| Pacific Northern Gas Ltd.
2022 Revenue Requirements Application for the PNG-West Division |
| Decision and Order G-281-22 |
| October 11, 2022 |
|
|
| Before: A. K. Fung, KC, Panel Chair A. C. Dennier, Commissioner B. A. Magnan, Commissioner |
TABLE OF CONTENTS
Page no.
2.0 2022 Revenue Requirements and Revenue Deficiency
2.1 Operating, Maintenance, and Administrative & General Expenses
2.1.2 Administrative & General Expenses
3.1 2021 Unplanned Capital Expenditures
3.2 Transmission Mainline Integrity Campaign & Assessments
3.3 CPCN-Approved Capital Projects
3.3.1 Salvus to Galloway Remediation Project
4.1 LNG Partners Option Fee Payment Deferral Account
4.3 Reactivation Project Development Cost Deferral Account
4.4 Transfer Pricing / Interaffiliate Recoveries Deferral Account
4.5 Proposed New Deferral Accounts
4.5.1 Incremental CCA Deferral Account
4.5.2 RECAP Deferred Demand Charges Deferral Account
4.5.3 CIS Project Recoveries Deferral Account
4.5.4 Shared Corporate Services Costs Variance Deferral Account
5.0 Overall Determination on Delivery Rates and Revenue Stabilization Adjustment Mechanism
6.0 Unaccounted for Gas Component of Company Use Gas
7.1 Rate Design and Amalgamation Considerations
COMMISSION ORDER G-281-22
APPENDICES
Appendix A: Glossary and List of Acronyms
Appendix B: Exhibit List
Pacific Northern Gas Ltd. (PNG) 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, referred to as its western division, or PNG-West. PNG-West serves approximately 20,500 natural gas customers with an additional 130 propane customers in Granisle, B.C.[1]
On March 7, 2022, PNG filed on behalf of PNG-West its 2022 revenue requirements application (RRA) requesting approval of permanent 2022 delivery rates for all rate classes and a permanent Revenue Stabilization Adjustment Mechanism (RSAM) credit rate rider of $0.786/Gigajoule (GJ), effective January 1, 2022, in addition to other approvals sought (the Application). The permanent 2022 delivery rates contained in the Application include the following:[2]
a) A 4.8 percent increase from $12.384/GJ to $12.974/GJ for Residential service;
b) A 4.5 percent increase from $10.425/GJ to $10.897 /GJ for Small Commercial service; and
c) A 5.7 percent increase from $7.095/GJ to $7.501/GJ for Granisle Propane service.
The Panel established a written public hearing process, in which two parties, British Columbia Old Age Pensioner’s Organization, Active Support Against Poverty, Council of Senior Citizen’s 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.
PNG-West applied for several adjustments during this proceeding to its 2022 delivery rates requested in the Application, which are summarized in PNG-West’s final argument.[3] PNG-West proposed to increase the credit amortization of the LNG Partners Option Fee Payment deferral account in 2022 to $0.605 million to maintain the final average delivery rate increase at approximately five percent after taking into account the impact of these adjustments.[4] The Panel found PNG-West's proposal to be a reasonable rate mitigation measure in order to achieve rate stability and reduce the amount of the delivery rate increase in 2022. Accordingly, the Panel approves PNG-West's request to amortize $0.605 million of the balance in the LNG Partners Option Fee Payment deferral account in 2022.
There are several factors that contribute to increases to PNG-West’s 2022 costs that were identified during the proceeding, including planned right-of-way clearing activities, new staff positions, and increases in TSU Shared Corporate Services Costs. Subject to an adjustment in respect of director’s fees and expenses, the Panel found PNG-West's forecasts of costs to be reasonable. The Panel approves the 2022 delivery rates and RSAM rate rider on a permanent basis and effective January 1, 2022, as filed by PNG-West in the Application and subject to the adjustments summarized in PNG-West’s final argument, along with the directives and determinations in this decision.
The Panel also approves PNG-West’s request to establish each of the following new deferral accounts:
• Incremental CCA deferral account to record the capital cost allowance (CCA) on unplanned capital expenditures, including those incurred in 2021, attracting interest at PNG-West’s short-term interest rate. A one-year amortization period is approved, with the December 31, 2021 balance to be fully amortized in 2022. This deferral account is approved on an ongoing basis until 2027;
• RECAP[5] Deferred Demand Charges deferral account to record interest recovered from currently contracted RECAP shippers for the period of 2020 and 2021, attracting interest at PNG-West’s weighted average cost of debt. The balance is to be creditable against the shippers’ demand charges once service to them commences;
• CIS[6] Project Recoveries deferral account to record net SAP[7] CIS Project recoveries realized in 2020 and 2021, attracting interest at PNG-West’s short-term interest rate. The balance is to be fully amortized in 2022, followed by the subsequent dissolution of the account; and
• Shared Corporate Services Costs Variance deferral account to record its portion of the variances in actual TSU Shared Corporate Services Costs from forecast amounts, including those realized in 2020 and 2021, attracting interest at PNG-West’s short-term interest rate. A one-year amortization period is approved, with the amount accumulated in 2020 and 2021 to be fully amortized in 2022.
The Panel observed that all four of these new deferral accounts raise the issue of retroactive ratemaking because adjustments to 2022 rates are sought on account of amounts relating to previous test periods for which permanent rates have already been set. However, based on the Panel’s assessment of the particular circumstances and factors related to these deferral account requests and for the reasons outlined in the decision, each of these requests warranted an exception to the rule against retroactive ratemaking.
In addition, the Panel makes various directives and approvals on specific issues which are set out in the decision.
1.0 Introduction
1.1 Nature of the Application
This proceeding reviews the 2022 revenue requirements application (RRA) that Pacific Northern Gas Ltd. (PNG) filed on behalf of its western division, PNG-West, for approval by the British Columbia Utilities Commission (BCUC) pursuant to sections 58 to 61 of the Utilities Commission Act (UCA). In a separate but related proceeding, the BCUC will review the RRA brought by PNG’s subsidiary, Pacific Northern Gas (N.E.) Ltd. (PNG(NE)), for the same test period.
For purposes of clarity, the term “PNG” will be used when referring to general corporate direction while the term “PNG‐West” will be used with reference to requests for approval made during the proceeding and any operational and non‐corporate issues related to the western division only.
1.2 Background
PNG 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. PNG-West serves approximately 20,500 natural gas customers with an additional 130 propane customers in Granisle, B.C.[8] PNG(NE) operates a natural gas processing plant and natural gas distribution systems providing service to some 21,500 natural gas customers in three service territories: Fort St. John (FSJ); Dawson Creek (DC); and Tumbler Ridge (TR).[9]
The PNG-West and PNG(NE) natural gas pipeline systems are illustrated in Figure 1.[10]
Figure 1: PNG-West and PNG(NE) Natural Gas Pipeline Systems
On November 30, 2021, PNG-West filed its 2022 RRA (Original Application) seeking, among other things, approval to amend its delivery rates and Revenue Stabilization Adjustment Mechanism (RSAM) rate rider on an interim and refundable/recoverable basis, effective January 1, 2022. PNG-West’s fiscal year 2022 is referred to as the “Test Period” or “Test Year”.
By Order G-378-21, the Panel approved interim delivery rates of $12.989/Gigajoule (GJ) for residential service and $10.908/GJ for small commercial service and $7.514/GJ for Granisle propane service. The Panel also approved a decrease in the RSAM rate rider from a debit rider of $0.380/GJ to a credit rider of $0.333/GJ. These interim approvals were effective January 1, 2022.
On March 7, 2022, PNG-West 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 and revisions, such as amended demand forecasts which take into consideration the effects of 2021 actual deliveries, updated customer count and cost forecasts, as well as the impact of 2021 actual operating results on rate-base items.[11] From this point forward, the “Application” refers to PNG-West’s amended 2022 RRA.
1.3 Regulatory Process
By Order G-378-21, 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, written final argument and reply argument.
The regulatory timetable was subsequently amended by Order G-57-22, as well as Order G-169-22, in which the Panel requested additional evidence regarding TSU Shared Corporate Services Costs.[12]
Two parties, British Columbia Old Age Pensioner’s Organization, Active Support Against Poverty, Council of Senior Citizen’s 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 two letters of comment on behalf of the Village of Granisle.
1.4 Approvals Sought
PNG-West summarizes the final approvals sought in its final argument as follows:[13]
1. Approval on a permanent basis, effective January 1, 2022, for the recovery of the applied for revenue deficiency and the resultant delivery rate changes, subject to adjustments identified during this proceeding, for the following rate classes, among other rate classes:[14]
a. A 4.8 percent increase from $12.384/GJ to $12.974/GJ for Residential service;
b. A 4.5 percent increase from $10.425/GJ to $10.897/GJ for Small Commercial service;
c. A 5.7 percent increase from $7.095/GJ to $7.501/GJ for Granisle Propane service; and
PNG-West is also seeking approval for a decrease in the RSAM rate rider on a permanent basis for PNG-West applicable to Residential, Small Commercial and Commercial Transport customers from a debit rider of $0.380/GJ to a credit rider of $0.786/GJ.
2. Approval of 2021 unplanned, necessary, integrity-related capital expenditures undertaken pursuant to BC Oil and Gas Commission (BCOGC) General Order 2021-0115-01.
3. Approval of the changes and additions to PNG-West’s existing deferral accounts and amortization expenses for 2022, including:
a. Approval to amortize $0.605 million[15] of the LNG Partners Option Fee Payment deferral account in 2022 to mitigate rate impacts on customer rates, subject to the impact of adjustments summarized in PNG-West’s final argument;
b. Approval to amortize the full balance of the COVID-19 deferral account accumulated to the end of 2021 in 2022;
c. Approval for the dissolution of the Reactivation Project Development Cost deferral account; and
d. Approval for the dissolution of the Transfer Pricing / Affiliate Recoveries deferral account at the end of 2022.
4. Approval to create a new short-term interest bearing[16] credit deferral account (Incremental CCA deferral account) to record the accelerated capital cost allowance (CCA) on unplanned capital expenditures in 2021, with the 2021 amount to be fully amortized in 2022.
5. Approval to create a new weighted average cost of debt (WACD) bearing credit deferral account (RECAP[17] Deferred Demand Charges deferral account) to record interest recovered from currently contracted Large Volume Industrial Transportation Rate (Rate Schedule 80 or RS 80) shippers for the period of 2020 and 2021 prior to BCUC approval of the underlying transportation services agreements in August 2021, with the balance to be creditable against shipper demand charges once service to them commences.
6. Approval to create a new short-term interest bearing[18] credit deferral account (CIS[19] Project Recoveries deferral account) to record net SAP[20] CIS Project recoveries realized in 2020 and 2021, with the balance to be fully amortized in 2022 and subsequent dissolution of the account.
7. Approval to create a new short-term interest bearing[21] credit deferral account (Shared Corporate Services Costs Variance deferral account) to record variances in actual TSU Shared Corporate Services Costs from forecast amounts realized in 2020 and 2021, with the balance to be fully amortized in 2022 and subsequent dissolution of the account.
8. Approval to continue the unaccounted for gas (UAF) Volume deferral account on the basis that the UAF volume forecasts for 2022 are set at 1.0 percent of deliveries with PNG-West recording the variance between 1.0 percent and a loss of up to 1.25 percent without having to seek further BCUC approval.
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 cost of service, including those associated with operating, maintenance, administrative and general expenses. Specifically, this section will address issues related to new staff positions, increased contractor costs, and increased TSU Shared Corporate Services Costs;
• Section 3.0 addresses issues related to PNG-West’s proposed capital expenditures, including PNG-West’s request for BCUC approval of unplanned integrity-related capital costs incurred in 2021, PNG-West’s multi-year Transmission Mainline Integrity Campaign, and proposed adjustments to Certificate of Public Convenience and Necessity (CPCN)-approved capital projects;
• Section 4.0 deals with issues related to PNG-West’s requests for BCUC approval of changes to existing deferral accounts, as well as the proposed creation of four new deferral accounts;
• Section 5.0 outlines the overall Panel determination on the PNG-West 2022 delivery rates and RSAM rate rider.
• Section 6.0 examines PNG-West’s request to increase the UAF component of Company Use gas from
0.0 percent to 1.0 percent and the loss cap for the UAF deferral account from 1.0 percent to 1.25 percent; and
• Section 7.0 addresses other matters, including the rate design and amalgamation considerations for both commodity costs and delivery rates among the PNG divisions.
2.0 2022 Revenue Requirements and Revenue Deficiency
To establish 2022 delivery rates, the Panel considers PNG-West’s total Revenue Requirement or its “cost of service”. PNG-West’s Revenue Requirement reflects the total amount of revenue that must be collected in rates to recover its forecast costs of service and to provide PNG-West an opportunity to earn a reasonable return. For Test Year 2022, PNG-West’s forecast cost of service is $46.589 million, excluding Company Use gas cost of $1.298 million, which is a $5.599 million increase over the Decision 2021 amount.[22]
In this section, the Panel reviews issues arising with respect to PNG-West’s 2022 forecast cost of service, specifically related to the Operating, Maintenance, and Administrative & General Expense costs associated with new staff positions and contractor costs, in addition to TSU Shared Corporate Services Costs.
2.1 Operating, Maintenance, and Administrative & General Expenses
PNG-West is requesting recovery of the following operating, maintenance and administrative & general (OMA&G) expenses for the 2022 Test Period, subject to the adjustments identified during this proceeding, as summarized in PNG-West’s final argument.[23] The increase in the forecast OMA&G expenses is $1.939 million or 9.1 percent as compared to the Decision 2021 amount,[24] as summarized in the following table:
Table 1: PNG-West OMA&G Expenses[25]
|
|
$000’s |
|
|
|
Decision 2021 |
Test Year 2022 |
| Operating (net of Company Use gas costs, transfers to capital and shared service cost recoveries from PNG(NE)) |
11,822 |
12,367 |
| Maintenance |
587 |
698 |
| Administrative and General (net of transfers to capital and shared service cost recoveries from PNG(NE)) |
8,885 |
10,168 |
| Total |
21,295 |
23,234 |
In the Application, PNG-West presents specific operating expense line items[26] and administrative and general expense line items[27] net of shared service cost recoveries from PNG(NE), which were subsequently provided on a grossed-up basis in responses to IRs. The shared service cost recoveries from PNG(NE) are in accordance with the shared services cost allocation and recovery methodology previously approved by Order G-114-13.[28]
PNG-West explains that the overall increase in OMA&G expenses is primarily due to (i) planned right-of-way clearing activities; (ii) additional required resources in field operations; and (iii) increased administrative and general costs related to the following: increases in financial reporting and customer billing information systems, insurance expense, pension expense, and the full recovery of the TSU Shared Corporate Services Costs.[29]
Overall Panel Determination on OMA&G Expenditures
The Panel has reviewed the evidence with respect to PNG-West's 2022 forecast OMA&G expenses, including the reasons provided for the changes in costs as compared to the Decision 2021 amounts. The Panel finds the forecast 2022 OMA&G expenses to be reasonable, subject to the adjustments summarized in PNG-West’s final argument and the determinations on the items addressed in the subsections below.
In order to provide greater transparency and improve regulatory efficiency, the Panel directs PNG-West to submit in its future RRAs, OMA&G expense line items on a gross basis before the shared service cost recoveries from PNG(NE).
2.1.1 Operating Expenses
PNG-West’s forecast 2022 operating expenses are $12.367 million, which is $0.545 million or 4.6 percent higher as compared to the $11.822 million Decision 2021 amount. As PNG-West maintains, in addition to general inflationary pressures on costs, the forecast cost increases are primarily driven by the following factors:
(i) Increased costs for planned activities for right-of-way clearing to meet the requirements of Canadian Standards Association (CSA) Z662, the Oil and Gas Activities Act, and the expectations set out by the BCOGC[30] which reflect the development of a science-based, geoclimatic vegetation management plan;[31]
(ii) Increased labour costs, including the provision for two new operations construction and maintenance management positions and two new operations field positions (namely, Utilityperson V and Admin Clerk); and
(iii) Increased contractor costs to provide assistance in the areas of Indigenous Relations engagement, a damage prevention campaign and information technology integration tools.[32]
We review issues related to operating expenses regarding the proposed staff additions and contractor costs in the subsections below.
New Staff Positions
As noted above, PNG-West is proposing to add two full-time equivalent (FTE) supervisor positions in the Construction and Maintenance business unit and two additional FTE bargaining unit positions, a Utilityperson V and an Admin Clerk.
