FortisBC Energy Inc.
2024 Annual Review of Delivery Rates |
Decision and Order G-334-23 |
December 7, 2023 |
|
Before: A. K. Fung, KC, Panel Chair T. A. Loski, Commissioner E. A. Brown, Commissioner |
TABLE OF CONTENTS
Page no.
1.1 Background to FEI’s Multi-Year Rate Plan
1.3 Application Review Process
2.0 Review of Approvals Sought
2.1 Components of the 2024 Revenue Requirement
2.1.2 Other Revenue – Late Payment Charges
2.1.3 Net Operations and Maintenance Expense – Integrity Digs and Renewable Gas Development Costs.
2.1.4 Deferral Amortization – Emissions Regulation Deferral Account
2.1.5 Financing and Return on Equity – Short-Term Debt.
2.1.6 FEI’s Proposal to Defer a Portion of the 2024 Revenue Requirement
2.1.7 Amortization Period of the 2023 and 2024 Revenue Deficiency Deferral Account
2.2.1 Demand Side Management Expenditure Plan Application Deferral Account
2.2.2 PST Rebate on Select Machinery and Equipment Deferral Account
2.3 Overall Determination on 2024 Delivery Rates
COMMISSION ORDER G-334-23
APPENDICES
APPENDIX A Glossary of Terms
APPENDIX B Exhibit List
On June 22, 2020, the British Columbia Utilities Commission (BCUC) approved a multi-year rate plan (MRP) for FortisBC Energy Inc. (FEI) covering a five-year period from 2020 to 2024 (MRP Decision). The MRP uses a performance or incentive-based regulatory rate-setting framework which links utility rates to performance and makes the controllable portion of FEI’s annual revenue requirement subject to a formula rather than to cost recovery based on a traditional cost-of-service approach. In accordance with the MRP Decision, an annual review process (Annual Review) is required to set rates for each year of the MRP.
On July 28, 2023, FEI filed its Annual Review for 2024 Delivery Rates Application (Application). Subsequently, on October 10, 2023, FEI filed an evidentiary update to the application (Evidentiary Update) seeking an 8.00 percent delivery rate increase effective January 1, 2024. FEI also seeks BCUC approval of various deferral accounts and rate riders, along with its Core Market Administration Expense (CMAE) budget for 2024. This proceeding reviews that Application.
The 2024 delivery rate increase is required due to the 2024 forecast revenue deficiency of $104.251 million, which is comprised of: a) $51.285 million in normal operating changes; and b) a $52.966 million impact resulting from the BCUC Decision and Order G-236-23 for the Generic Cost of Capital Stage 1 proceeding issued on September 5, 2023,[1] which approved increases to both FEI’s capital structure and return on equity effective January 1, 2023. In the normal course, FEI would be entitled to the full recovery of its total 2024 forecast revenue deficiency of $104.251 million in its 2024 delivery rates, along with the $63.994 million already deferred in the 2023 Revenue Deficiency deferral account. However, this would result in a 16.12 percent 2024 delivery rate increase which exceeds the 10 percent rate shock threshold. Instead, FEI proposes to defer $19.708 million of the 2024 revenue deficiency to the existing 2023 Revenue Deficiency deferral account, and to amortize the balance in that deferral account over five years, commencing January 1, 2025. The Panel agrees with FEI that to implement a 16.12 percent delivery rate increase in 2024 would not be reasonable as it would constitute rate shock.
The Panel finds FEI’s 2024 forecast revenue requirement to be reasonable and approves an 8.00 percent increase in FEI’s 2024 delivery rates on an interim and refundable/recoverable basis, pending the outcome of FEI’s 2024-2027 Demand Side Management Expenditures Application proceeding. The Panel approves FEI’s proposed approach to handling the remaining 2024 forecast revenue deficiency by deferring this amount to the existing 2023 Revenue Deficiency deferral account, to be renamed as the 2023 and 2024 Revenue Deficiency deferral account, with the balance therein to attract interest at FEI’s weighted average cost of capital. The Panel does not provide a determination on the proposed amortization period of the 2023 and 2024 Revenue Deficiency deferral account, but rather defers that determination to the future panel who will review FEI’s next rates application. Because the start date for the amortization of the balance in that account as proposed by FEI is 2025, this will not impact the 2024 delivery rates.
The Panel also approves FEI’s other deferral account and rate rider requests, as well as the CMAE budget, as applied-for.
1.0 Introduction
On June 22, 2020, the British Columbia Utilities Commission (BCUC) approved a multi-year rate plan (MRP) for FortisBC Energy Inc. (FEI) covering a five-year period (2020 to 2024) (MRP Decision).[2] The MRP Decision directed an annual review process (Annual Review) to set FEI’s delivery rates.
On July 28, 2023, FEI filed its Annual Review for 2024 Delivery Rates Application (Application). Subsequently, on October 10, 2023, FEI filed an evidentiary update to the Application (Evidentiary Update) seeking, among other things, an 8.00 percent delivery rate increase effective January 1, 2024.[3]
Unless otherwise indicated, references hereafter to the Application will be to the Application as supplemented by the Evidentiary Update.
1.1 Background to FEI’s Multi-Year Rate Plan
Pursuant to the MRP Decision, the BCUC approved an MRP for FEI that establishes the framework for setting rates in the period from 2020 through 2024. The MRP uses a performance or incentive-based regulatory rate setting framework which links utility rates to performance, and makes the controllable portion of FEI’s annual revenue requirement subject to a formula, rather than cost recovery based on a traditional cost of service approach. The expected benefits of this performance-based approach are increased efficiency, better control over Operations and Maintenance (O&M) costs and capital expenditures, and reduced regulatory costs resulting in more reasonable utility rates. The MRP uses a rate setting mechanism designed to incent FEI to find efficiencies while ensuring that reasonable and measurable service levels are maintained through agreed service quality indicators. The MRP includes elements that attempt to strike a balance between the interests of ratepayers and the utility, and appropriately manages and allocates risks and rewards.[4]
Certain cost components of the MRP are determined using a formula or index-based approach that considers inflation and other cost drivers adjusted to reflect FEI’s expected productivity improvements. Other revenue and cost components that are not conducive to an index-based approach are determined through a forecast approach like a traditional cost of service mechanism or flowed through to FEI’s annual revenue requirement. Revenue and cost components outside FEI’s control are handled through a deferral mechanism or are given flow-through or exogenous factor treatment.
FEI’s MRP includes the following:[5]
• Use of a formula or index-based approach to controllable O&M and FEI Growth capital, incorporating:
o An inflation factor based on Statistics Canada BC-Consumer Price Index (CPI) and the BC-Average Weekly Earnings (AWE) indexes;
o A growth factor multiplier; and
o A productivity (X) factor;
• Use of a forecast approach for FEI sustainment and other capital;
• A 50 percent sharing between customers and FEI’s shareholders if FEI’s achieved return on equity (ROE) is above or below that allowed, referred to as the Earnings Sharing Mechanism (ESM);
• Specific revenue requirement items approved for flow-through and deferral account treatment;
• 13 service quality indicators (SQIs), of which nine have benchmark and performance ranges set by a threshold level and four are informational;
• A plan off-ramp to be triggered if earnings in any one year vary from the allowed ROE by more than +/- 150 basis points (post sharing); and
• A Clean Growth Innovation Fund that is funded by a basic charge fixed rate rider of $0.40/month.
A key element of FEI’s MRP is the Annual Review. In the MRP Decision, the BCUC set out the following items to be addressed at each Annual Review in addition to setting delivery rates:[6]
1. Review of the current year projections and the upcoming year’s forecast, including the following items:
i. Customer growth, volumes and revenues;
ii. Year-end and average customers, and other cost information including inflation;
iii. Expenses, determined by the indexing formula plus items forecast annually;
iv. Capital expenditures, plus other items forecast annually;
v. Plant balances, deferral account balances and other rate base information and depreciation and amortization to be included in rates; and
vi. Projected earnings sharing for the current year and true-up to actual earnings sharing for the prior year;
2. Identification of any efficiency initiatives that FEI has undertaken, or intends to undertake, that require a payback period extending beyond the MRP term with recommendations to the BCUC with respect to the treatment of such initiatives;
3. Review of any exogenous events FEI or stakeholders have identified that should be put forward to the BCUC for review;
4. Review of FEI’s performance with respect to SQIs;
5. Assessment of recommendations with respect to any SQIs that should be reviewed in future Annual Reviews;
6. Reporting on the Clean Growth Innovation Fund status; and
7. Assessment of and recommendations to the BCUC on potential issues or topics for future Annual Reviews.
In addition to these specific topics, the BCUC may include any other topic for review as it considers necessary.[7]
This decision focuses on issues that merit Panel discussion or deliberations relating to the above items of review. For those items which were not contentious in the current Annual Review, we do not propose to discuss them in depth.
1.2 Approvals Sought
FEI seeks the following approvals pursuant to sections 59 to 61 of the Utilities Commission Act (UCA):[8]
1. A permanent 2024 delivery rate increase of 8.00 percent, effective January 1, 2024, with the remaining 2024 revenue deficiency to be recorded in FEI’s 2023 Revenue Deficiency deferral account; and
2. Approvals related to several deferral accounts and rate riders, as well as approvals related to the Core Market Administration Expense (CMAE) budget.
1.3 Application Review Process
In accordance with the regulatory timetables established by the BCUC, the Panel undertook the following public review process:[9]
• One round of BCUC and intervener information requests (IRs);
• A workshop held on October 23, 2023 (Workshop);
• Written final arguments from interveners filed by November 9, 2023; and
• FEI’s written reply argument filed by November 20, 2023.
The following six registered interveners participated in the proceeding:
• Movement of United Professionals (MoveUP);
• Residential Consumer Intervener Association (RCIA);
• BC Sustainable Energy Association and Sierra Club (BCSEA);
• Commercial Energy Consumers Association of British Columbia (the CEC);
• Air Products; and
• British Columbia Old Age Pensioners’ Organization et al. (BCOAPO).
1.4 Structure of the Decision
The remainder of this decision is structured as follows:
• Section 2.1 reviews the reasonableness of FEI’s 2024 forecast revenue requirement and its various components from the Application;
• Section 2.2 reviews the other approvals sought;
• Section 2.3 sets out the Panel’s overall determination on FEI’s 2024 delivery rates; and
• Section 3.0 discusses future rate application considerations.
2.0 Review of Approvals Sought
In the following subsections, we review the reasonableness of FEI’s 2024 forecast revenue requirement and its various elements from the Application as well as the other approvals sought, including a summary of the relevant evidence along with the parties’ submissions as applicable. We then conclude with an overall determination on FEI’s 2024 delivery rates.
