TABLE OF CONTENTS

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Executive summary. i

1.0          Introduction. 1

1.1          Nature of the Application. 1

1.2          Background. 1

1.3          Regulatory Process. 3

1.4          Approvals Sought. 4

1.5          Decision Framework. 7

2.0          2023 and 2024 Revenue Requirements and Revenue Deficiencies. 8

2.1          Termination of PNG-West Large Volume Industrial Transportation Customer. 9

2.2          Rate Mitigation Measures. 9

2.3          Operating, Maintenance, and Administrative & General Expenses. 9

2.3.1          New Staff Positions. 11

2.4          Depreciation. 12

2.4.1          Energy Transition. 13

2.5          Short-Term Debt Component. 14

3.0          Capital Expenditures. 15

3.1          Steel Main Replacement. 15

3.2          Rolla Lateral Repair & Recommissioning Project. 17

3.2.1          Dawson Creek Supply Study. 18

3.3          Unspecified System Betterment. 19

3.4          Mobile/Heavy Equipment. 20

3.4.1          New Criteria for Replacement of Passenger Vehicles. 20

4.0          Deferral Accounts. 21

4.1          Financing for Long-Term Non-Rate Base Deferral Accounts. 21

4.2          Closure of Existing Deferral Accounts. 23

4.2.1          COVID-19 Deferral Account. 23

4.2.2          Shared Corporate Services Costs Deferral Account. 23

4.3          Proposed Tumbler Ridge Supply Study Deferral Account. 24

4.4          Rate Smoothing Deferral Account. 25

5.0          Overall Determination on Basic Charges, Delivery Rates and Revenue Stabilization Adjustment Mechanism    27

6.0          Other Matters. 30

6.1          Other Issues Raised. 30

COMMISSION ORDER G-19-24

 

APPENDICES

 

Appendix A: Proposed Adjustments and Corrections

Appendix B: Glossary and List of Acronyms

Appendix C: Exhibit List

 

 

Executive summary

On February 28, 2023, Pacific Northern Gas (N.E.) [PNG(NE)] filed its 2023–2024 revenue requirements application (RRA) seeking permanent approval of 2023 and 2024 basic charges and delivery rates for all rate classes, in addition to other approvals sought (Amended Application).

 

Subsequently, on July 21, 2023, PNG(NE) filed an evidentiary update along with an updated application for approval of 2023 and 2024 (Test Period) rates on a permanent basis (Updated Application). The permanent 2023 and 2024 basic charges and delivery rates contained in the Updated Application include the following:

 

 

PNG(NE) also applies for approval of a permanent Revenue Stabilization Adjustment Mechanism (RSAM) rate rider, effective January 1, 2023, as follows:

•         Fort St. John/Dawson Creek: an increase from a credit rider of $0.235/gigajoule (GJ) to a credit rider of $0.206/GJ.

•         Tumbler Ridge: an increase from a credit rider of $0.306/GJ to a credit rider of $0.189/GJ.

 

In its final argument, PNG(NE) changed its request for 2024 rates from a permanent basis to on an interim and refundable basis pursuant to the British Columbia Utilities Commission (BCUC) decision accompanying Order G-236-23 approving Stage 1 of the BCUC Generic Cost of Capital proceeding.[1]

 

Subject to the adjustments identified during this proceeding as summarized in Appendix A to this decision, along with the directives and determinations set out in this decision, the Panel finds PNG(NE)’s forecast revenue requirements reasonable for setting the delivery rates and basic charges for the Test Period.

 

With respect to PNG(NE)’s proposal to adjust the basic charge, the Panel acknowledges that over the past 22 years, the basic charge has remained unchanged, while the delivery rate has increased. This shift in cost recovery has resulted in a substantial change in the allocation of costs, with an increasing proportion of costs recovered through the delivery rate and a corresponding decrease in the proportion of costs recovered through the basic charge.

 

The Panel finds that PNG(NE)’s proposal to increase the basic charge is reasonable given the significant shift in cost allocation. Therefore, the Panel approves PNG(NE)’s interim basic charges, delivery rates, and RSAM rate riders on a permanent basis, effective January 1, 2023. For each of the Fort St. John/Dawson Creek and Tumbler Ridge divisions, the Panel directs PNG(NE) to establish a deferral account (2023 Rate Variance deferral account), to record the difference between the permanent 2023 rates and the adjusted 2023 rates based on PNG(NE)’s compliance filing that reflects the adjustments summarized in Appendix A to this decision, along with the directives and determinations in this decision (final adjustments). The 2023 Rate Variance deferral account will accrue interest at the average prime rate of PNG(NE)’s principal bank for its most recent year. The disposition of the 2023 Rate Variance deferral account will be determined as part of the next RRA. Further, PNG(NE) is directed to update the 2024 interim rates in its compliance filing to reflect the final adjustments.

 

In addition, the Panel makes various directives, determinations and approvals on specific issues which are set out in this decision.

 

 

1.0              Introduction

1.1              Nature of the Application

This proceeding reviews the 2023–2024 revenue requirements application (RRA) that Pacific Northern Gas (N.E.) Ltd. [PNG(NE)] filed on behalf of its Fort St. John/Dawson Creek (FSJ/DC) and Tumbler Ridge (TR) divisions, for approval by the British Columbia Utilities Commission (BCUC) pursuant to sections 58 to 61 of the Utilities Commission Act (UCA). PNG(NE) maintains separate rate schedules for both the FSJ/DC and the TR divisions.[2] This decision discusses the approvals sought and issues raised by the 2023–2024 RRA.

 

In a separate but related proceeding, the BCUC reviewed the RRA brought by PNG(NE)’s parent, Pacific Northern Gas Ltd. (PNG), on behalf of its western division “PNG-West” for the same test period. The BCUC issued its final Order G-339-23 and accompanying decision on the PNG-West 2023–2024 RRA on December 11, 2023 (PNG-West Decision).

 

For purposes of clarity, the term “PNG” will be used when referring to general corporate direction while the terms “PNG(NE)” and “PNG-West” will be used with reference to requests for approval made during the separate but related proceedings and any operational and non-corporate issues.

1.2              Background

PNG(NE) owns and operates a natural gas processing plant and natural gas distribution systems in northeastern British Columbia providing service to approximately 21,600 natural gas customers in Fort St. John, Dawson Creek, and Tumbler Ridge. It is a wholly owned subsidiary of PNG, which in turn is a wholly-owned subsidiary of TriSummit Utilities Inc. (TSU). PNG owns and operates a natural gas transmission and distribution system located in the west central part of British Columbia commencing just north of Prince George at Summit Lake and extending west to Kitimat and Prince Rupert. This is referred to as PNG’s western division, or PNG-West. Along this corridor, PNG West serves 20,600 natural gas customers with an additional 130 propane customers being served in the community of Granisle, BC.[3]

 

The PNG(NE) and PNG-West natural gas pipeline systems are illustrated in Figure 1.[4]

 

Figure 1: PNG(NE) and PNG-West Natural Gas Pipeline Systems

 

On November 30, 2022, PNG(NE) filed its 2023–2024 RRA (Original Application) with the BCUC for the FSJ/DC and TR divisions seeking, among other things, approval to amend its basic charges, delivery rates and Revenue Stabilization Adjustment Mechanism (RSAM) rate riders on an interim and refundable/recoverable basis, effective January 1, 2023.[5] PNG(NE)’s 2023 and 2024 fiscal years are collectively referred to as the “Test Period” or “Test Years”.

 

By Order G-373-22, the Panel approved, among other things, the following, effective January 1, 2023:

•      For the FSJ/DC Division:

▪  For FSJ Residential service, an interim basic charge of $7.52/month and an interim delivery rate of $6.269/gigajoule (GJ);

▪  For FSJ Small Commercial service, an interim basic charge of $7.53/month and an interim delivery rate of $4.737/GJ;

▪  For DC Residential service, an interim basic charge of $7.52/month and an interim delivery rate of $6.071/GJ;

▪  For DC Small Commercial service, an interim basic charge of $7.53/month and an interim delivery rate of $4.200/GJ; and

▪  For Residential and Small Commercial customers, an increase in the RSAM rate rider from a credit rider of $0.235/GJ to a credit rider of $0.113/GJ.

•   For the TR Division:

▪  For TR Residential service, an interim basic charge of $9.26/month and an interim delivery rate of $11.953/GJ;

▪  For TR Small Commercial service, an interim basic charge of $9.28/month and an interim delivery rate of $9.430/GJ; and

▪  For Residential and Small Commercial customers, an increase in the RSAM rate rider from a credit rider of $0.306/GJ to a debit rider of $0.022/GJ.

 

On February 28, 2023, PNG(NE) filed an amended application to support its request for approval of rates on a permanent basis. The amended application includes all the information of the Original Application, with revisions such as amended demand forecasts which take into consideration the effects of 2022 actual deliveries, updated customer count and cost forecasts, as well as the impact of 2022 actual operating results on rate-base items.[6] From this point forward, the “Application” or “Amended Application” refers to PNG(NE)’s 2023–2024 RRA.

1.3              Regulatory Process

The BCUC established a regulatory timetable and a written public hearing process for the review of the Application. The timetable included intervener registration, filing an amended application, two rounds of BCUC and intervener information requests (IRs), responses to IRs, status updates, and final and reply arguments.[7]

 

On May 1, 2023, PNG submitted a request to pause the regulatory proceedings for the review of the PNG-West and PNG(NE) 2023–2024 RRAs for a period of four weeks given the uncertainty with respect to the existing PNG-West Rate Schedule 80 (RS 80) customer’s progress towards obtaining financing and a positive financial investment decision for its project.[8] The BCUC approved PNG’s request and directed PNG to provide a status update on the RS 80 customer’s project and financial situation and to file a recommendation on further process (Status Update).[9] On May 31, 2023, PNG filed its Status Update and requested a further pause in the regulatory proceedings to June 30, 2023, at which time PNG would provide a further status update and recommendation on further process (Further Status Update).[10] The BCUC approved PNG’s further request.[11]

 

On June 30, 2023, PNG filed its Further Status Update advising that the RS 80 customer had not obtained the financing required to support its short-term obligations and necessary to achieve a positive financial investment decision on its project. Further, the RS 80 customer was not able to demonstrate a certain course of action to secure financial support for its obligations to PNG-West and to advance its project. On this basis, PNG advised the BCUC that it had terminated its contractual arrangements with the RS 80 customer, effective June 27, 2023.[12]

 

On July 21, 2023, PNG(NE) filed an evidentiary update to its RRA, along with an updated application for approval of 2023 and 2024 basic charges and delivery rates on a permanent basis (Updated Application).

 

By Order G-305-23, the BCUC approved PNG(NE)’s basic charges, delivery rates and RSAM rate riders as set forth in the Updated Application, on an interim and refundable/recoverable basis, effective January 1, 2024, subject to this decision and the BCUC’s final decision on Stage 2 of its Generic Cost of Capital (GCOC) proceeding. These interim approvals, effective January 1, 2024, for Residential, Small Commercial and Granisle Propane service are as outlined in item 4 of Section 1.4 below for each of the FSJ/DC and TR divisions respectively.