PNG-West states that the two new supervisor positions are necessary to ensure that the appropriate oversight is provided for field activities of the Construction and Maintenance business unit, particularly given increased capital and operating activities.[33] Further, these positions are safety-sensitive roles and will allow for proactive coaching and mentoring of staff to ensure they are able to perform their duties in a safe and efficient manner.[34] PNG-West states that the supervisor positions represent a marked improvement in overall efficiency within the construction and maintenance department by furthering its ability to plan and coordinate work effectively, through decreasing the geographic and operational territory span covered by each individual management and supervisory role.[35]
With respect to the Utilityperson V position, PNG states that this role is required to meet increasing work requirements around operating and maintaining existing plant and infrastructure and for the installation of new plant and infrastructure necessary to provide service to new customers.[36] Further, the Admin Clerk position provides support to the operations’ leadership team to the capacity currently required.[37]
PNG-West provides the following historical internal labour costs and forecast for 2022:
Table 2: PNG-West Labour Cost[38]
|
|
$000’s |
|||
|
|
Actual 2019 |
Actual 2020 |
Actual 2021 |
Test Year 2022 |
| Labour Costs |
6,266 |
6,622 |
6,965 |
6,895 |
PNG-West explains that the labour costs are expected to remain relatively flat as the new positions represent a small increase in head count and in the overall labour costs. Further, PNG-West states that the current workforce is lean and incurs overtime costs at higher rates to compensate; therefore, a modest headcount increase is expected to have minimal impact on overall labour costs.[39]
Positions of the Parties
RCIA submits that it is not persuaded that adding two supervisors is required, considering there is no “new work” in 2022 to justify the tripling of this resource. RCIA recommends that the BCUC not approve the cost of the second new supervisor as part of the 2022 revenue requirement.[40] Regarding the Admin Clerk position, RCIA supports PNG-West making the position permanent.[41]
In reply, PNG-West submits that the addition of two new field officer positions is prudent and necessary and that requests for approval for new headcount positions are made with careful consideration and that additional resources are sought only when considered absolutely necessary.[42] PNG-West further argues that the two new field supervisor positions will allow the existing Construction and Maintenance Manager to operate at an elevated level as part of the overall integrity management planning leadership team specifically focused on PNG integrity programs.[43]
Panel Determination
The Panel has reviewed the evidence on record in the proceeding and accepts PNG-West’s explanation for the need to add the new Utilityperson V Position, Admin Clerk and two construction and maintenance superintendent positions.
The Panel notes that PNG-West's overall labour costs have remained relatively flat over the past three years and the new positions represent a small increase in the overall labour costs with proportionate reduction of overtime costs. With respect to the two construction and maintenance superintendent positions, contrary to RCIA’s submission, the Panel considers that the costs associated with these positions are necessary based on the extensive geographic spread of the PNG-West pipelines and the need to ensure that construction and maintenance staff are appropriately coached, mentored and supervised, ensuring a safe work environment for all workers.
Contractor Costs
PNG-West is forecasting increased contractor costs to provide assistance in the areas of Indigenous engagement, the development of a damage prevention campaign, implementation of information technology integration tools, and updating and testing of business continuity plans.[44]
PNG-West provided historical and forecast 2022 contractor costs, as follows:
Table 3: PNG-West Contractor Cost[45]
|
|
$000’s |
|||
|
|
Actual 2019 |
Actual 2020 |
Actual 2021 |
Test Year 2022 |
| Contractor Costs |
2,823 |
3,830 |
4,631 |
5,139 |
PNG-West explains that for small scope, low complexity, and small value maintenance work, it has several pre-qualified contractors that may be awarded work on a single source / direct award basis to reduce internal administration and contract development costs. For all other work, PNG-West regularly solicits pricing and proposals from known, fit-for-purpose, contractors via a competitive bid process.[46] Further, PNG-West states that it strategically leverages contract resources with job specific skills requiring senior levels of experience where regional skill pools do not afford or support the need for the hiring of full-time labour.[47]
Additionally, PNG-West submits that there may be a decrease in reliance on temporary employees and contractors[48] for the purposes of operating maintenance, core, and repeatable and predictable work[49] which would equate to stability, consistency in work product, and growth and development of institutional knowledge and experience within PNG.[50]
Positions of the Parties
BCOAPO and RCIA do not comment on the increasing contractor costs.
PNG-West submits that contractor costs support its resourcing strategy and reflect engaging contract resources for activities requiring specialized knowledge and senior-level experience not available internally.[51]
Panel Determination
The Panel accepts PNG-West’s explanation for the increase in the contractor costs while labour costs have remained mostly flat, despite PNG’s plan to decrease reliance on temporary workers and contractors. The Panel finds that PNG-West’s established labour resourcing strategy is sound. PNG-West plans to use contractors to manage work peaks in projects and temporary work, or where specific skills are required, while using employees for the purposes of operating, maintenance, core, or repeatable work. The Panel considers this to be an appropriate strategy given the size and location of PNG-West.
2.1.2 Administrative & General Expenses
Administrative and General expenses for 2022 are forecast to be $10.168 million (net of shared services cost recoveries, transfers to capital and cost adjustments), which is $1.283 million or 14.4 percent greater compared to the Decision 2021 amount. Administrative and General expenses are comprised of costs for administration, special services, insurance, employee benefits and general expenses (less transfer to capital). In addition to general inflationary pressures on costs, the forecast Administrative and General cost increases are primarily driven by the following factors:[52]
(i) Increased TSU Shared Corporates Services Costs allocated to PNG from its parent company;
(ii) Increased contractor costs related to financial system and information technology support;
(iii) Increased consultant costs, primarily related to Indigenous Nations relations, climate change policies and initiatives, and costs related to an updated residential end use study;
(iv) Increased insurance costs that reflect changes in the insurance market and increased premiums for all insurance coverages, but most notably for cyber insurance and property coverage due to market conditions and PNG’s recent claim history; and
(v) Increased pension plan expenses, primarily due to the increase in the defined benefit pension costs, which are actuarially determined and are primarily a result of the increased service cost, which is the result of recognizing changes in pension plan membership and increases in pensionable earnings over the preceding three years.
Positions of the Parties
BCOAPO submits that the increase in Administrative and General expenses (net of transfers to capital) should be capped at between 5 percent and 10 percent over the Decision 2021 amount, which would result in a downward adjustment to PNG-West’s proposed 2022 Administrative and General expenses of between $0.395 million and $0.839 million.[53] BCOAPO argues that it is unable to conclude that PNG-West has actively managed its OMA&G costs[54] and that PNG-West “did not identify any productivity adjustments”[55] and its IT initiatives have resulted in cost avoidance rather than cost savings.[56] BCOAPO further argues that PNG-West’s approach to setting its expense budgets is inherently bottom-up (a passive form of cost management)[57] and that when utilities are entering a period of rate pressures, the best way to contain costs is through both a top-down and bottom-up budgeting process.[58]
In reply, PNG-West responds that in making its proposal for the 2022 Administrative and General expenses to be capped, BCOAPO has disregarded the broad body of evidence on record providing justification for these costs and the inflationary trend playing out as 2022 advances.[59] PNG-West further objects to the proposed “blanket reduction to its cost of service noting that the BCUC has a statutory obligation to establish rates that permit PNG-West the opportunity to recover all of its costs of providing service and earn a fair return; any proposed cost of service or capital expenditure adjustments should be explicit and supported with valid reasoning.”[60]
Panel Determination
The Panel recognizes BCOAPO’s concern with respect to the increase in the forecast 2022 Administrative and General expenses. However, the Panel determines that applying a blanket reduction of the forecast costs of service for all Administrative and General expenses without evidence to justify the blanket reduction is without merit, considering the detailed submission by PNG-West to support its 2022 forecasts.
The Panel finds that the forecast 2022 Administrative and General expenses are reasonable, subject to the adjustments summarized in PNG-West’s final argument and the determinations related to the TSU Shared Corporate Services Costs as addressed in the subsection below.
TSU Shared Corporate Services Costs
PNG’s parent company, TSU, allocates costs to the PNG group (i.e. PNG-West, PNG(NE) FSJ/DC and PNG(NE) TR on a consolidated level) and its other subsidiaries using the Modified Massachusetts Formula (TSU Shared Corporate Services Costs). Historically, the PNG group only recovered from ratepayers a portion of these costs allocated from TSU; however, in the PNG-West 2020–2021 RRA Decision[61] (Decision 2020–2021), the BCUC approved the full recovery by the PNG group of the total amount of the TSU Shared Corporate Services Costs allocated to the PNG group from TSU. To mitigate ratepayer impacts in the 2020 and 2021 test period, the BCUC also approved the PNG group to defer a portion[62] of the approved allocated increase and to amortize it into the cost of service over a three-year period.[63]
In Test Year 2022, PNG requests approval to recover the full amount of TSU Shared Corporate Services Costs allocated to the PNG group from TSU of $2.039 million, which represents an increase of approximately $0.167 million from the Decision 2021 amount.[64] PNG submits that the TSU corporate structure enables it to share the costs associated with corporate services without incurring the full standalone costs of those services on its own.[65] It adds that the TSU Shared Corporate Services Costs allocation methodology is consistent with that in prior years and that the allocated share of costs from TSU is fair, reasonable, and prudently incurred.[66]
Similar to other shared services amongst the PNG group, PNG allocates its share of the TSU Shared Corporate Services Costs between PNG-West and the PNG(NE) divisions using the cost allocation methodology approved by the BCUC in Order G-114-13.[67] The cost allocation breakdown between PNG-West and the PNG(NE) divisions for 2020 to 2022 is illustrated in the table below:
Table 4: Cost Allocation between PNG-West and PNG(NE)[68]
|
|
$000’s |
||
| Cost Component |
Decision 2020 |
Decision 2021 |
Test Year 2022 |
| PNG-West |
1,160 |
1,207 |
1,358 |
| PNG(NE) – FSJ/DC |
634 |
624 |
638 |
| PNG(NE) – TR |
41 |
42 |
43 |
| Consolidated |
1,835 |
1,872 |
2,039 |
In Test Year 2022, PNG does not propose to defer a portion of the 2022 TSU Shared Corporate Services Costs given there is some certainty around RS 80 shipper revenues commencing in late 2022 and the impact of the portion of TSU Shared Corporate Services Costs that were deferred in 2020 and 2021 and are being amortized over a three-year period.[69] Consequently, the cost increase combined with the absence of any deferred amounts in Test Year 2022 makes the TSU Shared Corporate Services Costs the largest driver of the increase in the Administrative and General expenses for the PNG-West division.[70]
Since the TSU Shared Corporate Services Costs are allocated to the PNG divisions using a BCUC previously approved methodology, the Panel considers it appropriate to evaluate the reasonableness of the increase in the TSU Shared Corporate Services Costs on a consolidated, rather than a segregated, basis in the following subsection.
Increase in the TSU Shared Corporate Services Costs on a Consolidated Basis
PNG states that the increase of approximately $0.167 million in TSU Shared Corporate Services Costs allocated to the PNG group on a consolidated basis from the Decision 2021 amount to the 2022 forecast can be primarily attributed to additional resources to address the following: [71]
• Cybersecurity;
• Environmental, Social and Governance (ESG) reporting; and
• Potential transition of the TSU group of companies to reporting under International Financial Reporting Standards (IFRS) from the US Generally Accepted Accounting Principles (US GAAP) current reporting standards.
PNG explains that ESG reporting, cybersecurity, and potential transition to IFRS are needed to support corporate governance and to access capital financing for TSU, which is how the PNG group funds its safe and reliable service to its customers. PNG explains that each of these new business requirements provide the following benefits to its ratepayers in all its divisions:[72]
• ESG reporting is becoming increasingly important for the provision of financing, as many investors will only invest in opportunities which meet certain ESG standards. In order to attract these investors, companies must produce regular ESG reporting which discloses baseline levels, as well as future targets for ESG initiatives.
• Cybersecurity is a prominent business risk for all companies and is an emerging concern for corporate governance. Corporate governance is a factor that credit rating agencies and investors evaluate when analyzing the credit and investment risk of a company and may impact access to financing.
• Currently, TSU reports under US GAAP as permitted under a temporary exemption (exemptive relief)[73] from Canadian securities regulators. This exemptive relief is in effect until the earlier of January 1, 2024, or the effective date prescribed by the new IFRS Standard for rate regulated entities under development. Investors require the presentation and disclosure of financial information to be in accordance with specified standards and TSU is monitoring the development of the exposure draft to avoid limiting access to capital markets.
PNG provided a breakdown of the TSU Shared Corporate Services Costs allocated to the PNG group on a consolidated basis, by cost category for the 2020–2021 test period (Decision and actual) and 2022 (forecast). The following table reproduces this breakdown for 2021 (Decision and actual) and 2022 (forecast).
Table 5: Breakdown of PNG’s allocated TSU Shared Corporate Services Costs by Function for 2021 and 2022[74]
|
|
$000’s |
||
| Cost Component |
Decision 2021 |
Actual 2021 |
Test Year 2022 |
| Director’s fees and expenses |
108 |
152 |
165 |
| Employee costs[75] |
1,318 |
1,008 |
1,431 |
| Consultant fees |
205 |
186 |
224 |
| Audit |
60 |
56 |
55 |
| Translation |
23 |
14 |
24 |
| Directors’ and Officers’ (D&O) insurance |
55 |
45 |
55 |
| Insurance – excluding D&O |
48 |
39 |
50 |
| Provincial registration fees |
20 |
25 |
25 |
| Debt/equity administrative expenses |
34 |
8 |
|
| Total PNG cost pool |
1,872 |
1,535 |
2,039 |
Table may not add due to rounding.
The 2022 forecast is approximately $0.167 million higher than the Decision 2021 amount and approximately $0.504 million greater than 2021 actuals.[76] PNG states that the 2022 forecast TSU Shared Corporate Services Costs are reasonable as the business environment has changed from 2020 and 2021.[77] On a cost component basis, director’s fees, employee costs and consultant fees are the key factors contributing to the increase in 2022 forecast TSU Shared Corporate Services Costs as compared to both 2021 forecast and actual. Each of these factors is discussed further below.
PNG states that the increase in forecast 2022 director’s fees and expenses is primarily attributable to the following:
• One new independent director was added in 2020 following the acquisition of TSU by the Public Sector Pension Investment Board and the Alberta Teachers’ Retirement Fund Board on March 31, 2020, which was not contemplated as part of the 2020 and 2021 approved costs.[78] PNG states that this new director “provides incremental skills and experience in relation to Canadian utilities, and specifically executive-level experience with utilities in British Columbia, which benefits the PNG group’s ratepayers.”[79]
• One new independent director is being added in 2022 to replace the independent director currently serving as chair of the Audit Committee. This new independent director is being added prior to the planned retirement of the chair of the Audit Committee to provide continuity of governance for the committee over part of fiscal 2022. PNG clarifies that it is expected that the TSU board of directors will return to six independent non-executive directors after the retirement of the current Audit Committee chair.[80]
Employee costs are a major driver of the increase in forecast 2022 Shared Corporate Services Costs as compared to 2021 actual, and PNG explains that this increase is primarily due to the following:
• Additional positions: Three new employees are being added to address new business requirements of ESG reporting, cybersecurity, and potential transition of reporting standards.[81] Additionally, a Legal Counsel and an Executive Vice President, Corporate Strategy and Business Development were added for the full year of 2021.[82] The Legal Counsel position was included in the 2021 actuals and thus would only contribute to the increase in 2022 forecast costs as compared to the Decision 2021 amount. The Executive Vice President, Corporate Strategy and Business Development position contributes to the increase in 2022 forecast costs as compared to 2021 actuals as further discussed in the next bullet.
• Employee costs billed to growth opportunities: As part of the transition to a private company following the acquisition of TSU by the pension plans, certain TSU positions were transitioned to focus on growth opportunities, which removed the costs associated with these positions from the TSU Shared Corporate Services cost pool. The positions allocated to growth opportunities in 2021 were: the Director of Business Development, Vice President Corporate Affairs and Sustainability (formerly the Vice President Investor Relations) and the new Executive Vice President, Corporate Strategy and Business Development position. This cost variance occurs in the Decision 2021 amount versus actuals, primarily as the Vice President Investor Relations position was transitioned to growth opportunities after the 2021 forecast was filed as part of the PNG-West 2020–2021 RRA.[83] Additionally, the costs associated with the Executive Vice President, Corporate Strategy and Business Development position do not appear to be billed to growth opportunities in the 2022 Test Year, thereby contributing to the increase in employee costs for Test Year 2022 as compared to 2021 actual.[84]
• Pandemic impacts on travel and training: The previous RRA was submitted prior to the pandemic and the 2020 and 2021 forecast did not account for any pandemic impacts on travel and training. Accordingly, the 2021 actuals reflect lower travel and training costs incurred due to the pandemic.[85] Test Year 2022 travel and training costs are forecast to be higher than 2021 actuals as PNG expects the pandemic-related restrictions and safety measures to ease, resulting in a return to pre-pandemic expenditure levels.[86]
PNG clarifies that the 2022 forecast for third-party (consulting) fees is greater than 2021 actuals as a result of addressing new business requirements of both ESG reporting and the potential transition to new accounting standards.[87]
Positions of the Parties
BCOAPO and RCIA have no submissions specific to the TSU Shared Corporate Services Costs.
