009 COSA and RDA, the 2017 COSA and RDA, and the 2020 COSA. 15 Exhibit B-1-2, p. 1. 16 Exhibit B-1-1, Section 5, p. 11; FBC Final Argument, p. 1. 17 Exhibit B-1-1, Section 6.2, p. 22. 18 Exhibit B-1-1, pp. 12-15, 17-19; Appendix A, Section 1.3, p. 4 and Section 3.5.2, pp. 24-25.
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•
•
•
Classification of monthly power supply costs as demand-related or energy-related and then allocated to customer classes based on each class’s contribution to system peak and energy loads each month.
Classification of distribution plant based on a Minimum System Study (MSS) approach. A Peak Load Carrying Capability (PLCC) credit was applied to correct for the inherent double counting of demand with the MSS approach.
Allocation of demand-related generation and transmission costs using the two coincident peak (CP) method, which is the sum of two winter and two summer peaks, allocation of demand-related power purchases using the monthly CP, and allocation of demand-related distribution costs using the non-coincident peak (NCP).
FBC highlights the availability of Advanced Metering Infrastructure (AMI) data for detailed hourly load and consumption history in all customer classes as a notable change in the 2025 COSA compared to the 2017 COSA. Using the actual 2022 hourly AMI data, parameters such as load and coincidence factors can be calculated more accurately, which FBC notes as an improvement from the 2017 COSA. 19
FBC outlines the key steps in a COSA study as follows: • The first step, functionalization, is the separation of cost data into the functional activities performed in the operation of a utility (production, transmission and distribution) using FBC’s system of accounts for both the rate base and revenue requirement.
•
•
The second step, classification, determines the portion of the functionalized costs that is related to specific causal factors, such as those related to demand, energy, or customer. Demand-related costs are those incurred to meet a customer’s maximum instantaneous usage requirement (kilowatts or kW). Energy-related costs are those that vary directly with longer periods of consumption (kilowatt hours or kWh). Customer-related costs are those that vary with the number and type of customers served.
The third step, allocation, consists of allocating each of the classified costs to each class of service based on the most equitable method for each specific cost. At that point, the revenue requirement has been allocated to each class of service, and a determination of the necessary revenue adjustments between classes of service can be made. 20
The following Sections 2.1 through 2.3 address issues raised by interveners during the proceeding regarding the 2025 COSA study and methodology, specifically regarding data inputs, methodology changes, and other issues. In Section 2.4, the Panel provides its overall determination on the 2025 COSA.
2.1 Data Inputs to the 2025 Cost of Service Allocation Study 2.1.1 Load Forecast Data FBC calculates the R/C ratios for each rate class based on the forecast revenue and forecast cost of service in the COSA model and uses the resulting ratios to inform the need for revenue rebalancing. FBC explains that using forecasts in the COSA model is consistent with how FBC’s rates and revenues are set, because these are based on the forecast demand and forecast cost of service. 21
19 Exhibit B-1-1, Section 5.1.5, p. 15. 20 Exhibit B-1-1, Section 5.2, pp. 15-16. 21 Exhibit B-8, CEC IR 2.3.
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During the proceeding, the CEC inquired about the load forecast variances by rate class, the impact on the R/C ratios of using actual loads, and the potential impact on R/C ratios from load over-forecasting for Large Commercial rate classes, in particular RS 30 – Large Commercial – Primary. 22 FBC provided Table 1 below, which shows the percentage variance between forecast and actual loads for each rate class for each of the last three COSA studies (i.e. 2017, 2020, and 2025). As shown in the table, the actual load for RS 30 (Large Commercial – Primary) is lower than the forecast load in each of the COSA studies, resulting in forecast variances of -12.6 percent in 2017, -4.7 percent in 2020, and -15.8 percent in 2025. 23
Table 1: Comparison between Forecast and Actual Loads
FBC explains that, in cases where the actual loads were lower than forecast (i.e. load over-forecasting) the actual costs for allocation, such as power supply costs, would also be lower. Therefore, the lower actual costs for allocation purposes would offset the reduced revenue from lower actual load, mitigating the impact on the R/C ratios resulting from load forecasting variances. This, combined with the fact that the difference between forecast and actual load are captured in the approved flow-through deferral account, means that load forecast variances would not have the material impact that the CEC appears to believe they do. 25
The CEC then requested FBC to provide the impact on the R/C ratios if actual loads were used (in retrospect) for each of the last three COSA studies. FBC declined to provide this information and states that a backward-looking re-examination of COSA results using actual load data in conjunction with the forecast cost of service from each COSA is not appropriate to evaluate rates and rate design. 26
Positions of the Parties The CEC submits that the magnitude of the load forecast variances in each of the 2017, 2020, and 2025 COSA studies for the Large Commercial classes would have resulted in an understatement of these classes’ R/C ratios. The CEC recommends the BCUC direct FBC to provide in a compliance filing the CEC-requested information regarding the R/C ratios for RS 30 and RS 31 as per CEC IR 2.3 and CEC IR series 10 (i.e. using actual load). The
22 Exhibit B-8, CEC IR 2.2, 2.3; Exhibit B-14, CEC IR 10.0. 23 Exhibit B-14, CEC IR 10.1. 24 Exhibit B-14, CEC IR 10.3. 25 Exhibit B-14, CEC IR 10.1. 26 Exhibit B-8, CEC IR 2.3.
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CEC also notes that FBC uses the term “mitigating the impact” instead of “offsetting the impact” to describe the effect of the calculations on opposite sides of the R/C ratio. 27
In reply, FBC submits that it is not reasonable to spend the time and resources to provide the information requested by the CEC because using actual load data in conjunction with forecast costs would be unreasonable and inappropriate. FBC also notes that using actual load would be impractical due to the timing of the data and it would introduce a degree of inaccuracy in the COSA that is not aligned with the fair apportionment of costs. 28
Panel Determination The Panel finds FBC’s approach of calculating R/C ratios based on the forecast load in the COSA model for the purposes of revenue rebalancing to be reasonable because using forecasts is consistent with how FBC’s rates and revenues are set. The Panel rejects the CEC’s recommendation for the BCUC to direct FBC to provide the CEC-requested information regarding the R/C ratios for RS 30 and RS 31 in a compliance filing. Although Table 1 above shows that there has generally been a greater variance between actual and forecast load for RS 30 compared to the variances of other rate classes in the last three COSA studies, we are satisfied that, as FBC observes, the lower actual costs would offset the reduced revenue from lower actual load and that this would mitigate the impact on the R/C ratios. Therefore, we accept that any impact is immaterial and see no value in directing FBC to provide the information requested by the CEC in a compliance filing.
2.1.2 Rate Base Data FBC states that the COSA includes a revenue requirement from a forecast test year 2024 but reflects the account detail of actual costs from a historic year 2022 escalated to the approved revenue requirement for 2024 rates. It does not include actual costs, sales, or revenues for 2024 year-to-date. 29 FBC states that the rate base associated with the 2024 revenue requirement is $1.54 billion, which is an average of the 2021 and 2022 actuals. The use of a two-year average is consistent with the 2017 COSA and is intended to smooth out the impact of large capital expenditures. 30 FBC also states that comparing the percentage breakdown of the rate base component between the 2025 COSA and the rate base forecast from FBC’s 2024 Annual Review, shows that using 2024 values would have a negligible impact on the COSA results. 31
Positions of the Parties BCOAPO notes that the two-year average used in the 2017 COSA was based on 2016 and 2017 closing rate base values, which represented the opening and closing values for the test year 2017 and therefore were consistent with the determination of the mid-year rate base for the test year. In contrast, however, BCOAPO notes that, for the 2025 COSA, the test year used is 2024 but the rate base is based on the average of the closing rate bases for the years 2021 and 2022, and not 2023 and 2024. BCOAPO accepts FBC’s approach for purposes of the 2025 COSA given the relatively immaterial impact of using the forecast 2024 values. 32
27 CEC Final Argument, p. 16. 28 FBC Reply Argument, pp. 12–14. 29 Exhibit B-1-1, Section 5.1.3, p. 14, Appendix A, Section 2.2, p. 8. 30 Exhibit B-1-1, Section 5.1.3, p. 14, Appendix A, Section 2.2, p. 8. 31 Exhibit B-9, BCOAPO IR 5.1. 32 BCOAPO Final Argument, pp. 14–15.