 

Two parties, British Columbia Old Age Pensioners’ Organization, Active Support Against Poverty, Council of Senior Citizens’ Organizations of BC, Disability Alliance BC, and Tenants Resource and Advisory Center, known collectively as BCOAPO et al. (BCOAPO) and Residential Consumer Intervener Association (RCIA) participated as interveners in the proceeding. In addition, the BCUC received one letter of comment.[13]

 

By Order G-348-23, the BCUC made certain advance approvals, in response to PNG(NE)’s requests for advance approvals in its final argument, with reasons to follow. The reasons for the determinations and directives made by Order G-348-23 are contained in this decision.

1.4              Approvals Sought

PNG(NE) included its approvals sought in the Updated Application[14] and subsequently identified several adjustments to its 2023–2024 revenue requirements and resulting basic charges and delivery rates during this proceeding, which are outlined in Appendix A to this decision. PNG(NE) summarizes the final approvals sought in its final argument as follows:

 

FSJ/DC division:[15]

 

1.       Approval to amend the practice for recovery of test period revenue sufficiencies/deficiencies from recovery solely through the delivery rate to recovery through both the delivery rate and the basic charge, effective January 1, 2023.  

2.       Approval to increase basic charges and delivery rates effective January 1, 2023, on a permanent basis, for the FSJ/DC division to recover the forecast 2023 revenue deficiency for the following rate classes, among other rate classes:

1.       For Residential service, a 6.4 percent increase in the basic rate from $7.00/month to $7.45/month and a 6.4 percent increase in the delivery rate for FSJ from $5.839/GJ to $6.210/GJ and a 6.6 percent increase in the delivery rate for DC from $5.641/GJ to $6.012/GJ ;

2.       For Small Commercial service, a 6.4 percent increase in the basic charge from $7.00/month to $7.45/month and a 6.2 percent increase in the delivery rate for FSJ from $4.419/GJ to $4.693/GJ and a 7.1 percent increase in the delivery rate for DC from $3.882/GJ to $4.156/GJ; and

PNG(NE) also seeks approval to increase the RSAM rate rider effective January 1, 2023, on a permanent basis, for the FSJ/DC division applicable to Residential and Small Commercial customers from a credit rider of $0.235/GJ to a credit rider of $0.206/GJ.

3.       Approval for rate adjustment riders effective January 1, 2023 to December 31, 2023, on a permanent basis, for the FSJ/DC division to refund the net overcollection of revenues in 2022 for the following rate classes, among other rate classes:

1.       For Residential service, a credit rate rider of $0.055/GJ; and

2.       For Small Commercial service, a credit rate rider of $0.036/GJ.

4.       Approval to increase basic charges and delivery rates effective January 1, 2024, on an interim and refundable basis, for the FSJ/DC division to recover the forecast 2024 revenue deficiency for the following rate classes, among other rate classes:

a)       For Residential service, a 6.4 percent increase in the basic charge from $7.45/month to $7.93/month and a 6.4 percent increase in the delivery rate for FSJ from $6.210/GJ to $6.605/GJ and a 6.6 percent increase in the delivery rate for DC from $6.012/GJ to $6.407/GJ; and

b)      For Small Commercial service, a 6.4 percent increase in the basic charge from $7.45/month to $7.93/month and a 6.2 percent increase in the delivery rate for FSJ from $4.693/GJ to $4.985/GJ and a 7.0 percent increase in the delivery rate for DC from $4.156/GJ to $4.448/GJ.

PNG(NE) also seeks approval to increase the RSAM rate rider on an interim and refundable basis for the FSJ/DC division applicable to Residential and Small Commercial customers from a credit rider of $0.206/GJ to a credit rider of $0.051/GJ.

5.       Approval of PNG(NE)’s proposal to utilize the short-term interest-bearing Rate Smoothing deferral account in 2023 to levelized the impact of the combined net revenue deficiencies for 2023 and 2024 with the deferred amount fully amortized in 2024.

6.       Approval of changes to PNG(NE)’s existing deferral accounts and amortization expenses for 2023 and 2024, including approval for the dissolution of the:

a)       COVID-19 deferral account, effective January 1, 2023, as it is no longer required; and

b)      Shared Corporate Services Cost deferral account, effective December 31, 2024, as it is no longer required.[16]

7.       Approval of the depreciation expense and net salvage amortization for 2024 as determined based on the findings of a new depreciation study.

 

TR division:[17]

 

1.       Approval to amend the practice for recovery of test period revenue sufficiencies/deficiencies from recovery solely through the delivery rate to recovery through both the delivery rate and the basic charge, effective January 1, 2023.

2.       Approval to increase basic charges and delivery rates, effective January 1, 2023, on a permanent basis, for the TR division to recover the forecast 2023 revenue deficiency for the following rate classes, among other rate classes:

1.       For Residential service, an 8.2 percent increase in the basic charge from $8.50/month to $9.20/month and an 8.2 percent increase in the delivery rate from $10.968/GJ to $11.868/GJ;

2.       For Small Commercial service, an 8.4 percent increase in the basic charge from $8.50/month to $9.21/month and an 8.3 percent increase in the delivery rate from $8.641/GJ to $9.362/GJ; and

PNG(NE) also seeks approval to increase the RSAM rate rider, effective January 1, 2023, on a permanent basis, for the TR division applicable to Residential and Small Commercial customers from a credit rider of $0.306/GJ to a credit rider of $0.189/GJ.

3.       Approval for rate adjustment riders, effective January 1, 2023 to December 31, 2023, on a permanent basis, for the TR division to refund the net overcollection of revenues in 2022 for the following rate classes, among other rate classes:

1.       For Residential service, a credit rate rider of $0.669/GJ; and

2.       For Small Commercial service, a credit rate rider of $0.505/GJ.

4.       Approval to increase basic charges and delivery rates, effective January 1, 2024, on an interim and refundable basis, for the TR division to recover the forecast 2024 revenue deficiency for the following rate classes, among other rate classes:

1.       For Residential service, an 8.2 percent increase in the basic charge from $9.20/month to $9.95/month and an 8.2 percent increase in the delivery rate from $11.868/GJ to $12.841/GJ; and

2.       For Small Commercial service, an 8.4 percent increase in the basic charge from $9.21/month to $9.98/month and an 8.3 percent increase in the delivery rate from $9.362/GJ to $10.142/GJ.

PNG(NE) also seeks approval to decrease the RSAM rate rider, effective January 1, 2024, on a permanent basis, for the TR division applicable to Residential and Small Commercial customers from a credit rider of $0.189/GJ to a credit rider of $0.217/GJ.

5.       Approval of PNG(NE)’s proposal to utilize the short-term interest-bearing Rate Smoothing deferral account in 2023 to levelized the impact of the combined net revenue deficiencies for 2023 and 2024 with the deferred amount fully amortized in 2024.

6.       Approval of changes to PNG(NE)’s existing deferral accounts and amortization expenses for 2023 and 2024, including approval for the dissolution of the:

a)       COVID-19 deferral account, effective January 1, 2023, as it is no longer required; and

b)      Shared Corporate Services Cost deferral account, effective December 31, 2024, as it is no longer required.[18]

7.       Approval to create a new weighted average cost of debt (WACD) bearing non-rate base deferral account (Tumbler Ridge Supply Study deferral account) to record up to $475,000 in pre-Front End Engineering and Design and transmission line inspection costs for identified feasible long-term supply options for Tumbler Ridge, with the disposition of the account to be addressed in future RRAs.

8.       Approval of the depreciation expense and net salvage amortization for 2024 as determined based on the findings of a new depreciation study.

1.5              Decision Framework

In this decision, the Panel specifically addresses the following issues arising from the RRA:

•         Section 2.0 focuses on issues related to the revenue requirements, including those associated with operating, maintenance, administrative and general (OMA&G) expenses. Specifically, this section will address issues related to the termination of RS 80 customer contractual arrangements and related rate mitigation measures, new staff positions, updated depreciation and net salvage rates, and PNG(NE)’s short-term debt component;

•         Section 3.0 addresses issues related to PNG(NE)’s proposed capital expenditures and additions, including PNG(NE)’s Steel Main Replacement program, the Rolla Lateral project, Unspecified System Betterment, and PNG(NE)’s new criteria for vehicle replacements;

•         Section 4.0 deals with issues related to financing for PNG(NE)’s long-term non-rate base deferral accounts, PNG(NE)’s requests for approval to close certain deferral accounts, and PNG(NE)’s requests to establish new deferral accounts; 

•         Section 5.0 outlines the overall Panel determination on the PNG(NE) 2023 and 2024 basic charges, delivery rates and RSAM rate riders; and

•         Section 6.0 addresses other matters, including BCOAPO’s recommendation for PNG(NE) to file a long-term rate mitigation plan for consideration in PNG(NE)’s next RRA.

There are several issues arising from the FSJ/DC and TR Amended Applications which are similar to those in the PNG-West 2023–2024 RRA, such as those related to the 2022 Depreciation Study, short-term debt component, financing for long-term non-rate base deferral accounts and the closure of specific deferral accounts. These issues are addressed individually below for PNG(NE).

2.0              2023 and 2024 Revenue Requirements and Revenue Deficiencies

To establish 2023 and 2024 basic charges and delivery rates, the Panel considers PNG(NE)’s total revenue requirements, or its “cost of service” for the FSJ/DC division and the TR division, respectively. PNG(NE)’s revenue requirement for each division reflects the total amount of revenue that must be collected in rates to recover its forecast costs of service and to provide PNG(NE) an opportunity to earn a reasonable return.

 

For the FSJ/DC division, in Test Year 2023, the forecast cost of service is $22.895 million, excluding Company Use gas cost of $0.347 million. This represents a $1.656 million increase over the Decision 2022 amount.[19] In Test Year 2024, the forecast cost of service is $23.390 million, excluding Company Use gas cost of $0.333 million, which is a $0.494 million increase over the Test Year 2023 amount.[20] PNG(NE) forecasts overall gas deliveries for the FSJ/DC division of 5,328,196 GJ in Test Year 2023 and 5,329,226 GJ in Test Year 2024, as compared to 5,412,532 GJs in Decision 2022. The key driver of this decrease in load is the loss of deliveries from the Small Industrial Sales customer class (RS 4) which are forecast to decrease by approximately 122,000 GJ in Test Year 2023 compared to Decision 2022 followed by a further reduction of 35,000 GJ in Test Year 2024 over 2023.[21] PNG(NE) notes that this decrease is attributed to an oil and gas exploration customer planning an electrification project to convert their compressors to electric motors in Q2 2023, resulting in a reduced demand for fuel gas starting from 2023.[22] PNG(NE) states that the loss of demand from this small industrial customer results in an average residential delivery rate and basic charge increase of 1.44 percent in 2023 for FSJ/DC customers.[23]

 

For the TR division, in Test Year 2023, the forecast cost of service is $2.422 million, excluding Company Use gas cost of $0.080 million. This represents a $0.304 million increase over the Decision 2022 amount.[24] In Test Year 2024, the forecast cost of service is $2.370 million, excluding Company Use gas cost of $0.082 million, which is a $0.052 million decrease over the Test Year 2023 amount.[25] PNG(NE) forecasts overall gas deliveries for the TR division of 860,327 GJs in Test Year 2023 and 861,062 GJs in Test Year 2024, as compared to 858,197 GJs in Decision 2022.[26]

Panel Discussion

The Panel finds the overall forecast deliveries for the Test Period to be reasonable. The Panel is cognizant of the loss of load due to electrification in the FSJ/DC division and the likelihood of future impacts on demand in PNG(NE)’s service area, which would put upward pressure on rates. We have considered these challenges facing PNG(NE) in our discussion in Section 6.1 below.