Panel Determination
The issue for the Panel to consider is whether to approve the recovery in rates of the full TSU Shared Corporate Services Cost allocation to the PNG group of $2.039 million in 2022, of which $1.358 million is allocated to the PNG-West division. In assessing this issue, the Panel has considered the reasonableness of these costs in relation to the benefits they provide to the PNG group’s ratepayers. PNG has put forward evidence regarding the corporate services provided by its parent, TSU, on behalf of PNG and the other subsidiaries, including governance, business oversight, financing, administration, legal, accounting, and regulatory services. These services are necessary for PNG to access capital and borrowing to maintain its capital structure. These services are critical for any utility and without TSU, PNG would need to acquire these services on its own. The Panel acknowledges that the services provided by TSU give both direct and indirect benefits to the PNG group and their ratepayers, including achieving economies of scale, expanding access to capital, and sharing in corporate services costs without incurring the full standalone costs. For these reasons, the Panel finds that some allocation of costs is appropriate between TSU as PNG’s parent and provider of the shared corporate services and the PNG group, considering the services provided and the benefits achieved by the PNG group.
In making its determinations on whether to approve the full amount of the TSU Shared Corporate Services Costs, the Panel has reviewed the evidence related to the value of these services and costs for the PNG group and their ratepayers in order to assess the reasonableness of the full allocation amount.
The Panel notes that director’s fees, employee costs and consultant fees are the key cost components contributing to the increase in 2022 forecast costs as compared to both 2021 forecast and 2021 actual costs. The Panel has reviewed these costs and the supporting evidence provided by PNG and accepts the rationale put forward for employee costs and consultant fees as they relate to new business requirements of ESG reporting, cybersecurity and potential transition of reporting standards.
The Panel recognizes that TSU has reduced employee costs in the TSU Shared Corporate Services Costs pool in 2021 for costs billed to growth opportunities unrelated to existing TSU businesses. As of January 1, 2022, PNG states that the Executive Vice President, Corporate Strategy and Business Development, who in 2021 was not included in the cost pool, is fully involved in the existing TSU businesses, and is no longer working on growth opportunities. With this change in direction and scope of work of the Executive Vice President, the Panel finds it unclear whether or not all the 2022 forecast employee costs attributable to opportunities unrelated to existing regulated businesses were removed.
In order to remove any ambiguity relating to forecast employee costs that are attributed to opportunities unrelated to existing regulated businesses, the Panel directs PNG to provide a clear delineation of the following in its next RRA:
• Those positions and employee costs that were previously billed to growth opportunities unrelated to existing TSU business; and
• Changes to the position(s) and employee costs forecast to be billed to growth opportunities unrelated to existing TSU business, including the timing of and rationale for the change.
In addition, the Panel is not persuaded that the PNG group’s ratepayers should bear the compensation costs for the advance hiring of the new independent director in contemplation of the planned retirement of the chair of the Audit Committee. The early hiring of the new independent director to provide continuity of governance for the Audit Committee over part of 2022 is somewhat unusual. The Panel considers that while this may be in the interest of the TSU Board and shareholders, it is not necessarily in the interest of the PNG group’s ratepayers. The Panel views the continuity of governance for the Audit Committee should not be solely dependent on one individual (the chair of the committee) but is a shared responsibility of all of the committee members, and good corporate governance does not require that a replacement director be hired before the term of their predecessor ends.
The Panel directs PNG to remove the forecast compensation costs for the new independent director expected to be incurred prior to the planned date of the retirement of the chair of the Audit Committee from the total forecast 2022 TSU Shared Corporate Services Costs. PNG is directed to reflect this adjustment in its final regulatory schedules, to be filed with the BCUC within 30 days of the date of this decision.
The Panel acknowledges that the TSU Shared Corporate Services Costs allocated to the PNG group by their parent, TSU, are greater than previously approved. However, the Panel accepts that subject to the adjustment identified above in respect of director’s fees and expenses, PNG has put forward sufficient evidence to support the reasonableness of the TSU Shared Corporate Services Costs. PNG is approved to recover the forecast 2022 TSU Shared Corporate Services Costs of $2.039 million allocated to PNG on a consolidated level, subject to the direction regarding the forecast 2022 compensation costs for the new independent director. In addition, the Panel approves the allocation of the 2022 TSU Shared Corporate Services Costs amongst the PNG-West and the PNG(NE) divisions using the allocation methodology previously approved by Order G-114-13, as follows (i) PNG-West: $1.358 million; (ii) PNG(NE) FSJ/DC: $0.638 million; and (iii) PNG(NE) TR: $0.043 million. All allocated amounts are subject to the adjustments arising from the directives and determinations in this decision.
3.0 Capital Expenditures
PNG-West forecasts capital expenditures before overhead of approximately $113.386 million for the 2022 Test Period, as follows:
Table 6: PNG-West 2022 Capital Expenditures[88]
PNG-West also seeks approval for unplanned capital expenditures incurred in 2021. The subsections below address specific forecast 2022 capital expenditures, in addition to the 2021 unplanned capital expenditures.
3.1 2021 Unplanned Capital Expenditures
PNG-West is seeking approval of unplanned integrity-related capital costs incurred in 2021, which were required to comply with BCOGC General Order 2021-0115-01 (BCOGC Order). The BCOGC Order, issued in July 2021, directed PNG to reduce the operating pressure on segments of its Western Transmission System until identified defects were assessed and repaired.[89] PNG states that the operating pressure reduction would have caused significant operational challenges, particularly during the 2021/2022 winter months, and therefore immediately undertook the necessary integrity digs and associated repairs to satisfy the BCOGC Order.[90]
As a result of these previously unplanned integrity-related activities, PNG-West exceeded the approved amount for this work under Decision 2020–2021. PNG-West spent approximately $13.704 million on its integrity dig and repair program in 2021, of which $1.042 million had been previously approved by Decision 2020–2021.[91] The net incremental increase for this work in 2021 was $12.662 million. PNG-West seeks recovery of the full cost of the integrity program (i.e. $13.704 million) in 2021, including the unplanned expenditures.
PNG-West states that all the physical work required by the BCOGC Order was completed as of April 2022.[92]
PNG-West notes that on September 21, 2021, it submitted to the BCUC a copy of the BCOGC Order and a summary of the implications of the order to PNG-West, including an Association for the Advancement of Cost Engineering (AACE) Class 4 cost estimate of the incremental work required and an estimated date of completion.[93] PNG-West states that it would typically seek pre-approval of the identified capital expenditures through an RRA or seek acceptance of the expenditure pursuant to Section 44.2 of the UCA. However, given the need to commence the work immediately and that PNG-West would be filing its initial 2022 RRA by November 30, 2021, PNG-West elected to seek recovery of these capital expenditures as part of this current RRA proceeding.[94]
Positions of the Parties
RCIA agrees with the 2021 unplanned capital expenditures.[95]
BCOAPO takes no position on the 2021 unplanned capital expenditures.
Panel Determination
The Panel approves PNG-West’s unplanned integrity-related capital expenditures of $12.662 million incurred in 2021. Firstly, these particular expenditures could not have been foreseen during the previous RRA given the order from BCOGC directing this work was issued in July 2021. Secondly, as indicated by PNG-West, the alternative to not performing the integrity-related work ordered by the BCOGC would be to lower operating pressure on the transmission line and potentially jeopardize PNG-West’s ability to serve its customers.
The Panel acknowledges PNG-West’s efforts to notify the BCUC of the 2021 unplanned capital expenditures. The Panel reminds PNG-West to continue similar reporting of unanticipated capital expenditures, as directed by Order G-255-20.
3.2 Transmission Mainline Integrity Campaign & Assessments
PNG-West is seeking approval for planned non-CPCN capital expenditures to take place during Test Year 2022, the most significant of which being the Transmission Mainline Integrity Campaign project.
In 2022, PNG-West expects to undertake approximately 200 integrity digs, assessments and repairs across various segments of its Western Transmission System at an estimated cost of $26,787,762.[96] PNG-West states that the scope of the 2022 integrity program has been developed in response to the PNG-West’s increasing focus on the high-pressure system integrity as part of the regular and ongoing maintenance program, meeting the demand of new industrial customers, and meeting regulatory requirements.
PNG-West submits that this integrity work was a result of the BCOGC Aged Asset Audit and the associated
Engineering Assessments to address integrity anomalies that are identified by in-line inspection (ILI) to ensure the safe operation of the system. [97] PNG-West went on to state the need to maintain the integrity of PNG’s pipeline system assets for the safe and reliable supply of gas to existing customers and required regardless of whether the new industrial customers take service.[98]
PNG-West submits that the actual number of integrity digs is adjusted based on data from the on-going ILI runs and engineering assessments. For example, PNG-West states that the number of required integrity digs on its 10” Methanex lateral has been reduced following the results of an ILI run completed in 2022.[99] However, PNG-West does not believe that any adjustments to the 2022 forecast capital expenditures are required, as further ILI run results may potentially increase the number of integrity digs.[100]
Key ILI runs and cost estimates for 2022 are shown in the following table:
Table 7: PNG-West ILI runs 2022[101]
| Description |
$000’s |
| ILI (EMAT/MFL/DEF/IMU)[102] Run from R3 to R4 (10") |
1,052 |
| ILI (EMAT/MFL/DEF/IMU) Run from R5 to Methanex Station (10") |
1,036 |
| ILI (EMAT/MFL/DEF/IMU) Run from MP 209 to MP 240 (10") |
809 |
| ILI (EMAT/MFL/DEF/IMU) Run from Thornhill PLS to R5 (12" loop) |
716 |
| ILI (EMAT/MFL/DEF/IMU) Run from MP 251 to MP 256 (12") |
645 |
PNG-West has seen a significant increase in capital expenditures in the 2022 Test Year. The BCUC staff posed IRs with respect to PNG-West's capacity to complete the work required within the Test Year.
In response, PNG-West acknowledged that the 2022 capital expenditures are significantly greater than historic actuals; however, it has suitable risk mitigations in place to complete the work.[103] PNG-West notes that the majority of 2022 expenditures relate to CPCN projects which have project-specific integrated project management and delivery teams. Despite these risk mitigations, PNG-West confirms that some capital activities are being deferred as a result of integrity work being prioritized.[104] PNG-West provided its strategies to manage the large amount of integrity digs in 2022, which includes increasing internal and external resources.[105]
While PNG-West does not have specific execution plans for each project, it does have a project execution tactical team that reviews projects, gaps, and prioritizes them.[106]
PNG-West estimates the following integrity spending for its mainline integrity dig program over the next five years:[107]
| Year |
Mainline Integrity Campaign $000’s |
| 2023 |
26,500 |
| 2024 |
26,000 |
| 2025 |
25,600 |
| 2026 |
23,000 |
| 2027 |
23,500 |
Positions of the Parties
RCIA agrees with the Transmission Mainline Integrity Campaign expenditures.[108]
BCOAPO does not take any particular position on the Transmission Mainline Integrity Campaign or Integrity Related Capital Work.[109] However, BCOAPO does have concerns with PNG-West’s prioritization of non-CPCN capital expenditures and submits that PNG does not have an adequate framework or process in place regarding this matter.[110] BCOAPO notes that PNG-West provided a short list of deferred projects and did not provide any specific internal guidelines or targets to limit non-CPCN capital expenditures given current rate pressures. BCOAPO submits that a simple list of deferred capital projects with no context is not appropriate evidence of a robust capital expenditure prioritization framework.[111] BCOAPO recommends PNG-West develop a strategic plan which sets expenditure targets and asset management strategies in order to prioritize non-CPCN capital expenditures. BCOAPO also recommends that PNG-West include evidence regarding its asset management framework and processes in its next RRA.[112]
In reply, PNG-West submits that while no specific internal guidelines or targets to limit non-CPCN capital expenditure were issued, PNG is a small organization with a core team of highly qualified employees focused on the planning, prioritizing, executing, and monitoring of PNG’s capital program and that this team is very aware of the need for financial restraint and prudency.[113] PNG-West submits that it is actively exploring fit-for-purpose asset management solutions to incrementally improve its prioritization processes, and remains conscious of added cost implications of alternative or more advanced market solutions for an organization of PNG’s size, asset mix and expenditure profile.[114]
Panel Determination
The Panel accepts PNG-West’s submission regarding its expenditure plans for integrity-related capital work. With respect to BCOAPO’s recommendation regarding the prioritization of capital expenditures and asset management, the Panel finds that this would be an onerous task even for larger utilities. The overall strategic plan recommended by BCOAPO is further addressed in section 7.1. Given the size of the organization, the age of its infrastructure and the order issued by the BCOGC, the Panel considers that PNG-West appears to be taking a reasonable approach to carrying out the necessary integrity-related capital work.
The Panel considers, however, the Transmission Mainline Integrity Campaign to be a capital intensive, multi-year project which is of significant importance to the continued operation of PNG-West’s transmission system. The Panel is therefore concerned that the capital expenditures related to this project are to be reviewed and approved incrementally across successive RRAs. To facilitate the BCUC’s understanding of PNG-West’s long-term planning with respect to this project, the Panel directs PNG to include in its next RRA a Transmission Mainline Integrity Campaign Execution Plan, which includes the following information:
• Brief description of project objectives;
• Project schedule, including a description of activities PNG-West anticipates undertaking in each year of the multi-year project;
• Project cost estimate, including a breakdown of anticipated capital expenditures for each year of the multi-year project;
• Summary of identified risks which may impact either project schedule or cost, and strategies PNG-West is implementing to mitigate identified risks;
• Summary of relevant BCOGC orders or directives, as well as any evidence regarding BCOGC’s support for the project; and
• Summary of strategies PNG-West is implementing to ensure sufficient internal and external resources are available to execute the project’s scope.
3.3 CPCN-Approved Capital Projects
Planned capital expenditures to take place during Test Year 2022 include two projects for which the BCUC has granted CPCNs to PNG-West, specifically the Salvus to Galloway Remediation Project and the Reactivation Project. We discuss these two projects in the following subsections.
3.3.1 Salvus to Galloway Remediation Project
On July 8, 2021, the BCUC granted a CPCN for PNG-West’s Salvus to Galloway Remediation Project under Order C-4-21. The objective of the project is to remediate the Salvus to Galloway pipeline segment of the Western Transmission Gas Line to address existing compliance deficiencies relating to applicable pipeline standards and to ensure the continued provision of safe, reliable natural gas service to PNG-West’s customers in the Prince Rupert and Port Edward areas.[115]
In the Application, the forecast 2022 capital expenditures for the Salvus to Galloway Remediation Project are approximately $42.1 million, before allocations to capital overhead.[116] During the proceeding, PNG-West identified two updates to its 2022 forecast expenditures on the Salvus to Galloway Remediation Project.[117] These two forecast updates result in a net reduction in 2022 capital expenditures of $11.7 million from the amount of $42.1 million included in the Application to a revised forecast before overhead of $30.4 million. The impact of the change is a net reduction in the 2022 cost of service by $65,000, which equates to an average rate reduction of 0.15 percent for PNG-West.[118] The impact to the cost of service is modest as PNG-West explains that the Test Year 2022 cost of service does not include the return of capital component associated with 2022 capital additions and that PNG-West utilizes the accelerated CCA provision for income tax purposes.[119]
Positions of the Parties
RCIA does not comment on the proposed capital expenditure for the Salvus to Galloway Remediation Project.[120] Similarly, BCOAPO does not adopt any particular position on the Salvus to Galloway Remediation Project.[121]
Panel Determination
The Panel accepts the changes to the 2022 forecast capital expenditures for the Salvus to Galloway Remediation Project as reasonable. The Panel directs PNG to update the 2022 forecast capital expenditures in its final regulatory schedules to reflect the proposed adjustments to the Salvus to Galloway Remediation Project.
3.3.2 Reactivation Project
By Order C-5-21, the BCUC granted a CPCN for the reactivation and recommissioning of existing pipeline and compression assets, as well as the construction of new pipeline and compression assets on the Western Transmission Gas System (Reactivation Project). The Reactivation Project was considered necessary to meet the demand of new large industrial customers who have contracted for service under PNG-West’s Large Volume Industrial Transportation Rate (RS 80) tariff. The full scope of the Reactivation Project originally applied for has an estimated capital cost of approximately $88.5 million to be incurred over a four-year period, between 2021 and 2024.[122]
The forecast 2022 capital expenditures for the Reactivation Project included in the Application are $22.697 million, before allocations to capital overhead. The amended forecast reflects a subsequent downward adjustment to originally planned overall project capital spending contemplated in the CPCN application, resulting from the termination of shipper agreements for one of the two shippers, Top Speed Energy Canada Holdings Ltd. (Top Speed Energy), that had previously contracted for service under RS 80.[123]
During the proceeding, PNG-West proposed a further downward adjustment of $8.212 million to the Reactivation Project 2022 forecast capital expenditures of $22.697 million, resulting in an amended forecast of $14.485 million,[124] to be reflected in the final regulatory schedules. PNG-West states that this change is due to the delay and continued uncertainty in the in-service date for the remaining shipper, Port Edward LNG (PELNG). Until such time as there is greater certainty regarding the service commencement date for PELNG, PNG-West has opted to defer activities and costs associated with several Reactivation Project sub-projects. PNG-West states that this approach will ensure that the timing of PNG-West expenditures related to serving PELNG are in alignment with PELNG’s construction schedule and will help manage risk to PNG-West ratepayers. PNG-West notes that the remaining work in 2022 is limited to activities that provide value to the existing system operations through improved reliability and resiliency. PNG-West states that the impact of the adjustment to its 2022 forecast capital expenditures is a net increase in the 2022 cost of service by $0.297 million due to the loss of the accelerated CCA benefit, which is further addressed under the subsection, Positions of the Parties, below.[125]
In the Reactivation Project CPCN decision,[126] PNG was directed to file a rate impact mitigation plan, as part of the current RRA, outlining PNG-West’s refined rate stability strategies to mitigate the potential rate volatility of the Reactivation Project. With the continued uncertainty related to the timing of RS 80 shippers taking service and the associated capital expenditures, PNG-West states that it has not been able to develop a rate impact mitigation plan that specifically addresses rate impacts from prospective revenues and Reactivation Project costs. However, PNG-West has identified several potential mechanisms to help manage rate volatility and smooth rate impacts to customers. These include the use of both existing and new deferral accounts and the optimization of capital spending. For instance, PNG-West plans to further draw down the LNG Partners Option Fee Payment deferral account in future years to help mitigate rate impacts.[127] This deferral account is discussed further in section 4.1 below.