2.1 Components of the 2024 Revenue Requirement
The proposed delivery rates for 2024 are based on FEI’s 2024 forecast revenue requirement as set out in the Application. FEI outlines a forecast revenue deficiency of $84.543 million which results in an 8.00 percent increase in delivery rates from 2023.[10] Figure 1 summarizes both the components of the original forecast revenue deficiency of $47.554 million from the Application and additional items from the Evidentiary Update that result in the amended 2024 forecast revenue deficiency of $84.543 million.[11]
Figure 1: 2024 Forecast Revenue Deficiency After Evidentiary Update ($ millions)[12]
As shown in Figure 1 above, the increase in the 2024 forecast revenue deficiency is primarily due to increased net O&M, deferral amortization, taxes, and the impact on 2024 delivery rates arising from the Generic Cost of Capital (GCOC) Stage 1 Decision, which is offset by a proposed partial deferral of that deficiency. We review the key drivers of that revenue deficiency below.
Net O&M
Under the MRP, O&M expense is primarily determined by formula (Formula O&M) with the addition of several specific items that are forecast outside the formula on an annual basis (Non-Formula O&M).[13] Formula O&M is subject to an inflation factor (I-Factor), a productivity factor (X-factor), and a forecast of average customers with a 75 percent multiplier.[14] Non-formula O&M consists of items such as pension, insurance, integrity, BCUC levies, and costs related to clean growth initiatives such as biomethane and renewable gas.[15]
Formula O&M for 2024 is $312.561 million, representing a 4.43 percent[16] increase from the 2023 Approved amount of $299.302 million.[17] The increase in Formula O&M for 2024 is primarily due to increases in the I-Factor and the forecast of average customers.[18] Non-Formula O&M expenses for 2024 are $57.646 million, representing a 4.16 percent[19] increase from the 2023 Approved amount of $55.345 million.[20] The increase in Non-Formula O&M is mainly due to increases in insurance, integrity management activities, BCUC levies, and clean growth initiatives, offset by a decrease in pension costs.[21]
After netting capitalized overhead, Formula O&M and Non-Formula O&M contribute $11.138 million and $1.353 million, respectively, to the $12.491 million Net O&M impact to the forecast revenue deficiency noted in Figure 1 above.[22] In the Evidentiary Update, FEI updated the I-Factor to 4.414 percent from the Application I-Factor of 4.354 percent. FEI noted that when rounded to three decimal places there is no impact to Net O&M from using updated inflation data.[23]
Deferral Amortization
Table 1 provides a breakdown of the $19.048 million amount in Figure 1 that is attributed to deferral amortization.
Table 1: Breakdown of Deferral Amortization[24]
The increase in deferral amortization is primarily driven by: (i) an increase of $10.128 million in DSM deferral account amortization resulting from increased DSM expenditures, and (ii) a reduction of $25.949 million in credit amortization from the Emissions Regulation deferral account due to reduced carbon credits available for monetization after a large sale in 2022.[25] The overall increase is primarily offset by (i) a reduction of $5.728 million in amortization expense from the non-rate base Flow-Through deferral account, and (ii) a reduction of $4.827 million in amortization expense from the non-rate base MRP Earnings Sharing deferral account driven by index-based O&M, other revenues, and income taxes. [26]
Taxes
Income tax and property tax contribute $24.599 million[27] to the forecast revenue deficiency noted in Figure 1 above.
In the Application, FEI notes that property taxes are forecast to increase by $4.215 million in 2024 primarily due to higher assessed values of distribution lines and transmission lines, as well as an increase in in-lieu taxes.[28] In the Evidentiary Update, FEI notes a correction of $3.371 million to the 2023 Projected In-Lieu taxes which will be reflected in the 2023 Projected variance to be recorded in the Flow-Through deferral account.[29]
In the Application, FEI notes that income taxes are forecast to increase by $16.653 million in 2024 primarily due to lower income tax deductible through capital cost allowances (CCA).[30] The lower CCA is partly due to reduced undepreciated capital cost additions in higher rate CCA classes in 2024, and partly due to the phase-out of Canada’s Accelerated Investment Incentive starting from 2024. [31] Income taxes are also higher as a result of higher amortization of deferred charges as well as depreciation, which is partially offset by lower taxable temporary differences associated with pension and higher non-taxable temporary differences associated with removal costs.[32] This income tax amount is not inclusive of the GCOC Stage 1 Decision impact on 2024 delivery rates,[33] which is discussed below.
GCOC Impact on 2024 Rates and Deferred 2024 Revenue Deficiency
In the Application, FEI calculates the 2024 forecast revenue deficiency to be $47.554 million using the then-approved capital structure of 38.5 percent equity and 61.5 percent debt with an 8.75 percent ROE.[34]
Subsequent to the filing of the Application, on September 5, 2023, the BCUC issued Decision and Order G-236-23 (GCOC Stage 1 Decision) which approved a capital structure of 45.0 percent equity and 55.0 percent debt with a 9.65 percent ROE for FEI effective January 1, 2023.[35] As part of the GCOC Stage 1 Decision, FEI was also directed to file (i) a compliance filing for January 1, 2023 permanent rates in place of the previously approved 2023 interim rates, and (ii) an evidentiary update for the 2024 Annual Review proceeding to reflect and implement the deemed capital structure and allowed ROE as approved.[36] These two filings are discussed below.
On September 29, 2023, FEI filed an Application for the FortisBC Utilities Implementation of Capital Structure, Return on Equity and Permanent Rates for 2023 (2023 Compliance Filing).[37] In the 2023 Compliance Filing, FEI applied to, among other things, (i) make permanent the existing interim delivery rate increase of 7.69 percent effective January 1, 2023, and (ii) to establish a new non-rate base deferral account entitled the “2023 Revenue Deficiency deferral account,” attracting FEI’s weighted average cost of capital (WACC), to record the 2023 incremental revenue deficiency of $63.994 million.[38] BCUC Order G-275-23 issued on October 17, 2023, accepted FEI’s 2023 Compliance Filing and directed that the disposition of the 2023 Revenue Deficiency deferral account be reviewed in FEI’s 2024 Annual Review. [39]
On October 10, 2023, FEI filed the Evidentiary Update which includes the impact of the GCOC Stage 1 Decision on the 2024 forecast revenue requirement. The GCOC Stage 1 Decision results in a $52.966 million increase to the 2024 forecast revenue deficiency, as shown in Table 2 below.
Table 2: Incremental 2024 Deficiency due to the GCOC Stage 1 Decision[40]
The $56.707 million increase in return on deemed equity and ROE change is a result of the higher proportion of deemed equity and the higher ROE resulting from the GCOC Stage 1 Decision.[41] The $14.954 million decrease in return on deemed debt is conversely due to the lower proportion of deemed debt resulting from the GCOC Stage 1 Decision. [42] Specifically, the decrease is driven by: (i) a $4.776 million decrease in return on long-term debt as FEI is no longer forecasting a $200 million long-term debt issuance in 2024 to align with the lower deemed debt component; and (ii) a $10.178 million decrease in return on short-term debt as FEI is now forecasting no short-term interest on credit facilities, but rather an approximately 0.99 percent fixed financing fee.[43] The increased income tax expense of $18.422 million is a result of the increase in the earned return, reduction in interest expense and the change in non-rate base amortization.[44]
The total 2024 revenue deficiency that includes the GCOC Stage 1 Decision impact is $104.251 million before consideration of any rate smoothing mechanisms.[45] FEI proposes rate smoothing mechanisms to reduce the 2024 revenue deficiency to be recovered in 2024 delivery rates to $84.543 million, which are discussed further in Section 2.1.6.
Interveners generally do not oppose BCUC approval of the recovery of FEI’s 2024 forecast revenue requirement. However, some interveners raised concerns regarding the non-NGT LNG[46] demand forecast, specific components of other revenue and O&M expense, the Emissions Regulation deferral account, the treatment of short-term debt, the portion of the 2024 revenue requirement to be deferred, and the amortization period of the 2023 Revenue Deficiency deferral account. These concerns are further discussed below.
2.1.1 Demand Forecast
FEI’s demand forecast is made up of several components including, among other things, non-NGT LNG demand. Non-NGT LNG demand represents 1.5 petajoule (PJ) or 0.68 percent of FEI’s 220.2 PJ total demand in the 2024 forecast. [47] Table 3 summarizes FEI’s non-NGT LNG from 2022 to 2024 Forecast.
Table 3: Non-NGT LNG for 2022 to 2024 Forecast (GJ)[48]
|
2022 Approved |
2022 Actual |
2023 Approved |
2023 Projected |
2024 Forecast |
Non-NGT LNG (export) |
3,083,297 |
124,845 |
3,690,789 |
682,000 |
1,471,000 |
FEI explains that the non-NGT LNG demand decrease of 3,008,789 gigajoule (GJ) from 2023 Approved to 2023 Projected is due to weaker than expected demand over the winter of 2022/23. FEI states that 2024 Forecast is 2,219,789 GJ lower than 2023 Approved due to decreases to the LNG index price in Asia, FEI’s commodity rate increase on January 1, 2023, continued shipping and port issues including the port strike at GCT Delta Port, and other issues, such as completion of the required International Organization for Standardization (ISO) container certification. FEI further states that 2024 Forecast is 789,000 GJ higher than 2023 Projected primarily due to expected demand growth resulting from successful trial shipments to new customers in Asia using ISO containers. FEI indicates it is continuing discussions with existing and potential customers to secure firm contracts by the end of 2023.[49] FEI notes that discrepancies between forecast and actual LNG demand are managed through the Flow-Through deferral account and returned to or recovered from customers in subsequent years.[50]
Positions of the Parties
The CEC is the only intervener to comment on FEI’s demand forecast. The CEC is concerned with the significant under-recovery of revenue from LNG exports for two consecutive years (2022 and 2023 Projected) and the corresponding build-up in the Flow-Through deferral account which will be recovered from customers in subsequent years. The CEC recommends that the BCUC not approve the FEI non-NGT LNG forecast as submitted and instead reduce the forecast by 50 percent, which results in a forecast of 735,500 GJ which would reduce the Flow-Through deferral account impacts if 2024 Actuals are below 2024 Forecast.[51] The CEC also recommends that the BCUC reassess the merits of including FEI’s own projections for LNG export volumes related to spot purchase agreements in its LNG forecasts in a future proceeding.[52]
In reply, FEI submits that an arbitrary 50 percent reduction to its non-NGT LNG forecast has no reasonable foundation and is unlikely to produce a better forecast than FEI’s forecast based on its direct conversations with customers. FEI explains that it includes forecast demand to customers under spot purchase agreements pursuant to Order G-86-15. FEI notes that this demand is not backed by firm take-or-pay commitments, and therefore the forecast is naturally more uncertain. FEI submits that its forecast represents a reasonable expectation of the demand for sale of LNG via ISO containers in 2024 as supported by (i) the increased optimism of export customers, (ii) the expected increase in LNG prices in Asia over the winter of 2023/24, (iii) the recent decrease in FEI’s commodity rates, and (iv) the successful completion of trial shipments over the winter of 2022/23. In response to the CEC’s recommendation for future reassessment, FEI submits that it is premature to reconsider the BCUC’s determination from Order G-86-15 that FEI forecast the demand provided to customers under spot purchase agreements. FEI states that as it gains more traction in the LNG market and the challenges posed by the COVID-19 pandemic subside, LNG sales are likely to increase and forecasting accuracy will improve.[53]
Panel Determination
For the purposes of setting 2024 delivery rates, the Panel finds FEI’s demand forecast, including its non-NGT LNG demand forecast based on its direct conversations with customers, to be reasonable. The Panel disagrees with the CEC’s submissions on non-NGT LNG demand forecast and considers the CEC’s proposed 50 percent reduction of that forecast to be an arbitrary adjustment without any evidentiary basis. As FEI notes, discrepancies between forecast and actual LNG demand, including non-NGT LNG demand, are managed through the Flow-Through deferral account and returned to or recovered from customers in subsequent years. In essence, this amounts to simply a matter of difference in timing of recovery of these variances. That said, the Panel finds merit in the CEC’s recommendation for reassessment by FEI of its forecasting methodology for non-NGT LNG demand in its next rates application. Accordingly, the Panel directs FEI to discuss alternative methodologies for forecasting non-NGT LNG demand and to provide an update on its forecasts for LNG export volumes related to spot purchase agreements as part of its next revenue requirements application.