 

In the following subsections, the Panel reviews issues arising with respect to PNG(NE)’s 2023 and 2024 forecast cost of service. These issues include the termination of PNG-West’s RS 80 customer contractual arrangements and related rate mitigation measures, OMA&G expenses, depreciation, as well as PNG(NE)’s short-term debt component.

2.1              Termination of PNG-West Large Volume Industrial Transportation Customer

At the time the PNG-West 2023–2024 RRA was filed, concurrent with the filing of the PNG(NE) Original Application and Amended Application, there was ongoing uncertainty as to the timing of PNG-West’s Large Volume Industrial Transportation RS 80 tariff customer’s project. As noted in Section 1.3 above, the PNG-West 2023–2024 RRA proceeding was paused due to this ongoing uncertainty. Given the linkages and cost allocations between the PNG-West division and the PNG(NE) FSJ/DC and TR divisions, the review of the PNG(NE) 2023–2024 RRA was also paused since a potential material change to the PNG-West 2023–2024 RRA would have flow-through impacts on the PNG(NE) 2023–2024 RRA, primarily related to the PNG-West Shared Services Cost Recoveries and from Transfers to Capital.[27] In its Further Status Update, PNG notes that PNG-West’s RS 80 customer was unable to secure financial support for its obligations to PNG-West and as a result, PNG-West terminated its contractual arrangements with the RS 80 customer, effective June 27, 2023.[28]

 

PNG undertook several mitigative measures in response to the rate pressures in the Test Period resulting from the loss of margin with the PNG-West RS 80 customer, which led to cost reductions as well as flow-through impacts and balancing adjustments for each of the PNG-West, PNG(NE) FSJ/DC and TR divisions. The mitigation measures undertaken for the FSJ/DC and TR divisions are outlined in the next section.

2.2              Rate Mitigation Measures

To mitigate the adverse flow-through impacts of PNG-West losing margin from the RS 80 customer, PNG(NE) undertook an internal review of expenditures across the FSJ/DC and TR divisions to identify costs that could be reduced or deferred without affecting PNG(NE)’s ability to safely provide service to customers.[29] Based on this review, PNG(NE) reduced OMA&G expenses for the FSJ/DC division by $0.331 million in Test Year 2023 and by $0.362 million in Test Year 2024, and reduced OMA&G expenses for the TR division by $71,000 in Test Year 2023 and by $12,000 in Test Year 2024.[30]

 

With these mitigative cost reductions, Residential customers in FSJ/DC will experience a 6.4 percent increase in the basic charge and the delivery rate in each of the Test Years 2023 and 2024 as compared to 7.7 percent in Test Year 2023 and 7.6 percent in Test Year 2024 as proposed in the Amended Application, and Residential customers in TR will experience an 8.2 percent increase in the basic charge and the delivery rate in each of the Test Years 2023 and 2024 as compared to 8.9 percent in each of the Test Years as proposed in the Amended Application.[31]

2.3              Operating, Maintenance, and Administrative & General Expenses

PNG(NE) is requesting recovery of OMA&G expenses for each of the FSJ/DC and TR divisions for Test Years 2023 and 2024. As summarized in Table 1, OMA&G expenses for the FSJ/DC division are forecast to decrease in Test Year 2023 by $0.239 million or 2.21 percent as compared to the Decision 2022 amount, and forecast to increase by $0.062 million or 0.59 percent in Test Year 2024.^[32] Similarly, as summarized in Table 2, OMA&G expenses for the TR division are forecast to increase in Test Year 2023 by $0.003 million or 0.25 percent as compared to the Decision 2022 amount, and forecast to decrease by $0.021 million or 1.76 percent in Test Year 2024.^[33]

 

Table 1: PNG(NE) FSJ/DC OMA&G Expenses

 

 

Table 2: PNG(NE) TR OMA&G Expenses

 

 

For both FSJ/DC and TR, the overall OMA&G expenses are expected to remain relatively stable for both Test Years 2023 and 2024, despite some increases in operating expenses for TR, and maintenance expenses for FSJ/DC and TR.[34] As discussed in Section 2.2 above, PNG(NE) explains that due to the loss of the RS 80 customer in the PNG-West division, an internal review of expenditures was undertaken for both PNG-West and PNG(NE). The objective was to identify costs that could be eliminated to offset the adverse impacts resulting from the loss of margin from the RS 80 customer in the PNG-West division.[35] The forecast costs shown in the tables above reflect these cost reductions, which were primarily achieved through the rationalization of contractor costs and removal of temporary staffing costs.[36]

Overall Panel Determination on OMA&G Expenditures

The Panel finds the forecast OMA&G expenses for Test Years 2023 and 2024 to be reasonable, subject to the determinations on items addressed in the subsection below.

 

In the following subsection, we discuss the new staff positions proposed for Test Year 2023.

2.3.1        New Staff Positions

PNG(NE) is proposing to add the following three new staff positions in Test Year 2023:[37]

(i)                  Manager, Operations (NE) – to provide overall leadership to the FSJ/DC and TR teams (including Sales and Service, Construction and Gas Plant) and assume responsibility for identification, development, approval, resourcing and delivery performance of PNG’s maintenance activities.

(ii)                Customer Service Technicians (CST) (two positions, one in each of FSJ and DC) – to assist in repairs and adjust residential/commercial equipment on customer premises, installing and maintaining gas measurement and pressure regulation equipment and to assist in installation and maintenance of gas pressure regulation equipment at regulating stations.

PNG(NE) explains that these positions are critical to ensuring the near and long-term safe and reliable operation of the PNG(NE) system from a resource sufficiency and sustainment perspective.^[38] Further, PNG(NE) confirms that in order to improve the overall employee experience and to counter recent negative engagement surveys, it had engaged an external consultant who identified areas of improvement and where additional staffing was required. In response to IRs, PNG(NE) provided an overview of the benefits from each incremental staff position.^[39]

 

Furthermore, PNG(NE) provides the following historical labour costs and forecast for Test Years 2023 and 2024, reflecting the additional costs due to new staff additions:^[40]

 

Table 3: PNG(NE) Labour Cost

 

Positions of the Parties

BCOAPO submits that the increases in OMA&G expenses are not the most material drivers of the proposed delivery rate and basic charge increases for Residential customers. Furthermore, BCOAPO states it does not have any recommendations with respect to PNG(NE)’s proposed OMA&G expenses, which reflect the costs of the new staff positions, for Test Years 2023 and 2024.^[41]

 

RCIA supports the addition of two new staff positions (i.e. CST) but opposes PNG(NE)’s proposal to hire the Manager, Operations and recommends that PNG(NE) redevelop its hiring plan. RCIA submits that while it does not dispute the need for field-level supervision that the Manager, Operations is expected to carry out, adding this position creates a redundant layer of management and questions whether this position could be combined with the existing Director, Operations. RCIA also submits that removal of the Director, Operations position would result in lower revenue requirements for Test Years 2023 and 2024. Additionally, RCIA recommends that PNG(NE) hire a part-time meter reader instead of a second new CST.^[42]

 

In reply, PNG(NE) reiterates that all incremental staff positions for which approval is sought have been appropriately justified. PNG(NE) submits that both the roles of Manager, Operations and Director, Operations are supported by a review of the organizational structure within Operations & Engineering and changes in the organizational structure have broadened the responsibilities of both these positions. In the case of the CST roles, PNG(NE) states that the implementation of automated meter reading would require approximately 40 percent of a full-time position across the FSJ, DC and TR service areas and these activities would be assigned to CST on an as-needed basis.^[43]

Panel Discussion

The Panel finds merit in PNG(NE)’s explanation for the need to add the new staff positions for Test Year 2023 and is not persuaded by RCIA’s recommendation to combine the positions of the Manager, Operations and the Director, Operations. The Panel is satisfied that both these positions are appropriate for Test Year 2023. In the case of the CST, the Panel is satisfied that assigning meter reading activities to the CSTs on an as-required basis in accordance with PNG(NE)’s operational needs is a reasonable approach, and that there is insufficient evidence to support RCIA’s proposal to hire a part-time meter reader. While we acknowledge RCIA’s concerns, we consider that PNG(NE) has sufficiently justified the addition of these new staff positions.

2.4              Depreciation

In 2017, a depreciation study was conducted and approved as part of PNG(NE)’s 2018–2019 RRA. PNG(NE) undertook a new Depreciation Study in 2022 to update depreciation and net salvage rates for plant in service as at December 31, 2022 (2022 Depreciation Study). PNG(NE) has incorporated the results of the 2022 Depreciation Study, including new rates for depreciation and net salvage, for Test Year 2024.[44]

 

PNG(NE) explains that Test Year 2024 is the first year following the five-year phase-in period of net salvage pursuant to BCUC Order G-222-18. PNG(NE) adds that implementing the recommendations from the 2022 Depreciation Study in Test Year 2023, as opposed to Test Year 2024 would result in a minimal positive rate impact, offset by a minimal negative rate impact in Test Year 2024.[45]

 

The tables below summarize the rate impact of implementing recommended depreciation and net salvage rates from the 2022 Depreciation Study in Test Year 2024 for the FSJ/DC and TR divisions respectively, as proposed by PNG(NE):

 

Table 4: Impact of Implementing 2022 Depreciation Study Rates in 2024 for the FSJ/DC division^[46]

 

Table 5: Impact of Implementing 2022 Depreciation Study Rates in 2024 for the TR division^[47]

 

As part of the 2022 Depreciation Study, the potential impact of climate change on the service lives of PNG(NE)’s assets was covered, and is discussed below.