Positions of the Parties
RCIA supports PNG-West’s plan to continue a portion of the scheduled Reactivation Project spending that will improve system reliability, even in the absence of new RS 80 shippers.[128] With regards to the BCUC directive for PNG-West to provide a rate impact mitigation plan for the Reactivation Project, RCIA accepts the high-level actions provided by PNG-West as an interim response. RCIA recognizes that more defined rate impact mitigation plans will require more certainty with the timing of the RS 80 shippers’ commencement of service and Reactivation Project capital expenditures.[129]
Further in its final argument, RCIA recommends PNG-West clarify why a reduction in Reactivation Project capital expenditures in 2022 of $8.212 million results in an increase to the cost of service of $0.297 million.[130] In reply, PNG-West elaborates that the loss of the accelerated CCA benefit associated with the reduced capital expenditures is greater than the remaining cost of service items. PNG-West states that this reduction in the Reactivation Project capital expenditure results in the loss of a significantly greater tax benefit, and hence the Reactivation Project cost reduction results in an overall increase in the 2022 cost of service.[131]
BCOAPO does not comment on PNG-West’s proposals regarding the Reactivation Project capital spending in 2022.
Panel Determination
The Panel accepts the changes to the 2022 forecast capital expenditures for the Reactivation Project as reasonable. The Panel directs PNG to update the 2022 forecast capital expenditures in its final regulatory schedules to reflect the proposed adjustments to the Reactivation Project.
The Panel accepts that PNG-West has not been in a position to advance a strategic rate impact mitigation plan that specifically addresses rate impacts from the prospective revenues and costs of the Reactivation Project given the continued uncertainty and changes in timing of the RS 80 shippers’ in-service dates. Notwithstanding this, PNG-West identified some near-term mechanisms to help manage rate volatility for customers and some potential high-level actions with respect to the two potential RS 80 shippers in order to mitigate future rate impacts.[132] The Panel is persuaded by RCIA’s argument that more defined plans will require more certainty on the RS 80 shippers’ in-service dates. Accordingly, with regards to the BCUC directive for PNG to file a rate impact mitigation plan pursuant to Order C-5-21,[133] PNG has not satisfied this directive, but the Panel accepts PNG-West’s high-level strategies outlined in this proceeding as an interim response for the purposes of its 2022 RRA. PNG-West is directed to file a strategic rate impact mitigation plan as soon as there is greater certainty on the RS 80 shippers’ in-service dates and, in any event, is directed to file an update on its work on this plan in its next RRA.
4.0 Deferral Accounts
This section addresses PNG-West’s requests for BCUC approval of changes to existing deferral accounts, including additions and amortization, as well as the proposed creation of four new deferral accounts. These deferral account requests are discussed individually below.
4.1 LNG Partners Option Fee Payment Deferral Account
The BCUC previously approved the establishment of the LNG Partners Option Fee Payment deferral account[134] to record option fee payments received from customers wishing to secure future transportation capacity on PNG-West’s system. The amortization of this account has been determined under the BCUC’s directions in previous PNG-West RRAs.[135] PNG-West notes that the credit balance of this account as at December 31, 2021 is $2.537 million.[136]
The credit balance in this deferral account reflects the remaining balance due to an option fee forfeiture of $6.75 million which occurred in 2016.[137] In the Application, PNG-West proposes to amortize $0.325 million of the current credit balance of $2.537 million in the deferral account to alleviate the impact of the anticipated 2022 rate increases and to provide customers with rate stability. With this drawdown of the deferral account, delivery rate increases to customers are anticipated to be approximately five percent in 2022.[138] As summarized in PNG-West’s final argument,[139] PNG-West identified certain adjustments and corrections to 2022 forecast data during this proceeding. Consequently, PNG-West proposes to increase the proposed credit amortization of the LNG Partners Option Fee Payment deferral account by $0.280 million, to $0.605 million in 2022 to maintain the final average delivery rate increase at approximately five percent.[140]
During the IR process, the BCUC queried whether PNG-West considered alternate interest rates for the LNG Partners Option Fee Payment deferral account, observing that the short-term interest rate was being applied, as previously approved by the BCUC, to what has since become a long-term deferral account. In response, PNG-West observed that the appropriate return for a deferral account of this nature is its WACD, rather than PNG-West’s short-term interest rate. Accordingly, PNG-West proposes to apply WACD to the deferral account commencing in 2022 and to reflect this change in the final regulatory schedules.[141]
Positions of the Parties
RCIA supports PNG-West’s proposal to amortize the LNG Partners Option Fee Payment deferral account by $0. 605 million to limit the delivery rate increase to approximately five percent, while retaining a balance to mitigate future rate increases. However, in future RRAs, RCIA recommends that PNG be directed to provide an indicative rate increase trajectory to better inform the amortization of the LNG Partners Option Fee Payment deferral account.[142]
BCOAPO does not comment on PNG-West’s amortization proposal for this deferral account.
Interveners did not take a position on the interest rate applicable to the LNG Partners Option Fee Payment deferral account.
Panel Determination
The Panel approves PNG-West's request to amortize $0.605 million of the balance in the LNG Partners Option Fee Payment deferral account in 2022. The Panel finds PNG-West's proposal to be a reasonable rate mitigation measure in order to achieve rate stability and maintain the final average delivery rate increase at approximately five percent for 2022. The Panel notes that the purpose of the deferral account is to record option fee payments received from LNG customers wishing to secure future transportation capacity on PNG-West's system, to be credited against future revenues from the provision of transportation capacity to those customers. Given that these option fee payments have been forfeited by LNG customers such that they will no longer be credited against future revenues from those customers, it is appropriate for PNG-West to amortize a portion ($0.605 million) of the remaining balance in that deferral account ($2.537 million) for the benefit of all PNG-West ratepayers in order to achieve rate stability and reduce the amount of the delivery rate increase in 2022.
The Panel further approves the change in interest rate for the LNG Partners Option Fee Payment deferral account from the previously approved short-term interest rate to WACD, to be applied commencing in 2022. The Panel notes that this is consistent with the BCUC’s treatment of interest on deferral accounts which have a term longer than one year, as is the case with the LNG Partners Option Fee Payment deferral account. The Panel further notes that the long-term interest rate (WACD) on the deferral account is higher than the short-term rate.[143] To the extent that the remaining credit balance in this account will continue to be amortized for the benefit of ratepayers, they will benefit from the higher interest rate on this account as approved by the Panel.
As for RCIA’s recommendation to the BCUC to direct PNG-West to provide an indicative rate increase trajectory to better inform the amortization of the LNG Partners Option Fee Payment deferral account in future years, the Panel declines to provide such a directive. As the evidence in this proceeding shows, the outlook for PNG-West is uncertain in light of several factors, including the potential for amalgamation and rate harmonization such that any forecast of indicative rate increases in the future is at best speculative and may not be meaningful. In these circumstances, the Panel considers that requiring PNG-West to provide projections of future rate increases is unwarranted.
4.2 COVID-19 Deferral Account
In 2020, the BCUC approved the establishment of a COVID-19 deferral account for PNG-West to record any incremental unplanned expenses and cost savings related to the COVID-19 pandemic.[144] To ensure transparency of the deferral account balances, PNG-West reported to the BCUC on the COVID-19 deferral account balances on a monthly basis for the period from April 17, 2020 to December 31, 2021.[145] On February 1, 2022, the BCUC approved PNG-West’s request to cease monthly reporting at the end of 2021.[146]
In the Application, PNG-West proposes to amortize the credit balance of $1.058 million in the deferral account as at December 31, 2021 in Test Year 2022, and maintain the deferral account for the Test Year.[147]
PNG-West considers that amortization of the full deferral account credit balance in Test Year 2022 will return the balance to the benefit of ratepayers and avoid intergenerational inequity issues.[148] PNG-West adds that the amortization of the COVID-19 deferral account in 2022 would also help moderate the forecast rate increase for 2022.[149] Under a scenario where the December 31, 2021 balance is not amortized in Test Year 2022, PNG-West states that the deferral account credit balance would help to mitigate rate pressures when amortized in a future test period. However, it notes that there are additional mechanisms to mitigate future rate volatility by way of the Large Volume Industrial Deferral Account (LVIDA) and LNG Partners Option Fee Payment deferral account.[150]
The Test Year 2022 cost of service incorporates the forecast impact of the ongoing COVID-19 pandemic.[151] Specifically, PNG-West has reduced forecast 2022 travel and training costs, resulting in a budget for Test Year 2022 that is significantly lower than that presented in Decision 2020–2021. PNG-West considers, however, that as travel and other COVID-19 restrictions and safety measures ease, cost savings previously realized in these areas will dissipate.[152] The cost of service for Test Year 2022 does not include provision for any incremental costs related to the COVID-19 pandemic because PNG-West considers the pandemic situation to be improving and does not expect to incur additional costs.[153]
Notwithstanding that Test Year 2022 reflects the expected impact of the COVID-19 pandemic, PNG-West considers in light of the ongoing uncertainty around the pandemic, it is prudent to keep the deferral account in place in the immediate term to capture any COVID-19-related expenditures and/or cost savings that may arise. PNG-West states that this would provide both administrative and regulatory efficiency should a need arise to make use of the account in the future. Accordingly, it requests that rather than directing PNG-West to close the deferral account, the BCUC authorize PNG-West to continue to capture any COVID-19 costs and savings in the deferral account on a go-forward basis. It proposes that the disposition of the COVID-19 deferral account be addressed in its next RRA.[154]
Positions of the Parties
RCIA supports the continued use of the COVID-19 deferral account and the amortization as proposed by PNG-West.[155] BCOAPO does not comment on PNG-West’s COVID-19 deferral account proposals.
Panel Determination
The Panel approves PNG-West’s proposal to amortize the COVID-19 deferral account balance of $1.058 million as at December 31, 2021 in the 2022 Test Year. The Panel agrees with PNG-West that the credit balance in the deferral account which resulted from cost savings due to the pandemic should be returned to the benefit of current ratepayers, who have borne the brunt of the pandemic, to avoid inter-generational inequity issues and help to mitigate the impact of the delivery rate increase for Test Year 2022.
The Panel also approves the continuance of the COVID-19 deferral account to capture costs and savings due to the pandemic on an ongoing basis, and that it be maintained for the Test Year 2022 and beyond. While the pandemic appears to have abated somewhat in 2022, uncertainty still remains with respect to its potential re-emergence and impacts. In the meantime, the Panel considers it prudent for the deferral account to remain in place for PNG-West to capture pandemic-related costs and savings during 2022 and beyond. However, in the event that the pandemic ceases to be of concern after 2022, the Panel directs PNG to address, as part of its next RRA, the disposition of the balance in the COVID-19 deferral account and the potential closure of the account after 2022 if warranted.
4.3 Reactivation Project Development Cost Deferral Account
The Reactivation Project Development Cost deferral account was established in 2020, after BCUC approval,[156] to capture development, permitting and consultation expenses, and costs related to advancing front-end engineering and design and other early-stage development works incurred prior to the BCUC’s approval of PNG’s Reactivation Project CPCN application. Subsequent to the BCUC granting a CPCN to PNG for the Reactivation Project,[157] 2020 and 2021 expenditures recorded to this deferral account of $2.5 million have been transferred to capital. At the end of 2021, a small balance of $68,000 remains and will be transferred to capital in 2022. As the deferral account was established for a specific purpose and is no longer required, PNG-West seeks BCUC approval to eliminate the Reactivation Project Development Cost deferral account following the 2022 Test Period.[158]
Positions of the Parties
Interveners do not take a position on the dissolution of this deferral account.
Panel Determination
The Panel agrees with PNG-West that the Reactivation Project Development Cost deferral account has achieved the specific purpose for which it was established and is no longer required following the transfer of the remaining balance of $68,000 to capital in Test Year 2022. Accordingly, the Panel approves PNG-West’s request to close the Reactivation Project Development Cost deferral account at the end of 2022 following the transfer to capital of the remaining balance as at December 31, 2021.
4.4 Transfer Pricing / Interaffiliate Recoveries Deferral Account
By Order G-255-20 the BCUC approved the Transfer Pricing / Interaffiliate Recoveries deferral account to record variances between forecast and actual charges to affiliated parties for non-regulated services or activities, with amounts to be amortized over a one-year period.[159] The BCUC approved this deferral account to protect ratepayers from forecasting risk and address the uncertainty regarding PNG’s level of non-regulated business activity under its new owner, TSU.[160]
PNG-West acknowledges that it has garnered experience in forecasting non-regulated services/affiliate-related activities, and also that variances from forecast have not been material (2020: $13,000 credit addition to the deferral account; 2021: $25,000 debit addition to the deferral account). Based on this, PNG-West suggests that there may no longer be a need for this deferral account and requests approval to close the deferral account at the end of 2022, following amortization of the $12,000 balance as at December 31, 2021 in the 2022 Test Year.[161]
Positions of the Parties
No intervener raised any issues with the proposed closure of PNG-West’s Transfer Pricing/Interaffiliate Recoveries deferral account.
Panel Determination
The Panel finds that the Transfer Pricing/Interaffiliate Recoveries deferral account has served its purpose. Based on the immaterial differences between forecast and actual amounts captured in that deferral account in 2020 and 2021, the Panel finds that there is no need for PNG-West to continue to maintain this deferral account following Test Year 2022. The Panel approves PNG-West’s request to close the Transfer Pricing/Interaffiliate Recoveries deferral account at the end of 2022 following the amortization of the $12,000 balance as at December 31, 2021.
4.5 Proposed New Deferral Accounts
PNG-West requests approval to establish four new deferral accounts to record credit amounts which have been accrued but not dealt with in prior test years.[162] PNG-West suggests that these credit amounts should be amortized in Test Year 2022’s cost of service as this would be the most appropriate, most efficient and most practical mechanism to return the benefits to customers, both from an administrative and a regulatory review and approval perspective.[163] PNG-West states that had the credit variances been debit variances, it would not have sought to recover the incremental costs from customers.[164]
Since PNG-West's requests relate to the establishment of new deferral accounts to capture prior test period variances and recoveries, they raise the issue of retroactive ratemaking. However, the factual circumstances and nature of these deferral accounts differ. Accordingly, the Panel reviews the particulars of these deferral account requests and makes its determinations on each separately in the subsections below.
4.5.1 Incremental CCA Deferral Account
In 2021, PNG-West incurred significant capital expenditures beyond those approved in Decision 2020–2021. This is primarily related to projects for which the BCUC granted CPCNs in 2021 (e.g. Kitimat Let Down Station #1 and Salvus to Galloway Remediation Project), as well as the unplanned capital work related to integrity digs required to comply with BCOGC Order 2021-0115-01.[165]
As a result of the unplanned increase in capital expenditures, there is also an increase in associated capital cost allowance (CCA) deductions available for tax purposes. Given the emergent nature of the need for the unplanned repairs in late 2021, PNG-West states that the related tax benefit was not reasonably foreseeable in advance of the submission of PNG-West’s 2022 RRA.[166]
PNG-West has utilized the Government of Canada’s Accelerated Investment Incentive to accelerate CCA deductions for 2021 and has recorded the related CCA provision of $1.449 million in a short-term interest deferral account. PNG-West requests approval for the proposed Incremental CCA deferral account and to fully amortize the balance in Test Year 2022.[167] Without the proposed deferral account, PNG-West states that the benefit of the CCA tax benefit recorded by PNG in the 2021 taxation year would not flow to ratepayers. PNG-West states that BCUC approval of the proposed deferral account will allow for the tax benefit to be returned to PNG-West ratepayers in 2022 via the credit amortization of this deferral, which would result in an average delivery rate decrease of 4.95 percent in 2022.[168] In PNG-West’s view, the deferral account should remain in place from 2022 through to 2027 when the Accelerated Investment Incentive ends.[169]
PNG-West first utilized the Accelerated Investment Incentive in 2019 and was approved in Decision 2020–2021 to record the related 2019 CCA provision in a short-term interest deferral account, amortize the balance in 2020, and close the account in 2021.[170] PNG-West states that its request for the Incremental CCA deferral account in the current (2022) RRA is essentially the same as what the BCUC approved in Decision 2020–2021.[171]
Positions of the Parties
RCIA supports the creation of the Incremental CCA deferral account and the amortization of the tax benefits to the benefit of ratepayers in 2022. RCIA considers that it is reasonable for this deferral account to continue past 2022 as the Accelerated Investment Incentive continues past 2022.[172]
BCOAPO does not comment on the issue of potential retroactive ratemaking arising from PNG-West's proposal or the creation of this deferral account.