2.1.2 Other Revenue – Late Payment Charges
FEI’s 2024 Forecast Late Payment Charges total $3.607 million, which compares to 2023 Projected of $3.576 million and 2023 Approved of $3.385 million. Historically, FEI forecast its Late Payment Charges based on the average of the most recent three years of actuals. FEI changed its forecast methodology in the 2023 Annual Review to use the most recent two years of actuals due to fluctuations caused by the COVID-19 pandemic to reflect an expected increase in Late Payment Charges for 2023. FEI has used the same forecasting approach (i.e. most recent two years of actuals) for Late Payment Charges in the 2024 Annual Review for the same reasons.[54]
Positions of the Parties
The CEC is the only intervener to comment on Late Payment Charges in final argument. The CEC notes that FEI has experienced higher than historical collections for Late Payment Charges in 2022 Actuals and 2023 Projected, in part because of the impact of higher cost of gas and carbon tax on customers’ bills. The CEC recommends that the BCUC direct FEI to provide a forecast for Late Payment Charges based on anticipated customer bill changes, as opposed to averages of prior years and therefore, to forecast 10 percent more than the projected level for 2023, which amounts to $3.914 million.[55]
In reply to the CEC, FEI notes that the CEC did not explore this forecasting method on the record in this proceeding, nor did the CEC explain why it would result in a more reasonable forecast than FEI’s. FEI states that it remains unclear in the CEC’s submissions how FEI would forecast Late Payment Charges based on “anticipated customer bill changes.” FEI notes it is also unclear how the CEC’s method would address the potential impacts of higher costs of gas and carbon tax. FEI submits that using the average of 2022 Actual and 2023 Projected Late Payment Charges provides an accurate representation of the expected Late Payment Charges in 2024.[56]
Panel Determination
The Panel finds FEI’s forecast Late Payment Charges of $3.607 million to be reasonable for the setting of 2024 delivery rates. The Panel notes that FEI adjusted its methodology in 2023 to reflect the impact of the COVID-19 pandemic and now proposes to apply the same updated methodology in 2024 as appropriate to its operations and economic environment following the pandemic. The Panel further notes that the BCUC endorsed this change in methodology from a three-year historical average to a two-year historical average forecast for Late Payment Charges in FEI’s 2023 Annual Review, which had the effect of increasing FEI’s forecast Late Payment Charges for 2023, because it resulted in a more accurate forecast as reflected in FEI’s 2023 delivery rates.
The Panel views the CEC’s proposed 10 percent increase to FEI’s 2024 forecast of Late Payment Charges as an arbitrary amount, with the calculation of its proposed $3.914 million not clearly defined. Given the uncertainties of FEI’s current operating environment, the Panel is not persuaded that the CEC’s proposal would result in a more accurate forecast of Late Payment Charges than FEI’s continued use of its revised forecast methodology that was developed in response to an uncertain operating and economic environment caused by the pandemic. That said, the Panel concedes that the CEC does have a point regarding the potential of the continuing increase in carbon tax, all else equal, to increase the amount of the Late Payment Charges in absolute dollars, although the trajectory of future gas commodity prices remains unclear at this time.
The Panel notes that unlike the case of variances between forecast and actual LNG demand, variances between forecast and actual Late Payment Charges are not subject to flow-through treatment, so that any variances between forecast and actuals become subject to earnings sharing between shareholders and ratepayers on a 50/50 basis under the MRP and may, therefore, be perceived as susceptible to under-forecasting of these revenues on that basis, even though there is no evidence to that effect in this proceeding. To address this concern, the Panel directs FEI to evaluate the impacts of alternative methodologies for forecasting Late Payment Charges, including forward-looking approaches (e.g. as a function of projected revenue or customer bills) and backward-looking approaches (e.g. the current two-year versus prior three-year historical average basis) as part of its next revenue requirements application.
2.1.3 Net Operations and Maintenance Expense – Integrity Digs and Renewable Gas Development Costs
With respect to O&M expenses, some of the interveners raised concerns related to the cost of FEI’s integrity digs as well as its renewable gas development expenditures.
Integrity Digs
FEI forecasts integrity dig expenditures of $10.2 million in 2024, which equates to $63,000 cost per dig. As shown in Table 4 below, which summarizes integrity digs from 2020 to 2024, both the cost per integrity dig and the total integrity dig expenditures have increased in the 2024 forecast. Factors that impact dig costs include site access, site management during the dig, site restoration, and pipeline repairs. FEI states that fluctuations in average costs will occur due to year-to-year variability in dig categories and the geographic locations of the digs.[57] Under the MRP, integrity digs are treated as a flow-through item with variances between forecast and actual amounts captured in the Flow-Through deferral account.[58]
Table 4: Summary of Integrity Digs[59]
Renewable Gas Development Costs
FEI explains that due to the progression of government policy initiatives and regulations regarding climate action, including the Greenhouse Gas Reduction (Clean Energy) Regulation (GGRR) and the implementation of the Greenhouse Gas Reduction Standard (GHGRS), there is a greater need for FEI to prepare its system for the introduction of low carbon fuels, including hydrogen, lignin and synthesis gas (syngas).[60] FEI expects to continue to progress potential opportunities to develop the supply and use of hydrogen, lignin, and syngas in 2023 and 2024.[61]
Renewable gas development O&M costs are $4.052 million for 2024 Forecast, which compares to 2023 Approved of $2.000 million and 2023 Projected of $3.069 million. FEI explains that the 2023 Projected amount is comprised of (i) $1.25 million in internal labour resources and external consultants, and (ii) $1.8 million in work to continue progressing the ongoing hydrogen development activities on supply acquisition, offtake and end-use feasibility, safety, codes and standards, feasibility, and business development.[62]
FEI explains that the increase in the 2024 Forecast is related to requirements to continue work to progress feasibility, safety, codes and standards, and business development. FEI explains that the 2024 Forecast includes: (i) labour costs of $1.4 million including one incremental resource, and (ii) non-labour costs of $2.6 million related to various activities and projects related to the development of hydrogen and lignin.[63]
At the Workshop, FEI’s participation in the hydrogen market was discussed. FEI explained that its planned gas system hydrogen study will focus on feasibility and technical assessment to inform FEI’s evolving strategy, roadmap plan, and blending targets. FEI intends to collaborate with other gas system operators in B.C. who are also planning their own hydrogen feasibility studies.[64] FEI noted that it is at the early stages of a nascent hydrogen market in B.C. and if a call for tenders or public process, inviting third parties to submit proposals or bids for the production of turquoise hydrogen, green hydrogen or other hydrogen makes sense when FEI steps into growing its hydrogen supply, FEI would consider doing so. [65]
At the Workshop, FEI further stated that if a production or offtake opportunity develops to a point in time where it needs to submit an application to the BCUC, then FEI would lay out the approvals sought and submit an application accordingly. However, FEI notes that it has not yet brought such an application to the BCUC. [66]
Positions of the Parties
With respect to FEI’s integrity digs, the CEC is the only intervener to comment on this. While generally supportive of FEI’s integrity activities as necessary for contributing to the safety of the gas system, the CEC considers the 2024 forecast average cost per dig excessive given that there is a “vacuum of clarity” in the Application as it concerns the use of new tools and their expected impact on the average cost per dig. In the CEC’s view, the explanations offered with respect to FEI’s average cost per integrity dig are insufficient justification for the forecast 2024 expenditures. The CEC recommends that the BCUC encourage FEI to seek productivity improvement in its cost per dig process and approve a level of $58,000 as the cost per dig and a planned level of $9.4 million. The CEC notes this would be a 20.8 percent year-over-year increase in the cost per dig, saving $1.8 million from the plan.[67]
In reply, FEI contends that its 2024 forecast for incremental integrity O&M is reasonable and should be approved. FEI emphasizes that the cost associated with integrity digs, including uncertainties and the need for compliance, are primarily beyond FEI’s control, and the increased forecast is explained by first-time in-line inspections and factors such as inflation-related cost pressures and the location of pipeline digs.[68]
With respect to FEI’s renewable gas development costs, Air Products is the only intervener to comment on this. Air Products raises concern on the application of standard utility regulatory principles to the entry of FEI into the competitive hydrogen production marketplace.[69] It opposes FEI recovering O&M costs related to hydrogen production that are not authorized by the GGRR, nor tested against third-party supply costs. Air Products requests the BCUC to identify any Application costs related to hydrogen that are recoverable for reasons other than the GGRR and delineate where costs are recoverable due to the GGRR.[70] It also requests the BCUC to articulate an expectation in its decision on this proceeding to require FEI to submit standard cost information on the public record, even if the content attaches to undertakings already authorized by the GGRR, to the benefit of both FEI and observing parties in the hydrogen space.[71]
In reply, FEI submits that Air Products’ characterization of FEI’s hydrogen development activities is inaccurate and that Air Products’ position regarding FEI’s ability to pursue hydrogen production opportunities within a regulated utility is without merit and outside the scope of this proceeding. FEI states that all of its hydrogen development activities are (i) aligned with and supported by provincial policy to reduce GHG emissions in B.C. and (ii) are reasonable and in the public interest. [72]
FEI summarizes its renewable gas development activities as follows: [73]
• FEI is transitioning its core business to the distribution of low-carbon and renewable gas;
• FEI’s hydrogen procurement strategy will consider all options available to optimize the hydrogen supply and the value for FEI’s customers; and
• FEI’s hydrogen activities must remain within the regulated utility as the production or purchase of hydrogen is included as a prescribed undertaking in the GGRR and pursuant to section 18 of the Clean Energy Act, the BCUC may not exercise its powers to prevent a public utility from carrying out a prescribed undertaking and must allow public utilities to recover their costs of doing so.
FEI’s position is that both GGRR and non-GGRR hydrogen activities are in the public interest as they are all products of the same public policy drivers to reduce emissions. FEI states that it is prudent and cost-effective for FEI to pursue opportunities to acquire lower cost hydrogen for customers. FEI submits that all of its hydrogen development costs are reasonable and in the public interest and should be approved as filed.[74]
Panel Determination
With respect to forecast O&M expenditures related to integrity digs, the Panel is persuaded by the explanations for the increase in cost per dig as outlined by FEI in this proceeding and finds FEI’s forecast to be reasonable. As for the CEC’s proposal to cap the cost of FEI’s integrity digs, beyond expressing its desire to see FEI seek productivity improvement in that cost, the CEC has not provided an evidentiary basis for its proposed limit of $58,000 per dig or $9.4 million in 2024. The Panel also notes that under the MRP, integrity digs are treated as a flow-through item with variances between forecast and actual amounts captured in the Flow-Through deferral account such that the recovery of any variances becomes simply a matter of timing.