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BCOAPO notes that FBC’s 2024 Annual Review provides total rate base values for the Hydro Production, Transmission, Distribution and General Plant categories and the relative proportions differ from those based on the average for 2021 and 2022. It submits that FBC could use the available averages of the year-end values forecast for 2023 and 2024 (i.e. the equivalent to the mid-year 2017 rate base used previously) for each of these major categories and then use the more detailed account information from 2021-2022 to breakdown the need for rate rebalancing. BCOAPO submits that FBC should be directed to use this approach the next time it undertakes a COSA for the purposes of rate rebalancing. 33
In reply, FBC submits that it is unnecessary and would be premature to direct FBC to calculate rate base in future COSAs in the way BCOAPO suggests. FBC always use the best information available, and no direction is needed in this regard. Moreover, FBC submits that the very particular method BCOAPO has suggested is unnecessarily complicated as it is based on a misunderstanding of the information available. 34
Panel Determination The Panel finds FBC’S approach to calculating rate base to be reasonable for the purposes of the 2025 COSA and resulting rebalancing. The Panel is satisfied that FBC uses what it considers to be the best information available at the time of preparing the 2025 COSA. Given the data and timing considerations outlined by FBC when preparing the 2025 COSA, the Panel agrees with FBC’s approach of using the 2021 and 2022 end of year actuals. We note that interveners also accept this approach as reasonable.
The Panel rejects BCOAPO’s recommendation to direct FBC to use BCOAPO’s suggested approach to calculating rate base in the next COSA study. BCOAPO has not demonstrated the need for such a complicated approach, which, moreover, lacks the transparency of FBC’s approach.
2.1.3 Customer Class Load Factors FBC explains that allocating costs in the COSA uses a combination of customer, demand (load), and energy factors. It notes that in the past, developing the necessary load factors required piecing together information from various sources and estimating data. 35 For example, it refers to the 2020 COSA where it acknowledged that for certain customer classes with significant load spread over a relatively small number of customers, year-over-year variation in consumption may result in swings in class load factor leading to R/C ratios that fluctuate in the short term. FBC also noted that a reversal may occur in subsequent years and addressed this in the 2020 COSA by using an average load factor for RS 31, 40, and 41 in the model that considered load factors from the test years of both the 2017 and 2020 COSA studies (i.e. the historical years 2016 and 2019). 36
Since installing automated metering for all customers, however, FBC notes that hourly data is now available on a more accurate aggregate summary basis and this provided the basis for peak demands by class. 37 As a result, FBC notes that the 2025 COSA does not use average load factors for any rate class. It explains that EES did not adjust the 2025 COSA to average certain load factors across studies because the data overall was more complete due to the availability of hourly AMI readings, and averaging a more complete data set with aspects of a less
33 BCOAPO Final Argument, pp. 14–15. 34 FBC Reply Argument, p. 9. 35 Exhibit B-1, Appendix A, Section 3.5, p. 23. 36 Exhibit B-4, p. 3. 37 Exhibit B-1, Appendix A, Section 3.5, p. 23.
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complete data set would tend to dilute the value of higher quality data. 2022. 39
38 For the 2025 COSA, FBC uses data from
Positions of the Parties The CEC recommends that the BCUC direct FBC, at a minimum, to calculate and use average (multi-year) load factors for all rate classes in the next COSA study or to direct FBC to provide a compliance filing making the adjustment to the Commercial rate classes RS 31, RS 40, and RS 41 to reflect multi-year load factors. 40
BCOAPO does not object to EES’s reliance on load factors calculated using a single year’s (2022) actual data for the 2025 COSA. However, BCOAPO submits that FBC should be directed to assess for its next COSA the impact that year to year changes in load factors can have on the R/C ratios and whether the variations are sufficiently significant to warrant the use of averaging for some or all rate classes. 41
In reply, FBC submits that smoothing load factors in the COSA is unnecessary. FBC will consider whether to use average load factors as part of the next COSA study, but it would be premature for the Panel to direct FBC to use average load factors in the next COSA. As a general principle, averaging goes against the point-in-time nature of the COSA, and adds complexity and cost. While there are exceptions to the point-in-time approach (e.g., using two years for rate base and adjusting for known and measurable changes), these are indeed exceptions, as the vast majority of the data are point in time in nature. 42
Panel Determination The Panel finds FBC’s approach of using a single year’s load factors for the purposes of the 2025 COSA to be reasonable. The Panel rejects the CEC’s recommendations for a direction to FBC to make certain adjustments in a compliance filing to reflect multi-year load factors or to use average (multi-year) load factors in the next COSA. The Panel is persuaded that it is not necessary to use average load factors for any rate class in the 2025 COSA because hourly AMI readings are now available, providing a more accurate dataset from which to assign peak demands by class than the multi-year methods employed in previous COSA studies. The Panel also reject’s BCOAPO’s recommendation for a direction to FBC to assess the impact of year-to-year load factor changes and whether the use of averaging for the next COSA is warranted. We do not consider the direction requested by BCOAPO necessary because we are satisfied with FBC’s acknowledgement that it will consider whether to use average load factors in the next COSA study.
2.2 Cost of Service Allocation Study Methodology Changes 2.2.1 Rate Schedule 38 Large Commercial Service – Interruptible Service FBC’s Large Commercial Interruptible Rate (RS 38) is a non-firm, large commercial rate where customers are subject to service suspensions. This service is available to customers whose load would normally be eligible for
38 Exhibit B-5, BCUC IR 9.2.1. 39 Exhibit B-8, CEC IR 3.1. 40 CEC Final Argument, p. 9 41 BCOAPO Final Argument, pp. 17-19. 42 FBC Reply Argument, pp. 5–6.
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service on RS 30 or RS 31. 43 A customer taking service under RS 38 is considered an Interruptible Customer. The BCUC approved RS 38 in 2023, subsequent to FBC’s 2020 COSA, on a five-year pilot basis effective August 1, 2023. 44
FBC proposes to allocate the revenues of RS 38 to all customers as an offset to the revenue requirement for compensating for the use of the system, which is the treatment approved for RS 37 in the 2017 COSA and RDA decision. FBC proposes to apply the same treatment because both RS 37 and RS 38 are calculated based on the monthly hourly Mid-C price in effect when the service is used. 45 FBC explains that both RS 37 and RS 38 rates were developed outside of the COSA process with no intention of recovering embedded costs that are already being recovered through rates. 46
FBC explains that RS 38 is focused primarily on allowing load to connect in instances where it would otherwise not be possible, and RS 38 customers are responsible for all incremental costs to serve them, so other customers are better off having new interruptible sales. 47 This is not unlike RS 37, where other customers are better off having stand-by sales because the alternative would provide no additional revenues. 48
During the proceeding, FBC provided an alternative, although in its view a less appropriate, method to treat RS 38 revenues, which is to create a separate rate class for RS 38 by assigning certain applicable costs or by netting the direct assignments of pass-through costs. However, FBC notes that, even if the R/C ratio of RS 38 were to fall outside the RoR, it would not make sense to rebalance that rate since it is based on a market rate. FBC also notes that while creating this separate rate class has slightly lowered all other R/C ratios, no additional rate classes move outside the RoR. 49
FBC states it has a single customer taking service under RS 38. However, there were no RS 38 revenues for the 2024 test year as the customer’s load was served under RS 31 at the time. FBC considers it appropriate to reflect the change in the COSA load apportionment as a known and measurable change to the test year. Based on the customer’s 2022 total load served under RS 31 and that customer’s RS 31 Contract Demand as determined in the RS 31 Agreement, FBC has estimated the revenue to be approximately $3,574,198. 50
Positions of the Parties Citing the similarity between RS 37 and RS 38 and the BCUC’s previous decision on the treatment of RS 37, BCOAPO does not have concerns with the proposed treatment of RS 38 revenue in the COSA. BCOAPO points out that no RS 38 revenues were included in the 2024 COSA test year, corresponding to no RS 38 revenues under a strict application of the ‘point in time’ principle of a COSA. However, the BCOAPO accepts FBC’s estimating methodology, which employed the 2022 actual load for the single RS 38 customer served under RS
43 Rate Schedule 30 is Large Commercial Service – Primary and provides to customers with a contract Demand of 500 KVA or more. (Tariff Page, RS 30) 44 Decision and Order G-136-23 dated June 12, 2023, p. 32; FortisBC Inc. Large Commercial Interruptible Rate, Final Order G-170-23 dated June 29, 2023, p. 1. 45 Exhibit B-1-1, Section 5.1.2.1, p. 14. 46 Exhibit B-5, BCUC IR 2.4. 47 Exhibit B-5, BCUC IR 2.1. 48 Exhibit B-5, preamble of BCUC IR 1.0. 49 Exhibit B-5, BCUC IR 3.2.1. 50 Exhibit B-1-1, Section 5.1.2.1, p. 13.