Panel Determination
As PNG-West notes, in Decision 2020–2021, the BCUC approved PNG-West capturing the amount of the 2019 CCA tax benefit resulting from its utilization of the Accelerated Investment Incentive in a short-term interest deferral account, amortizing the balance in 2020 and closing the account in 2021. As part of the current Application, PNG-West advises that it proposes the establishment of a new Incremental CCA deferral account to capture the CCA tax benefit recorded by PNG-West in the 2021 taxation year and to fully amortize the balance in Test Year 2022. The Panel notes, however, that in Decision 2020–2021, the BCUC approved, among other things, PNG-West's delivery rates on a permanent basis for a two-year test period, which did not include the establishment of a deferral account to capture CCA tax benefits arising in 2021 or subsequent taxation years. Accordingly, the Panel considers that PNG-West's request to establish a new deferral account to capture CCA benefits accrued in the previous test period (2020 to 2021) amounts to retroactive ratemaking.
The prohibition against retroactive ratemaking is well established. The Supreme Court of Canada stated in ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board) (ATCO Decision):[173]
[…] The Board was seeking to rectify what it perceived as a historic overcompensation to the utility by ratepayers. There is no power granted in the various statutes for the Board to execute such a refund in respect of an erroneous perception of past over-compensation. It is well established throughout the various provinces that utilities boards do not have the authority to retroactively change rates [...]
Consistent with this reasoning in the ATCO Decision, the BCUC typically sets rates on a prospective basis only and the BCUC does not allow recovery or refunds on a retroactive basis, that is, once rates have been made permanent. Well-established exceptions to retroactive ratemaking include, in part, setting of interim rates which are subject to later adjustment, and recognition of amounts in deferral accounts to be carried forward to be disposed of in future years.[174]
In the case of the CCA tax benefit accrued in 2021 by PNG-West, the Panel notes that this benefit should have been captured and reflected in PNG-West’s 2021 rates and not in 2022. Instead, PNG-West is proposing to reduce the rate impact on customers in 2022 by amortizing the amount of the CCA benefit accrued in 2021 ($1.449 million) in a new deferral account after permanent 2021 rates have already been approved by the BCUC. The Panel considers that doing so would amount to retroactive ratemaking because the CCA tax benefits were realized in 2021 and were associated with unplanned capital expenditures in 2021, a test year for which BCUC has already approved permanent rates. PNG-West’s proposal to capture the prior test period’s recoveries of CCA benefits in a new deferral account in 2022 is only a convenient mechanism for retroactively returning that benefit to ratepayers, and not necessarily a justification for retroactive ratemaking. Nonetheless, the Panel acknowledges that the BCUC has in previous decisions allowed exceptions to the general rule in limited circumstances where warranted.
One such example is the BCUC’s decision in the PNG-West 2018–2019 RRA, which approved PNG-West's request to retroactively record, in an existing deferral account, a 2016 goods and services tax (GST) remittance of $0.321 million to the Canada Revenue Agency relating to a 2016 option fee forfeiture. In so doing, the BCUC considered several factors including “the size of the adjustment, the timeliness of the request, whether PNG-West acted responsibly and the foreseeability of the problem.” In particular, the BCUC noted the following:[175]
• The “option fee forfeited amounts to $6.75 million, all of which is to the benefit of ratepayers. The resultant GST remittance amount is a direct consequence of the option fee and should be matched against it.”
• The amount of the GST remittance was substantial and would have a material effect on PNG-West's ability to earn its fair rate of return.
• The option fee forfeiture occurred during PNG-West's previous RRA proceeding and could not be predicted prior to its occurrence.
• Given that the GST remittance would be recorded to an existing deferral account, parties were aware that future rates were subject to change with no direct impact on the rates previously established.
Depending on the nature and circumstances of the specific request, the Panel considers some, if not all, of the following factors may be helpful in assessing the reasonableness of a request for the BCUC to allow an exception to the rule against retroactive ratemaking:
• Whether the item can be reasonably forecast or known at the time of the previous revenue requirement decision;
• Whether approval of the request would better adhere to cost causation principles for specific groups of customers;
• Whether the request has a material impact on customer rates in the test period;
• Whether there are any significant intergenerational inequity considerations; and
• Whether the approval or denial of the request would establish certain utility or ratepayer expectations in the future.
In the case of the CCA benefit, the Panel notes that PNG-West first utilized the Accelerated Investment Incentive in 2019 to trigger a related CCA benefit which, with the BCUC’s approval, was captured in a new deferral account for amortization in the 2020 to 2021 test period. To the extent that PNG-West has been aware of the existence of this incentive since 2019, it should have contemplated and sought approval of the continuance of that deferral account to capture CCA benefits arising from unplanned capital expenditures beyond 2021. Had it done so, the issue of retroactive ratemaking would not have arisen since deferral account treatment is a well-established exception to the rule. At the same time, however, the Panel acknowledges that the amount of the increase in CCA deductions available to PNG-West in 2021 is at least due, in part, to the increase in unplanned capital expenditures in 2021. Given the emergent nature of the need for the unplanned repairs in late 2021, the Panel accepts that the CCA tax benefit related to these unplanned capital expenditures in late 2021 was not reasonably foreseeable prior to the submission of PNG-West’s 2022 RRA.[176]
With respect to the question whether the request has a material impact in the test period, the Panel notes that the proposed amortization of the $1.480 million of CCA benefit in the new deferral account results in an average delivery rate decrease of 4.95 percent in 2022, which is material.[177] In other words, if the Panel were to deny this request from PNG-West, the average delivery rate for PNG-West's customers would have to increase by another 4.95 percent, which combined with the proposed delivery rate increase of approximately 5 percent, would approach rate shock.
In light of these factors, the Panel approves PNG-West's request to establish the Incremental CCA deferral account to record the CCA on unplanned capital expenditures in 2021, attracting interest at PNG-West’s short-term interest rate. The balance is to be fully amortized in 2022, as set forth in section 2.9 of the Application. As the federal Accelerated Investment Incentive will continue until 2027, the Panel further approves the continuance of the Incremental CCA deferral account from 2022 to 2027 to capture any CCA on PNG-West's unplanned capital expenditures during that period, with an amortization period of one year.
4.5.2 RECAP Deferred Demand Charges Deferral Account
PNG-West is seeking approval to establish the RECAP Deferred Demand Charges deferral account to capture certain interest recovered in 2020 and 2021 from currently contracted RS 80 or RECAP shippers that are potentially creditable back to the RS 80 shippers once service commences as per contractual arrangements.[178] PNG-West proposes that this deferral account attract interest at PNG-West’s WACD. PNG-West will continue to evaluate the appropriate interest rate for this deferral account, depending on the duration and amortization period for the account, and will include a recommendation in the application anticipated to be filed in the third quarter (Q3) of 2022.[179]
With regards to the timing of this request, PNG-West explains that it had planned to keep the creditable interest recovered from RS 80 shippers within the LVIDA as this revenue is related to the Transmission Service Agreements. However, PNG-West subsequently determined that administratively, it made more sense to capture these amounts in a separate deferral account as they are creditable against the RS 80 shippers’ demand charges, while other revenue captured in the LVIDA will be used to the benefit of all PNG-West ratepayers.[180]
PNG-West is not proposing any amortization of this credit deferral in Test Year 2022, and therefore, there are no delivery rate impacts in the Test Period. At the end of 2022, PNG-West notes that there is a forecast balance of $0.657 million that is creditable against the RS 80 shippers’ future demand charges.[181]
Positions of the Parties
When asked whether this proposal amounts to retroactive ratemaking, PNG-West submits that the request to establish this new deferral account does not result in retroactive ratemaking as it simply “facilitates the reclassification of amounts already being captured in the previously approved LVIDA.”[182]
PNG-West further submits that should the reclassification of the creditable interest recovered from RS 80 shippers into a distinct deferral account not be approved, the amount can be tracked separately within the LVIDA.[183]
Interveners do not make any submissions on the creation of this deferral account.
Panel Determination
The Panel finds that even though the request relates to interest that was accrued in a prior test period (2020 to 2021), the request nonetheless aligns with the principle of cost causation. Specifically, the interest is creditable against the RS 80 shippers’ demand charges once service to them commences in accordance with their contractual arrangements with PNG-West, while the other revenue captured in the LVIDA is to the benefit of all ratepayers. In that sense, the interest recovered from currently contracted RS 80 shippers in the prior test period should not have been included in the LVIDA to begin with. Rather, it should have been tracked in a separate deferral account from the outset.
In these circumstances, the Panel considers it appropriate and reasonable for PNG-West to correct this error going forward. Accordingly, the Panel approves PNG-West to establish the RECAP Deferred Demand Charges deferral account to record interest recovered from currently contracted RECAP shippers for the period of 2020 and 2021, attracting interest at PNG-West’s WACD. The balance is to be creditable against the shippers’ demand charges once service to them commences, as set forth in section 2.9 of the Application.
4.5.3 CIS Project Recoveries Deferral Account
PNG jointly implemented the SAP CIS Project with the TSU corporate group during 2020 and 2021 and PNG was compensated for the time spent by employees dedicated to the project. PNG-West states that the recoveries from the SAP CIS Project were intended to offset incremental support costs incurred by PNG for backfill resources and project management assistance. PNG-West notes that final project recoveries were in excess of incremental costs incurred, creating a net positive cost recovery. PNG-West has recorded a positive net recovery of $110,000 in 2020 and a further $31,000 positive net recovery in 2021. PNG-West requests approval to create a new short-term interest-bearing CIS Project Recoveries deferral account to fully amortize the balance in Test Year 2022 to the benefit of ratepayers, and to close the deferral account after 2022.[184]
PNG-West first identified the CIS Project net recoveries in early 2021 but expected that the deferral account treatment could be more efficiently addressed in the next RRA.[185] PNG-West concedes that the approval of the proposed additions to this new deferral account may be viewed as retroactive ratemaking. PNG-West accepts that the BCUC had previously approved the SAP CIS Project and the related costs, and it was reasonably foreseeable that there might be variances from forecast amounts. However, PNG-West had not anticipated net cost recoveries at the end of the project. Cognizant of ongoing rate pressures, PNG-West captured these benefits in a deferral account so that they could be returned to PNG-West ratepayers.[186] In 2022, PNG-West states that the credit amortization of this deferral account would result in an average delivery rate decrease of 0.36 percent.[187]
Positions of the Parties
RCIA recommends that the BCUC approve the CIS Project Recoveries deferral account and the amortization of the net recoveries from 2020 and 2021 to the benefit of ratepayers in 2022.[188]
RCIA agrees with PNG-West that the proposed deferral account is the simplest, most efficient, and timely manner to return the net CIS project recoveries to ratepayers.[189]
BCOAPO does not comment on the issue of retroactive ratemaking or the establishment of this new deferral account.
Panel Determination
The Panel notes that while the BCUC had previously approved the SAP CIS Project and its related costs and it was reasonably foreseeable that the actual costs might vary from the forecast amounts, PNG-West nonetheless did not anticipate that there would be net cost recoveries at the conclusion of the project within the previous test period. While PNG-West recorded a positive net recovery of $110,000 in 2020 and a further $31,000 in 2021, instead of returning those amounts to ratepayers during the previous test period, it determined that it would be more efficient to deal with the disposition of the net recovery as part of this RRA by establishing a new deferral account to capture that net recovery and amortize the balance to the benefit of ratepayers in Test Year 2022.
The Panel acknowledges that the BCUC does not typically require utilities to account for variances in forecast and actual costs that arise from project execution. To the extent that there are positive variances, they would normally accrue to the shareholder. To the extent that there are negative variances, the shareholder would have to absorb those costs once permanent rates have been set.
In assessing whether an exception should be made in this case, the Panel considers the following factors to be relevant:
• While the amount of the net recovery ($141,000) is not substantial, if amortized in Test Year 2022, it nonetheless would result in an average 2022 delivery rate decrease of 0.36 percent, which benefits customers;
• PNG-West concedes that returning the benefit of this net recovery amounts to retroactive ratemaking, but nonetheless, proposes to do so in order to mitigate the impact of the delivery rate increase on customers in 2022;
• No intervener opposes this request, and at least one intervener, RCIA, recommends that the BCUC approve this deferral account and the amortization of recoveries from 2020 and 2021 to the benefit of ratepayers in 2022; and
• If the Panel were to deny the request, the net recovery from the project would simply enrich PNG-West’s shareholder rather than benefit ratepayers.
In light of the above factors, the Panel approves PNG-West to establish the CIS Project Recoveries deferral account to record net SAP CIS Project recoveries realized in 2020 and 2021, attracting interest at PNG-West’s short-term interest rate. The balance is to be fully amortized in 2022, as set forth in section 2.9 of the Application, and the deferral account dissolved thereafter. However, should variances on future projects occur or appear to be likely, the Panel advises PNG-West to notify the BCUC in advance and if required, apply for deferral account treatment promptly in order to avoid the issue of retroactive ratemaking. It would then be up to the BCUC, not PNG-West, to determine if it would be more efficient from an administrative and regulatory perspective to defer the matter to a subsequent RRA, and to do so with full knowledge that this may raise the issue of retroactive ratemaking for the subsequent panel. PNG-West should not presume in advance that the BCUC would make the same determination as PNG-West did in this instance.
4.5.4 Shared Corporate Services Costs Variance Deferral Account
As noted above, in Decision 2020–2021, the BCUC approved the recovery by PNG-West of the full amount of the annual TSU Shared Corporate Services Costs. TSU undertakes to true up the costs allocated amongst its corporate group based on actual costs incurred. Based on these true-ups, actual costs allocated are lower than the forecast by $0.142 million and $0.216 million in 2020 and 2021, respectively.[190] PNG-West seeks approval to create a new Shared Corporate Services Costs Variance deferral account for Test Year 2022, attracting interest at PNG-West’s short-term interest rate to capture the credit amounts from 2020 and 2021, and approval to amortize the full credit balance in Test Year 2022 to the benefit of ratepayers. Following which, PNG-West proposes that the deferral account would be closed. However, PNG-West states that it has no opposition should the BCUC determine there remains value in continuing the use of the Shared Corporate Services Costs Variance deferral account.[191]
PNG-West concedes that the approval of the proposed additions to this new deferral account may be viewed as retroactive ratemaking as the BCUC had previously approved the TSU Shared Corporate Services Costs and it was reasonably foreseeable that there may be variances from forecast amounts.[192] However, PNG-West submits that the variance only came to light in early 2021, when the 2020 fiscal year-end was being finalized, and after the conclusion of the 2020–2021 RRA proceeding.[193] It identified the following factors as contributing to the difference between forecast and actual Shared Corporate Services Costs, and states that all identified factors are beyond the control of both its management and TSU’s management:[194]
• Frictional vacancies, where there is a delay between an existing employee leaving their role and a new employee being hired for the role;
• Insurance market changes, which drive changes in insurance premiums;
• COVID-19 restrictions and safety measures, which impact training and travel expenses; and
• Employee costs billed to growth opportunities unrelated to existing TSU businesses, therefore reducing the employee costs in the shared services cost pool.
PNG-West considers that recording the credit amounts in a deferral account and amortizing the balance in 2022 is the most appropriate, efficient and practical mechanism to return the benefits to customers.[195] It adds that amortizing the full amount of this credit balance in Test Year 2022 results in an average delivery rate decrease of 0.96 percent in 2022.[196]
Positions of the Parties
RCIA agrees that the proposed deferral account is the simplest, most efficient, and timely manner to return the Shared Corporate Services Costs credit variance to ratepayers. With respect to the proposed additions to the deferral account being considered retroactive ratemaking, RCIA views that it is reasonable to allow retroactive ratemaking to correct the error of not requesting the deferral account when the variances were first identified, such that the utility does not benefit from its own error. RCIA supports approval of the Shared Corporate Services Costs Variance deferral account and the amortization of the credit variances from 2020 and 2021 to the benefit of ratepayers in 2022.[197]
BCOAPO does not provide submissions on this matter.