With respect to FEI’s forecast O&M expenditures relating to renewable gas development, there is no evidence before this Panel that the renewable gas development costs included within O&M expense for 2024 are not authorized by the GGRR or were not prudently incurred by FEI. FEI’s forecast renewable gas development O&M costs in 2024 related to such development activities appear to be appropriate expenditures reasonably incurred by FEI to explore the role of renewable gas including hydrogen for its system in the energy transition.
Furthermore, the evidence in this proceeding suggests that FEI is not engaging in hydrogen production for commercial purposes, but rather is assessing the feasibility of its options for hydrogen blending. For the time being, this approach by FEI appears to be reasonable. The Panel notes that in the Final Report issued in the BCUC’s Inquiry into the Regulation of Hydrogen Energy Services on November 23, 2023 in which FEI participated, the BCUC observed that the development of hydrogen energy services in B.C. is in a nascent stage, and like Pacific Northern Gas Ltd., FEI is not currently producing commercial hydrogen but simply assessing in-B.C. and out-of-B.C. resources for hydrogen production.[75] We consider it prudent for gas distribution utilities in B.C. to do so in light of the clear direction set out in the Province’s CleanBC Roadmap,[76] which calls into question the continued role of natural gas in the energy transition within the Province.
In any event, we consider that this Annual Review is not the appropriate time or place to explore nor comment on FEI’s role, if any, in the hydrogen production market. If these renewable gas development costs become larger in future rate applications involving FEI or if it files an application for a Certificate of Public Convenience and Necessity (CPCN) for a capital project related to renewable gas, interveners are free to make submissions on whether FEI should continue to have a role in the development of these resources and whether costs related thereto are covered under the GGRR and should be recoverable from ratepayers at that time. Furthermore, as and when it becomes evident that the provision of hydrogen or other renewable gas energy services is a competitive marketplace in B.C., the role and extent of the utility’s participation in that market could be reviewed and limits imposed thereon as the BCUC determines appropriate. In the meantime, we encourage Air Products to continue to participate in FEI’s future rate and CPCN applications and raise these concerns.
2.1.4 Deferral Amortization – Emissions Regulation Deferral Account
As shown in Table 5 below, which summarizes the historical carbon credit validation timelines, FEI has 3,432 carbon credits pending validation as at the end of March 2023. Of these carbon credits, FEI is projecting to monetize 2,415 carbon credits as part of this Application, which were submitted for the 2021 compliance period. The 2,415 carbon credits equate to a 2023 addition to the Emissions Regulations deferral account of $0.759 million and the resulting credit amortization to customer rates in 2024.[77]
Table 5: Summary of Carbon Credit Validation as of March 2023[78]
FEI anticipates that the remaining 1,008 carbon credits, which were submitted for the 2022 compliance period, will be validated in 2024. However, FEI did not include the monetization of the 1,008 carbon credits as a forecast addition to the Emissions Regulations deferral account because it is uncertain on the timing of when these credits will be validated. If the credits are validated in 2024, FEI would likely attempt to monetize the credits in 2024, and the credits would thus be amortized into delivery rates in 2025.[79]
In terms of FEI’s general approach to the monetization of carbon credits, FEI states that it generally monetizes all credits within a year from the date that the credits are validated. However, FEI will consider the actual sale of these credits after they have been validated based on the actual bids received from potential buyers.[80]
Positions of the Parties
BCOAPO is the only intervener to comment on this issue. BCOAPO submits that the 1,008 carbon credits should be monetized and recorded as such in the 2024 revenue requirement reducing FEI’s amortization expense by approximately $0.461 million. BCOAPO calculates the $0.461 million as the product of the 1,008 credits and a value per credit of $457.28.[81] BCOAPO states that FEI has not presented compelling evidence indicating it cannot reasonably expect these credits to be monetized in 2024.[82]
In reply, FEI submits that its forecast is reasonable given the significant time it has taken to monetize credits in the past. FEI notes that if the BCUC were to direct that FEI’s 2024 forecast include the monetization of all carbon credits, FEI’s proposed delivery rates would still remain at 8.00 percent and the impact would simply reduce the revenue deficiency to be deferred to the 2023 Revenue Deficiency deferral account. In essence, the impact would likely be to amortize the monetization of the credits over five years, rather than the full amount in 2025. FEI states it will have more certainty in its next rates application at which time it will be able to forecast the monetization of these credits more accurately.[83]
Panel Determination
Based on FEI’s previous experience with the carbon credit validation process, the Panel accepts FEI’s submission that the timing of validation of carbon credits by the provincial authority is not certain. Therefore, the Panel finds FEI’s approach for dealing with the potential monetization of carbon credits to be reasonable given the uncertainty of the timing of the carbon credit approval process, which is not a matter that is within FEI’s control.
The Panel also notes that any proposed monetization of the FEI’s carbon credits would not impact the 2024 delivery rate increase either way, given the proposed 8.00 percent delivery rate increase and the large revenue deficiency, but would simply reduce the remaining revenue deficiency deferred to the 2023 Revenue Deficiency deferral account with its corresponding impact on carrying charges related to that balance.
2.1.5 Financing and Return on Equity – Short-Term Debt
Table 6 below shows FEI’s updated return on capital as provided in the Evidentiary Update which includes the impact of the GCOC Stage 1 Decision.
Table 6: Return on Capital ($000s)[84]
FEI explains that for forecasting purposes, the short-term debt is generally used to fill the gap between FEI’s
rate base and the combination of deemed equity and long-term debt. FEI’s current (i.e. already issued) long-term debt plus the deemed equity of 45 percent already exceed the 2024 Forecast rate base (i.e. at 101.37 percent). FEI has therefore set the 2024 Forecast for short-term debt at -1.37 percent so that FEI’s capital structure remains at 100 percent of its rate base. Since FEI maintains a committed credit facility which provides short-term liquidity to fund its capital projects and working capital requirements, FEI incurs fixed financing fees for maintaining the credit facility and letter of credit facility, which are converted into a short-term rate in percentage terms (i.e. -0.99 percent) for forecasting purposes.[85]
At the Workshop, FEI elaborated on the short-term debt as presented in Table 6. FEI noted that it did not forecast interest income but did acknowledge that there should be interest income savings associated with the negative short-term debt in 2024. FEI also explained that the actual interest savings in 2024 will be returned to customers through the Flow-Through deferral account.[86]
As an undertaking to the Workshop, FEI analyzed several alternate scenarios for handling the short-term debt amount in 2024. Table 7 compares these scenarios against FEI’s proposed treatment in the Evidentiary Update.
Table 7: Comparison of Different Scenarios of Debt Treatment[87]
(1) After-Tax WACC is equivalent to AFUDC.
(2) The 2024 Delivery Rate Increase (%) does not change under each scenario under FEI’s proposed methodology for deferring a portion of the 2024 revenue deficiency via the 2023 and 2024 Revenue Deficiency deferral account.
FEI states that Scenario 1 in Table 7 does not reflect the reality of how FEI would manage its debt and therefore, while FEI could theoretically revise its revenue requirement forecast in accordance with this scenario, the actual 2024 results would be different.[88] FEI notes that Scenario 2 in Table 7 would not be beneficial for FEI or customers given early redemption fees, make-whole payments, early amortization of debt issuance costs, and other tax implications of early redemption of debt.[89]
FEI considers that Scenario 3 presented above is representative of its approach in the Evidentiary Update, with the only difference being that Scenario 3 includes a forecast of interest income on the cash balance whereas in the Evidentiary Update FEI forecasts a “0” amount of interest income.[90] FEI is amenable to including a forecast of interest income in the 2024 revenue requirement if so directed. It notes that regardless of whether a forecast amount of interest income is included in the 2024 revenue requirement, the proposed delivery rate increase will remain at 8.00 percent and any variances between forecast and actual interest income will be captured in the Flow-Through deferral account and returned to/recovered from customers in 2025. [91]
Positions of the Parties
BCOAPO is the only intervener to comment on this issue. BCOAPO submits that Scenario 3 as outlined in Table 7 is the “most pragmatic and fair solution given the circumstances.” BCOAPO recommends that the negative short-term debt be treated as an investment and the related interest income of $3.350 million be recognized as a reduction to the 2024 forecast revenue requirement rather than be captured in a Flow-Through deferral account.[92]
In reply, FEI reiterates that it is amenable to including a forecast of interest income in the 2024 revenue requirement as outlined in Scenario 3 in Table 7. However, FEI notes that as it will only recover its cost of capital from customers at the approved deemed equity of 45 percent and deemed debt of 55 percent, it is not necessary for the BCUC to direct FEI to take a specific approach in this Annual Review.[93]
Panel Determination
The Panel agrees with BCOAPO, and as conceded by FEI, that including the forecast interest income in FEI’s 2024 revenue requirement (i.e. Scenario 3 in Table 7) is appropriate. Accordingly, the Panel directs FEI to include $3.350 million of forecast interest income in the 2024 revenue requirement. This would not impact the proposed 8.00 percent delivery rate increase in 2024, but would reduce the amount of the revenue deficiency to be deferred in the 2023 Revenue Deficiency deferral account for recovery in future years.
2.1.6 FEI’s Proposal to Defer a Portion of the 2024 Revenue Requirement
FEI seeks approval to defer a portion of the 2024 forecast revenue requirement to the 2023 Revenue Deficiency deferral account that was approved by Order G-275-23.[94] As noted above, the 2023 Revenue Deficiency deferral account has a starting balance of $63.994 million. FEI outlines five options to address the combined impact of this revenue deficiency along with the impact of the GCOC Stage 1 Decision in the 2024 Annual Review:[95]
1. Recover the full 2023 Revenue Deficiency deferral account balance and the full 2024 revenue requirement after taking into account the GCOC Stage 1 Decision impact. This results in a 16.12 percent 2024 delivery rate increase which was not assessed as reasonable by FEI due to rate shock considerations.
2. Recover the full 2024 revenue requirement only, after taking into account the GCOC Stage 1 Decision impact. This results in a 9.87 percent 2024 delivery rate increase, which FEI deems to be a reasonable approach.
3. Recover a portion of the 2024 revenue requirement after taking into account the GCOC Stage 1 Decision impact while deferring $19.708 million of the remaining revenue deficiency via the 2023 Revenue Deficiency deferral account. This results in an 8.00 percent 2024 delivery rate increase. FEI proposes this option in the Evidentiary Update.
4. Recover a portion of the 2024 revenue requirement after taking into account the GCOC Stage 1 Decision impact while deferring $40.816 million of the remaining revenue deficiency via the 2023 Revenue Deficiency deferral account. This results in a 6.00 percent 2024 delivery rate increase, which FEI deems to be a reasonable approach.