2.4.1        Energy Transition

In the 2022 Depreciation Study, Concentric Advisors, ULC (Concentric) notes that the evolving landscape with respect to climate change legislation may have a significant impact on the estimated service lives of the PNG(NE) system. Concentric anticipates that large scale retirement of assets may be required between now and 2050.[48]

 

Concentric defines the “economic planning horizon” as one of the parameters used to set depreciation rates to accurately reflect consumption in service value. The timing of asset retirements, whether ongoing or terminal, is represented by a single point called the economic planning horizon.[49]

 

PNG(NE) and Concentric confirm that the PNG(NE) system will experience both ongoing and terminal asset retirement activity.[50] However, Concentric has clarified that the introduction of an economic planning horizon will depend on circumstances in place at the time of filing the next depreciation study, which is expected to be filed in 2028.[51]

 

PNG(NE) also explains that given the uncertainty of the future impacts of climate change legislation, these have currently not been studied and hence, have not been considered for the purposes of the 2022 Depreciation Study.[52]

Positions of the Parties

BCOAPO submits that it is common regulatory practice to implement the results of depreciation studies in the next test year after the study is carried out and to conduct an updated depreciation study at least once every five years. BCOAPO considers that PNG(NE)’s reasons for deferring the results of the 2022 Depreciation Study to Test Year 2024 are “administrative” and “bureaucratic” in nature and do not present valid reasons for delaying the implementation. Therefore, BCOAPO recommends that the BCUC order PNG(NE) to implement the 2022 Depreciation Study in Test Year 2023.[53]

 

In response to BCOAPO’s submissions, PNG(NE) reiterates that the overall net impact to the Test Years 2023 and 2024 revenue requirements would be minimal (i.e. 0.01 percent increase in residential customer rates for the FSJ/DC division and 0.08 percent decrease for the TR division) even if the results of the 2022 Depreciation Study were implemented in Test Year 2023.[54] PNG(NE) also explains that the timing of the 2022 Depreciation Study aligns with the net salvage phase-in as directed under BCUC Order G-222-18. PNG(NE) notes that even though the concerns raised by BCOAPO regarding implementation of the 2022 Depreciation Study might appear “administrative” and “bureaucratic”, these concerns are not the basis for PNG(NE)’s proposed implementation of the study results in 2024.[55]

Panel Determination

The Panel approves the depreciation rates and net salvage rates included in the 2022 Depreciation Study, effective January 1, 2024, as per section 56(2) of the UCA. The Panel agrees with PNG(NE)’s view that implementing the results of the 2022 Depreciation Study in Test Year 2024 would align with the first test period following the five-year phase-in of the provision for net salvage as approved by BCUC Order G-222-18. Furthermore, the Panel acknowledges there would only be a minimal net rate impact if the 2022 Depreciation Study was implemented in Test Year 2023.

 

Regarding the issue surrounding the energy transition, the Panel notes Concentric’s views on when an economic planning horizon may be introduced. However, in consideration of the proposed rate increases, the Panel directs PNG(NE) to file its next depreciation study as part of its RRA for test year 2026. Additionally, the Panel directs PNG(NE) to discuss the work carried out on the economic planning horizon in its next RRA.

2.5              Short-Term Debt Component

PNG(NE) explains that historically, its short-term debt component in its capital structure was set at approximately 5 percent of rate base, reflective of the fact that the majority of assets forming part of the rate base are long-term in nature. However, in the Application, PNG(NE) has revised this assumption to 1 percent of rate base, a decision based on “past practice and experience”, which has resulted in lower forecast short-term borrowings for Test Year 2023 as compared to Decision 2022 by $3.261 million for the FSJ/DC division[56] and $0.266 million for the TR division.[57]

 

PNG(NE) clarifies that this reduction of the short-term debt component is closer to PNG(NE)’s actual business practices.[58] Further, PNG(NE) explained that recent significant increases in short-term interest rates make it more beneficial for PNG(NE) to pursue long-term debt.[59]

Positions of the Parties

BCOAPO views the reduction of the short-term debt component to 1 percent of rate base as reasonable for the current RRA.[60] However, it adds that merely citing “past practice” to justify reduction of the short-term debt component would not facilitate the decision-making requirements of the BCUC and recommends that the BCUC direct PNG(NE) to provide an analysis of the risk and return (cost) considerations associated with its proposed proportion of short-term debt in the next RRA.[61]

 

In reply, PNG(NE) objects to BCOAPO’s recommended direction for the next RRA, considering it unnecessary, as the BCUC does not prescribe how debt is allocated between the short-term and long-term components.[62]

Panel Determination

The Panel directs PNG(NE) to provide an evaluation of whether the proportion of short-term and long-term debt is appropriate as part of its next RRA. The Panel agrees with PNG(NE)’s view that reducing the short-term debt component to 1 percent of rate base will provide greater cost certainty to ratepayers. Nevertheless, the Panel acknowledges the merit in BCOAPO’s recommendations and finds it appropriate to review PNG(NE)’s proportion of short-term debt in its capital structure, such that the BCUC can verify that any changes to the debt structure for the purposes of setting rates are justified and do not result in undue financial burden for ratepayers.

3.0              Capital Expenditures

PNG(NE) forecasts capital expenditures before overhead of $5.430 million and $6.728 million for the FSJ/DC division for 2023 and 2024, respectively.[63] For the TR division, PNG(NE) forecasts capital expenditures of $661,410 for 2023 and $332,955 for 2024.[64] These figures are subject to the adjustments to be reflected in PNG(NE)’s compliance filing as summarized in Appendix A to this decision.

 

The following subsections address specific capital expenditures forecast for 2023 and 2024.

3.1              Steel Main Replacement

PNG(NE)’s Steel Main Replacement (SMR) is an ongoing multi-year program that commenced in 2018 in response to industry best practice learnings.[65] The SMR program is meant to replace vintage pipelines to maintain the integrity and reliability of the mainline transmission system.[66] 

 

PNG(NE) explained that a number of SMRs that represented significant integrity and public threats were undertaken from 2019 through 2022. These replacements were prioritized based on critical locations, historic leaks, and known integrity threats from third-party activity. PNG(NE) submits that it has identified the need to improve and reprioritize its approach for SMRs after addressing these immediate threats with the aim of effectively managing asset risk and reprioritizing related activities.[67] The average actual annual expenditures for this program between 2020 and 2022 are approximately $500,000.[68]

 

For this Test Period, PNG(NE) is forecasting capital expenditures before overhead of $268,000 in 2023 and $768,000 in 2024.[69] PNG(NE) states that this forecast reflects a reduction in planned physical SMR activities compared to recent years and an increased focus on additional measures to validate PNG(NE)’s current risk prioritization.[70] Accordingly, in 2023, PNG(NE) plans to perform a number of planned indirect and direct assessments.[71] PNG(NE) expects to identify locations for excavation and direct inspections through non-destructive examination (NDE) methods based on data collected from indirect inspections to further verify the integrity condition and health status of the steel mains.[72] In PNG(NE)’s view, improving upon its distribution system dataset will allow for better determination and decision-making of future SMR based on overall risk evaluation and prioritization of SMR activities against other asset management programs and plans while considering future rate impacts.[73] PNG(NE) confirmed that planning and prioritization of SMRs will not be based on only indirect inspection or direct assessment but rather a combination of both.[74]

 

PNG(NE) explained that the 2024 capital expenditures are based on anticipated findings from the 2023 assessments, followed by re-engagement of physical replacement activities, which include targeted SMRs based on the outcomes from 2023’s analysis and reconnection and/or replacement of steel mains being removed from service due to integrity concerns.[75] Subject to outcomes from the 2023’s assessments, PNG(NE)’s plans for 2024 also include the replacement of three distribution steel mains with polyethylene pipe, one of which experienced leaks due to external corrosion in 2022.[76] PNG(NE) clarified that these SMR projects were originally planned for 2023 and 2024 prior to the decision to stop SMR and reassess the program in 2023.[77] PNG(NE) submits that to avoid the deferral of costs into subsequent years of the program following the 2023 pause in physical SMR work, it has elected to intensify direct assessments and replacement efforts in 2024, aiming to restore the program’s pace as originally planned in 2019.[78]

 

PNG(NE) anticipates basing future capital needs for the program on average spending from previous years, with necessary adjustments for specific situations, alignment with annual budget amounts, and reallocation of uncompleted scope to remaining program execution years.[79] PNG(NE) states that it expects to provide the forecast expenditures that are anticipated in the upcoming 5 to 10 years for this program in the next RRA.[80]

Positions of the Parties

RCIA supports PNG(NE)’s strategy of using integrity condition-based data from both indirect and direct assessments for the SMR program. However, RCIA disagrees with the use of a “general, non-condition-based approach” to the SMR. RCIA considers it inappropriate to catch-up with the original 2019 schedule in 2024 as it does not reflect a risk-informed approach to decision-making. Thus, RCIA recommends that PNG(NE) develop the 2024 forecast costs for SMR using the three-year average of the actual expenditures from 2020 to 2022, which could reduce the 2024 capital expenditures by $261,000.[81]

 

In reply, PNG(NE) clarified that although the 2023 expenditures reflect inspection costs to inform future work, the 2024 expenditures are not for “general” expenditures and are indeed designated for three specific projects as outlined in responses to information requests. PNG(NE) disagrees with RCIA’s recommendation regarding adjustments to SMR costs for 2024.[82]

Panel Determination

The Panel finds the proposed capital expenditures for the SMR program for the Test Period to be reasonable and appropriate. The Panel is persuaded by PNG(NE)’s risk-based approach to SMR and accepts PNG(NE)’s 2024 budget, which aims, in part, at replacing three pipelines, including one with leaks.