Panel Determination
As the Panel has already noted above in the discussion relating to the CIS Project Recoveries deferral account, the BCUC does not typically retroactively adjust for variances between forecast and actual costs in setting a utility’s rates. However, in this particular instance, the Panel is persuaded on balance that despite PNG-West’s concession that this request amounts to retroactive ratemaking, the establishment of the new deferral account to capture variances between forecast and actual TSU Shared Corporate Services Costs in 2020 and 2021 is warranted. The Panel makes this finding based on the following:
• The proposed amortization of the total variance of $0.358 million in Test Year 2022 results in an average delivery rate decrease of 0.96 percent in 2022, which is not an insubstantial amount to PNG-West ratepayers;
• PNG-West only identified the variances in early 2021 when the 2020 fiscal year-end was being finalized;
• As noted above, the factors that lead to the variances were all external and beyond the control of both PNG-West’s and TSU’s management; and
• No intervener opposes this request, and one intervener, RCIA, supports the approval of the request, noting that it is reasonable to allow retroactive ratemaking to correct PNG-West’s error of not requesting the deferral account when the variances were first identified, such that the utility does not benefit from its own error.
Accordingly, the Panel approves PNG-West to establish the Shared Corporate Services Costs Variance deferral account to record its portion of the variances in actual TSU Shared Corporate Services Costs from forecast amounts, including those realized in 2020 and 2021, attracting interest at PNG-West’s short-term interest rate. The December 31, 2021 balance is to be fully amortized in 2022, as set forth in section 2.9 of the Application. The Panel notes that since variances between forecasts and actuals in the Shared Corporate Services Costs have occurred in 2020 and 2021, they can reasonably be expected to continue to occur in the future. Accordingly, the Panel approves the continuance of the Shared Corporate Services Costs Variance deferral account beyond 2022 to capture annual variances in PNG-West’s actual TSU Shared Corporate Services Costs from forecast amounts, with an amortization period of one year.
5.0 Overall Determination on Delivery Rates and Revenue Stabilization Adjustment Mechanism
Subject to the adjustments identified during this proceeding, as summarized in PNG-West's final argument,[198] along with the directives and determinations on the components of the 2022 forecast revenue requirements for PNG-West as set out in this decision, the Panel finds the forecast revenue requirements reasonable for setting delivery rates for the 2022 Test Period.
The Panel approves the 2022 delivery rates and RSAM rate rider as filed by PNG-West, on a permanent basis, effective January 1, 2022, subject to the adjustments summarized in PNG-West’s final argument, along with the directives and determinations in this decision.
6.0 Unaccounted for Gas Component of Company Use Gas
The American Gas Association defines unaccounted for gas (UAF) as follows:
The difference between the total gas available from all sources, and the total gas accounted for as sales, net interchange, and company use. This difference includes leakage or other actual losses, discrepancies due to meter inaccuracies, variations of temperature and/or pressure, and other variants, particularly due to measurements being made at different times. In cycle billings, an amount of gas supply used but not billed as of the end of a period.[199]
PNG-West requests approval to increase both the UAF component of Company Use gas from 0.0 to 1.0 percent and the UAF Volume deferral account loss cap from 1.0 to 1.25 percent. PNG-West has a UAF Volume deferral account, and the deferral account amounts are recovered from or refunded to customers via the Gas Cost Variance Account (GCVA) Company Use rider. Changes to the GCVA Company Use rider are proposed and approved as part of the BCUC’s review of PNG-West’s quarterly reporting on gas supply costs. BCUC approval is required to record any UAF amounts greater than the loss cap in the deferral account.
PNG-West states that the request for changes to the UAF component of Company Use gas is not predicated on any particular issue that the utility has been experiencing with the existing regulatory treatment. Rather, it is based on the fact that PNG-West has experienced average net UAF losses equal to 1.88 percent over the five-year period from 2015 to 2019.[200] For the three-year period from January 2019 to December 2021, PNG-West has experienced average running 12-month UAF losses equal to 1.1 percent of deliveries.[201]
PNG-West reports its UAF for a 12-month period ending in December, when the unbilled accrual error is the largest, and as such, PNG-West submits that a non-zero component of UAF in Company Use gas is appropriate.[202] PNG-West provides the actual UAF losses, total deliveries, and the UAF losses as a percentage of deliveries for each year from 2004 to 2021 in the table below.
Table 8: Actual UAF Losses, Total Deliveries, and the UAF Losses as a Percentage of Deliveries[203]
In the PNG-West 2020–2021 RRA, PNG-West requested approval to increase both the UAF component of Company Use gas from 0.0 to 1.0 percent and the UAF Volume deferral account loss cap from 1.0 to 1.5 percent.[204] In Decision 2020–2021, the Panel outlined several concerns regarding the proposal to amend the UAF percentages, including the calculation of the accrual error and risks borne by ratepayers.[205] PNG-West was also directed to file a report outlining the findings of PNG-West’s analysis of the factors that contributed to the UAF losses in 2019 (2019 UAF Review Report).[206]
The following subsections address the calculation of accrual error and the risk to ratepayers, the results of the 2019 UAF Review Report, as well as the basis for the requested changes to the UAF loss cap, and the impact of the proposed changes on rates.
Accrual Error
To address the PNG-West 2020–2021 RRA panel’s concerns regarding UAF losses arising from accrual error, a number of IRs were asked on this topic in this proceeding. PNG-West provided detailed explanations of its methodology for estimating Accrual Error from Unbilled Estimates.[207]
PNG-West explains that errors in the unbilled estimates create offsetting UAF losses and gains.[208] This is because an accrual is generated when customers’ consumption occurs between when the meters are read, and the end of the calendar month, and this accrual is reversed the following month. To estimate customers’ consumption in a calendar month, PNG-West sums the consumption billed each month, the accrual for the unbilled estimate in that month, and the reversal of the accrual made the previous month. PNG-West explains that the net impact of 12 monthly accruals and reversals over a calendar year is equal to the estimate made in December of the current year, less the estimate made in December of the previous year.[209] An illustration of the accrual process was provided in response to IRs.[210]
As a result of PNG-West’s practice to record annual sales over a calendar year, the impact of unbilled estimates on UAF is greater than if a different period were used (e.g. July to June). This is because the unbilled estimate methodology may not be able to accurately reflect consumption during cold winter months owing to extreme temperatures and variations in customers’ consumption patterns over the Christmas holiday period.[211]
PNG-West implemented a new unbilled estimation algorithm in January 2022, which is being used concurrent with the existing estimation spreadsheet. A determination of the performance of the new algorithm will require several years of data.[212]
2019 UAF Review Report
PNG-West filed its 2019 UAF Review Report with the BCUC on December 30, 2020.[213] Aside from leaks detected and repaired on the Salvus to Galloway pipeline, and the replacement of meters at customer locations where current flow volumes deviate significantly from when they were first installed, no anomalies were discovered.[214]
UAF Risk
PNG-West submits that there would be no change to the existing risks borne by the ratepayer should the request to set the UAF component of Company Use gas to 1.0 percent be approved. However, the increase of the loss cap to 1.25 percent could potentially result in an additional $63,500 to be recovered from ratepayers via the GCVA Company use rate rider. Any losses above 1.25 percent would be subject to BCUC approval.[215]
UAF Loss Cap
The request for a loss cap of 1.25 percent is based on a 0.98 percent theoretical minimum UAF that the utility can be expected to achieve, with an escalation factor of 1.25. PNG-West states that this method is consistent with the method used in past requests.[216]
The theoretical minimum UAF is estimated based on four primary drivers: Measurement Error, Blowdown and Venting Estimate Error, Linepack Error, and Accrual Error, and the narrowest possible bandwidth of UAF is equal to the sum of all four of the associated contributions.[217]
UAF Impact on Rates
The inclusion of 1.0 percent UAF in the Company Use gas component contributes 0.32 percent to the 2022 delivery rates increase (i.e. 5.71 percent delivery rate increase for a residential customer, compared to an increase of 5.39 percent if the UAF were set at 0.0 percent).[218]
PNG-West states that setting the UAF component of Company Use gas at 1.0 percent would only result in a timing difference for the collection of funds related to UAF and Company Use gas. The inclusion of 1.0 percent allows for recovery of this cost in the delivery rate rather than recovering it subsequently via the GCVA Company use rate rider. PNG-West submits that there may be some ratepayer value from the recovery of the UAF immediately through the Company Use gas charge, as it avoids the short-term interest rate the GCVA attracts. PNG-West notes that should actual UAF be lower than 1.0 percent, this amount would be subsequently refunded back to customers via the GCVA Company use rate rider.[219]
PNG-West is also seeking approval to increase the approved UAF loss cap to be recorded in the UAF Volume deferral account from 1.0 percent to 1.25 percent, which, as previously noted, could potentially result in an additional $63,500 to be recovered from ratepayers via the GCVA Company use rate rider. PNG-West notes that it would require BCUC approval to recover any UAF losses in excess of the proposed 1.25 percent loss cap.[220]
Positions of the Parties
PNG-West, in its final argument, reiterates that both the actual UAF experienced over the past three years (1.1 percent of deliveries) and the theoretical minimum average UAF that the utility can be expected to achieve (0.98 percent of deliveries) support the requested changes.[221]
RCIA supports the inclusion of UAF at 1.0 percent of deliveries in Company Use gas, noting that it reduces inter-generational inequity and is a similar approach taken by other utilities.[222]
RCIA does not support adjusting the loss cap at this time. RCIA submits that a faulty industrial meter may have caused all monthly UAF values prior to 2019[223] to be higher than they should be. If the historical record shows that UAF is below the three-year average of 1.1 percent, there may not be a need to adjust the loss cap. RCIA further notes that corrections made to the UAF due to the faulty meter reduced UAF below the historical three-year and five-year averages to 0.42 percent and -0.77 percent of deliveries for 2020 and 2021, respectively.[224]
In reply, PNG-West agrees that the full historical impact of the industrial metering error has not been reflected in the data on which PNG-West’s request for the loss cap has been founded. PNG-West further concedes that the supporting analysis should have been amended as far back to the August 2014 installation date for the meter in question and that the underlying UAF values in the supporting analysis may, in fact, be higher than they should be. However, PNG-West states that it is not practicable to cost effectively obtain the information necessary to amend the historical data.[225]
BCOAPO does not comment on the proposed changes to the regulatory treatment of UAF.
Panel Determination
The Panel recognizes that historically between 2004 and 2021, PNG-West experienced offsetting UAF gains and losses; however, in the last three years, PNG-West has recorded UAF losses of 1.1 percent of deliveries. In PNG-West’s 2019 UAF Review Report[226], no anomalies were discovered aside from leaks detected and repaired on the Salvus to Galloway pipeline, and the replacement of meters at customer locations where current flow volumes deviate significantly from when they were first installed.
As a result of PNG-West’s practice to record annual sales over a calendar year, the impact of unbilled estimates on UAF is greater than if a different period were used (e.g. July to June). Until further data is collected using the new unbilled estimation algorithm is obtained and the model assessed, PNG-West’s current model to capture unbilled estimates on UAF is used. The accrual error is the main driver to the UAF losses, and PNG-West has provided evidence that demonstrates that the theoretical minimum average UAF that the utility is expected to achieve is 0.98 percent of deliveries. The Panel recognizes that if the UAF losses are increased to 1.0 percent that the corresponding request for a loss cap of 1.25 percent, which is based on a 0.98 percent theoretical minimum UAF that the utility can be expected to achieve, with an escalation factor of 1.25, is reasonable to achieve regulatory efficiency. If approved, PNG-West would require BCUC approval to recover any UAF losses in excess of the proposed 1.25 percent loss cap.
Based on the evidence and explanation provided by PNG-West on UAF losses in this proceeding, the Panel approves the increase in the UAF component of Company Use gas from 0.0 percent to 1.0 percent and the loss cap for the UAF Volume deferral account from 1.0 percent to 1.25 percent.
The Panel also notes that RCIA supports the increase in the UAF component of Company Use gas from 0.0 percent to 1.0 percent. Although RCIA does not support increasing the loss cap from 1.0 to 1.25 percent, the Panel approves the change for regulatory efficiency as previously discussed. The Panel appreciates RCIA’s recommendation that PNG-West should update its historical analysis but agrees with PNG-West that updating the historical analysis is not practical or cost effective, in view of PNG-West’s calculated theoretical minimum value for the loss cap as 0.98 percent.
7.0 Other Matters
7.1 Rate Design and Amalgamation Considerations
In Decision 2020–2021[227] and PNG(NE)'s 2020–2021 RRA Decision, the BCUC reiterated its concern with rising costs, decreasing system throughput, and declining customer use per account.[228] The BCUC stated that it may be in the best interests of both the shareholder and ratepayers for PNG to examine the long-term plans of its utilities and the continued viability of their current rate design as part of PNG-West’s and PNG(NE)’s next RRAs.[229] The BCUC urged PNG to focus on the consideration and development of a comprehensive business strategy to address the current challenges. The BCUC noted that such strategy may necessitate consideration of rate design changes, including postage stamp rates and/or amalgamation of its various entities to reduce costs on a consolidated basis or produce greater operational efficiencies for the mutual benefit of ratepayers and the shareholder.[230]
In this proceeding, PNG-West provides a response with respect to its considerations on rate design and amalgamation opportunities for both commodity costs and delivery rates, which are discussed below.
PNG-West notes that there is some variability in the commodity rates among the divisions, with customers in the non-integrated parts of the system (Granisle and Tumbler Ridge) paying notably more for commodity. In an effort to provide greater rate certainty, PNG is evaluating new potential rate design alternatives that would harmonize the commodity costs across the various PNG service territories (PNG-West; PNG-West – Granisle; PNG(NE) FSJ/DC; and PNG(NE) TR). PNG-West states that harmonizing commodity costs would bring PNG’s commodity rate design closer in alignment with the principle of postage stamp rates.[231]
PNG has also undertaken a preliminary analysis to better understand the potential opportunities to amalgamate two or more of PNG’s three divisions (PNG-West; PNG(NE) FSJ/DC; and PNG(NE) TR) and harmonize delivery rates.[232] PNG-West notes that there are significant differences between the service territories with the main one being that the Western Transmission System, which is unique to PNG-West and not comparable in size to the infrastructure in the northeast system. PNG-West adds that the delivery rate harmonization would require breaking out of the transmission related costs and implementing a unique transmission rate for each division on top of potentially harmonized delivery rates. However, PNG-West believes there may be administrative and regulatory efficiencies to be achieved from this approach but notes that it is a more complicated initiative and will likely require third-party assistance.[233]
PNG-West acknowledges the letters of comment received in both the PNG-West 2022 RRA and PNG(NE) 2022 RRA proceedings, which raise significant concerns primarily in the communities of Tumbler Ridge and Granisle around rising rates.[234] PNG-West states that it is engaging with stakeholders on the potential consolidation of commodity costs and harmonization of delivery rates.[235] In response to IRs, PNG-West noted that it has had preliminary discussions with the elected officials in Granisle and Tumbler Ridge to hear their concerns with respect to energy affordability.[236] Feedback received from letters of comment and elected officials has solidified PNG-West’s understanding of the hardships and affordability challenges that residents in those higher cost areas are facing and confirms its belief that options need to be thoroughly explored and evaluated in order to help mitigate some of the rate impacts.[237]
PNG-West states that it is not requesting any decisions related to the possible harmonization of its gas commodity costs nor harmonizing delivery rates in this Application.[238] It expects to file the consolidation of commodity cost amongst the PNG divisions in Q3 or Q4 2022 and an amalgamation application to harmonize delivery rates in 2023. It adds that the timing of these applications will depend on the results of engagement activities and the incorporation of any feedback received from stakeholders, as well as resource availability at PNG given the other regulatory applications.[239] PNG-West considers these timelines to be reasonable given the magnitude of work to be undertaken, noting that the potential options need to be thoroughly explored, evaluated and engaged on prior to submission of any application, as any benefit to one group of ratepayers will put upward pressure on the rates for other groups of ratepayers.[240]
Positions of the Parties
BCOAPO states that PNG-West did not directly address the development of a comprehensive business strategy to address the affordability challenges that residents in those higher cost areas are facing.[241] It adds that it appreciates that the PNG companies are operating in a uniquely challenging time but states that this does not absolve the utilities of their duty to make extraordinary efforts to proactively map the way into the future via a timely, comprehensive business strategy.[242] It acknowledges that PNG-West has mechanisms for managing rate pressures in the near to middle term. However, it notes that this does little to satisfy the need to address the issue of affordability that was raised by the BCUC in the PNG-West and PNG(NE) 2020–2021 RRA decisions.[243] BCOAPO notes that PNG-West plans to engage with customer representatives and interveners as part of its engagement activities for the potential consolidation of commodity charges and harmonization of delivery rates. However, it adds that although the BCOAPO is ready to engage, this does not address its concerns with respect to the lack of action taken by PNG-West thus far.[244] For the next RRA, BCOAPO recommends that the BCUC direct PNG to develop a strategic plan that includes, among other things, a long-term scenario analysis, financial evaluation of uncertainties, and a multi-year plan for OMA&G expenses, capital expenditures, and deferral accounts.[245]
In reply, PNG-West concedes that it has not prepared specific strategy documents related to these challenges. It adds that in the intervening period it has made considerable effort in understanding and evaluating many elements related to the changes emerging in the energy market and to increasing the utilization of its assets.[246] PNG-West submits that it has given extensive consideration to the issues identified by BCOAPO in its argument. However, the uncertainties identified were the very driver for PNG-West’s decision to depart from its usual practice of submitting RRAs for a two-year test period by submitting a one-year application for 2022. The need to devote resources in doing so has precluded in the meantime the formulation and implementation of concrete, longer-term strategies.[247] It adds that while BCOAPO may not be satisfied with the summary of potential mechanisms presented by PNG-West for managing future rate pressures, PNG-West observes that the mechanisms available to achieve this objective are limited. PNG-West reiterates that while much has been made about the potential benefits to be derived from amalgamation, the primary benefits are expected to be modest administrative and regulatory efficiencies and not significant operating efficiencies. Further, PNG-West repeats that any benefit conferred to one group of customers will put upward pressure on the rates of other customer groups and as such amalgamation and rate design should not be considered a solution for future rate increases and rate uncertainty.[248]
PNG-West reiterates that the uncertainty around the RS 80 shipper projects and the related revenues has challenged PNG-West to advance a meaningful strategic plan.[249] PNG-West observes that the BCOAPO’s recommendation exceeds the scope of work undertaken by even very large utilities and would require additional resources, costs and time to implement.[250] PNG-West submits that it will provide a proposal for the disposition of the LVIDA in its next RRA, and will consider other deferral accounts as a mechanism to mitigate rate volatility and rate impacts.[251]
RCIA supports PNG’s plan to update its cost-of-service allocation study as it is a useful tool to assist in setting rates and notes that it will be valuable in the consideration of any amalgamation between PNG service territories.[252]
Panel Discussion
The Panel notes that the BCUC has reiterated in PNG’s two preceding RRAs the importance of the utilities and their shareholder developing a comprehensive business strategy to deal with the challenges they are facing in their service territory. The ongoing pandemic, along with the increasing focus on decarbonization and electrification in this Province and their uncertain impact on the natural gas industry, has made that need more acute. The Panel applauds PNG’s efforts to consider possible amalgamation of its entities, rate harmonization and rate design changes. The Panel accepts that in doing so, PNG must carefully and thoughtfully balance the interests and needs of all stakeholders. In that regard, like RCIA, the Panel heartily supports PNG’s plan to file a cost-of-service allocation study for BCUC review. Prior to or concurrent with the filing of any application to effect a reorganization or rate harmonization proposal, the Panel would like PNG to provide an analysis of the pros and cons (for both the ratepayers and the utilities) of alternatives. The Panel expects that PNG will consult with all stakeholders and consider their concerns, modify their proposal(s) where appropriate and necessary, and re-evaluate their alternatives based on the consultation feedback. In any event, the Panel requests PNG to provide an update on the status and timing of any such future applications in the next RRA which PNG expects to file by the end of November 2022.