5. Defer the full 2023 Revenue Deficiency deferral account balance and the 2024 revenue deficiency due only to the GCOC Stage 1 Decision impact (i.e. $52.996 million) for recovery in future years. This results in a 4.85 percent 2024 delivery rate increase which was not assessed as reasonable by FEI due to deferring too large a portion to be recovered in future years.
FEI proposes that the deferred portion of the GCOC Stage 1 Decision impact on 2024 delivery rates be $19.708 million as outlined in option 3 above and as shown in Figure 1 in Section 2.1 of this Decision. FEI states that this option best balances the 2024 delivery rate impact (i.e. rate smoothing) and cost causation principles (i.e. recovery in the period incurred).[96] Under FEI’s proposed approach, $33.258 million of the 2024 revenue deficiency due to the GCOC Stage 1 Decision impact (as shown in Table 2 in Section 2.1 of this Decision) would be recovered in 2024 delivery rates.[97] Based on current gas costs, FEI states that the proposed 8.00 percent delivery rate increase would result in 2024 bill impacts of 6.49 percent for Rate Schedule (RS) 1 Residential customers, 6.09 percent for RS 2 Small Commercial customers, 5.93 percent for RS 3 Large Commercial customers, and 4.00 percent for RS 5 General Firm customers.[98]
Positions of the Parties
MoveUP and RCIA support FEI’s proposed approach. The CEC and BCOAPO support a lower 2024 delivery rate increase and therefore a larger deferred amount in the 2023 Revenue Deficiency deferral account. BCSEA supports a higher 2024 delivery rate increase and recovery of the entire 2024 revenue requirement in 2024 rates. Air Products does not comment on this issue.
MoveUP submits that amongst the options FEI proposes, the only viable ones are 8.00 percent or 9.87 percent and agrees with FEI that the 8.00 percent is the “least-bad” option.[99]
RCIA supports FEI’s proposed $19.708 million partial deferral of the 2024 GCOC Stage 1 Decision impact because not deferring any of the 2024 revenue deficiency results in a “rate shock increase” of 9.87 percent.[100]
The CEC recommends a 5.00 percent delivery rate increase for 2024, with the remaining 2024 revenue deficiency deferred via the 2023 Revenue Deficiency deferral account. The CEC states that this will enable subsequent upper bound future delivery rate increases to be in the 5.00 to 6.00 percent range and accomplish a more levelized rate smoothing option, which the CEC recommends should be the FEI and BCUC objective for rate impacts.[101]
BCOAPO recommends a 6.00 percent delivery rate increase for 2024, with the remaining 2024 revenue deficiency deferred via the 2023 Revenue Deficiency deferral account. BCOAPO states that its 6.00 percent proposal better balances customer rate impacts in 2024 and the potential for future rate impacts over BCOAPO’s recommended deferral period (discussed in Section 2.1.7). BCOAPO states that a 6.00 percent rate increase in 2024 results in even annual rate increases of 6.05 percent for 2020 to 2024 which is consistent with the 6.07 percent annual rates approved for 2020 to 2023.[102]
BCSEA supports a delivery rate increase of 9.87 percent corresponding to full recovery of the 2024 revenue requirement in 2024 delivery rates to allow for cost recovery as close to the period incurred as possible, but at the same time to balance rate smoothing regarding the GCOC Stage 1 Decision impact to “stay below the bill shock threshold.”[103]
In reply to interveners, FEI states the following:[104]
• FEI disagrees with RCIA’s characterization of a 9.87 percent delivery rate increase as rate shock. FEI states that the threshold for rate shock is typically considered to be an increase of 10 percent or greater;
• FEI states that the CEC’s proposed 5.00 percent delivery rate increase is inappropriately based on FEI’s directional, 20-year view from the 2022 Long Term Gas Resource Plan. FEI does not yet know what the overall 2025 delivery rate increase might be and is not anticipating any offsetting revenues in 2025 to mitigate the rate increase. FEI submits that the CEC’s proposal does not give sufficient consideration to the incremental rate impacts in future years of deferring too much of the revenue deficiency;
• FEI submits that BCOAPO’s proposed 6.00 percent delivery rate increase proposal defers too much revenue deficiency to future years. FEI disagrees with BCOAPO’s assessment that the average annual rate increase from 2020 to 2023 should be the measure for delivery rate impacts in 2024. In FEI’s view, it is more important to consider rate impacts going forward; and
• FEI is amenable to BCSEA’s recommended delivery rate increase of 9.87 percent in 2024.
Panel Determination
As already noted, interveners generally do not take issue with the reasonableness of FEI’s overall forecast of its 2024 revenue requirement nor its recovery, notwithstanding concerns expressed by some regarding specific elements of the forecast. We note that FEI’s total 2024 forecast revenue deficiency before rate smoothing considerations is $104.251 million, which is comprised of $51.285 million in normal operating changes and a $52.966 million impact related to the GCOC Stage 1 Decision. In the normal course, FEI would be entitled to the full recovery of its total 2024 forecast revenue deficiency of $104.251 million in its 2024 delivery rates, along with the $63.994 million already deferred in the 2023 Revenue Deficiency deferral account. However, this would result in a 16.12 percent 2024 delivery rate increase which exceeds the 10 percent rate shock threshold. We agree with FEI that to implement such rate increase would not be reasonable.
This leaves us to consider the viability of the remaining four options considered by FEI to balance the need for rate smoothing with the timely recovery of costs. Of the remaining four options, we find that deferring recovery of the full balance in the 2023 Revenue Deficiency deferral account along with the 2024 GCOC Stage 1 impact to be unpalatable because it unnecessarily defers a large portion of the revenue deficiency that is attributable primarily to one factor (the conclusion of the GCOC Stage 1 proceeding in 2023) for years to come. We further find it unfair to saddle future ratepayers with the burden of recovery of these deferred costs in future years, in return for limiting the 2024 delivery rate increase to 4.85 percent, which we view as short term gain for long term pain. Accordingly, we reject that option.
This leaves us with the three other options considered by FEI, all of which it deems to be reasonable. Those options result in a range of 2024 delivery rate increases from 6.00 percent to 8.00 percent to 9.87 percent, with the 8.00 percent increase being FEI’s preferred option. MoveUP similarly supports this option as the “least bad” option. RCIA also agrees with FEI’s proposal.
We agree with FEI’s analysis as supported by MoveUP and RCIA. Suffice it to say that there is no perfect option to deal with the large 2024 revenue deficiency that is exacerbated by the timing of the GCOC Stage 1 Decision. Under the circumstances, we find that FEI’s proposal for an 8.00 percent delivery rate increase in 2024 strikes an appropriate and reasonable balance between the timely recovery of its costs and the need for rate smoothing to avoid rate shock.
Other interveners have proposed alternative delivery rate increases and methods for arriving at the same objective in this proceeding. We acknowledge that different permutations of different delivery rates coupled with differing amounts of deferral are plausible. However, we find no evidence in this proceeding to suggest that the alternative proposals put forward by some of the interveners have any greater merit than that proposed by FEI in this instance. FEI has considered five proposals, three of which it assesses as reasonable and proposes the 8.00 percent delivery rate option as its preferred option. We find no reason to disagree with FEI’s assessment. Accordingly, we do not consider it fruitful to review interveners’ alternative proposals in detail.
As the 8.00 percent approved 2024 delivery rate increase will be insufficient to recover FEI’s total forecast 2024 revenue requirement, we direct FEI to record the remaining 2024 revenue deficiency in the 2023 Revenue Deficiency deferral account and to re-name that account as the 2023 and 2024 Revenue Deficiency deferral account going forward, with the balance therein to attract interest at FEI’s WACC.
We now turn to assessing the appropriate amortization period for the 2023 and 2024 Revenue Deficiency deferral account.
2.1.7 Amortization Period of the 2023 and 2024 Revenue Deficiency Deferral Account
Pursuant to BCUC Order G-275-23 accepting FEI’s 2023 Compliance Filing, FEI includes an assessment of amortization periods of one to five years for the 2023 and 2024 Revenue Deficiency deferral account in the Evidentiary Update to this proceeding.[105] FEI proposes five years as the best option to balance rate smoothing and intergenerational equity considerations.[106] Table 8 below provides the incremental rate impacts under various scenarios, both in terms of the amount of the 2024 revenue deficiency deferred to the 2023 and 2024 Revenue Deficiency deferral account and in terms of the length of the amortization period.
Table 8: Amortization Alternatives for the 2023 and 2024 Revenue Deficiency deferral account [107]
However, at the Workshop, some interveners raised the issue of whether the amortization period of the 2023 and 2024 Revenue Deficiency deferral account needs be determined in this proceeding, or whether it could be deferred until next year’s proceeding when more information on the impact to the 2025 rate would be available. In response, FEI stated:[108]
MS. WALSH: … I don’t think that we need to determine necessarily an amortization period in this annual review. We were responding to the order request – the recent order from the GCOC compliance filing that requested that we propose disposition of the deferral account. But you’re correct that we’re not proposing to start recovering in 2024. So, that could be considered in the next revenue requirement application.
Positions of the Parties
The CEC supports FEI’s proposed five-year amortization period, while BCOAPO and BCSEA support a different amortization period. RCIA, on the other hand, submits that the decision on the length of the amortization period should be deferred to the 2025 rates proceeding. MoveUP and Air Products do not comment on this issue.
The CEC supports a five-year amortization period of its proposed $115.543 million in the 2023 and 2024 Revenue Deficiency deferral account starting balance.[109]
BCOAPO supports a six-year amortization period beginning in 2025. BCOAPO states that if FEI’s proposal to defer a portion of the 2024 revenue requirement is approved, then BCOAPO’s suggested amortization period of six-years would result in an incremental delivery rate impact of 1.7 percent in each year from 2025 to 2029.[110]
BCSEA submits that a two-year amortization period beginning in 2025 is appropriate for timely recovery of costs. Under its proposed 9.87 percent 2024 delivery rate increase, BCSEA notes that a two-year amortization period would result in 3.3 percent incremental impacts in 2025 and 2026 as shown in Table 8 above.[111]
RCIA recommends the BCUC establish the amortization period in the next FEI rate proceeding given the uncertainty in future revenue requirements. RCIA expects this will be the 2025-2029 multi-year rate plan proceeding.[112]
In reply to interveners, FEI states the following:[113]
• FEI submits that the extra year of deferral under BCOAPO’s proposed six-year amortization period is not warranted. FEI states that BCOAPO’s proposal does not strike as reasonable a balance as FEI’s proposal, does not give sufficient consideration to the incremental rate impacts in future years of deferring too much of the revenue deficiency, and increases inter-generational inequity issues and the impacts of increased carrying costs.
• FEI disagrees with BCSEA’s proposal for a two-year amortization period. FEI considers that a 3.3 percent delivery rate impact in 2025 and 2026 does not achieve a reasonable degree of rate smoothing. FEI also notes that FEI does not yet know what the overall 2025 delivery rate increase might be, and is not anticipating any offsetting revenues in 2025 to mitigate the rate increase; and
• FEI does not oppose RCIA’s position that the amortization period of the 2023 and 2024 Revenue Deficiency deferral account should be determined in a future proceeding. However, FEI considers it unnecessary to defer this determination. FEI has provided the incremental delivery rate impacts based on a variety of amortization periods and considers that, regardless of future rate increases, a five-year amortization period as proposed results in a reasonable level of rate smoothing.