 

3.2              Rolla Lateral Repair & Recommissioning Project

In the Updated Application, PNG(NE) included forecast capital expenditures before overhead of $612,000 in 2023 and $1.206 million in 2024 to execute Phase 2 of the Rolla Lateral Repair and Recommissioning project in DC (Rolla Lateral Project).[83] The Rolla Lateral Project was originally planned to be executed in a two-phase approach, with project planning and front-end engineering design (FEED) activities to be completed in Phase 1, and construction execution activities planned for Phase 2.[84] PNG(NE) confirms that Phase 1 was completed in the 2020–2021 test period. However, the project was further developed relative to the 2020–2021 plans, and PNG(NE) identified the need for additional engineering and design work to execute the scope planned for 2023–2024.[85]

 

The primary purpose of the Rolla Lateral Project is to provide a secondary high-pressure feed to DC to enable PNG(NE) to perform integrity inspection and repair works while efficiently maintaining a continuous gas supply through the existing main town feed pipeline, i.e. the 6” Sunrise and Penn West pipeline (Penn West pipeline).[86] Anticipated integrity inspection and repair works on the Penn West pipeline require system-wide outages.[87] PNG(NE) states that another driver for the reactivation of the Rolla Lateral is to avoid outages by Enbridge due to emerging integrity repairs being executed on its transmission mainline, which supplies gas to the Penn West pipeline.[88]

3.2.1        Dawson Creek Supply Study

In response to IRs, PNG(NE) noted that due to the recent changes to Enbridge’s integrity repair plans on the transmission mainline that feeds the Penn West pipeline, the associated potential threat to DC supply, and anticipated future costs to PNG(NE), PNG(NE) made the decision to pause activities and spending on the Rolla Lateral Project in 2023 and 2024.[89] PNG(NE) asserts that Enbridge anticipates regular integrity work in the future, underscoring the need for an alternative supply source to DC.[90] Accordingly, PNG(NE) submits that it has shifted focus to develop an overall DC gas supply study with the purpose of improving costs, certainty of a solution, and longer-term reliability for the overall DC system.[91] The study will evaluate prospective supply alternatives, including those already identified as feasible. These may include (i) integrity repairs to the Penn West pipeline, (ii) Penn West pipeline replacement, (iii) Rolla Lateral recommissioning, (iv) Rolla Lateral replacement, (v) additional pipeline from other operators, and (vi) Liquefied natural gas supply for ongoing operations.[92]

 

Accordingly, PNG(NE) proposes to revise the capital expenditures in the Test Period to reduce expenditures related to the Rolla Lateral Project down to $145,000 in 2023 and nil in 2024.[93] Additionally, PNG(NE) proposes to add a provision for capital expenditures of $25,000 in 2023 and $364,750 in 2024 to complete the DC supply study.[94]

 

PNG(NE) states it expects to complete the study in 2024 and file an application with the proposed preferred supply alternative for approval of a Certificate of Public Convenience and Necessity (CPCN) to the BCUC for this project in 2025.[95]

Positions of the Parties

RCIA supports PNG(NE)’s decision to pause activities on the Rolla Lateral Project to focus on the supply study to DC.[96] However, RCIA notes that while PNG(NE) will reflect the adjustments in the final regulatory schedules, PNG(NE) did not provide the resulting impacts to the revenue deficiencies and rate increases for the Test Period in its final argument.[97]

In reply, PNG(NE) provides a summary of the revenue deficiency and rate impact of the proposed adjustments to be made in its final regulatory schedules, which include adjustments to the Rolla Lateral Project and the addition of the DC supply study. PNG(NE) submits that the impact of all proposed adjustments will be very minimal on the average residential rate increases for each year, with the FSJ/DC average rate increase to decrease by 0.1 percent in 2023 and 2024, and the TR average rate increase to remain unchanged.[98]

Panel Determination

The Panel directs PNG(NE) to create a new deferral account (Dawson Creek Supply Study deferral account) to record initial pre-FEED and FEED costs up to $390,000, attracting interest at PNG(NE)’s weighted average cost of capital (WACC). The disposition of this deferral account will be determined as part of a future RRA. The Panel considers PNG(NE)’s decision to pause activities related to the recommissioning of the Rolla Lateral Project to focus on developing a supply study to DC reasonable and prudent. However, similar to the TR supply study discussed in Section 4.3 of this decision, the supply study for DC will inform a CPCN application expected to be filed in 2025. Therefore, the Panel considers it appropriate to record the associated forecast costs in a deferral account, rather than capitalizing these amounts as proposed by PNG(NE). The Panel determines the financing costs for this deferral account in Section 4.1 below, along with PNG(NE)’s other long-term non-rate base deferral accounts. Further, we find it reasonable to determine the disposition of this deferral account in a future RRA.

 

With respect to the DC supply study, the Panel has concerns about PNG(NE) adding a new natural gas pipeline as a long-term supply alternative to DC due to potential declines in future demand related to federal and provincial government greenhouse gas emission reduction policies. Therefore, the Panel recommends that PNG(NE) provide a demand-supply scenario analysis in its forthcoming CPCN that takes into account all current applicable climate change policies and legislation, and weather-related demand which may impact future load in PNG(NE)’s service area. Further, the Panel expects PNG(NE) to include the potential for greenhouse gas emission reductions as a criterion of its analysis of alternative solutions in its DC supply project CPCN application.

3.3              Unspecified System Betterment

In the Updated Application, PNG(NE) forecasts capital expenditures for the Unspecified System Betterment capital project of $389,000 and $455,000 in 2023 and 2024, respectively.[99] The purpose of this capital project is to address unplanned repairs or improvements across the PNG(NE) system. PNG(NE) clarified that the Unspecified System Betterment program encompasses the former Main Repairs and Assessment capital program, which has incurred average actual capital expenditures in the last three years (i.e. 2020–2022) of approximately $201,000.[100]

 

PNG(NE) submits that the expenditures for the 2023 to 2024 Test Period could be associated to directives from a Municipality or the Ministry of Transportation and Infrastructure, which may require modifications, removals, relocations, or replacements.[101]

 

In addition to this, PNG(NE) explained that the forecast expenditures for 2023 cover the costs related to:[102]

•         Damage caused by third-party line strikes; and

•         Repairs and relocations related to geotechnical and hydrotechnical activity (e.g. washouts, line exposures from seasonal runoff, etc.).

PNG(NE) asserts that, when feasible, the costs from third-party line strikes are recovered from the responsible parties and are utilized to help cover the cost associated with construction repairs. PNG(NE) states that once collection efforts are exhausted, the remaining unrecovered costs are capitalized.[103] PNG(NE) submits that the primary contributors to the increased forecast in the Test Period are upward pressures associated with road and water infrastructure relocations and betterment and observed seasonal weather trends.[104]

Positions of the Parties

RCIA submits that the forecast capital expenditures for the Unspecified System Betterment program have not been justified by PNG(NE), as PNG(NE) did not provide concrete details to support the budget increase for the Test Period. In RCIA’s view, PNG(NE)’s reasons are “vague and speculative”. Therefore, RCIA recommends that PNG(NE) keep the forecast for the Test Period at levels consistent with the recent approved forecasts of $200,000 per year.[105]

 

In reply, PNG(NE) states that it has reviewed the actual capital expenditures and noted that no funds will be incurred in 2023. As a result, PNG(NE) proposes to reduce the 2023 and 2024 forecasts to zero and $200,000, respectively, to align with the average approved forecast from 2020–2022. PNG(NE) proposes to reflect this change in its final regulatory schedules.[106]

Panel Determination

The Panel finds PNG(NE)’s adjustments to forecast capital expenditures for the Unspecified System Betterment capital project appropriate and reasonable. The Panel notes that PNG(NE) will reflect the adjustments for this capital program for the 2023–2024 Test Period in its final compliance filing for this proceeding.

3.4              Mobile/Heavy Equipment

PNG(NE) forecasts capital expenditures for its Mobile/Heavy Equipment in the FSJ/DC division of $383,000 in 2023 and $142,000 in 2024. These forecast expenditures are allocated for replacement and acquisition of passenger vehicles and heavy equipment for the Test Period.[107]

 

PNG(NE)’s forecast Mobile/Heavy Equipment expenditures for the Test Period are based on its updated policy for vehicle replacements, which is discussed in the following subsection.

3.4.1        New Criteria for Replacement of Passenger Vehicles

Prior to 2023, like most Canadian utilities, PNG(NE)’s historical criteria for vehicle replacements were based on mileage and age. However, PNG(NE) recognizes that the current rate pressures may require a different approach. PNG(NE) explains that as a result of increasing costs, persistent global supply chain issues and the associated uncertainty of each vehicle’s timely delivery, PNG(NE) began a more vehicle-specific approach to its vehicle replacement program.[108] Thus, in addition to the overall mileage and age, the new criteria also consider an assessment of each vehicle’s condition based on the specific application within PNG(NE)’s operational requirements, such as highways, short-distance driving, and rugged or paved terrains.[109]

 

To identify whether the useful life of specific units can be extended beyond the historical replacement practice, PNG(NE) explains that an assessment of each vehicle is performed, considering factors such as physical condition, maintenance history, mileage at the time of assessment, and primary usage.[110]

 

PNG(NE) notes that its revised, condition-based vehicle replacement criteria will responsibly reduce vehicle replacement costs that allow for funds to be used for higher risk needs.[111] Accordingly, PNG(NE) submits that applying the new replacement criteria as opposed to the historical approach results in a reduction of overall capital expenditures for this program for the FSJ/DC division in Test Year 2023.[112]

Positions of the Parties

RCIA appreciates PNG(NE)’s proactive approach to revise its vehicle replacement policy and address cost pressures. Nonetheless, RCIA recommends that PNG(NE) reassess its vehicle replacement policy regarding which positions require a dedicated vehicle and which can make use of shared or personal vehicles. RCIA also recommends that the BCUC direct PNG(NE) to file the updated vehicle use policy in its next RRA, including a review of assigned vehicles to management positions.[113]

In reply, PNG(NE) submits that it is committed to conducting a review of the need for dedicated vehicles as part of this program, and to incorporate the outcome in its next RRA.[114]

Panel Determination

The Panel accepts PNG(NE)’s proposed capital expenditures for Mobile/Heavy Equipment for the Test Period. The Panel notes that PNG(NE) has committed to revise its vehicle replacement policy, including the assignment of dedicated vehicles, in its next RRA. Based on the foregoing, the Panel does not consider a need to direct PNG(NE) to file the updated vehicle use policy in its next RRA, as recommended by RCIA.

4.0              Deferral Accounts

The subsections below address PNG(NE)’s approved financing for long-term non-rate base deferral accounts, requests to close specific deferral accounts, and requests to establish a new Tumbler Ridge Supply Study deferral account and Rate Smoothing deferral account.

4.1              Financing for Long-Term Non-Rate Base Deferral Accounts

PNG(NE) states that the current treatment of compensation for financing deferral account balances aligns with the determinations made by the BCUC in the PNG(NE) 2013 RRA Decision.[115] PNG(NE) further observes that the determinations under Order G-131-13 align with the key principles for deferral accounts established by the BCUC in the FortisBC Inc. 2012–2013 RRA Decision.[116]

 

During the IR process, the BCUC queried whether PNG(NE) considered it appropriate to re-evaluate its existing long-term non-rate base deferral accounts to attract interest at PNG(NE)’s WACC as opposed to WACD going forward, including for the proposed Tumbler Ridge Supply Study deferral account. In response, PNG(NE) stated that while it has no concern with the established principles, should the BCUC consider it desirable to re-evaluate the principles, PNG(NE) would support the BCUC’s efforts in this regard. PNG(NE) also observed that applying WACC to these deferral accounts would reflect the company’s cost of financing because it attempts to mirror the approved capital structure.[117]

Positions of the Parties

Interveners did not comment on the interest rate applicable to PNG(NE)’s long-term non-rate base deferral accounts.

Panel Determination

The Panel directs PNG(NE) to change the interest rate for its existing long-term non-rate base deferral accounts from the previously approved WACD to PNG(NE)’s WACC, commencing in Test Year 2023, and to continue using this approach going forward, subject to future determinations from the GCOC proceeding. The Panel finds WACC more appropriate for PNG(NE)’s long-term non-rate base deferral accounts to align with PNG(NE)’s actual cost of financing these long-term deferrals. This will result in the amounts expended on behalf of customers being financed for rate-making purposes at the same rate they are financed by PNG(NE). We note that changing the interest rate from WACD to WACC will have a minimal impact on the Test Period revenue requirements, as the interest costs are rolled into the balance of the long-term deferral account being amortized. Therefore, this change will have no material impact on rates for the Test Period.