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31, the RS 31 contract demand for the RS 38 customer and the mid-C pricing over the same period. Correspondingly, BCOAPO ultimately agrees with FBC’s proposal to include $3,574,198 in RS 38 revenue in the COSA as a known and measurable change. 51
In reply, FBC states that it followed standard industry practice in adjusting for RS 38 revenue as it was a known and measurable change and the adjustment was reasonable. 52
The CEC is satisfied with FBC’s treatment of RS 38 revenue for the 2025 COSA but recommends the BCUC direct FBC to reconsider this treatment in the next COSA. The CEC notes that RS 38 is a recently developed class of service, with no track record and therefore it is premature for FBC to be seeking alternative methodologies for the 2025 COSA. However, in the CEC’s opinion, a further load erosion among large commercial rate schedules may warrant a re-evaluation of the treatment of RS 38 revenue, and recommends that the BCUC direct FBC to consider the impact of customer load transitions from RS 31 to RS 38 in the next COSA. 53
In reply, FBC states that it will take into consideration circumstances present at the time of the next COSA, including any impact of transitions from RS 31 to RS 38 and no direction is needed in this regard. 54
Panel Determination The Panel finds FBC’s proposed treatment for RS 38 revenue to be reasonable. We acknowledge that, similar to RS 37, FBC did not develop RS 38 as part of the COSA process. Since FBC collects revenues at market prices instead of recovering embedded costs, the Panel accepts the rationale for considering the revenue outside the COSA. This treatment recognizes that all ratepayers incur the cost to support the overall system and therefore, similar to RS 37, these same ratepayers should receive the corresponding benefit.
The Panel also finds the proposed value of $3,574,198 to be reasonable as a known and measurable change from the 2024 revenue requirement decision for use in the 2025 COSA. From the evidence before us, the Panel sees no reason to dispute FBC’s data and method and observes BCOAPO’s support.
The Panel is persuaded to maintain the current, as-designed treatment for the 2025 COSA, given that RS 38 is a new service. The Panel, however, also recognizes the potential for the degree of participation to change, either in attracting more customers or losing its single customer. Correspondingly, the Panel expects that FBC will monitor the relevant circumstances of RS 38 and consider whether an alternative treatment for RS 38 would have merit for the next COSA.
2.2.2 Input Assumptions for the Lighting Rate Class For the 2025 COSA, FBC notes that EES changed the input assumptions regarding the Lighting class compared to the 2017 COSA. 55 EES explains that the 2025 COSA does not allocate material amounts of upstream Primary and Secondary rate base (upstream rate base) to Lighting due to the directly assigned costs and the large reduction in demand from the conversion of most lights to LED technology. There is some upstream cost for Lighting, but
51 BCOAPO Final Argument pp. 4–5 52 FBC Reply Argument, p. 4. 53 CEC Final Argument, pp. 7-8 54 FBC Reply Argument, p. 4. 55 Exhibit B-9, BCOAPO IR 1.1.1.
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because there is such a large drop in wattage typically for the more efficient technology, a full upstream allocation would tend to over-allocate the impact based on historical costs. Therefore, the input adjustment to exclude those costs is appropriate. 56 EES further explains that, unlike other rate classes, Lighting has its distribution costs directly assigned because FBC tracks both the capital cost and lighting-related operation and maintenance (O&M) separately. If Lighting were separately allocated costs in addition to those that are directly assigned, it would double count costs attributable to it. 57
Positions of the Parties BCOAPO submits that there is no evidence on the record demonstrating a significant reduction in wattage requirements of street lighting due to the conversion to LED, nor is there evidence that this reduction would reduce to zero the Lighting demand allocators applicable to Primary and Secondary Distribution services, which is effectively the result of EES’ approach. BCOAPO submits that a more appropriate approach would have been to make a specific adjustment to the Lighting demand allocators to account for this reduction in wattage. But even if the BCUC were to accept EES’s explanation that there should be no allocation of demand-related Primary and Secondary Distribution services costs due to the reduction in wattage, BCOAPO remarks that EES’s approach also means that the Lighting class is not allocated a share of the customer-related Primary and Secondary Distribution services costs. Therefore, BCOAPO recommends, for the purpose of the 2025 COSA, that the BCUC direct FBC to revise its COSA methodology such that the Lighting class is allocated an appropriate share (based on its relative customer count) of the customer-related Primary and Secondary Distribution services costs identified using the Minimum System Study. 58
In reply, FBC submits that there is no need to act on this recommendation in the 2025 COSA because Lighting has its distribution costs directly assigned since FBC separately tracks the lighting-related capital and O&M costs. If Lighting were separately allocated costs in addition to those that are directly assigned, double counting of costs attributable to Lighting would occur. Furthermore, FBC states that the switch to LED lighting has resulted in significant and sustained reductions to the wattage requirements for street lighting. It acknowledges that, while it could have used other methods, the result in the 2025 COSA is reasonable in that few distribution costs should be allocated to Lighting and directly allocated costs are a reasonable proxy for this amount. FBC states that it can revisit its methodology in the next COSA but considers that no change is necessary to the 2025 COSA. 59
56 Exhibit B-15, BCOAPO IR 17.1. 57 Exhibit B-9, BCOAPO IR 8.2. 58 BCOAPO Final Argument, p. 7. 59 FBC Reply Argument, p. 7.
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Panel Determination The Panel finds the changed input assumptions for street lighting since the last COSA to be reasonable. The Panel accepts these changes as they reflect the adoption of LED technology since the last COSA. We note that there is no evidence what the difference would be if FBC used a different methodology. However, we accept FBC’s assertion that the assumptions used in the 2025 COSA are reasonable given FBC’s statement about the wattage requirements for street lighting since the adoption of LED. Therefore, we are satisfied that there is no need for FBC to revise its COSA methodology or the 2025 COSA. However, we direct FBC to provide evidence in its next COSA study demonstrating the immaterial difference, such as by comparing the results of alternative methods, and justifying the methodology it proposes.
2.3 Other Cost of Service Allocation Study Methodology Issues 2.3.1 Use of the Minimum System Study Approach One of the key assumptions in the 2025 COSA is that distribution plant is classified based on an MSS approach with a PLCC adjustment, updated to reflect current data. EES states that there are two methods to classify a utility’s distribution costs: 100 percent demand versus the MSS approach. The 100 percent demand methodology assumes that the distribution system is built to meet the NCP, and therefore, classifies distribution costs as 100 percent demand-related. The MSS approach reflects that the system is built in part to connect customers to the system, regardless of load level. Consistent with previous FBC COSA studies, including the 2017 COSA, EES used the MSS approach. 60
The MSS approach assumes a certain size of the distribution plant is required to serve customers’ minimum load requirements, thus the costs associated with such a minimum system are dependent on the number of customers (i.e. customer-related regardless of their level of demand). The remaining costs of the distribution plant are then classified as demand-related since any cost associated with the distribution plant beyond the minimum system requirement is considered to be due to the customers’ demand being greater than the level that a minimum system can serve. While the minimum system is in theory designed to carry only a minimal amount of load, the actual facilities designated as the minimal size can carry an amount of load beyond the theoretical level, therefore overstating the level of customer-related component. To account for this, a PLCC adjustment is incorporated into the analysis. 61
The PLCC adjustment determines how much demand for a rate class can be met by the minimum system and credits this amount against the class’s NCP demands used for determining demand allocators. The adjusted rate class’s NCPs can then be used to allocate the distribution plant’s demand-related costs, eliminating the double-counting. 62
Table 2 below shows FBC’s percentage splits between demand-related and customer-related distribution costs based on the MSS and PLCC adjustment in both 2017 and 2025.
60 Exhibit B-1-1, Appendix A, Section 3.4.2, p. 17. 61 Exhibit B-1-1, Section 5.2.2.2, pp. 17-18. 62 Exhibit B-1-1, Appendix A, Appendix B, p. 42.
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Table 2: Classification of Distribution Accounts using MSS and PLCC Adjustment 63 Classification Distribution Accounts 2017 MSS 2025 MSS Substations, Including Land and Station Equipment 100% Demand 100% Demand
Poles, Towers & Fixtures Conductors & Devices Line Transformers Services, Meters and Installation on Customer Premises Streetlights & Signal Systems
19% Demand 81% Customer 35% Demand 65% Customer 31% Demand 69% Customer 100% Customer Direct Assignment
14% Demand 86% Customer 35% Demand 65% Customer 57% Demand 43% Customer
100% Customer Direct Assignment
EES explains that the increase in the percentage of customer-related costs for poles is likely due to growth on the system occurring in more rural areas whereas the decrease in the percentage of customer-related cost for transformers is likely due to significant changes in transformer costs from 2017 to 2025. Those are the only percentage split changes between the two COSA studies. 64
EES also reviewed methodologies from other jurisdictions and concluded that this review supported maintaining the current approach. 65 Most of the utilities surveyed use the MSS approach, that is, they do not classify 100 percent of investment in distribution plant accounts related to Poles, Towers & Fixtures, Conductors & Devices, and Line Transformers as demand. 66
FBC continues to consider the MSS approach to be reasonable and appropriate for classifying distribution costs. FBC sees no disadvantages of continuing with this approach, while it notes the following benefits: 67
•
• •
The MSS approach is theoretically sound and the calculations reasonable, providing assurances that the results can be reasonably relied on.
Maintaining a consistent method means that results are comparable to previous COSA study results. The MSS approach strikes a reasonable balance between simplicity and complexity. It is more detailed than other approaches taken by other utilities surveyed and relies on real engineering data which is a better approach than simply making an industry-informed general assumption, and it avoids the time and cost of more complex methods.