Panel Determination
The Panel agrees with RCIA that the issue of the appropriate length of the amortization period for the 2023 and 2024 Revenue Deficiency deferral account is better addressed in the next FEI rates application. Because the start date for the amortization of the balance in that account as proposed by FEI is 2025, this will not impact the 2024 delivery rates.
Since FEI’s next rates application may be a multi-year filing, the panel reviewing that application will have greater visibility into the multi-year rate impact associated with the amortization of the 2023 and 2024 Revenue Deficiency deferral account based on the anticipated 2025 delivery rate at that time. Accordingly, we find it appropriate to defer to that panel’s determination of the amortization period of that deferral account in that proceeding. We view it as premature for us to make that determination now based on the limited information available to us and the uncertainty as to the nature of FEI’s next revenue requirement application, the length of the test period and the anticipated delivery rate.
2.2 Other Approvals Sought
In addition to the approvals sought regarding the recovery of 2024 revenue requirement and the approvals sought related to the 2023 and 2024 Revenue Deficiency deferral account as discussed above in Section 2.1, FEI seeks several other approvals as follows:[114]
1. Approval of the following rate base deferral accounts:
i. 2025 Multi-year Rate Plan (MRP) Application deferral account, with the amortization period to be determined in a future proceeding;
ii. 2023 Cost of Service Allocation (COSA) Study deferral account, with the amortization period to be determined in a future proceeding;
iii. 2024-2027 Demand Side Management (DSM) Expenditure Plan Application deferral account, with amortization over a four-year period commencing January 1, 2024; and
iv. Provincial Sales Tax (PST) Rebate on Select Machinery and Equipment deferral account, with amortization over a one-year period commencing January 1, 2024.
2. Approval of a one-year amortization period for the existing Transportation Service Report deferral account, commencing January 1, 2024.
3. A Biomethane Variance Account Rate Rider for 2024 in the amount of $0.181 per gigajoule (GJ) as set out in Section 10.3.1 of the Application.
4. Revenue Stabilization Adjustment Mechanism riders for 2024 in the credit amount of $0.106 per GJ as set out in Table 10-5 in Section 10.3.2 of the Application.
5. A Fort Nelson Residential Customer Common Rate Phase-in Rate Rider for 2024 in the credit amount of $0.863 per GJ as set out in Section 10.3.3 of the Application.
6. The 2024 CMAE budget of $6.050 million and the allocation of the CMAE between FEI’s Commodity Cost Reconciliation Account and Midstream Cost Reconciliation Account based on the allocation percentages of 30 percent and 70 percent, respectively.
Positions of the Parties
No interveners oppose the approval of the above items sought by FEI, with the exception of FEI’s proposal to defer the DSM Expenditure Plan Application deferral account over the length of the DSM plan and to return the PST Rebate on Select Machinery and Equipment deferral account over one-year beginning in 2024.
Panel Determination
With the exception of the length of amortization period of the DSM Expenditure Plan Application deferral account and the PST Rebate on Select Machinery and Equipment deferral account as discussed below, the Panel finds FEI’s proposals in respect of the other approvals sought to be reasonable and accordingly approves them as requested. Some interveners provide submissions on the amortization period of the DSM Expenditure Plan Application deferral account as well as on the PST Rebate on Select Machinery and Equipment deferral account. We review their submissions on these two items and outline our determinations in Section 2.2.1 and 2.2.2 below.
2.2.1 Demand Side Management Expenditure Plan Application Deferral Account
On July 12, 2023, FEI filed the 2024-2027 DSM Expenditures Application.[115] FEI is requesting approval to establish a rate base deferral account to capture regulatory costs associated with the 2024-2027 DSM Expenditures Application. These costs include BCUC costs, participant funding costs, external legal fees, expert/consulting costs, notice publication costs, and miscellaneous facilities, stationery, and supplies costs. FEI forecasts costs of $0.100 million in 2023 and $0.100 million in 2024. Consistent with past practice, FEI proposes to amortize the costs over four years, beginning in 2024, which represents the four-year time period of the DSM plan. Any variances between the forecast account balances and the actual incurred costs will be amortized in rates in the following years.[116]
Positions of the Parties
The CEC is the only intervener to comment on this issue. The CEC supports BCUC approval of a 2024-2027 DSM Expenditure Plan Application deferral account as proposed by FEI. However, it submits that the amortization of these costs should be tied to the benefits of the DSM expenditures for appropriate matching of costs and benefits as opposed to FEI’s proposal which ties the amortization of these costs to the DSM expenditures (i.e. four years). The CEC recommends that the BCUC deal with the amortization of these deferred costs at the time of the 2025 MRP Application.[117]
In reply, FEI clarifies that these are not expenditures to implement demand-side measures, but regulatory proceeding costs. Consistent with past practice previously approved by the BCUC, FEI has reasonably proposed to amortize these regulatory application costs over four years, matching the term of the DSM expenditure plan for which FEI has sought acceptance.[118]
Panel Determination
The Panel approves the DSM Expenditure Plan Application deferral account as proposed by FEI. We note that the amortization of the regulatory costs of the DSM plan is not intended to match the benefits of the plan whose programs have different benefit periods, but rather is tied to the period that the plan covers (i.e. four years). Given that after four years, FEI will have to submit another DSM plan and incur regulatory costs in doing so, the regulatory costs related to the current DSM plan filing should be fully amortized before further regulatory costs are incurred. We note that this is consistent with the BCUC’s previous determinations and in any event, the amortization of the total forecast regulatory costs of $0.200 million for the current DSM plan does not materially impact FEI’s 2024 delivery rate, given the size of the revenue deficiency.
2.2.2 PST Rebate on Select Machinery and Equipment Deferral Account
FEI requests approval to establish a rate base deferral account to capture the PST Rebates on Select Machinery and Equipment received from the Province of BC. To date, FEI has received $1.071 million in rebates and expects additional rebates of approximately $1.102 million to be received by December 31, 2023.[119] FEI states that the use of a deferral account is more transparent because it allows the BCUC and interveners to see the total amount of PST rebates received and flowed back through rates as the amortization of the rebate is reflected as a standalone amount.[120]
FEI proposes to amortize these rebates to customers over one year beginning January 1, 2024, to match the approximate qualifying period of eligible PST paid on purchases.[121] FEI states that a one-year amortization period ensures the return of the PST rebates back to customers in a timely and transparent manner.[122]
In the absence of a deferral account, FEI states that the rebate would be recorded as an offset in the applicable accounts where the original PST costs were recorded (i.e. O&M or capital). FEI considers this to be a less transparent way of recording the rebates as it is the cost of service impacts of the amounts credited to capital that would be returned to customers over a longer timeframe, rather than the rebate amount itself over one year as proposed using the deferral account approach.[123] FEI states that if the proposed PST rebate deferral account is not approved, the 2024 proposed deficiency will increase by approximately $2.237 million.[124]
Positions of the Parties
The CEC is the sole intervener to comment on this issue. The CEC submits that FEI should return the PST rebates as a flow-through to customers in 2023 and forego the need to create a deferral account and amortization into 2024 rates. The CEC states that this should lower the interim rate request of FEI below the current high level and get these funds back to customers as soon as possible.[125] The CEC states that if the BCUC does not support the CEC’s recommendation, then it supports FEI’s request to create a deferral account to capture PST rebates on select machinery and equipment and the proposal to amortize it over one year, starting on January 1, 2024.[126]
FEI notes that it is not possible to flow the PST rebates to customers in 2023 as 2023 rates have already been approved as permanent by the BCUC. FEI notes that if it were directed to record the PST rebates in 2023 Projected Other Revenue, the rebates would be captured in the Flow-through deferral account and amortized in 2024, which is no different in effect than FEI’s proposal. FEI reiterates that its proposal to flow through the rebates to customers in 2024 provides the benefits to customers as soon as possible.[127]
Panel Determination
The Panel approves the PST Rebates on Select Machinery and Equipment deferral account as proposed by FEI. The Panel disagrees with the CEC’s proposal and the suggested impact of that proposal. In the Panel’s view, FEI’s proposal would provide the most timely return of these amounts to ratepayers, namely, in 2024. The Panel further notes that if the proposed deferral account is not approved, the 2024 proposed revenue deficiency would increase by approximately $2.237 million, which would exacerbate the balance that would accumulate in the 2023 and 2024 Revenue Deficiency deferral account to the detriment of future ratepayers.
2.3 Overall Determination on 2024 Delivery Rates
Based on the determinations on the components of the forecast revenue requirement set out above, the Panel finds the forecast revenue requirements set out in Figure 1 in Section 2.1 to be reasonable. Due to the ongoing concurrent BCUC review of FEI’s 2024-2027 DSM Expenditures Application, the Panel is foreclosed from approving permanent 2024 rates at this time pursuant to section 44.2 of the UCA.
The effect of this UCA provision is to prohibit the amendment of FEI’s rates schedules to increase delivery rates by 8.00 percent on a permanent basis for 2024 because that delivery rate increase in part includes the recovery of 2024 DSM expenditures, for which the BCUC has not accepted FEI’s proposed DSM expenditure schedule yet. However, section 44.2(2)(b) of the UCA allows the amendment of FEI’s rates schedules to increase delivery rates on an interim basis rather than on a permanent basis.
Therefore, consistent with past practice and these UCA provisions, the Panel approves an 8.00 percent increase in FEI’s 2024 delivery rates on an interim and refundable/recoverable basis, pending the outcome of FEI’s 2024-2027 DSM Expenditures Application proceeding. FEI is directed to file as a compliance filing the tariff continuity and billing impact schedules for 2024 reflecting the approved interim 8.00 percent delivery rate increase no later than 10 days from the date of the order issued concurrently with this Decision.
3.0 Future Rate Applications
As discussed in Section 1.1 of this Decision, 2024 is the last year in FEI’s current MRP term. This section outlines some of the intervener comments regarding FEI’s future rate applications after the end of the MRP term.
Positions of the Parties
MoveUP submits that “kicking the can of rate impact has pretty much run its course” and urges the BCUC to approach the energy transition directly and proactively to enable a process of transition to a stable new equilibrium in a lower-carbon future.[128]
The CEC submits the following items for the BCUC to direct FEI to file or address in its next rates application: [129]
• Alternatives to its current methodology for developing the ‘Forecast cost of gas’ for its Annual Review processes to better account for the seasonal variability of gas commodity costs;
• To modify the MRP formula for forecasting gross customer additions such that it anticipates declining additions related to rising delivery rate costs and government policy drivers to reflect anticipated demand destruction; and
• A discussion of factors influencing the trend of the declining labour weighting used in FEI’s I-Factor calculation.