The Panel appreciates the suggestions made by BCOAPO regarding the need for PNG-West to develop a strategic plan that includes, among other things, a long-term scenario analysis, a financial evaluation of uncertainties, and a multi-year plan for OMA&G expenses, capital expenditures, and deferral accounts. However, the Panel finds that requiring PNG-West to undertake these tasks would be onerous from both perspectives of time and money, and agrees with PNG-West that even large utilities would find it difficult to carry out such a program, particularly in light of the current uncertainties that PNG-West is facing with respect to the outlook for the Reactivation Project and the impact of decarbonization and electrification policies on the future of natural gas in British Columbia.
Dated at the City of Vancouver, in the Province of British Columbia, this 11th day of October 2022.
Original signed by:
____________________________________
A. K. Fung, KC
Panel Chair / Commissioner
Original signed by:
____________________________________
A. C. Dennier
Commissioner
Original signed by:
____________________________________
B. A. Magnan
Commissioner
Pacific Northern Gas Ltd.
2022 Revenue Requirements Application
for the PNG-West Division
Glossary and List of Acronyms
| Acronym |
Description |
| 2019 UAF Review Report |
Compliance Filing of 2019 UAF Review Reports dated December 30, 2020 pursuant to Directive 11 of Order G-255-20 |
| AACE |
Association for the Advancement of Cost Engineering |
| Application |
PNG-West’s Amended 2022 RRA dated March 7, 2022 |
| ATCO Decision |
ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board) |
| BCOAPO |
British Columbia Old Age Pensioner’s Organization, Active Support Against Poverty, Council of Senior Citizen’s Organizations of BC, Disability Alliance BC, and Tenants Resource and Advisory Center, known collectively as BCOAPO et al. |
| BCOGC |
BC Oil and Gas Commission |
| BCOGC Order |
BCOGC General Order 2021-0115-01 |
| BCUC |
British Columbia Utilities Commission |
| CCA |
Capital Cost Allowance |
| CIS |
Customer Information System |
| CPCN |
Certificate of Public Convenience and Necessity |
| CSA |
Canadian Standards Association |
| D&O |
Directors’ and Officers’ |
| DC |
Dawson Creek |
| Decision 2020–2021 |
PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20 |
| Decision 2021 amount |
The 2021 BCUC-approved amount in the PNG-West 2020-2021 RRA Decision and accompanying Order G-255-20 |
| DEF |
High resolution deformation |
| EMAT |
Electromagnetic acoustic transducer |
| ESG |
Environmental, Social and Governance |
| FSJ |
Fort St. John |
| FTE |
Full-time equivalent |
| GCVA |
Gas Cost Variance Account |
| GJ |
|
| GST |
Goods and services tax |
| IFRS |
International Financial Reporting Standards |
| ILI |
In-line inspection |
| IMU |
Inertial movement unit |
| IR |
Information request |
| LVIDA |
Large Volume Industrial Deferral Account |
| MFL |
Magnetic flux leakage |
| OMA&G |
Operating, maintenance and administrative & general |
| Original Application |
PNG-West’s 2022 RRA dated November 30, 2021, seeking, among other things, approval to amend its delivery rates and Revenue Stabilization Adjustment Mechanism rate rider on an interim and refundable/recoverable basis, effective January 1, 2022 |
| PELNG |
Port Edward LNG |
| PNG |
Pacific Northern Gas Ltd. |
| PNG(NE) |
Pacific Northern Gas (N.E.) Ltd. |
| PNG(NE) 2020–2021 RRA decision |
Order G-263-20 and accompanying decision on the PNG(NE) 2020–2021 RRA dated October 21, 2020 |
| PNG-West |
PNG-West Division |
| Q3 |
Third quarter of the fiscal year |
| RCIA |
Residential Consumer Intervener Association |
| Reactivation Project |
Western Transmission Gas System Reactivation and Recommissioning Project |
| RECAP |
Reactivated Capacity Allocation Process |
| RRA |
Revenue Requirements Application |
| RS 80 |
Rate Schedule 80 or Large Volume Industrial Transportation Rate |
| RSAM |
Revenue Stabilization Adjustment Mechanism |
| SAP |
Systems Applications and Products |
| “Test Period” or “Test Year” |
PNG-West’s fiscal year 2022 |
| Top Speed Energy |
Top Speed Energy Canada Holdings Ltd. |
| TR |
Tumbler Ridge |
| TSU |
TriSummit Utilities Inc. |
| UAF |
Unaccounted for gas |
| UCA |
Utilities Commission Act |
| US GAAP |
United States Generally Accepted Accounting Principles |
| WACD |
Weighted average cost of debt |
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
Pacific Northern Gas Ltd. (West)
2022 Revenue Requirements
EXHIBIT LIST
Exhibit No. Description
Commission documents
| A-1 |
Letter dated December 8, 2021 – BCUC appointing the Panel for the review of Pacific Northern Gas Ltd. West Division 2022 Revenue Requirements
|
| A-2 |
Letter dated December 16, 2021 – BCUC Order G-378-21 establishing a regulatory timetable |
| A-3 |
Letter dated February 28, 2022 – BCUC Order G-57-22 amending the regulatory timetable |
| A-4 |
Letter dated April 4, 2022 – BCUC Information Request No. 1 |
| A-5 |
CONFIDENTIAL – Letter dated April 4, 2022 – BCUC Confidential Information Request No. 1 |
| A-6 |
Letter dated May 11, 2022 - BCUC response to PNG West proposed date change to file responses to RCIA Confidential Information Request No. 1 |
| A-7 |
Letter dated May 24, 2022 – BCUC Information Request No. 2 |
| A-8 |
CONFIDENTIAL – Letter dated May 24, 2022 – BCUC Confidential Information Request No. 2 |
| A-9 |
Letter dated June 20, 2022 – BCUC Order G-169-22 amending the regulatory timetable |
| A-10 |
Letter dated June 20, 2022 – BCUC Information Request No. 3 to PNG-West |
Commission Staff documents
| A2-1 |
Letter dated April 4, 2022 – BCUC Staff submitting PNG 2019 UAF Review Reports dated December 30, 2020 |
Applicant documents
| B-1 |
Pacific Northern Gas Ltd. (West) [PNG (West)] - 2022 Revenue Requirements dated November 30, 2021
|
| B-1-1 |
CONFIDENTIAL – PNG West 2022 Revenue Requirements Confidential Appendices dated November 30, 2021
|
| Letter dated December 21, 2021 – PNG West submitting errata to 2022 Revenue Requirements Application
|
|
| Letter dated February 7, 2022 – PNG West submitting compliance with G-378-21 notifications
|
|
| B-3 |
Letter dated February 25, 2022 – PNG West submitting request for amendment to the regulatory timetable
|
| B-4 |
Letter dated March 7, 2022 – PNG West submitting Amended 2022 Revenue Requirements Application (RRA)
|
| B-4-1 |
CONFIDENTIAL - Letter dated March 7, 2022 – PNG West submitting Confidential Appendix C to Amended 2022 RRA
|
| B-4-2 |
CONFIDENTIAL - Letter dated March 7, 2022 – PNG West submitting Confidential Appendix D to Amended 2022 RRA
|
| B-4-3 |
CONFIDENTIAL - Letter dated March 7, 2022 – PNG West submitting Confidential Appendix G to Amended 2022 RRA
|
| B-5 |
Letter dated April 27, 2022 – PNG West submitting responses to BCUC Information Request No. 1
|
| B-5-1 |
CONFIDENTIAL - Letter dated April 27, 2022 – PNG West submitting confidential responses to BCUC Information Request No. 1
|
| B-6 |
Letter dated April 27, 2022 – PNG West submitting public responses to BCUC Confidential Information Request No. 1
|
| B-7 |
Letter dated April 27, 2022 – PNG West submitting responses to BCOAPO Information Request No. 1
|
| B-8 |
Letter dated April 27, 2022 – PNG West submitting responses to RCIA Information Request No. 1
|
| B-8-1 |
CONFIDENTIAL - Letter dated April 27, 2022 – PNG West submitting confidential responses to RCIA Information Request No. 1
|
| B-9 |
CONFIDENTIAL - Letter dated May 16, 2022 – PNG West submitting responses to RCIA confidential Information Request No. 1
|
| B-10 |
Letter dated June 9, 2022 – PNG West submitting responses to BCUC Information Request No. 2
|
| B-11 |
CONFIDENTIAL - Letter dated June 9, 2022 – PNG West submitting confidential responses to BCUC Confidential Information Request No. 2
|
| B-11-1 |
Letter dated June 9, 2022 – PNG West submitting public responses to BCUC Confidential Information Request No. 2
|
| B-12 |
Letter dated June 9, 2022 – PNG West submitting responses to BCOAPO Information Request No. 2
|
| B-13 |
Letter dated June 9, 2022 – PNG West submitting responses to RCIA Information Request No. 2
|
| B-14 |
Letter dated June 27, 2022 – PNG West submitting responses to BCUC Information Request No. 3 |
Intervener documents
| C1-1 |
BC Old Age Pensioners’ Organization, Active Support Against Poverty, Council of Senior Citizens’ Organizations of BC, Disability Alliance BC, Tenants Resource and Advisory Centre, and Together Against Poverty Society, known collectively in regulatory processes as “BCOAPO et al.” (BCOAPO et al) - Letter dated January 22, 2022 - Request for Intervener Status by Leigha Worth, Kristin Barham, Darren Rainkie and Kelly Derksen |
| C1-2 |
Letter dated April 11, 2022 – BCOAPO submitting Information Request No. 1 to PNG West
|
| C1-3 |
Letter dated May 24, 2022 – BCOAPO submitting Information Request No. 2 to PNG West
|
| C2-1 |
Residential Consumer Intervener Association (RCIA) - Letter dated January 31, 2022 - Request for Intervener Status by Samual Mason |
| C2-2 |
Letter dated April 5, 2022 – RCIA submitting Confidentiality Declaration and Undertakings |
| C2-3 |
Letter dated April 11, 2022 – RCIA submitting Information Request No. 1 to PNG West
|
| C2-3-1 |
CONFIDENTIAL - Letter dated April 11, 2022 – RCIA submitting confidential Information Request No. 1 to PNG West
|
| C2-4 |
Letter dated May 24, 2022 – RCIA submitting Information Request No. 2 to PNG West
|
Interested party documents
| D-1 |
FortisBC Energy Inc. (FEI) - Submission dated January 13, 2022 request for Interested Party Status |
Letters of comment
| E-1 |
Village of Granisle (Granisle) – Letter of Comment dated January 24, 2022 |
| E-2 |
Rustad, J. MLA Nechako Lakes (Rustad-MLA) – Letter of Comment dated February 8, 2022 |
[1] Exhibit B-4, Section 1.1, p. 2.
[2] Exhibit B-4, Section 1.4, pp. 13–14.
[3] PNG-West Final Argument, Section 5, p. 8.
[4] Exhibit B-10, BCUC IR 104.2; PNG-West Final Argument, Section 13.5, pp. 24–25.
[5] Reactivated Capacity Allocation Process.
[6] Customer Information System.
[7] Systems Applications and Products.
[8] Exhibit B-4, Section 1.1, p. 2.
[9] Exhibit B-4, Section 1.1, p. 2.
[10] Exhibit B-4, Section 1.1, p. 3.
[11] Exhibit B-4, Section 1, p. 1.
[12] Order G-169-22.
[13] PNG-West Final Argument, Section 2, pp. 3–5.
[14] Exhibit B-4, Section 1.4, pp. 13–14; The adjustments identified during this proceeding are summarized in section 5 of PNG-West’s Final Argument.
[15] PNG-West Final Argument, Section 2, pp. 3–5 and Section 4, p. 7.
[16] Exhibit B-4, Section 2.9, Table 29, pp. 71, 75.
[17] Reactivated Capacity Allocation Process.
[18] Exhibit B-4, Section 2.9, Table 29, p. 71.
[19] Customer Information System.
[20] Systems Applications and Products.
[21] Exhibit B-4, Section 2.9, Table 29, p. 71.
[22] Exhibit B-4, Section 2, Table 6, p. 23. “Decision 2021 amount” refers to the 2021 BCUC-approved amount in the PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20.
[23] PNG-West Final Argument, Section 5, p. 8.
[24] Exhibit B-4, Section 2.6, p. 67.
[25] Exhibit B-4, pp. 39, 50, 52, 67.
[26] Exhibit B-4, Section 2.3, p. 39; Exhibit B-5, BCUC IR 15.1 (line 685 – General Operations and line 711/713/714 – Customer Care).
[27] Exhibit B-4, Section 2.5, p. 52; Exhibit B-5, BCUC IR 27.1 (line 721 – Administration and line 728 – General).
[28] Exhibit B-4, Section 2.11, p. 81.
[29] PNG-West Final Argument, p. 6.
[30] PNG-West Final Argument, p. 10.
[31] PNG-West Final Argument, p. 11.
[32] PNG-West Final Argument, p. 10; Exhibit B-5, BCUC IR 16.1.
[33] PNG-West Final Argument, p. 11.
[34] Exhibit B-5, BCUC IR 22.2.
[35] Exhibit B-5, BCUC IR 22.3.
[36] Exhibit B-4, p. 46.
[37] Exhibit B-4, p. 47.
[38] Exhibit B-5, BCUC IR 16.3.
[39] Exhibit B-10, BCUC IR 92.4.
[40] RCIA Final Argument, p. 7.
[41] RCIA Final Argument, p. 8.
[42] PNG-West Reply Argument, p. 11.
[43] PNG-West Reply Argument, p. 11.
[44] PNG-West Final Argument, p. 12.
[45] Exhibit B-5, BCUC IR 16.3.
[46] Exhibit B-5 BCUC IR 18.2.
[47] Exhibit B-10, BCUC IR 92.3.
[48] Exhibit B-4, Section 2.3.5, p. 46.
[49] Exhibit B-10, BCUC IR 92.3.
[50] Exhibit B-5, BCUC IR 23.3.1.
[51] PNG-West Final Argument, p. 12.
[52] PNG-West Final Argument, pp. 13–17.
[53] BCOAPO Final Argument, pp. 6, 17.
[54] BCOAPO Final Argument, p. 16.
[55] BCOAPO Final Argument, p. 15.