FBC notes that a more simplified approach may save some time and cost, but there would be less confidence in the reasonableness of the results and there may be impacts to residential and other classes with relatively low
63 Table created based on Exhibit B-1-1, Appendix A, Section 3.4.2, p. 19, Exhibit B-5, BCUC IR 6.1 and on Exhibit B-1, Attachment A, pp. 26-27 of FBC‘s 2017 RDA and COSA Application. 64 Exhibit B-5, BCUC IR 6.1. 65 Exhibit B-1-1, Appendix A, Section 3.4.1, p. 17. 66 Exhibit B-5, BCUC IR 5.2. 67 Exhibit B-5, BCUC IR 5.3.
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average load factors. FBC notes that the MSS data only impacts Distribution Plant allocations; it does not impact Transmission or Power Supply allocations for rate classes that do not take distribution service. If a simplified approach is taken, such as allocating the Distribution Plant based on demand only, then the results would shift additional costs to rate classes with a larger difference between the average use and their maximum use or load factors. As such, rate classes such as the residential class, which have a relatively low average of load factors but a large number of customers, would be most impacted by this type of change in methodology. 68
Positions of the Parties Except for the CEC, interveners either support or take no position on the MSS approach. 69 The CEC recommends the BCUC direct FBC in its next COSA to adopt the simpler alternative approach for classifying distribution costs based on demand only as it would save time and costs compared to the MSS approach and result in R/C ratios that better represent the costs and benefits associated with the provision of service to commercial rate classes with higher load factors. 70
In reply, FBC submits that the simpler, 100 percent demand approach is unreasonable and that the BCUC should not direct it to use this approach for the current or future COSA studies. FBC notes that there would be less confidence in the reasonableness of the results and that there may be impacts to residential and other classes with relatively low average load factors. 71
Panel Determination The Panel finds that the MSS approach with PLCC adjustment continues to be reasonable and appropriate to classify distribution costs in the 2025 COSA. We acknowledge that utilities use a variety of approaches to classify distribution costs. We are not persuaded by the CEC that there is a need to direct FBC to adopt a different methodology at this time. We accept FBC’s rationale, supported by EES as well as prior BCUC review, for continuing to use the MSS approach because it offers a reasonable balance between simplicity and complexity. EES has demonstrated that it has considered the 100 percent demand approach and therefore we are satisfied that EES and FBC will continue to evaluate alternatives to the MSS approach in future COSA studies as needed.
2.3.2 Rate Schedule 37 Large Commercial Service – Stand-by and Maintenance Service
The Large Commercial Service – Stand-by and Maintenance Service (RS 37) is intended to provide the customer with a firm supply of electric power and energy when that customer's generating facilities are not in operation or are operating at less than full rated capability. Access to RS 37 rates is only available to customers taking service under RS 31. 72
68 Exhibit B-5, BCUC IR 5.3. 69 BCOAPO Final Argument, pp. 8-9; RCIA Final Argument, pp. 6-7; BCMEU Final Argument, p. 1. 70 CEC Final Argument, pp. 14-15. 71 FBC Reply Argument, p. 11. 72 FortisBC Tariff Page, RS 37; RS 31 provides Large Commercial Service – Transmission to industrial customers with loads of 5,000 kVA or more. The Customer’s Contract Demand is expressed in KVA and specified in the General Service Agreement between FortisBC and the Customer.
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The RS 37 rates, in effect only when standby-by service is used, are calculated from a price determined at an electricity trading hub and set by market forces (the hourly Mid-C). The RS 37 revenues are outside of the typical embedded COSA framework because the actual rate and revenue are market-driven rather than being based on a value per billing unit that the BCUC has approved. In the 2017 COSA and RDA Application, FBC explained that since the RS 37 rates do not reflect the fully embedded cost resulting from the 2017 COSA, FBC treats the revenues as an offset to the overall revenue requirement thereby compensating all ratepayers for the use of the system, which is paid for by all ratepayers. 73
In the 2017 COSA and RDA decision, the BCUC found this approach appropriate because all customers contribute to the fixed costs of FBC’s system, which is providing service to RS 37, and therefore all customers should receive the benefit of the RS 37 revenue. The BCUC also declined to approve the Industrial Customers Group (ICG)’s request to apply the RS 37 revenues only to the RS 31 customer class. 74 FBC notes there have been no changes in circumstances that would require a change in the treatment of RS 37 revenues in the 2025 COSA. 75
FBC confirms that self-generating customers taking service under RS 37 for stand-by service must also take service under the Large Commercial Transmission rate (RS 31) for standard firm power and there is currently only one customer taking service under RS 37. 76 Typically, a customer served on RS 31 and RS 37 will only have a minimal amount of RS 31 Contract Demand, such that the resulting cost allocation reflected in a COSA study is minimal. FBC explains that, in contrast to RS 31, RS 37 was not developed through a COSA process and RS 37 load is not reflected in the 2025 COSA and therefore does not attract cost allocation and contribute to the embedded system costs. The RS 37 revenue is therefore dispersed to all rate classes as compensation for use of the system required to serve the customer load that is normally self-supplied. 77
Under a scenario where all RS 37 revenues were allocated to RS 31 rather than applying them as an offset to the overall revenue requirement, the R/C ratio for RS 31 would change from 105.3 percent to 117.6 percent. However, FBC cautions that there would likely be a matching increase in directly assigned costs such that the impact to the class would be negligible. 78
Positions of the Parties ICG submits that revenues from RS 37, a class comprising one RS 31 self-generation customer, should be attributed to RS 31 customers for the purposes of computing the RS 31 R/C ratio. ICG reasons this is appropriate since self-generation customers use both RS 31 and RS 37 to meet their load requirements, and since RS 37 is revenue neutral. 79 The directly assigned costs transferred from RS 37 to RS 31 would, in ICG’s opinion, be negligible since costs that merit direct assignment are already assigned to RS 31 or are for customer-owned equipment. Therefore, the commensurate impact to the RS 31 class would (and should) be significant. 80
73 2017 COSA and RDA Decision, p. 17. 74 2017 COSA and RDA Decision, p. 17. 75 Exhibit B-1-1, Section 3.2.2, p. 7. 76 Exhibit B-7, ICG IR 9.1. 77 Exhibit B-5, BCUC IR 1.1. 78 Exhibit B-7, ICG IR 9.1. 79 ICG Final Argument p. 2. 80 ICG Final Argument p. 3.
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In reply, FBC states allocating RS 37 revenues to RS 31 would not satisfy any valid rate design principle given RS 31 and RS 37 are separate services, the former having a COSA based rate that reflects all the RS 31 revenues and allocated costs and the latter being a separate stand-by service with a rate developed outside the COSA. Further, the system costs associated with serving RS 37 are paid by all customers, not just RS 37 customers. Therefore, following the principle of cost causation, and in accordance with the 2017 COSA and RDA decision the RS 37 revenue should be attributed to all customers. 81
Panel Determination The Panel finds applying RS 37 revenues as an offset to the overall revenue requirement remains appropriate to compensate all customers for their payment towards the system costs. The Panel notes this issue was addressed in the 2017 COSA and RDA proceeding and has no evidence on which to re-open the debate. The Panel finds shifting RS 37 revenues to RS 31 for COSA purposes as suggested by ICG would be contrary to the cost causation principle. Although the customer is served under not only RS 37 but also under RS 31, it has minimal RS 31 contract demand attributed to it and therefore minimal resulting cost allocation for COSA purposes. Keeping RS 37 system revenues separate from the COSA aligns with how the RS 37 rate class was developed and therefore remains appropriate for rate-making purposes.
2.3.3 Net Metering Data Net metering is a billing system that allows consumers who generate their own electricity, typically from solar panels, to feed excess electricity back to the grid and receive credits that offset their electricity consumption. FBC notes that although net metering is not part of its overall proposal for rebalancing and does not impact the COSA results, EES retained the net metering data for consistency across historical COSA modelling. 82
Table 3 below shows the net consumption for residential net metering customers across the 2017, 2020, and 2025 COSA studies. Residential net metering amounts to less than 1 percent of the number of residential customers. 83 Table 4 below shows the residential class NCP and CP load factors with and without net metering. As noted above, the NCP and CP load factors are used to allocate the demand-related portion of various rate base items and costs to customer classes, including the residential class.
Table 3: Residential Net Metering: Number of Customers and Net Consumption
81 FBC Final Reply, p. 3 82 Exhibit B-8, CEC IR 6.1 83 Exhibit B-1-1, Application, Appendix A, COSA Report, Appendix A, EES COSA Model, Schedule 8.1, pdf p. 128. The number of residential customers without net metering averaged 128,020, and they accounted for 1,402,953,903 kWh of energy sales in 2022. 84 Exhibit B-8, CEC IR 6.1.