 

In the FortisBC Inc. 2020–2021 Annual Review Decision, the BCUC stated: [118]

 

In our view, the 2012-2013 RRA Decision is not binding on subsequent panels; section 75 of the UCA is clear that we are not bound to follow prior BCUC decisions. […]

 

On the other hand, we recognize that the BCUC seeks to make decisions that are consistent with prior, relevant decisions.

 

Above all, though, we return to section 75 of the UCA which requires us to make our decision on the merits and justice of the case. FBC incurs costs to finance its deferral accounts. A deferral account creates a timing difference between when funds are spent and when those costs are returned to or recovered from ratepayers, and that timing difference leads to financing costs for the utility. […] The Panel accepts FBC’s justification for rate base treatment for these deferral accounts since it results in the amounts expended on behalf of customers being financed for rate making purposes at the same rate they are financed by the utility. […]

 

The BCUC established that deferral account financing costs is in scope in the GCOC proceeding and will be reviewed after the completion of Stage 1 and Stage 2 of the GCOC proceeding.[119]

 

We agree with the FBC 2020–2021 Annual Review Decision that under section 75 of the UCA, we are not bound by precedent, including prior BCUC decisions. Further, the timing of the GCOC decision on this matter is uncertain. Therefore, we find it appropriate to change the financing costs of PNG(NE)’s long-term non-rate base deferral accounts at this time, subject to future determinations from the GCOC proceeding.

4.2              Closure of Existing Deferral Accounts

The subsections below address PNG(NE)’s requests for approval to close the COVID-19 deferral account and the Shared Corporate Services Costs deferral account, respectively.

4.2.1        COVID-19 Deferral Account

In 2020, the BCUC approved the establishment of a COVID-19 deferral account for PNG(NE) to record any incremental expenses and cost savings related to the COVID-19 pandemic. Costs accumulated in 2020 and 2021 in this deferral account were fully amortized in 2022. PNG(NE) states that its operations have not been significantly impacted by COVID-19 during 2022 and there are no forecast additions to this deferral account.[120] In PNG(NE)’s view, there is no longer a need for this deferral account and PNG(NE) requests approval to close the deferral account, effective January 1, 2023.[121]

Positions of the Parties

RCIA did not comment on PNG(NE)’s COVID-19 deferral account. BCOAPO has no concerns with the closure of the COVID-19 deferral account.[122]

Panel Determination

The Panel approves PNG(NE)’s request to close the COVID-19 deferral account for each of the FSJ/DC and TR divisions, effective January 1, 2023. The Panel finds that the COVID-19 deferral account has served its purpose. Given that the balance in this deferral account was fully amortized in 2022 and PNG(NE) does not anticipate significant impacts to its operations by COVID-19 since 2022, the Panel finds that there is no need for PNG(NE) to continue to maintain this deferral account.

4.2.2        Shared Corporate Services Costs Deferral Account

The Shared Corporate Services Costs deferral account was established in 2020 to smooth the rate impact of the approved full recovery of the forecast annual TSU Shared Corporate Services Costs. PNG(NE) was directed to record to this account $375,000 of its allocated portion of these costs for the FSJ/DC division and $24,000 for the TR division and in 2020 and $372,000 of its allocated portion of these costs for the FSJ/DC division and $25,000 for the TR division in 2021. Balances in this account are being amortized over a three-year period, with Test Years 2023 and 2024 reflecting the final amortization of the 2020 and 2021 additions to this deferral account.[123] In PNG(NE)’s view, it would be appropriate to close the Shared Corporate Services Costs deferral account following the amortization of final balances in Test Year 2024 and PNG(NE) requests approval to close the deferral account, effective December 31, 2024.[124]

Positions of the Parties

RCIA did not comment on PNG(NE)’s Shared Corporate Services Costs deferral account. BCOAPO has no concerns with the closure of this deferral account after the balance is fully amortized.[125]

Panel Determination

The Panel approves PNG(NE)’s request to close the Shared Corporate Services Costs deferral account for each of the FSJ/DC and TR divisions, effective December 31, 2024. The Panel finds that the Shared Corporate Services Costs deferral account has served its purpose to smooth the rate impact associated with the change to full recovery of the forecast annual TSU Shared Corporate Services Costs. Given that the balance in this deferral account will be fully amortized in 2024, the Panel finds that there is no need for PNG(NE) to continue to maintain this deferral account after Test Year 2024.

4.3              Proposed Tumbler Ridge Supply Study Deferral Account

In 2022, PNG(NE) commenced pre-Front End Engineering and Design (pre-FEED) to explore long-term supply options for Tumbler Ridge. Challenges persist with the existing supply arrangement due to feed gas variability, inconsistent gas quality from the supplier, and uncertainties regarding the long-term supply. In addition, PNG(NE)’s processing and transmission assets are aging and require substantial investment to continue safe and reliable service.[126]

 

PNG(NE) seeks approval to establish the Tumbler Ridge Supply Study deferral account to record initial pre-FEED, FEED costs, and transmission line inspections costs, up to $475,000, related to evaluating identified feasible long-term supply options for Tumbler Ridge.^[127] PNG(NE) also plans to fund the Metal Magnetic Memory Method (MMM)[128] inspection of segments of the transmission line with a forecast cost of $118,000 from the proposed study funding of $475,000.[129] PNG(NE) expects to file a CPCN application for a long-term supply solution for Tumbler Ridge in April 2024[130] and to propose a deferral account recovery mechanism in the next RRA, which is expected to be filed in November 2024.[131]

 

PNG(NE) proposes that this deferral account attract interest at PNG(NE)’s WACD in line with the deferral account principles established in the FortisBC Inc. 2012–2013 RRA Decision. However, PNG(NE) stated that should the BCUC consider it desirable to re-evaluate the principles, PNG(NE) would support the BCUC’s efforts in this regard.^[132]

 

If the forecast costs, prior to the Evidentiary Update, of approximately $407,000 in 2023 and $68,000 in 2024 were expensed in the year incurred, PNG(NE) calculates that the average residential basic charge and delivery rate would increase by 27.6 percent in Test Year 2023 and decrease by 5.7 percent in Test Year 2024, compared to rate increases of 8.2 percent in each of Test Years 2023 and 2024 with the costs recorded in the deferral account.[133] Subsequent to the Evidentiary Update, while total forecast expenditures remain at $475,000, the forecast costs for elements of the Supply Study deferral account have been revised with forecast costs of $410,858 in 2023 and $64,142 in 2024. This includes the updated MMM inspection forecast cost of $118,000 in 2023.[134]

 

During the proceeding, PNG(NE) confirmed that it would make a correction to the Test Year 2023 additions to the Supply Study deferral account in its final regulatory schedules to $475,000 and to the associated imputed interest for both Test Years 2023 and 2024.[135]

Positions of the Parties

RCIA did not comment on the Tumbler Ridge Supply Study deferral account. BCOAPO has no concerns with PNG(NE)’s proposals regarding this deferral account.[136]

Panel Determination

The Panel approves the establishment of the Tumbler Ridge Supply Study deferral account to record initial pre-FEED, FEED costs, and transmission line inspections costs, up to $475,000, attracting interest at PNG(NE)’s WACC. The disposition of this deferral account will be determined as part of the next RRA. The Panel finds it reasonable that the proposed forecast costs be deferred for the Test Period. The Panel considers it appropriate for PNG(NE) to carry out the supply study for TR and notes that this study will inform a CPCN application expected to be filed in 2024. The Panel determines the financing costs for this deferral account in Section 4.1 above, along with PNG(NE)’s other long-term non-rate base deferral accounts. Further, we find it reasonable to determine the disposition of this deferral account in the next RRA, as proposed by PNG(NE).

 

The Panel directs PNG(NE) to update the Test Year 2023 additions to the TR Supply Study deferral account, including the flow through impacts to correct the imputed interest, in its compliance filing.

4.4              Rate Smoothing Deferral Account

PNG(NE) seeks approval to create a short-term interest-bearing deferral account in 2023 to smooth the impact of the combined net revenue deficiencies for 2023 and 2024 to be fully amortized in 2024, which is consistent with the approach to smooth rates in the PNG(NE) 2020–2021 and 2018–2019 RRAs.[137]

 

For the FSJ/DC division, PNG(NE) proposes to move $0.490 million of the 2023 revenue deficiency to a short-term interest-bearing deferral account for amortization in 2024. This results in residential basic charge and delivery rate increases of approximately 6.4 percent in each of 2023 and 2024. In the absence of the rate deferral mechanism, the residential rate increases would be approximately 8.7 percent in 2023 and 1.8 percent in 2024.[138]

 

For the TR division, PNG(NE) proposes to move $0.120 million of the 2023 revenue deficiency to a short-term interest-bearing deferral account and amortize in 2024. This results in residential basic charge and delivery rate increases of approximately 8.2 percent in each of 2023 and 2024. In the absence of the rate deferral mechanism, the residential rate changes would be an increase of approximately 13.9 percent in 2023 and a subsequent decrease of approximately 2.5 percent in 2024.[139]

 

PNG(NE) submits that, subject to rebalancing to reflect the adjustments summarized in Section 3.2 of its final argument, the proposed rate deferral mechanism should be approved as applied for to provide customers with rate stability by reducing volatility in rates that would otherwise be determined.[140]

Positions of the Parties

RCIA supports the use of the Rate Smoothing deferral account to equalize the rate impacts over the two Test Years. Conversely, RCIA would not support an attempt to rate-smooth beyond the Test Years by deferring a portion of the revenue deficiency for a longer period, as there is no expectation that PNG(NE)’s revenue requirement will decrease in future test years.[141]

 

BCOAPO recommends an alternative rate mitigation option that involves PNG(NE) targeting levelized residential rate increases of 5 percent in both 2023 and 2024, by using the Rate Smoothing deferral account and leaving an estimated balance of $557,000 in the FSJ/DC account and $183,000 in the TR account at the end of 2024 to be amortized (i.e. recovered) in future test years.^[142] BCOAPO submits that its proposal is reasonable considering the potential amalgamation opportunities between the PNG divisions and a long-term strategic rate mitigation approach.[143]

 

In reply, PNG(NE) submits that it has presented a realistic approach to rate setting for the Test Period and rejects BCOAPO’s proposal to defer revenue deficiencies into the future through a longer amortization of the Rate Smoothing deferral account, considering that a reduction in the cost of service is not anticipated and load growth opportunities are limited.^[144]

Panel Determination

The Panel approves the establishment of a Rate Smoothing deferral account for each of the FSJ/DC and TR divisions bearing interest at PNG(NE)’s short-term interest rate to record the following amounts, subject to adjustments identified during the proceeding regarding capital expenditures and the TR Supply Study deferral account, along with the directives and determinations in this decision:

•         FSJ/DC division: $0.490 million of the 2023 revenue deficiency, to be amortized in 2024.