RCIA recommends that the BCUC revisit the Consensus Recommendation[130] with respect to SQIs at the next MRP proceeding to clarify the criteria for levying penalties.[131] RCIA states that the Consensus Recommendation may need clarification as it does not explicitly state whether all four criteria need to be met as a prerequisite for the imposition of penalties. RCIA suggests that it may be worthwhile to revisit the Consensus Recommendation at the next MRP proceeding, as FEI could effectively always avoid a penalty if it takes some action, however minimal, to ameliorate service degradation, even if FEI’s own prior actions are what caused the service degradation in the first instance.[132]
FEI replies to the CEC’s submissions as follows:
• FEI submits that it would be unreasonable for FEI to attempt to forecast gas costs in its Annual Reviews given (i) FEI does not request approval of its forecast cost of gas in its Annual Reviews, but forecasts its cost of gas based on the latest approved commodity cost recovery charge; (ii) the quarterly commodity cost recovery charges approved by the BCUC can move up or down each quarter depending on a variety of factors, including the price for natural gas at market hubs, not “seasonal variability” as the CEC states; and (iii) variations in gas costs are captured in deferral accounts and set quarterly because it has long been accepted that commodity costs are driven by factors outside of FEI’s control and cannot be reasonably and reliably forecast. FEI also notes that any variations between forecast and actual gas costs are returned to, or recovered from, customers through existing deferral account mechanisms, there is no benefit to customers from FEI attempting to forecast gas costs in its Annual Reviews.[133]
• FEI contests that the CEC has not established any reasonable grounds for revising FEI’s gross customer additions forecast going forward, and the CEC’s recommendation should be rejected as: (i) FEI reasonably forecasts its gross customer additions based on the best available information, (ii) FEI is forecasting gross customers additions for only one year in the future, and demand is inelastic in the short term, and (iii) the variance between forecast and actual gross customer additions is trued up in future years, so customers will only pay for costs that reflect actual gross customer additions.[134]
• Finally, FEI submits that the CEC’s recommendation should be rejected, as (i) FEI’s labour weighting has not changed materially over the MRP term, having shifted only 3percent over a 5-year period, and (ii) the cost and effort of undertaking a historical analysis of the variety of factors impacting the labor weighting each year would add no value to the calculation of the I-Factor.[135]
In reply to RCIA, FEI submits that the Consensus Recommendation has provided an effective and efficient means of assessing the utility’s SQI performance in the current MRP term and remains appropriate. FEI states that RCIA’s characterization of the Consensus Recommendation is incorrect. Nowhere does the Consensus Recommendation state that meeting a single factor and, in particular, the actions taken by the utility to ameliorate the deterioration in service, necessarily avoid a penalty. Instead, in the years of the current MRP term where the BCUC has declined to impose a financial penalty, FEI was able to establish that the performance results were not attributable to the actions or inactions of the utility and that FEI had taken reasonable actions to mitigate the impacts to customers and maintain an overall high level of customer service. FEI submits that RCIA has not provided any reasonable basis to determine that the Consensus Recommendation should be varied.[136]
Panel Discussion
Having reviewed all of the parties’ submissions in respect of FEI’s next rates application, the Panel declines some interveners’ invitation for the Panel to direct FEI to adopt specific proposals as part of its next rates application. However, we offer the following observations for FEI’s consideration:
• Should FEI’s next rate application be a multi-year rate plan, the Panel would strongly urge FEI to consider new mechanisms within the framework that will specifically address the effects of the ongoing energy transition. In the Panel’s view, the next MRP should be substantially different from the current MRP and should be responsive to FEI’s current operating environment as well as the changing needs and expectations of stakeholders and ratepayers in the ongoing energy transition in British Columbia.
• The next rates application should take a holistic view to FEI’s current operations and challenges/opportunities in the gas market.
• Ultimately, the form of the next rates application will be up to FEI to determine in consultation with its stakeholders and there is no need for the BCUC to be prescriptive in directing either a multi-year rate plan or a cost of service filing.
• The Panel disagrees with RCIA’s characterization of the Consensus Recommendation with respect to SQIs. The current SQI review process leaves room for the BCUC’s consideration of the relevant specific circumstances which may have contributed to the results (e.g. pandemics, economic conditions, extreme weather, etc.) as opposed to the automatic imposition of a penalty for any sustained degradation of service. The Panel views this to be consistent with the spirit of the Consensus Recommendation and the BCUC’s previous directives in that regard.
• The Panel declines to opine on the nature and extent of the SQIs for the next MRP, nor on the appropriate thresholds and benchmarks, as these matters will be subject to review in FEI’s next rates application should it elect to file another multi-year rate plan. However, we encourage FEI to work closely with interveners to come up with a suitable proposal in that regard.
Dated at the City of Vancouver, in the Province of British Columbia, this 7th day of December 2023.
Original signed by:
____________________________________
A. K. Fung, KC
Panel Chair / Commissioner
Original signed by:
____________________________________
T. A. Loski
Commissioner
Original signed by:
____________________________________
E. A. Brown
Commissioner
2024 Annual Review of Delivery Rates
Glossary and List of Acronyms
Acronym |
Description |
2024 Annual Review |
FortisBC Energy Inc. 2024 Annual Review of Delivery Rates |
2023 Compliance Filing |
FortisBC Energy Inc. Application for the FortisBC Utilities Implementation of Capital Structure, Return on Equity and Permanent Rates for 2023 |
Annual Review |
Annual review process |
Application |
FortisBC Energy Inc. Annual Review for 2024 Delivery Rates |
AWE |
Average Weekly Earnings |
BCOAPO |
British Columbia Old Age Pensioners’ Organization et al. |
BCSEA |
BC Sustainable Energy Association and Sierra Club |
BCUC |
British Columbia Utilities Commission |
CCA |
Capital Cost Allowances |
The CEC |
Commercial Energy Consumers Association of British Columbia |
CMAE |
Core Market Administration Expense |
COSA |
Cost of Service Allocation |
CPCN |
Certificate of Public Convenience and Necessity |
CPI |
Consumer Price Index |
DSM |
Demand Side Management |
ESM |
Earnings Sharing Mechanism |
Evidentiary Update |
FortisBC Energy Inc. evidentiary update filed on October 10, 2023 |
FBC |
FortisBC Inc. |
FEI |
FortisBC Energy Inc. |
GCOC |
Generic Cost of Capital |
GCOC Stage 1 Decision |
BCUC Decision and order G-236-23 on the Stage 1 of the Generic Cost of Capital proceeding dated September 5, 2023 |
GGRR |
Greenhouse Gas Reduction (Clean Energy) Regulation |
GHG |
Greenhouse Gas |
GHGRS |
Greenhouse Gas Reduction Standard |
GJ |
Gigajoule |
I-Factor |
Inflation factor |
IR |
Information request |
ISO |
International Organization for Standardization |
LNG |
Liquefied Natural Gas |
MoveUP |
Movement of United Professionals |
MRP |
Multi-year rate plan |
MRP Decision |
BCUC Decision and Orders G-165-20 and G-166-20 on the FEI and FBC Application for Approval of a Multi-Year Rate Plan for the Years 2020 through 2024 dated June 22, 2020 |
NGT |
Natural Gas for Transportation |
O&M |
Operations and Maintenance |
PJ |
Petajoule |
PST |
Provincial Sales Tax |
RCIA |
Residential Consumer Intervener Association |
ROE |
Return on equity |
RS |
Rate Schedule |
SQI |
Service quality indicator |
Syngas |
Synthesis gas |
UCA |
Utilities Commission Act |
WACC |
Weighted Average Cost of Capital |
Workshop |
In person workshop held by the BCUC on October 23, 2023 to review FEI’s 2024 delivery rates |
X-factor |
Productivity factor or productivity improvement factor |
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
FortisBC Energy Inc.
2024 Annual Review of Delivery Rates
EXHIBIT LIST
Exhibit No. Description
Commission documents
A-1 |
Letter dated July 21, 2023 - Appointing the Panel for the review of FortisBC Energy Inc. 2024 Annual Review of Delivery Rates Application
|
A-2 |
Letter dated July 21, 2023 – BCUC Order G-194-23 establishing a regulatory timetable |
A-3 |
Letter dated August 18, 2023 – BCUC response to RCIA and BCOAPO extension requests to file Information Request No. 1 |
Letter dated August 21, 2023 – BCUC response to RCIA and BCOAPO extension requests to file Information Request No. 1 |
|
A-5 |
Letter dated August 22, 2023 – BCUC response to CEC extension request to file Information Request No. 1 |
A-6 |
Letter dated August 23, 2023 – BCUC Information Request No. 1 to FEI |
A-7 |
Letter dated September 13, 2023 – BCUC Order G-241-23 amending the regulatory timetable |
A-8 |
Letter dated September 20, 2023 – BCUC submitting workshop information |
Applicant documents
B-1 |
FortisBC Energy Inc. (FEI) – Application for 2024 Annual Review of Delivery Rates proposed process and timetables dated June 28, 2023
|
B-2 |
Letter dated July 28, 2023 – FEI submitting Application for 2024 Annual Review of Delivery Rates
|
B-3 |
Letter dated August 1, 2023 – FEI submitting public notice in compliance with Order G‑194‑23
|
B-4 |
Letter dated August 21, 2023 – FEI response to RCIA and BCOAPO extension requests to file Information Request No. 1
|
B-5 |
Letter dated September 12, 2023 – FEI submitting extension request to file Information Request No. 1 responses
|
B-6 |
Letter dated September 20, 2023 – FEI submitting response to BCUC Information Request No. 1
|
B-7 |
Letter dated September 20, 2023 – FEI submitting response to BCOAPO Information Request No. 1
|
B-8 |
Letter dated September 20, 2023 – FEI submitting response to BCSEA Information Request No. 1
|
B-9 |
Letter dated September 20, 2023 – FEI submitting response to CEC Information Request No. 1
|
B-10 |
Letter dated September 20, 2023 – FEI submitting response to MoveUP Information Request No. 1
|
B-11 |
Letter dated September 20, 2023 – FEI submitting response to RCIA Information Request No. 1
|
B-12 |
Letter dated October 5, 2023 – FEI submitting Workshop Agenda |
B-13 |
Letter dated October 10, 2023 – FEI submitting Evidentiary Update to the Application
|
B-14 |
Letter dated October 20, 2023 – FEI submitting Workshop Presentation |
B-15 |
Letter dated October 27, 2023 – FEI submitting Workshop Transcript Corrections |
B-16 |
Letter dated October 27, 2023 – FEI submitting response to Workshop Undertakings |
Intervener documents
C1-1 |
Movement of United Professionals (MoveUP) - Letter dated July 30, 2023 submitting request to intervene by Jim Quail |
C1-2 |
Letter dated August 23, 2023 – MoveUP submitting Information Request No. 1 to FEI
|
C2-1 |
Residential Consumer Intervener Association (RCIA) – Letter dated August 2, 2023 request to intervene by Samuel Mason
|
Letter dated August 17, 2023 – RCIA submitting extension request to file Information Request No. 1
|
|
C2-3 |
Letter dated August 30, 2023 – RCIA submitting Information Request No. 1 to FEI
|
C3-1 |
BC Sustainable Energy Association (bcsea) - Letter dated August 11, 2023 Request to Intervene by T. Hackney |
C3-2 |
Letter dated August 23, 2023 – BCSEA submitting Information Request No. 1 to FEI
|
C4-1 |
Commercial Energy Consumers Association of BC (CEC) – Letter dated August 11, 2023 request to intervene by David Craig
|
C4-2 |
Letter dated August 21, 2023 – CEC submitting extension request to file Information Request No. 1
|
C4-3 |
Letter dated August 30, 2023 – CEC submitting Information Request No. 1 to FEI
|
C5-1 |
Air products (Air Products) - Letter dated August 11, 2023 request to intervene by Miles Heller
|
C6-1 |
British Columbia Old Age Pensioners’ Organization, Active Support Against Poverty, Council of Senior Citizens’ Organizations of BC, Disability Alliance BC, and Tenant Resource and Advisory Centre (BCOAPO et al) – Letter dated August 16, 2023 late request to intervene by Leigha Worth
|
C6-2 |
Letter dated August 18, 2023 – BCOAPO submitting extension request to file Information Request No. 1
|
C6-3 |
Letter dated August 30, 2023 – BCOAPO submitting Information Request No. 1 to FEI
|
Letters of comment
D-1 |
Radan, A. (Radan) – Letter of Comment dated September 6, 2023 |
D-2 |
Exhibit Removed and transferred to the FEI BERC Rate Methodology and Review of Revised RNG Program proceeding |
|
|
[1] BC Utilities Commission Generic Cost of Capital, Decision and Order G-236-23 (GCOC Stage 1 Decision), p. 136, Order G-236-23 p. 2.