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Table 4: Residential Class NCP and CP Load Factors
EES did not examine commercial net metering separately, nor does FBC propose any rebalancing related to net metering. 86 FBC states that EES did not separate commercial net metering from other commercial data in the same way as for residential due to that information not being part of the COSA model. FBC also notes that it does not have any pending commercial net metering applications. 87 FBC states that the rise in residential net metering could be a factor in reduced summer peak but is unlikely to be a driving factor overall since the capacity of residential net metering installations are not a significant portion of the overall load of FBC. The COSA methodology uses information for forecast system peak provided by FBC but does not provide any qualitative or quantitative analysis on why the forecasts change over time, as these considerations are not part of the scope of the study. 88
Positions of the Parties The CEC was the only intervener to comment on this matter. The CEC recommends that the BCUC direct FBC to augment the next iteration of its COSA model to (i) separately track and report on net consumption data for commercial net metering applications in the same manner as it does for residential, and (ii) track and report on net metering grid exports, separately for residential and commercial installation in a similar format as net consumption figures. 89 The CEC also recommends the BCUC direct FBC to discuss in its next COSA the effects of increased net metering penetration levels on COSA allocations, and if applicable, on the MSS scope. Alternatively, the BCUC could consider directing FBC to provide a compliance filing including the 2025 COSA of NCP and CP load factors for the Commercial rate classes that reflect commercial net metering data. 90
In reply, FBC observes that net metering is immaterial to the COSA at this time. For example, the annual NCP and CP load factor is virtually the same for the Residential class with and without net metering. As there are even fewer commercial net metering customers than residential, FBC submits there is no benefit to filing a compliance filing with the NCP and CP load factors for the Commercial rate classes that reflect commercial net metering data as it would have no material impact and would serve no purpose. Furthermore, FBC submits that net metering would have no impact on the MSS because the net metering rate has an installed-system cap set equal to the annual consumption, which minimizes exports by design. Finally, FBC notes that it prepares its COSA using the best available information at the time and as net metering grows, it recognizes that it will need to consider the impacts in its COSA studies to ensure customers are paying their fair share of system costs. Therefore, FBC submits, no direction is needed with respect to net metering. 91
85 Exhibit B-8, CEC IR 6.3. 86 Exhibit B-8, CEC IR 6.1. 87 Exhibit B-14, CEC IR 13.1. 88 Exhibit B-14, CEC IR 13.3. 89 CEC Final Argument, p. 1. 90 CEC Final Argument, p. 13. 91 FBC Reply Argument, pp. 10–11.
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Panel Determination The Panel finds that net metering has an immaterial impact on the COSA at this time. The Panel is persuaded by FBC’s evidence showing that the annual NCP and CP load factor is virtually the same for the Residential class with and without net metering demonstrating that net metering has an immaterial impact on the 2025 COSA. Therefore, no direction to FBC is necessary in this regard. Accordingly, the Panel rejects the CEC’s recommendation for a direction to FBC to provide certain information related to net metering in FBC’s next COSA or in a compliance filing. The Panel is satisfied with FBC’s statement that as net metering grows, it will consider the impacts in its COSA studies. Further, given that there are even fewer commercial net metering customers than residential, the Panel sees no benefit to requiring FBC to file data specific to commercial net metering.
2.3.4 Demand Metering Interval FBC observes that the implementation of AMI provides it with hourly data. EES confirms that hourly intervals for demand are the most available for all rate classes and the most common interval in power supply markets and thus appropriate for FBC’s 2025 COSA. 92
Positions of the Parties ICG states that it does not take issue with EES’s use of an hourly demand metering interval for RS 31 in the 2025 COSA, however, it submits that it is unfair for FBC to use a 15-minute demand metering interval for the RS 31 rate class for billing purposes (i.e. in the Electric Tariff). ICG requests that the BCUC “compel” FBC to adopt the 30-minute interval for demand billing in its electric tariff. 93
In reply, FBC submits that the topic of which demand window FBC should use in its electric tariff is a rate design issue that is beyond the scope of the current proceeding, and it has not been the subject of any evidence in this proceeding. FBC submits that EES’s assumption regarding demand windows for the purposes of conducting its COSA study has no bearing on demand windows that FBC uses for billing purposes.
Panel Determination The Panel finds EES’ use of an hourly demand interval for RS 31 for the purposes of conducting the 2025 COSA to be reasonable, which ICG does not take issue with, as hourly intervals for demand are the most available for all rate classes. The Panel rejects ICG’s recommendation to direct FBC to revise the terms of its Electric Tariff to reflect a 30-minute demand interval. We are persuaded that the demand windows used for the 2025 COSA have no direct bearing on the demand windows used for billing purposes. The issue of which demand window FBC should be using for billing purposes is a rate design matter that is beyond the scope of this proceeding.
92 Exhibit B-13, ICG IR 4.1. 93 ICG Final Argument, pp. 5, 7.
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2.4 Overall Panel Determination on the 2025 Cost of Service Allocation Study The Panel finds that the 2025 COSA methodology employed by FBC is an appropriate basis for setting rates that are just and reasonable. The Panel notes that the 2025 COSA methodology generally follows approved methodologies as established in the 2017 COSA and RDA and the 2020 COSA. The Panel is satisfied the limited changes including the use of AMI data and the treatment of RS 38 have been adequately explained and justified by EES and FBC.
3.0 Range of Reasonableness, Revenue Rebalancing, and Phase in This section addresses FBC’s approach in assessing which customer class’s R/C ratio need to be rebalanced, provides an overview of the R/C ratios resulting from the 2025 COSA, and FBC’s proposal for rate rebalancing.
FBC uses a Range of Reasonableness (RoR) of 95 to 105 percent to assess which customer class’s R/C ratio need to be rebalanced. FBC considers that each customer class’s R/C ratio that falls within the RoR is recovering its fair cost and does not need rebalancing. However, a customer class’s R/C ratio that falls outside the RoR would indicate that revenues are either insufficient or exceed the cost of service, which suggests that rate rebalancing may be needed. Therefore, FBC proposes rebalancing to move only those classes that are outside the range to its nearest boundary rather than to unity. 94
FBC explains that it is industry standard practice to assess R/C ratios based on whether they fall within an established RoR, which is then used to evaluate whether revenue rebalancing may be needed. The use of an RoR is warranted because cost allocations in a COSA study necessarily involve assumptions, estimates, simplifications, judgements and generalizations. FBC notes that its use of a 95 to 105 RoR is consistent with past BCUC determinations, 95 and its approach of rebalancing to within the RoR rather than to unity is consistent with recent BCUC determinations and other Canadian regulators’ determinations. 96 Specifically, in the recent Fortis Energy Inc. (FEI) 2023 COSA and Revenue Rebalancing Decision, the BCUC stated that it agrees with FEI’s approach to use an R/C range “within which a rate schedule’s revenue is considered to be recovering its costs to assess the need to rebalance a rate class.” 97 Table 5 below summarizes the R/C ratios in the 2025 COSA.
94 Exhibit B-1-1, pp. 21, 25. 95 Exhibit B-1-1, p. 21; FBC 2009 COSA and RDA Decision, p. 78; FBC 2017 COSA and RDA Decision, p. 26. 96 Exhibit B-1-1, pp. 22–25; FEI 2016 Rate Design Application Decision, pp. 41–42; FEI 2023 COSA and Revenue Rebalancing Decision, pp. 20–21, 25–26; Ontario Energy Board issued Filing Requirements for Electricity Distribution Rate Applications – 2022 Edition for 2023 Rate Applications – For Small Utilities, chapter 2A; Nova Scotia Utility and Review Board, IN THE MATTER OF AN APPLICATION of the RIVERPORT ELECTRIC LIGHT COMMISSION for Approval of Amendments to its Schedule of Rates and Charges for the provision of electric supply and services to its customers and its Schedule of Rules and Regulations 2023 NSUARB 56 M10810. 97 FEI 2023 COSA and Revenue Rebalancing Decision, p. 20.
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Table 5: 2025 COSA R/C Ratios
As shown in the table above, the R/C ratios of five customer classes are within the RoR, while the remaining four fall outside the range. Specifically, the Small Commercial (RS 20) and Large Commercial Transmission (RS 31) customer classes are above the RoR, while the Irrigation (RS 60) and Wholesale Primary (RS 40) classes are below the RoR.