•         TR division: $0.120 million of the 2023 revenue deficiency, to be amortized in 2024.

The Panel finds that PNG(NE)’s approach is reasonable, given that it results in the benefit of rate stability over the Test Period, with rate increases smoothed evenly over the two years. This approach is consistent with that approved in the PNG(NE) 2020–2021 and 2018–2019 RRAs.

 

The Panel recognizes that the DC and TR supply studies, as discussed in Sections 3.2.1 and 4.3 above, respectively, will put upward pressure on future rates. Thus, the Panel is persuaded by PNG(NE)’s proposal to recover these costs in the Test Period rather than deferring additional rate pressures to 2025, as BCOAPO proposes. We note that there is no expected reduction to PNG(NE)’s future revenue requirements, limited load growth opportunities; and that the proposed rate increases are lower than that approved for the PNG-West division.

5.0              Overall Determination on Basic Charges, Delivery Rates and Revenue Stabilization Adjustment Mechanism

Historically, PNG(NE) has solely applied approved revenue requirement increases to the delivery rate. Consequently, the basic charge has remained unchanged for more than 20 years.[145] Since 2000, there has been a significant shift in cost allocation, with an increasing proportion of costs recovered volumetrically through the delivery rate and a corresponding decrease in the proportion of costs recovered through the basic charge. In the case of FSJ/DC, with a standard consumption rate of approximately 100 GJs annually, the proportion of costs recovered through the basic charge has declined from 33 percent in 2000 to 12 percent in 2022, while the proportion allocated to the delivery rate has risen from 67 percent to 88 percent.[146] In the case of TR, with a standard consumption rate of approximately 88 GJs annually, the proportion of costs recovered through the basic charge has declined from 50 percent in 2000 to 9 percent in 2022, while the proportion allocated to the delivery rate has risen from 50 percent to 91 percent.[147]

 

PNG(NE) now seeks to change its historical practice, and effective January 1, 2023, proposes to recover the revenue sufficiency/deficiency through both the delivery rate and the basic charge.[148] PNG(NE) notes that the average bill increase for customers will remain unchanged. However, there will be small differences among customers based on their consumption.[149]

 

Although PNG(NE) has not undertaken a fully allocated cost of service study (FACOSS) in more than 20 years, it considers it appropriate to change the historic practice of solely changing the delivery rate to recover any revenue sufficiency/deficiency for a test period. PNG(NE) considers that even without updated FACOSS results, it is reasonable to assume that the basic charge would have been impacted by inflation over the 22 years, and as such, these increases are now being recovered through the delivery rate.[150]

 

PNG(NE) adds that it is in the early stages of undertaking a FACOSS, which will be used to determine the appropriate basic charge and delivery rate based on updated cost allocations and other factors, including revenue certainty. Given the length of time the basic charge has remained unchanged, PNG(NE) believes that despite not having an updated FACOSS, it is appropriate to allocate the revenue sufficiency/deficiency to both the delivery rate and the basic charge.[151]

 

Additionally, PNG(NE) is aware that its capital structure will be reviewed as part of Stage 2 of the BCUC GCOC proceeding. In the decision accompanying Order G-236-23 approving Stage 1 of the GCOC proceeding, PNG(NE) notes that the BCUC has indicated that for utilities that currently use FortisBC Energy Inc. (the Benchmark Utility) to set their capital structure and equity return, rates effective January 1, 2024 are to be set on an interim, refundable or recoverable basis pending the BCUC’s final decision on Stage 2 of the GCOC proceeding.[152] The BCUC also indicated that it will determine the manner by which any variance between approved interim rates and permanent rates, including interest if any, will be refunded or recovered at the time the BCUC renders its final decision on Stage 2 of the GCOC proceeding.[153]

 

PNG(NE) also seeks permanent approval for the RSAM rate rider for Test Year 2023, assuming a two-year amortization of the annual projected balances. This approach is consistent with prior years and was approved by the BCUC in its decision accompanying Order G-131-13.[154] As noted in Section 1.3 above, PNG(NE)’s RSAM rate riders for both Test Years 2023 and 2024 are currently approved on an interim and refundable/recoverable basis. PNG(NE) recommends that following this decision, as part of the compliance filing for this RRA for administrative efficiency, the approved RSAM rate rider for Test Year 2024 can be determined, incorporating actual data for 2023 and any adjustments arising from differences between the interim and approved 2023 and 2024 RSAM rate riders.[155]

Positions of the Parties

RCIA supports PNG(NE)’s proposal to address the revenue deficiency through increases in both the delivery rate and the basic charge and acknowledges that the basic charge no longer recovers the same level of costs as when it was initially approved.[156] RCIA adds that it supports the approach of increasing the basic charge in advance of PNG(NE) undertaking a FACOSS.[157]

 

BCOAPO supports PNG(NE)’s proposed changes to the basic charge, effective January 1, 2023, and submits that PNG(NE)’s approach avoids an unnecessarily steep one-time increase following completion of the FACOSS review.[158]

Panel Determination

PNG(NE)’s basic charges, delivery rates, and RSAM rate riders that were approved on an interim basis by Order G-373-22, are approved on a permanent basis, effective January 1, 2023.

 

For each of the FSJ/DC and TR divisions, PNG(NE) is directed to establish a deferral account (2023 Rate Variance deferral account) accruing interest at the average prime rate of PNG(NE)’s principal bank for its most recent year to record the difference between the following:

(i)      The permanent 2023 delivery rates and the adjusted 2023 delivery rates based on PNG(NE)’s compliance filing that reflect the adjustments summarized in Appendix A to this decision, along with the directives and determinations in this decision; and

(ii)    The permanent 2023 basic charges and the adjusted 2023 basic charges based on PNG(NE)’s compliance filing that reflect the adjustments summarized in Appendix A to this decision, along with the directives and determinations in this decision.

 

The disposition of the 2023 Rate Variance deferral account will be determined as part of the next RRA.

 

PNG(NE) is also directed to record the difference between the 2023 permanent RSAM rate rider and the RSAM rate rider as proposed in the Updated Application in the RSAM interest bearing deferral account for each of the FSJ/DC and TR divisions. The disposition of this difference will be determined as part of the next RRA.

 

Subject to the adjustments identified during this proceeding as summarized in Appendix A to this decision, along with the directives and determinations on the components of the 2023 and 2024 forecast revenue requirements for PNG(NE) as set out in this decision, the Panel finds the forecast revenue requirements reasonable for setting the delivery rates and basic charges for the Test Period. Additionally, the Panel finds the proposed RSAM rate riders for Test Year 2023 to be reasonable. However, in light of the timing of this decision, the Panel considers it reasonable to set 2023 interim rates as permanent. The variance between the 2023 permanent rates and the rates that would result from the adjustments summarized in Appendix A to this decision, along with the directives and determinations in this decision are to be recorded in a newly established 2023 Rate Variance deferral account for each of the FSJ/DC and TR divisions. This approach eliminates the need for any rate adjustments, providing PNG(NE) with better certainty for planning and operating.

 

Shifting focus to the 2024 Test Year, by Order G-305-23, the Panel approved PNG(NE)’s basic charges, delivery rates and RSAM rate riders as set forth in the Updated Application, on an interim and refundable/recoverable basis, effective January 1, 2024, subject to this decision and the BCUC’s final decision on Stage 2 of the GCOC proceeding. The Panel granted these approvals to support regulatory and administrative efficiency by ensuring PNG(NE) had sufficient time to implement interim rate changes, effective January 1, 2024, given the expected timing of this decision. Additionally, the Panel recognizes that PNG(NE) uses the Benchmark Utility to set its capital structure and equity return. Based on the decision accompanying Order G-236-23 approving Stage 1 of the GCOC proceeding, the Panel accepts that rates effective January 1, 2024 should remain interim and refundable or recoverable, pending the BCUC’s final decision on Stage 2 of the GCOC proceeding. Accordingly, further to Orders G-305-23 and G-236-23, the Panel directs PNG(NE) to update the 2024 interim basic charges, delivery rates and RSAM rate riders in its compliance filing to reflect the adjustments summarized in Appendix A to this decision, and the directives and determinations in this decision. PNG(NE) is further directed to include in its compliance filing, the mechanism to refund or recover any difference between the 2024 interim rates approved by Order G-305-23 and the 2024 interim rates resulting from this decision.

 

With respect to adjusting the basic charge, the Panel acknowledges that over the past 22 years, the basic charge has remained unchanged, while the delivery rate has increased. This shift in cost recovery has resulted in a substantial change in the allocation of costs, with an increasing proportion of costs recovered through the delivery rate and a corresponding decrease in the proportion of costs recovered through the basic charge. For the FSJ/DC division, the proportion of costs recovered through the basic charge has decreased from 33 percent in 2000 to 12 percent in 2022, and the proportion covered by the delivery rate has increased from 67 percent to 88 percent. For the TR division, the proportion of costs recovered through the basic charge has decreased from 50 percent in 2000 to 9 percent in 2022, and the proportion covered by the delivery rate has increased from 50 percent to 91 percent.

 

The Panel finds that PNG(NE)’s proposal to increase the basic charge is reasonable given the significant shift in cost allocation. This change aims to achieve a better balance in cost recovery between fixed and variable charges while addressing the revenue sufficiency/deficiency. The Panel also considers this a prudent measure pending the outcome of the upcoming FACOSS, which will further inform the appropriate allocation of costs and rates.

6.0              Other Matters

6.1              Other Issues Raised

This section addresses the recommendations made by BCOAPO that the BCUC direct PNG(NE) to complete a long-term rate mitigation plan for consideration in PNG(NE)’s next RRA.