[2] FortisBC Energy Inc. and FortisBC Inc. Application for Approval of a Multi-Year Rate Plan for the Years 2020 through 2024, Decision and Orders G-165-20 and G-166-20 dated June 22, 2020 (MRP Decision).
[3] Exhibit B-13, p. 1.
[4] MRP Decision, p. 168.
[5] MRP Decision, p. 169.
[6] MRP Decision, p. 167.
[7] MRP Decision, p. 167.
[8] Exhibit B-13, Appendix B, p. 2.
[9] Orders G-194-23 and G-241-23.
[10] Exhibit B-13, p. 2, Table 1.
[11] Exhibit B-13, p. 2, Table 1.
[12] Graph adapted from Exhibit B-14, p. 12. Emphasis removed.
[13] Exhibit B-2, p. 9.
[14] Exhibit B-2, p. 12.
[15] Exhibit B-2, Table 6-4, p. 44.
[16] Calculated as: ($312.561 million - $299.302 million) / $299.302 million.
[17] Exhibit B-2, Table 6-1, p. 41.
[18] Exhibit B-2, Table 6-2, p. 42.
[19] Calculated as: ($57.646 million - $55.345 million) / $55.345 million.
[20] Exhibit B-2, Table 6-1, p. 41.
[21] Exhibit B-2, Table 6-4, p. 44.
[22] Exhibit B-2, Figure 1-1, pp. 8–9; Exhibit B-14, pp. 11–12.
[23] Exhibit B-13, Table 1, pp. 2–3.
[24] Exhibit B-2, p. 10; Exhibit B-14, pp. 11–12; Exhibit B-6, BCUC IR 1.2.
[25] Exhibit B-2, p. 10; Exhibit B-6, BCUC IRs 1.2, 12.3.1.
[26] Exhibit B-2, p. 10; Exhibit B-6, BCUC IRs 1.2, 16.1.
[27] Calculated as: $20.868 million “Taxes” plus $3.731 million “2023 Projected Property Tax Correction” per Figure 1.
[28] Exhibit B-2, p. 10.
[29] Exhibit B-13, p. 2; Exhibit B-6, BCUC IR 14.1.
[30] Exhibit B-2, pp. 10–11.
[31] Exhibit B-2, pp. 10–11.
[32] Exhibit B-2, pp. 10–11.
[33] Exhibit B-14, p. 11.
[34] Exhibit B-2, p. 76; Exhibit B-13, Table 1, p. 2.
[35] BC Utilities Commission Generic Cost of Capital, Decision and Order G-236-23 (GCOC Stage 1 Decision), p. 136, Order G-236-23 p. 2.
[36] GCOC Stage 1 Decision, Order G-236-23 p. 2.
[37] FortisBC Utilities Implementation of Capital Structure, Return on Equity and Permanent Rates (2023 Compliance Filing), Exhibit B-1.
[38] 2023 Compliance Filing, Exhibit B-1, Appendix C, pp. 1–2.
[39] 2023 Compliance Filing, Order G-275-23.
[40] Exhibit B-14, p. 13.
[41] Exhibit B-13, p. 4.
[42] Exhibit B-13, Table 4, pp. 4–7.
[43] Exhibit B-13, Table 4, pp. 4–7.
[44] Exhibit B-14, p. 13.
[45] Calculated as: $84.543 million plus $19.708 million per Figure 1.
[46] (NGT): Natural Gas for Transportation; (LNG): Liquefied Natural Gas.
[47] Exhibit B-2, Figures 3-1 and 3-11, pp. 18, 28.
[48] Table created using information from Exhibit B-2, Table 3-2, Figure 3-11 p. 28; Exhibit B-11, RCIA IR 2, 2.2.
[49] Exhibit B-2, Table 3-2, pp. 28-29; Exhibit B-10, MoveUP IR 2.1.
[50] Exhibit B-11, RCIA IR 2.3.
[51] CEC Final Argument, p. 26.
[52] CEC Final Argument, p. 26.
[53] FEI Reply Argument, pp. 11–12.
[54] Exhibit B-2, pp. 34–35.
[55] CEC Final Argument, pp. 29–30.
[56] FEI Reply Argument, p. 13.
[57] Exhibit B-2, p. 49.
[58] Exhibit B-2, p. 46.
[59] Exhibit B-9, CEC IR 6.12.
[60] Exhibit B-2, p. 52.
[61] Exhibit B-2, p. 52.
[62] Exhibit B-2, p. 52.
[63] Exhibit B-2, pp. 52–54.
[64] FEI Annual Review for 2024 Delivery Rates Workshop (Workshop) dated October 23, 2023, Transcript Volume 1 Revised, p. 66.
[65] Workshop dated October 23, 2023, Transcript Volume 1 Revised, pp. 74–75.
[66] Workshop dated October 23, 2023, Transcript Volume 1 Revised, p. 73.
[67] CEC Final Argument, p. 37.
[68] FEI Reply Argument, pp. 13–15.
[69] Air Products Final Argument, p. 2.
[70] Air Products Final Argument, p. 3.
[71] Air Products Final Argument, p. 3.
[72] FEI Reply Argument, p. 15.
[73] FEI Reply Argument, pp. 15–23.
[74] FEI Reply Argument, pp. 21–23.
[75] BC Utilities Commission Inquiry into the Regulation of Hydrogen Energy Services, Final Report dated November 23, 2023, pp. 20–22.
[76] Government of B.C.’s “CleanBC Roadmap to 2030” Plan retrieved from: https://www2.gov.bc.ca/assets/gov/environment/climate-change/action/cleanbc/cleanbc_roadmap_2030.pdf.
[77] Exhibit B-6, BCUC IR 12.2.
[78] Exhibit B-6, BCUC IR 12.1.
[79] Exhibit B-6, BCUC IRs 12.2–12.3.
[80] Exhibit B-6, BCUC IR 12.3.
[81] BCOAPO Final Argument, pp. 16–17. Source of value per credit: Exhibit B-6, BCUC IR 12.2; https://www2.gov.bc.ca/gov/content/industry/electricity-alternative-energy/transportation-energies/renewable-low-carbon-fuels/credits-market.
[82] BCOAPO Final Argument, pp. 16–17.
[83] FEI Reply Argument, p. 25.
[84] Exhibit B-13, Appendix A, Schedule 26, p. 33.
[85] Exhibit B-13, p. 6.
[86] Workshop dated October 23, 2023, Transcript Volume 1 Revised, pp. 54–56.
[87] Exhibit B-16, Undertaking 6, p. 4.
[88] Exhibit B-16, Undertaking 6, p. 5.
[89] Exhibit B-16, Undertaking 6, pp. 3, 5.
[90] Exhibit B-16, Undertaking 6, p. 1.
[91] Exhibit B-16, Undertaking 6, p. 5.
[92] BCOAPO Final Argument, pp. 14–15.
[93] FEI Reply Argument, p. 8.
[94] Exhibit B-13, p. 8.
[95] Exhibit B-14, p. 6; Exhibit B-13, pp. 8–10.
[96] Exhibit B-13, p. 9.
[97] Calculated as: $52.966 million impact to the 2024 revenue deficiency less a proposed deferral of $19.708 of that amount.
[98] Exhibit B-13, p. 9.
[99] MoveUP Final Argument, pp. 4–5.
[100] RCIA Final Argument, p. 10.
[101] CEC Final Argument, pp. 1, 3.
[102] BCOAPO Final Argument, pp. 26–28.
[103] BCSEA Final Argument, pp. 1–3.
[104] FEI Reply Argument, pp. 4–7.
[105] Exhibit B-13, p. 10.
[106] Exhibit B-13, p. 10.
[107] Exhibit B-14, p. 7.
[108] Workshop dated October 23, 2023, Transcript Volume 1 Revised, pp. 20–21.
[109] CEC Final Argument, p. 3.
[110] BCOAPO Final Argument, p. 28.
[111] BCSEA Final Argument, pp. 1–3.
[112] RCIA Final Argument, pp. 10–11.
[113] FEI Reply Argument, pp. 4–7.
[114] Exhibit B-13, Appendix B, p. 2.
[115] FortisBC Energy Inc.) 2024-27 Demand Side Management Expenditures Plan, Exhibit B-2.
[116] Exhibit B-2, p. 74.
[117] CEC Final Argument, p. 3.
[118] FEI Reply Argument, p. 23.
[119] Exhibit B-2, p. 74.
[120] Exhibit B-6, BCUC IR 11.3.
[121] Exhibit B-2, p. 74.
[122] Exhibit B-6, BCUC IR 11.7.
[123] Exhibit B-2, p. 70.
[124] Exhibit B-6, BCUC IR 11.14.
[125] CEC Final Argument, p. 3.
[126] CEC Final Argument, p. 48.
[127] FEI Reply Argument, p. 24.
[128] MoveUP Final Argument, p. 5.
[129] CEC Final Argument, pp. 1–3, 14.
[130] Pursuant to the BCUC’s Consensus Recommendations, the BCUC will take into account the following factors: 1) Any economic gain made by FEI in allowing service levels to deteriorate, 2) The impact on the delivery of safe, reliable and adequate service, 3) Whether the impact is seen to be transitory or a sustained nature and 4) Whether FEI has taken measures to ameliorate the deterioration in service (Reference: FortisBC Energy Inc. and FortisBC Inc. Application for Approval of Service Quality Indictor Performance Ranges, Order G-14-15 dated February 14, 2015, Directive 1).
[131] RCIA Final Argument, p. 4.
[132] RCIA Final Argument, p. 8.
[133] FEI Reply Argument, pp. 8–9.
[134] FEI Reply Argument, pp. 9–11.
[135] FEI Reply Argument, p. 9.
[136] FEI Reply Argument, pp. 25–27.