FBC notes that a simple shift of the revenue between the rate schedules that are outside the RoR (RS 20, RS 31, RS 40, and RS 60) is not feasible because the total decrease in revenues resulting from bringing RS 20 and RS 31 down to 105 percent is less than the revenue required to bring RS 40 and RS 60 up to 95 percent. Thus, rebalancing these four rate schedules to the nearest RoR boundary would result in the rebalancing not being revenue neutral and a significant rate impact to RS 60 customers. 99
FBC assesses and compares the following five rebalancing options to bring the R/C ratios of the four customer classes within the RoR while maintaining revenue neutrality:
•
•
• •
•
Option 1: rebalance all out-of-range rate schedules to the RoR boundary, with additional credit from rebalancing allocated to other rate schedules currently with R/C ratios above 100 percent; 100
Option 2: rebalance RS 20, RS 31, and RS 40 to the RoR boundary, and rebalance RS 60 to achieve revenue neutrality; 101
Option 3: rebalance RS 01, 20, 31, 40, 41, 50 and 60, with the R/C ratio of RS 60 capped at 85 percent; 102 Option 4: rebalance RS 20 and RS 31 to the RoR boundary, cap RS 60 at a 5 percent rate increase, and rebalance RS 40 to achieve revenue neutrality; 103 and
Option 5: rebalance RS 31 and RS 40 to the RoR boundary, cap RS 60 at an R/C ratio of 80 percent, and rebalance RS 20 to achieve revenue neutrality. 104
98 Exhibit B-1-1, Table 5-5, pp. 19–20. 99 Exhibit B-1-1, p. 26. 100 Exhibit B-1-1, pp. 27–29. 101 Exhibit B-1-1, pp. 29–30. 102 Exhibit B-1-1, pp. 30–31. 103 Exhibit B-1-1, pp. 32–33. 104 Exhibit B-1-1, pp. 33–34.
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Table 6 below summarizes the revenue shifts and the resulting R/C ratios of each rate schedule, while Table 7 below summarizes the estimated bill impact for the average customer by rate schedule for each rebalancing option.
Table 6: Revenue Shifts and Resulting R/C Ratios Between Rate Schedules for Each Rebalancing Option
Table 7: Monthly Bill Impact for an Average Customer in Each Rate Schedule for Each Rebalancing Option
FBC notes the following regarding the rebalancing options as shown in the above tables: 107 • Only Option 1 rebalances all rate schedules to within the RoR but also leads to a 22.9 percent rate increase to RS 60 customers.
•
•
Option 2 results in all rate schedules moving to within the RoR except for RS 60, and results in no impacts to the rate schedules that are already within the RoR. This option moves RS 60 closer to the lower bound (from 77.3 percent to 88.9 percent) and leads to a 14.9 percent rate increase for those customers.
Option 3 better mitigates the rate impact to RS 60 compared to Options 1 and 2 by capping the R/C ratio of RS 60 at 85 percent, but still results in a rate increase of 9.9 percent for those customers. This option
105 Exhibit B-1-1, Table 7-6, p. 34. 106 Exhibit B-1-1, Table 7-7, p. 35. 107 Exhibit B-1-1, pp. 35–36.
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•
•
affects the most rate schedules, as all rate schedules will be rebalanced except for RS 21 and RS 30 (albeit the impact on most rate schedules is minor at 0.1 percent).
Option 4 limits the rebalancing to the rate schedules outside of the RoR and, by capping the rate increase at 5 percent for RS 60, the rate impacts for all rate classes subject to rebalancing are reasonably mitigated. However, RS 60’s R/C ratio will be at 81.2 percent, which is still well below the lower bound of the RoR, and, to achieve revenue neutrality, RS 40 will be rebalanced to 95.7 percent, which is only slightly within the lower bound of the RoR.
Option 5, similar to Option 4, limits the rebalancing to the rate schedules outside of the RoR, but mitigates the rate impact to RS 60 by capping its R/C ratio at 80 percent. However, to achieve revenue neutrality, RS 20 is only moved from an R/C ratio of 107.5 percent to 106.0 percent, which is still outside the upper bound of the RoR.
In evaluating revenue rebalancing options, FBC applied the eight Bonbright Principles. FBC considers that all five of its rebalancing options will have either no impact or minimal impact to Bonbright Principle 1 – Recovering the Cost of Service, Principle 3 – Price signals that encourage efficient use and discourage inefficient use, Principle 5 – Practical and cost-effective to implement, Principle 7 – Revenue stability, and Principle 8 – Avoidance of undue discrimination. Thus, FBC was primarily guided by the following Bonbright Principles when considering the rebalancing options: 108
•
•
•
Principle 2 – Fair apportionment of costs among customers: FBC considered the extent to which all R/C ratios fall within the RoR of 95 percent to 105 percent, such that the cost recovery through each rate schedule closely reflects the fair apportionment of costs from each customer group.
Principle 4 – Customer understanding and acceptance: FBC considered the number of rate schedules that would be adjusted and, in particular, whether any customer group would be adjusted even though their R/C ratio is already within the RoR.
Principle 6 – Rate stability (customer rate impact should be managed): FBC considered whether any customer group would experience significant rate increases or rate shock (an increase greater than 10 percent in any year).
Based on FBC’s evaluation of the revenue rebalancing options against the Bonbright Principles, FBC proposes Option 2 as the preferred option because it reflects the best balance of the rate design principles compared to the other options. 109 To mitigate the rate impact to RS 60 customers from rebalancing, FBC proposes a phase-in approach for RS 60. Table 8 below summarizes the bill impact to RS 60 customers of phase-in periods ranging from 1 year to 5 years. The table shows that a five-year phase-in period will reduce the immediate impact to RS 60 customers from 14.9 percent to 3.0 percent.
108 Exhibit B-1-1, pp. 26–27. 109 Exhibit B-1-1, p. 36.
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Table 8: Bill Impact to RS 60 Customers over a Phase-in Period from One to Five Years
FBC considers a 5-year phase-in period the most appropriate as it avoids rate shock even when considering the combined impact of the rebalancing and FBC’s annual general rate increases, which have been in the range of 4 to 6 percent in recent years. 111 FBC notes that Irrigation customers are charged at RS 60 rates during the in-season (i.e. from April to October) and charged at RS 20 or RS 21 rates the remainder of the year. Therefore, for the overall revenue from RS 60 to increase by 3.0 percent based on a 5-year phase in period, the irrigation in-season rates will need to increase by approximately 3.9 percent each year. 112
To facilitate the phase-in of the rate impact to RS 60 customers and maintain overall revenue neutrality, FBC seeks approval of a non-rate base deferral account, titled the Irrigation Rebalancing Phase-in deferral account, attracting FBC’s weighted average cost of capital, to capture the revenue deficiency resulting from the phase-in for RS 60 customers. FBC proposes to amortize the deferral account over the same 5-year phase-in period and recover the balance from all customers through FBC’s general rate increases. 113 The estimated impact to all rate schedules of the proposed deferral account is an incremental rate increase of 0.1 percent in the first year, which then decreases each year thereafter. 114
Positions of the Parties Except for the CEC, interveners either support or do not oppose FBC’s use of a 95 percent to 105 percent RoR and the approach of moving any class outside the RoR toward the nearest boundary rather than to unity. 115 The CEC recommends that the BCUC direct FBC to rebalance R/C ratios that are within the RoR boundaries under circumstances where more rate classes can be accommodated well within the boundaries to increase fairness for all rate classes. 116
In reply to the CEC, FBC submits that there is no evidence to support that an R/C ratio at the boundary of the RoR is any less fair than an R/C ratio within the RoR since an R/C ratio falling anywhere within the RoR is considered to be recovering its full cost of service. 117
Except for the CEC, interveners also generally support FBC’s proposed Option 2. BCMEU and RCIA support Option 2 with a 5-year phase-in period for RS 60. 118 BCOAPO supports Option 2, but with a shorter phase-in period of either 3 or 4 years. 119 ICG supports Option 2, but with an adjustment to the RS 31 R/C ratio to include
110 Exhibit B-1-1, Table 7-9, p. 36. 111 Exhibit B-1-1, p. 36; Exhibit B-5, BCUC IR 8.1.2. 112 Exhibit B-1-1, p. 37. 113 Exhibit B-1-1, p. 37. 114 Exhibit B-11, BCUC IR 13.2. 115 BCOAPO Final Argument, pp. 20, 22; RCIA Final Argument, p. 7. 116 CEC Final Argument, p. 19. 117 FBC Reply Argument, p. 16. 118 BCMEU Final Argument; RCIA Final Argument, pp. 9, 10. 119 BCOAPO Final Argument, pp. 30, 40.
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RS 37 revenues, as discussed in Section 2.3.2 of this decision. 120 The CEC supports Option 3 because it better mitigates the rate impact to RS 60 by capping the R/C ratio at 85 percent instead of 88.9 percent, while minimizing the impacts on other affected rate classes. 121
Except for BCOAPO, interveners either support or do not oppose FBC’s proposed Irrigation Rebalancing Phase-in deferral account. BCOAPO supports a shorter amortization period to align with a shorter phase-in period of the revenue rebalancing for RS 60. 122
In reply to BCOAPO, FBC submits that phase-in periods of three or four years would result in rate increases of 5.0 percent and 3.7 percent, respectively, to RS 60 customers or increases of 6.4 percent and 4.8 percent, respectively, for the RS 60 in-season rates. When considered in combination with annual general rate increases, assumed to be in the range of 4 to 6 percent, FBC argues that shorter phase-in periods could result in rate shock for RS 60 customers. 123
Regarding the CEC’s recommendation of Option 3, FBC submits that capping RS 60’s R/C ratio at 85 percent, at the expense of other rate schedules (i.e. RS 1, RS 41 and RS 50), is not as reasonable as Option 2, which brings RS 60 closer to the RoR without increasing the R/C ratio of any other customer class that is already within the RoR. 124
Panel Determination The Panel finds FBC’s approach of using a RoR of 95 to 105 percent to assess whether a customer class’s R/C ratio needs to be rebalanced, reasonable. The Panel also finds rebalancing those classes that are outside the range to or towards its nearest boundary to be reasonable. As FBC has noted, the 2025 COSA results are imprecise, being subject to various assumptions, estimates and judgements. The Panel finds that FBC’s approach is consistent with past BCUC determinations and sees no changes in circumstances that would warrant a change in approach. The Panel is not persuaded by the CEC that a R/C ratio at the boundary of the RoR is less fair than an R/C ratio that is within the boundary. Therefore, the Panel rejects the CEC’s recommendation to direct FBC to rebalance R/C ratios that are within the RoR boundaries.