[56] BCOAPO Final Argument, p. 15.
[57] BCOAPO Final Argument, p. 16.
[58] BCOAPO Final Argument, pp. 16–17.
[59] PNG-West Reply Argument, p. 7.
[60] PNG-West Reply Argument, p. 7.
[61] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20.
[62] The full amount deferred in 2021 is $1.1 million on a consolidated basis (calculated by BCUC staff based on the 2021 deferred amounts for each of the PNG divisions (PNG-West; PNG(NE) FSJ/DC; PNG(NE) TR as illustrated below):
(i) PNG-West: $703,000 (Exhibit B-4, Tab 2, p. 16);
(ii) PNG(NE) FSJ/DC: 372,000 (PNG(NE) 2022 RRA proceeding, Exhibit B-5 FSJ/DC Division, Tab 2, p. 11); and
(iii) PNG(NE) TR: 25,000 (PNG(NE) 2022 RRA proceeding, Exhibit B-5 TR Division, Tab 2, p. 11).
[63] Exhibit B-5, BCUC IR 36.4.
[64] Exhibit B-4, Section 2.5.1, p. 53. Decision 2021 amount refers to the 2021 BCUC-approved amount in the PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20.
[65] Exhibit B-4, Section 2.5.7.1, p. 63.
[66] PNG-West Final Argument, Section 9.1, para. 46, p. 16.
[67] Exhibit B-5, BCUC IR 36.1.
[68] Exhibit B-4, Section 2.5.1, pp. 53–54; PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 3.3.1, Table 5,
p. 25; PNG(NE) 2022 RRA Proceeding, Exhibit B-5, FSJ/DC Division, Section 2.5.8, p. 38, Exhibit B-5, TR Division, Section 2.5.8, p. 36.
[69] Exhibit B-5, BCUC IR 36.4.
[70] Exhibit B-4, Section 2.5, Table 19, p. 52, Section 2.5.1, Table 20, p. 53.
[71] Exhibit B-4, Section 2.5.1, p. 53.
[72] Exhibit B-5, BCUC IR 36.2; Exhibit B-10, BCUC IR 96.10; Exhibit B-14, BCUC IR 119.1.
[73] For annual periods beginning on or after January 1, 2015, rate-regulated entities that are Canadian publicly accountable enterprises and are not dual listed (i.e. Canadian entities also registered with the US Securities Exchange Commission), are required to apply IFRS Standards, however temporary relief is available from the Canadian securities regulators. Several of these investor-owned entities apply US GAAP in order accurately reflect the economics of their rate regulated business. Reference: Canadian Accounting Standards Board, Rate Regulated Activities Research Paper dated November 2018, pp. 9–11, para. 25 and 28.
[74] Exhibit B-5, BCUC IR 36.1; Exhibit B-10, BCUC IR 96.3.
[75] Employee costs include salaries, benefits, office costs, IT costs and travel and training costs. Also included in Employee costs are the True-up category represents the timing and accrual differences related to when TSU incurs the costs and when the subsidiaries are billed for the costs and are predominantly related to employee costs. PNG states that although the True-Up (Timing) category is a consolidation of all TSU Corporate Shared Services Costs, many of the costs are Employee costs therefore it is reasonable to combine these two categories.
[76] Exhibit B-4, Section 2.5.1, p. 53; the difference between 2021 actual and 2022 forecast was calculated by BCUC staff.
[77] Exhibit B-14, BCUC IR 119.1.
[78] Exhibit B-5, BCUC IR 36.1.1 and Exhibit B-10, BCUC IR 96.6.
[79] Exhibit B-10, BCUC IR 96.6.
[80] Exhibit B-10, BCUC IR 96.7.
[81] Exhibit B-5, BCUC IR 36.2; Exhibit B-14, BCUC IR 119.5.
[82] Exhibit B-10, BCUC IR 96.1.
[83] Exhibit B-10, BCUC IR 96.1; Exhibit B-14, BCUC IR 119.2.
[84] Exhibit B-10, BCUC IR 96.1.
[85] Exhibit B-10, BCUC IR 96.1.
[86] Exhibit B-5, BCUC IR 49.3; Exhibit B-14, BCUC IR 119.5.
[87] Exhibit B-5, BCUC IR 36.2; Exhibit B-10, BCUC IR 96.1; Exhibit B-4, BCUC IR 119.5.
[88] Exhibit B-4, Section 2.13.1.2, p. 91.
[89] Exhibit B-4, Appendix F, p. 8.
[90] Exhibit B-4, Section 1.2.2, p. 6.
[91] Exhibit B-4, Section 1.2.2, p. 6.
[92] Exhibit B-5, BCUC IR 55.9.1.
[93] Exhibit B-4, Section 1.2.2, p. 6.
[94] Exhibit B-4, Section 1.2.2, p. 6.
[95] RCIA Final Argument, Section 2.5.5, p. 22.
[96] Exhibit B-4, Section 2.13.1.2, p. 94.
[97] Exhibit B-5, IR 55.14.
[98] Exhibit B-5, IR 55.16.3.
[99] Exhibit B-10, BCUC IR 109.1.2.
[100] Exhibit B-10, BCUC IR 109.1.2.
[101] Exhibit B-4, Section 2.13.1.2, p. 97.
[102] Electromagnetic acoustic transducer (EMAT), magnetic flux leakage (MFL), high resolution deformation (DEF), Inertial movement unit (IMU).
[103] Exhibit B-5, BCUC IR 66.6.
[104] Exhibit B-5, BCUC IR 66.5.
[105] Exhibit B-4, Section 2.13.1.2, p. 91.
[106] Exhibit B-10, IR 107.1.3.
[107] Exhibit B-5, BCUC IR 55.22.
[108] RCIA Final Argument, Section 2.5.5, p. 22.
[109] BCOAPO Final Argument, p. 6.
[110] Ibid., p. 19.
[111] Ibid., p. 20.
[112] Ibid., p. 20.
[113] PNG-West Reply Argument, Section 2.4, para 26.
[114] Ibid., para 29.
[115] Exhibit B-4, Section 2.13.1.2, p. 101.
[116] Exhibit B-4, Section 2.13.1.2, p. 91.
[117] Exhibit B-6, BCUC IR 1.2; Exhibit B-10, BCUC IR 104.2.
[118] Exhibit B-6, BCUC IR 1.2; Exhibit B-10, BCUC IR 104.2; PNG-West Final Argument, p. 30.
[119] Exhibit B-10, BCUC IR 104.1.
[120] RCIA Final Argument, Section 2.5.3, p. 20.
[121] BCOAPO Final Argument, p. 6.
[122] Exhibit B-4, Section 2.13.1.2, p. 102.
[123] Exhibit B-4, Section 2.13.1.2, p. 102; PNG-West Final Argument, Section 14.1.3, p. 30.
[124] Exhibit B-10, BCUC IR 104.2.
[125] Exhibit B-10, BCUC IR 104.2, PNG-West Final Argument, Section 14.1.3, pp. 30–31.
[126] Decision and Order C-5-21 dated November 30, 2021, p. 31.
[127] Exhibit B-5, BCUC IR 2.9; Exhibit B-10, BCUC IR 84.1.
[128] RCIA Final Argument, Section 2.5.4, pp. 20–21.
[129] RCIA Final Argument, pp. 27, 30.
[130] RCIA Final Argument, p. 29.
[131] PNG-West Reply Argument, p. 14.
[132] Exhibit B-10, BCUC IR 84.1.
[133] Order C-5-21 and Accompanying Decision, Directive 15 on the Summary of Approvals and Directives Table in Section 10.0 of the Decision.
[134] Order G-174-08.
[135] Exhibit B-4, Section 2.9, p. 77.
[136] Exhibit B-4, Section 1.3, p. 10, Section 2.9, p. 77.
[137] Pacific Northern Gas Ltd. 2018-2019 RRA, Order G-151-18 and Decision dated August 15, 2018, pp. 30–31.
[138] Exhibit B-4, Section 1.3, p. 11; PNG-West Final Argument, Section 13.5, p. 24.
[139] PNG-West Final Argument, Section 5, p. 8.
[140] Exhibit B-10, BCUC IR 104.2; PNG-West Final Argument, Section 13.5, pp. 24–25.
[141] Exhibit B-10, BCUC IR 100.1; PNG-West Final Argument, Section 13.5, p. 25.
[142] RCIA Final Argument, Section 2.4.6, p. 15.
[143] Exhibit B-4, Attachment – Tab Schedules, Tab 5, p. 1.
[144] Exhibit B-4, Section 2.9, p. 79; Order G-146-20 and G-147-20.
[145] Exhibit B-5, BCUC IR 49.5.
[146] Order G-21-22.
[147] Exhibit B-4, Section 2.9, p. 79.
[148] Exhibit B-5, BCUC IR 49.2.
[149] Exhibit B-5, BCUC IR 49.1.
[150] Exhibit B-5, BCUC IR 49.1.
[151] Exhibit B-4, Section 2.9, p. 79.
[152] Exhibit B-5, BCUC IR 49.1.
[153] Exhibit B-5, BCUC IR 49.1 and 49.3.
[154] Exhibit B-5, BCUC IR 49.7, Exhibit B-10, BCUC IR 103.3.
[155] RCIA Final Argument, Section 2.4.4, p. 12, Section 3, p. 29.
[156] Order G-35-20, as amended by Order G-237-21.
[157] Decision and Order C-5-21 dated November 30, 2021, p. 39.
[158] Exhibit B-4, Section 2.9, p. 77; PNG-West Final Argument, Section 13.1.1, p. 20.
[159] Exhibit B-4, Section 2.9, p. 76.
[160] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20; Section 5.2, p. 46; Exhibit B-5, BCUC IR 37.4.
[161] Exhibit B-4, Section 2.9, p. 76, Tab 2, p. 17; Exhibit B-5, BCUC IR 37.4; PNG-West Final Argument, Section 2, p. 4.
[162] That is the Incremental CCA, CIS Project Recoveries, and the Shared Corporate Services Costs Variance deferral accounts. The interest to be captured in the RECAP Deferred Demand Charges deferral account was originally planned to be captured in the LVIDA, which is discussed further in section 4.5.2 of this decision.
[163] Exhibit B-5, BCUC IR 43.5.
[164] Exhibit B-5, BCUC IR 43.10; PNG-West Reply Argument, Section 3.2.2, p. 12.
[165] PNG-West Final Argument, p. 21.
[166] Exhibit B-5, BCUC IR 43.1 and 43.4.
[167] PNG-West Final Argument, p. 21; Exhibit B-4, Section 2.9, p. 75.
[168] Exhibit B-5, BCUC IR 43.7 and 44.1.
[169] Exhibit B-10, BCUC IR 98.1.
[170] Exhibit B-4, Section 2.9, p. 74.
[171] Exhibit B-5, BCUC IR 44.3.
[172] RCIA Final Argument, Section 2.4.1, pp. 9–10.
[173] ATCO Gas &Pipelines Ltd. V. Alberta (Energy & Utilities Board), 2006 SCC 4 (CanLII), [2006] 1 SCT 140, para. 71.
[174] Creative Energy Vancouver Platforms Inc. 2019–2020 RRA for the Core Steam System and Northeast False Creek Service Areas, Decision and Order G-227-20, p. 39.
[175] PNG-West 2018–2019 RRA Decision and Order G-151-18, Section 5.3, pp. 30–31.
[176] Exhibit B-5, BCUC IR 43.1 and 43.4.
[177] Exhibit B-5, BCUC IR 43.7; Exhibit B-4, p. 75 and Tab Schedules – Tab 2, pp. 16–17; this reflects credit additions of $1,449,000 in 2021 plus interest accrued.
[178] PNG-West Final Argument, p. 22.
[179] Exhibit B-4, Section 2.9, p. 78; Exhibit B-5, BCUC IR 46.3 and 46.4.
[180] Exhibit B-5, BCUC IR 43.4 and 46.1.
[181] Exhibit B-5, BCUC IR 43.7.
[182] Exhibit B-5, BCUC IR 43.3.
[183] Exhibit B-11-1, BCUC Confidential IR 2.1 (public response).
[184] Exhibit B-4, Section 2.9, Table 29, p. 71 and p. 79; PNG-West Final Argument, Section 13.2.3, p. 22.
[185] Exhibit B-5, BCUC IR 43.2.
[186] Exhibit B-5, BCUC IR 43.2 and 43.3.
[187] Exhibit B-5, BCUC IR 43.7.
[188] RCIA Final Argument, Section 2.4.2, p. 11.
[189] RCIA Final Argument, Section 2.4.2, p. 10.
[190] Exhibit B-9, Section 2.9, p. 79.
[191] Exhibit B-10, BCUC IR 102.2.
[192] Exhibit B-5, BCUC IR 48.1.
[193] Exhibit B-5, BCUC IR 43.2.
[194] Exhibit B-5, BCUC IR 48.2 and 48.2.2.
[195] Exhibit B-5, BCUC IR 43.5.
[196] Exhibit B-5, BCUC IR 43.7.
[197] RCIA Argument, Section 2.4.3, p. 12.
[198] PNG-West Final Argument, Section 5, p. 8.
[199] American Gas Association, Glossary, retrieved on October 7,2022 from: https://www.aga.org/natural-gas/glossary/u/
[200] Exhibit B-4, Section 2.2.3, pp. 34, 37; Exhibit B-10, BCUC IR 88.4.
[201] Exhibit B-4, Section 2.2.3, p. 37.
[202] Exhibit B-4, Section 2.2.3, p. 37.
[203] Exhibit B-5, BCUC IR 8.11.
[204] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 5.1, p. 42.
[205] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 5.1, p. 45.
[206] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 5.1, pp. 44–45.
[207] Exhibit B-4, Section 2.2.3, p. 35; Exhibit B-5, BCUC IR Series 14.0; Exhibit B-10, BCUC IR Series 91.0.
[208] Exhibit B-5, BCUC IR 14.8.
[209] Exhibit B-10, BCUC IR 91.4.
[210] Exhibit B-10, BCUC IR91.4.
[211] Exhibit B-5, BCUC IR 14.2.
[212] Exhibit B-5, BCUC IR 14.3.
[213] Exhibit A2-1.
[214] Exhibit A2-1, Section 4, p. 11.
[215] Exhibit B-5, BCUC IR 8.2.
[216] Exhibit B-5, BCUC IR 8.8.
[217] Exhibit B-4, Section 2.2.3, p. 37.
[218] Exhibit B-5, BCUC IR 8.3.1.
[219] Exhibit B-10, BCUC IR 88.4.
[220] Exhibit B-5, BCUC IR 8.2.
[221] PNG-West Final Argument, Section 15.2, p. 33.
[222] RCIA Final Argument, Section 2.6, p. 23.
[223] Billing adjustments were made for 2020, however PNG-West is unable to make adjustments to the customer’s bill prior to 2019 due to the terms of the Gas Sales Tariff.
[224] RCIA Final Argument, Section 2.6, pp. 23–24.
[225] PNG-West Reply Argument, Section 3.5, para. 56, p. 15.
[226] Exhibit A2-1.
[227] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20.
[228] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 6.3, pp. 51–52.
[229] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 6.3, p. 52.
[230] PNG-West 2020–2021 RRA Decision and accompanying Order G-255-20, Section 6.3, p. 52.
[231] Exhibit B-4, Section 3.4.1.4.1, pp. 145–146.
[232] Exhibit B-4, Section 3.4.1.4.2, pp. 147–148.
[233] Exhibit B-5, BCUC IR 80.2.
[234] PNG-West Final Argument, Section 1, p. 1, Exhibit E-1, Exhibit E-2; PNG(NE) 2022 RRA proceeding, PNG(NE) Final Argument, Section 1, p. 1, Section 14.7, p. 28, Exhibit C1-1, Exhibit D-3-1, Exhibits E-1 to E-14.
[235] Exhibit B-4, Section 3.4.1.4.2, pp. 147–148.
[236] Exhibit B-5, BCUC IR 81.2.
[237] Exhibit B-10. BCUC IR 117.3.
[238] Exhibit B-5, BCUC IR 79.1, 79.2, 79.3, 80.3, 80.4, 80.5, 80.6, 80.7, 81.1, 81.4.1.
[239] Exhibit B-5, BCUC IR 81.7.
[240] Exhibit B-10. BCUC IR 117.4.
[241] BCOAPO Final Argument, p. 7.
[242] BCOAPO Final Argument, p. 8.
[243] BCOAPO Final Argument, pp. 8–9.
[244] BCOAPO Final Argument, p. 10.
[245] BCOAPO Final Argument, pp. 13–14.
[246] PNG-West Final Argument, p. 2, para. 16.
[247] PNG-West Final Argument, p. 3, para. 12.
[248] PNG-West Final Argument, pp. 3-4, para. 13.
[249] PNG-West Reply Argument, Section 2.1, p. 3.
[250] PNG-West Reply Argument, Section 2.2, p. 5.
[251] PNG-West Reply Argument, Section 2.5, p. 9.
[252] RCIA Final Argument, Section 2.9.1, p. 28.