 

In the PNG(NE) 2020–2021 RRA Decision, the BCUC urged PNG (collectively) to focus on the consideration and development of a comprehensive business strategy to address challenges of rising costs, decreasing system throughput, and declining customer use per account.[159] Further, in the PNG(NE) 2022 RRA Decision, the BCUC noted that the increased focus in BC with respect to decarbonization and electrification has made this need more acute.[160]

Positions of the Parties

Similar to BCOAPO’s concerns raised during the PNG(NE) 2022 RRA, BCOAPO submits that PNG(NE)’s rate mitigation strategies continue to be a short-term response to a longer-term strategic problem. BCOAPO considers that this longer-term problem is likely to be further exacerbated as a result of climate change policy and other business pressures such as aging infrastructure. Therefore, BCOAPO recommends that the BCUC direct PNG(NE) to complete a long-term rate mitigation plan for consideration in PNG(NE)’s next RRA.[161]

 

BCOAPO further submits that if PNG(NE) does not have the resources to complete such a plan, then the annual levelized rate increases of 6.4 to 8.2 percent should justify the cost of PNG(NE) obtaining external assistance on the plan and amortizing these costs over a term of at least five years given the ongoing value of such a plan to customers.[162]

 

PNG(NE) observes that it is cognizant of the challenges it faces and submits that it is persistently evaluating opportunities to mitigate rate increases. With a small customer base and limited load growth opportunities, PNG(NE) has focused on actions within its control, including the optimization of capital spending and the management of other expenditures. PNG(NE) further submits that it will continue to evaluate opportunities that are prudent, including those that may be achieved through amalgamation, rate harmonization and rate design changes.[163]

Panel Determination

The Panel directs PNG(NE) to file a long-term rate mitigation plan that extends two years beyond PNG(NE)’s next test period. For instance, if PNG(NE) files a two-year RRA for its next test period, the plan should span four years (i.e. the two-year test period and two years following the test period). The Panel considers a long-term rate mitigation plan is necessary considering the magnitude of the Test Period rate increases year over year, the expected upward pressure on future rates resulting from the DC and TR supply studies discussed previously, and the ongoing rate pressures for PNG(NE)’s customers. The Panel considers it crucial that PNG(NE) continue to address future pressure on rates in the context of the evolving climate change policies and legislation.

 

 

Dated at the City of Vancouver, in the Province of British Columbia, this            22^nd           day of January 2024.

 

 

 

Original signed by:

____________________________________

C. M. Brewer

Panel Chair / Commissioner

 

 

 

Original signed by:

____________________________________

T. A. Loski

Commissioner

 

 

 

 

 

Pacific Northern Gas (N.E.) Ltd.

2023–2024 Revenue Requirements Application

for the Fort St. John/Dawson Creek and Tumbler Ridge Divisions

 

 

 

After the Updated Application, PNG(NE) identified the following adjustments to its Test Period revenue requirements that it proposes to reflect in its final regulatory schedules.

 

The following table summarizes the proposed adjustments for each of the FSJ/DC and TR divisions.[164]

 

Table 6: PNG(NE) FSJ/DC and TR - Summary of Adjustments to Final Regulatory Schedules

 

Pacific Northern Gas Ltd.

2023–2024 Revenue Requirements Application

for the Fort St. John/Dawson Creek and Tumbler Ridge Divisions

 

Glossary and List of Acronyms

 

Acronym	Description
2022 Depreciation Study	PNG(NE) undertook a depreciation study in 2022 to update depreciation and net salvage rates for plant in service as at December 31, 2022
Amended Application	PNG (NE’)s amended 2023–2024 RRA dated February 28, 2023
BCOAPO or BCOAPO et al.	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 Center
BCUC	British Columbia Utilities Commission
Benchmark Utility	FortisBC Energy Inc.
Concentric	Concentric Advisors, ULC
CPCN	Certificate of Public Convenience and Necessity
CST	Customer Service Technician
DC	Dawson Creek
FACOSS	Fully allocated cost of service study
FBC	FortisBC Inc.
FEED	Front-End Engineering Design
FSJ	Fort St. John
Further Status Update	PNG(NE)’s further status update on PNG-West’s RS 80 customer’s project and financial situation filed on June 30, 2023
GCOC	Generic Cost of Capital
GJ	Gigajoule
IR	Information request
MMM	Metal Magnetic Memory method
NDE	Non-destructive examination
OMA&G	Operating, maintenance, administrative and general
Acronym	Description
Original Application	On November 30, 2022, PNG(NE) filed its 2023–2024 RRA seeking approval of, among other things, 2023 and 2024 basic charges and delivery rates on an interim and refundable/recoverable basis, effective January 1, 2023
Penn West Pipeline	Sunrise and Penn West pipeline
PNG	Pacific Northern Gas Ltd.
PNG(NE)	PNG’s subsidiary, Pacific Northern Gas (N.E.) Ltd.
PNG-West	PNG’s western division
PNG-West decision	PNG-West 2023-2024 RRA decision and final order G-339-23, dated December 11, 2023
RCIA	Residential Consumer Intervener Association
Rolla Lateral Project	Rolla Lateral Repair and Recommissioning project
RRA	Revenue requirements application
RS	Rate schedule
RS 80	PNG-West’s Large Volume Industrial Transportation Rate Schedule 80
RSAM	Revenue Stabilization Adjustment Mechanism
SMR	Steel Main Replacement
Status Update	PNG(NE)’s status update on PNG-West’s RS 80 customer’s project and financial situation filed on May 31, 2023
Test Period or Test Years	PNG(NE)’s fiscal years 2023 and 2024
TR	Tumbler Ridge
TSU	TriSummit Utilities Inc.
UCA	Utilities Commission Act
Updated Application	On July 21, 2023, PNG(NE) filed an evidentiary update to its RRA along with an updated application for approval of, among other things, revised 2023 and 2024 basic charges and delivery rates on a permanent basis
WACC	Weighted average cost of capital
WACD	Weighted average cost of debt

 

 

IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

and

 

Pacific Northern Gas (N.E.) Ltd.
Fiscal 2023 to 2024 Revenue Requirements

EXHIBIT LIST

 

Exhibit No.                                                                          Description

 

Commission documents

 

A-1	Letter dated December 15, 2022 – Appointing the Panel for the review of Pacific Northern Gas (N.E.) Ltd. 2023–2024 Revenue Requirements
A-2	Letter dated December 16, 2022 - BCUC Order G-373-22 establishing a regulatory timetable and public notice
A-3	Letter dated April 14, 2023 – BCUC Order G-83-23 amending the regulatory timetable
A-4	Letter dated April 17, 2023 – BCUC Information Request No. 1 to PNG(NE) Tumbler Ridge Division
A-5	PUBLIC - Letter dated April 17, 2023 – BCUC Public Information Request No. 1 to PNG(NE) Fort St. John/Dawson Creek and Tumbler Ridge Divisions
A-6	CONFIDENTIAL - Letter dated April 17, 2023 – BCUC Confidential Information Request No. 1 to PNG(NE) Fort St. John/Dawson Creek and Tumbler Ridge Divisions
A-7	Letter dated May 3, 2023 – BCUC Order G-102-23 amending the regulatory timetable
A-8	Letter dated June 1, 2023 – BCUC Order G-124-23 establishing a further regulatory timetable
A-9	Letter dated June 13, 2023 – BCUC amending the Panel for the review of the application
A-10	Letter dated July 10, 2023 – BCUC Order G-180-23 establishing a further regulatory timetable
A-11	Letter dated August 28, 2023 – BCUC Information Request No. 2 to PNG(NE) Tumbler Ridge Division
A-12	Letter dated August 28, 2023 – BCUC Information Request No. 2 to PNG(NE) Fort St. John/Dawson Creek and Tumbler Ridge Divisions
A-13	Letter dated September 27, 2023 – BCUC requesting final argument submissions from PNGNE
A-14	Letter dated October 25, 2023 – BCUC response to BCOAPO final argument extension request
A-15	Letter dated October 26, 2023 – BCUC response to BCOAPO additional final argument extension request
A-16	Letter dated November 10, 2023 – BCUC Order G-305-23 for Interim Rates for 2024 with Reasons for Decision
A-17	Letter dated December 14, 2023 - BCUC Order G-348-23 response to PNGNE request for advanced approvals

 

Applicant documents

 

B-1	Pacific Northern Gas (N.E.) Ltd. (PNG NE) - Fiscal 2023 to 2024 Revenue Requirements dated November 30, 2022
B-1-1	Letter dated February 28, 2023 – PNG NE submitting Amended Fiscal 2023 to 2024 Revenue Requirements
B-1-2	CONFIDENTIAL - Letter dated February 28, 2023 – PNG NE submitting Amended Fiscal 2023 to 2024 Revenue Requirements Confidential Appendix E
B-2	Letter dated February 13, 2023 – PNG NE submitting G-373-22 notification confirmation compliance
B-3	Letter dated May 1, 2023 – PNG NE submitting request to adjourn the proceeding
B-4	Letter dated May 12, 2023 – PNG NE Tumbler Ridge response to BCUC Information Request No. 1
B-5	Letter dated May 12, 2023 – PNG NE submitting response to BCUC Information Request No. 1
B-6	CONFIDENTIAL - Letter dated May 12, 2023 – PNG NE submitting response to BCUC Confidential Information Request No. 1
B-7	Letter dated May 12, 2023 – PNG NE submitting response to BCOAPO Information Request No. 1
B-8	Letter dated May 12, 2023 – PNG NE submitting response to RCIA Information Request No. 1
B-8-1	CONFIDENTIAL - Letter dated May 12, 2023 – PNG NE submitting response to RCIA Confidential Information Request No. 1
B-9	PUBLIC - Letter dated May 31, 2023 – PNG NE submitting redacted status update and recommendation on further process
B-9-1	CONFIDENTIAL - Letter dated May 31, 2023 – PNG NE submitting confidential status update and recommendation on further process
B-10	Letter dated June 30, 2023 – PNG NE submitting status update and recommendation on further process
B-11	Letter dated July 21, 2023 – PNG NE submitting evidentiary update
B-11-1	Letter dated July 21, 2023 – PNG NE submitting amended application
B-12	Letter dated September 20, 2023 – PNG NE submitting response to BCUC Information Request No. 2
B-13	Letter dated September 20, 2023 – PNG NE Tumbler Ridge submitting response to BCUC Information Request No. 2
B-14	Letter dated September 20, 2023 – PNG NE submitting response to BCOAPO Information Request No. 2
B-15	Letter dated September 20, 2023 – PNG NE submitting response to RCIA Information Request No. 2

Intervener documents

C1-1	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 January 6, 2023 request to intervene by Leigha Worth
C1-2	Letter dated April 26,2023 – BCOAPO submitting Information Request No. 1 to PNGNE
C1-3	Letter dated August 28, 2023 – BCOAPO submitting Information Request No. 2 to PNGNE
C1-4	Letter dated October 24, 2023 – BCOAPO submitting extension request to file Final Argument
C1-5	Letter dated October 25, 2023 – BCOAPO submitting additional extension request to file Final Argument
C2-1	Residential Consumer Intervener Association (RCIA) - Letter dated January 30, 2023 Request to Intervene by Samuel Mason
C2-2	Letter dated March 23, 2023 – RCIA submitting Confidentiality Declaration and Undertakings
C2-3	Letter dated April 10,2023 – RCIA submitting extension request to file Information Request No. 1
C2-4	PUBLIC - Letter dated April 26,2023 – RCIA submitting Information Request No. 1 to PNGNE
C2-4-1	CONFIDENTIAL - Letter dated April 26,2023 – RCIA submitting confidential Information Request No. 1 to PNGNE
C2-5	Letter dated August 28, 2023 – RCIA submitting Information Request No. 2 to PNGNE

 

Letters of comment

 

E-1	Mahone, J. (Mahon) – Letter of Comment dated January 4, 2023