The Panel finds that Option 2, with a phase-in period to mitigate rate shock for RS 60, strikes the best balance between the relevant Bonbright rate design principles. Although Option 2 brings the R/C ratio of RS 60 closer to the RoR, at 88.9 percent, it is still outside the lower boundary of the range. Considering the large rate increase to RS 60 customers that would be required to bring the R/C ratio to the lower bound of 95 percent, the Panel is satisfied that Option 2 is the best option. This is because, of the options considered, Option 2 limits the rebalancing to the rate schedules outside the RoR, yet brings RS 60 to an R/C ratio as close as possible to the RoR while still maintaining revenue neutrality. Therefore, the Panel approves the revenue rebalancing of FBC’s rate schedules as set out in Option 2.
120 ICG Final Argument, PDF p. 2. 121 CEC Final Argument, pp. 20, 21. 122 BCOAPO Final Argument, pp. 40 – 41; RCIA Final Argument, p. 9; CEC Final Argument, p. 21. 123 FBC Reply Argument, pp. 17 – 18. 124 FBC Reply Argument, p. 20.
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The Panel finds the appropriate phase-in period for the rate impact to RS 60 customers to be four years. Although FBC proposes a five-year period, we find that a four-year period strikes a better balance of a quicker rebalancing of RS 60’s R/C ratio while minimizing the annual rate increases to a reasonable level. We note that under FBC’s proposed five-year phase-in period, when combined with an estimate of FBC’s general rate increases, the total annual rate increase to RS 60 customers is up to 9.0 percent or up to 9.9 percent. 125 Compared to a four-year phase-in period, where the total annual rate increase is up to 9.7 percent or up to 10.8 percent, 126 the difference is less than 1 percent. While it is generally accepted that annual rate increases greater than 10 percent is considered rate shock, the Panel does not consider it reasonable to delay reaching the targeted R/C ratio for RS 60 by another year for what amounts to less than a 1 percent difference in rate impact.
Accordingly, the Panel directs FBC to implement the rate changes of all billing-determinant-related rate components of its rate schedules as follows, effective January 1, 2026, as a result of revenue rebalancing:
•
•
•
•
RS 20 Small Commercial Service and RS 22 Commercial Service – Secondary – Time of Use such that revenues decrease by 2.4 percent;
RS 31 Large Commercial Service - Transmission and RS 33 Large Commercial Service – Transmission – Time of Use such that revenues decrease by 0.3 percent;
RS 40 Wholesale Service – Primary and RS 42 Wholesale Service – Primary – Time of Use such that revenues increase by 1.1 percent; and
RS 60 Irrigation and Drainage and RS 61 Irrigation and Drainage – Time of Use such that revenues increase by 3.7 percent each year (with the in-season irrigation rate from April to October increasing by 4.8 percent each year) over a four-year phase-in period.
The Panel approves the establishment of the Irrigation Rebalancing Phase-in deferral account as proposed by FBC, but with an amortization period of four years to align with the phase-in period for the rate impact to RS 60 customers.
4.0 Other Matters and Approvals Sought This section reviews various other matters and approvals sought including updates to transformation discounts resulting from the 2025 COSA, FBC’s proposed 2025 Cost of Service Allocation deferral account, and the timing of FBC’s next COSA study.
4.1 Transformation Discounts As a result of the 2025 COSA, FBC has proposed a number of changes to certain transformation discounts. For customers under RS 21, 30, and 40, delivery voltage discounts are available in consideration of the variations from the typical service connection. FBC has 27 customers under RS 21, two customers under RS 30, and one customer under RS 40 that are taking service at the higher voltage with the transformation discount. 127
125 9.0 percent = 3.0 percent COSA impact + 6.0 percent assumed general rate increase; 9.9 percent = 3.9 percent COSA impact + 6.0 percent assumed general rate increase. 126 9.7 percent = 3.7 percent COSA impact + 6.0 percent assumed general rate increase; 10.8 percent = 4.8 percent COSA impact + 6.0 percent assumed general rate increase. 127 Exhibit B-1-1, p. 38.
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For RS 21, FBC explains that the rate is designed on the basis that customers receive service at the secondary voltage. However, some customers might choose to own the transformation equipment required to convert their service voltage from the primary level to the secondary level. In these cases, the customer is taking service at the primary voltage available at the location of the interconnection, and the customer is entitled to a discount from the demand charge under the rate schedule as transformation and secondary costs would normally be included in the rate. Similarly, the rates of RS 30 and RS 40 are designed on the basis that customers are normally taking service at the primary voltage. However, if the customers choose to take service at the transmission voltage with their own associated transformation equipment, a discount on the delivery is available. 128
As a result of the 2025 COSA, FBC proposes to update these discounts to reflect the updated cost allocations for each of the affected rate schedules, consistent with the 2017 COSA and RDA. 129
FBC is seeking to update the transformation discounts as follows: • For RS 21 Commercial Service, from $0.409 to $0.4841 per kilowatt (from $0.371 to $0.4357 on a kilovolt-ampere basis) of Billing Demand;
•
•
For RS 30 Large Commercial Service – Primary, from $6.727 to $5.980 per kilovolt-ampere of Billing Demand; and
For RS 40 Wholesale Service – Primary, from $3.390 to $3.780 per kilovolt-ampere of Billing Demand for Wires Charge, and from $0.00985 to $0.00926 per kilowatt-hour for Energy Charge.
Positions of the Parties Interveners either support or do not comment on FBC’s proposed updated transformation discounts.
Panel Determination The Panel approves updating the transformation discounts as sought by FBC. The changes are based on costs that FBC updated in the 2025 COSA, which follows a methodology that the Panel found, in Section 2.4 above, to be an appropriate basis for setting rates that are just and reasonable. The Panel also notes that no concerns or comments arose regarding the proposed transformation discounts.
4.2 2025 Cost of Service Allocation Deferral Account FBC seeks to establish a new rate base deferral account, titled the 2025 COSA deferral account, to record the costs associated with the regulatory review of the Application. FBC estimates the total regulatory proceeding costs to be $450,000 for BCUC costs, Participant Cost Award funding, external legal fees, and consulting fees for EES Consulting. FBC proposes to amortize the deferral account over one year, commencing January 1, 2026. FBC considers a one-year amortization period to be appropriate as the rate impact to customers is relatively small at 0.13 percent, or $1.70 per year for an average residential customer. 131
128 Exhibit B-1-1, p. 38. 129 Exhibit B-1-1, p. 38. 130 BCMEU Final Argument, p. 1; BCOAPO Final Argument, p. 41; the CEC Final Argument, p. 3; RCIA Final Argument, p. 10. 131 Exhibit B-1-1, p. 3.
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Positions of the Parties Only two interveners commented on this matter. The CEC supports the deferral account as proposed, while BCOAPO submits that a longer amortization period may be appropriate to match the costs to the period of benefit and to decrease the rate impact in the context of other rate pressures facing FBC. 132
In reply, FBC submits that the benefit of stretching the amortization period over longer than a year is negligible and that it is more appropriate to recover these expenses over a short period to minimize the income tax expense and financing costs accruing on the account balance. 133
Panel Determination FBC is approved to establish a new rate base deferral account, titled the 2025 COSA deferral account, to record the actual costs associated with the regulatory review of the Application, and to amortize the deferral account over one year, commencing January 1, 2026. The Panel considers that a one-year amortization period is reasonable because of the relatively small impact to ratepayers.
4.3 Timing of Next Cost of Service Allocation Study FBC submits that the BCUC need not indicate a deadline for the filing of the next COSA study, but rather can rely on FBC to file it when there is a significant change in its operations, structure, or rate design that warrant a further COSA study. FBC notes that it is common for the frequency of utility COSA studies and rate design applications to vary as they are generally completed following significant changes in circumstances such as changes to internal operations or the external environment in which the utility operates. 134
However, should the BCUC consider it necessary to direct a timeframe, FBC recommends a minimum of five years until the next COSA study is filed. If significant changes occur to FBC’s internal operations, or external events result in significant changes to FBC’s operations or structure, FBC states that it would undertake a COSA study sooner, irrespective of a prescribed timeframe. At this time, however, FBC states that the rates and rate designs generally continue to perform as intended, as evidenced by the results of the 2025 COSA where only a limited amount of revenue rebalancing was required. 135
Positions of the Parties Interveners who commented on this matter recommend the next COSA study be conducted within five years. RCIA suggests five years or earlier if triggered by material changes in FBC’s operations, system configuration, or rate design. 136 The CEC recommends a COSA study by no later than 2030 for the reasons provided by FBC and to address potential developments in operations including RS 38 and net metering developments. 137
132 The CEC Final Argument, p. 21; BCOAPO Final Argument, pp. 42–43. 133 FBC Reply Argument, p. 21. 134 Exhibit B-5, BCUC IR 12.1; FBC Final Argument, pp. 16–17. 135 Exhibit B-5, BCUC IR 12.1; FBC Final Argument, pp. 16–17. 136 RCIA Final Argument, p. 10. 137 The CEC Final Argument, p. 17.
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BCOAPO submits that it is unclear what types of changes FBC considers significant-enough to trigger the need for a COSA update but in BCOAPO’s submission it should cover significant changes in FBC’s cost structure (e.g. the proportions of rate base functionalized as generation, transmission, distribution) as well as material changes in the coincident peak and non-coincident peak load factors for the various rate schedules as both could have a material impact on the COSA results. If these aspects are also included in FBC’s ongoing assessments and reporting, then BCOAPO has no issues with FBC’s suggested five-year timeframe. 138
In reply, FBC states that it continues to be of the view that no direction on the timing of the next COSA study is needed. However, if the next COSA report must be filed in five years, FBC submits that it should be five years from the effective date of any rate adjustments approved by the BCUC as a result of the current Application (i.e. January 1, 2026). FBC also notes that the suggestions for monitoring triggers would not be practical as it would require doing some COSA work each year to track the potential triggers. 139
Panel Discussion The Panel is satisfied that FBC will file its next COSA study when there is a significant change in its operations, structure, or rate design and that a new or updated COSA study is necessary following such event. We accept that it would not be practical to direct FBC to monitor specific triggers because of the COSA work that FBC would have to do each year. Given the cost and effort involved in preparing this COSA, the Panel does not see the need at this time to direct FBC to file a COSA study by a certain deadline and expects FBC will file the next COSA study when it is practicable and appropriate to do so.
DATED at the City of Vancouver, in the Province of British Columbia, this 13
th
day of November 2025.
Electronically signed by Blair Lockhart _________________________________ E. B. Lockhart Panel Chair/Commissioner
Electronically signed by Elizabeth A. (Lisa) Brown _________________________________ E. A. Brown Commissioner
138 BCOAPO Final Argument, p. 41. 139 FBC Reply Argument, pp. 14-15.
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Acronym AMI
Application
BCMEU
BCOAPO
BCUC
Bonbright Principles
CEC
COSA
CP
EES
FBC
ICG
IR
kW
kWh
kVA
MSS
MW
Order G-265-25
FortisBC Inc. 2025 Cost of Service Allocation and Revenue Rebalancing
LIST OF ACRONYMS
Description Advanced Metering Infrastructure
FBC’s May 15, 2025 updated COSA application for approval of revenue rebalancing
British Columbia Municipal Electric Utilities
British Columbia Old Age Pensioners’ Organization et al.
British Columbia Utilities Commission
The eight rate design principles identified by Dr. James C. Bonbright
The Commercial Energy Consumer Association of British Columbia
Cost of Service Allocation
Coincident Peak
EES Consulting Inc.
FortisBC Inc.
Industrial Customers Group
Information request
Kilowatts
Kilowatt hours
Kilovolt-ampere
Minimum System Study
Megawatts
1 of 2
NCP
O&M
Original Application
PLCC
R/C
RCIA
RDA
RoR
RS
Order G-265-25
Non-Coincident Peak
Operation and Maintenance
FBC’s February 14, 2025 COSA application for approval of revenue rebalancing
Peak Load Carrying Capability
Revenue-to-cost
Residential Consumer Intervener Association
Rate Design Application
Range of Reasonableness
Rate Schedule
APPENDIX A
2 of 2
FortisBC Inc. 2025 Cost of Service Allocation and Revenue Rebalancing
EXHIBIT LIST
Exhibit No.
Description
COMMISSION DOCUMENTS
A-1
A-2 A-3
A-4 A-5 A-6 A-7 A-8 A-9 A-10
February 25, 2025 – Panel Appointment
March 5, 2025 – BCUC Order G-60-25 establishing a regulatory timetable March 11, 2025 – Timeline for FBC to provide notice of application and confirmation of notification
April 3, 2025 – BCUC letter regarding intervener participation April 9, 2025 – BCUC Information Request No. 1 to FBC April 22, 2025 – BCUC letter regarding BCMEU Intervener Information Request No. 1 April 28, 2025 – BCUC letter regarding BCMEU Revised Information Request No. 1 May 27, 2025 – BCUC Order G-127-25 establishing an amended regulatory timetable June 5, 2025 – BCUC Information Request No. 2 to FBC June 16, 2025 – BCUC letter regarding BCOAPO Information Request No. 2
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APPLICANT DOCUMENTS
B-1
B-1-1 B-1-2 B-2
B-3
B-4 B-5 B-6 B-7 B-8 B-9 B-10 B-11 B-12 B-13 B-13-1 B-14 B-15
February 14, 2025 – FORTISBC INC. (FBC) – 2025 Cost of Service Allocation (COSA) and Revenue Rebalancing application
APPENDIX B
May 15, 2025 – FBC submitting updated application May 15, 2025 – FBC submitting updated blackline application March 13, 2025 – FBC submitting confirmation of public notice in compliance with Order G-60-25
March 31, 2025 – FBC submitting confirmation of social media notice in compliance with Order G-60-25
April 14, 2025 – FBC submitting the 2020 COSA study May 15, 2025 – FBC submitting responses to BCUC Information Request No. 1 May 15, 2025 – FBC submitting responses to BCMEU Information Request No. 1 May 15, 2025 – FBC submitting responses to ICG Information Request No. 1 May 15, 2025 – FBC submitting responses to CEC Information Request No. 1 May 15, 2025 – FBC submitting responses to BCOAPO Information Request No. 1 May 15, 2025 – FBC submitting responses to RCIA Information Request No. 1 July 4, 2025 – FBC submitting responses to BCUC Information Request No. 2 July 4, 2025 – FBC submitting responses to BCMEU Information Request No. 2 PUBLIC -July 4, 2025 – FBC submitting responses to ICG Information Request No. 2 CONFIDENTIAL – July 4, 2025 – FBC submitting responses to ICG Information Request No. 2 July 4, 2025 – FBC submitting responses to CEC Information Request No. 2 July 4, 2025 – FBC submitting responses to BCOAPO Information Request No. 2
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INTERVENER DOCUMENTS
C1-1
C1-2 C1-3 C1-4 C2-1
C2-2 C2-3 C3-1
C3-2 C3-3 C4-1
C4-2 C4-3 C4-4 C5-1
C5-2 C5-3
March 11, 2025 - BC MUNICIPAL ELECTRICAL UTILITIES (BCMEU) – Request to Intervene submitted by Scott Spencer
APPENDIX B
April 16, 2025 – BCMEU submitting Information Request No. 1 to FBC April 25, 2025 – BCMEU submitting revised Information Request No. 1 to FBC June 12, 2025 – BCMEU submitting Information Request No. 2 to FBC March 31, 2025 - INDUSTRIAL CUSTOMERS GROUP (ICG) – Request to Intervene submitted by Robert Hobbs
April 16, 2025 – ICG submitting Information Request No. 1 to FBC June 12, 2025 – ICG submitting Information Request No. 2 to FBC March 31, 2025 - COMMERCIAL ENERGY CONSUMERS ASSOCIATIONS OF BC (CEC) - Request to Intervene submitted by David Craig
April 16, 2025 – CEC submitting Information Request No. 1 to FBC June 12, 2025 – CEC submitting Information Request No. 2 to FBC March 31, 2025 - BC OLD AGE PENSIONERS ORGANIZATION ET AL (BCOAPO) - Request to Intervene submitted by Irina Mis
April 16, 2025 – BCOAPO submitting Information Request No. 1 to FBC June 12, 2025 – BCOAPO submitting Information Request No. 2 to FBC June 17, 2025 – BCOAPO submitting clarification of Information Request No. 2 to FBC March 31, 2025 - RESIDENTIAL CONSUMER INTERVENOR ASSOCIATION (RCIA) - Request to Intervene submitted by Abdulrahman Abomazid
April 16, 2025 – RCIA submitting Information Request No. 1 to FBC June 12, 2025 – RCIA submitting Information Request No. 2 to FBC
Order G-265-25
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