TABLE OF CONTENTS

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1.0          Introduction. 1

1.1          The Applicant. 1

1.2          Key Issues. 1

1.3          Organization of the Decision. 2

1.4          Background. 2

1.5          Legislative Authority. 3

1.6          Regulatory Process and Participants. 3

2.0          Setting 2019 Rates for the Core Steam System.. 4

2.1          Background. 4

2.2          Creative Energy’s Proposal for 2019 Rates. 6

3.0          Setting 2020 Rates for the Core Steam System.. 16

3.1          2020 Proposed Revenue Requirement. 16

3.2          Deferral Accounts. 27

3.2.1          Water Cost Deferral Account. 28

3.2.2          Property Tax Deferral Account. 29

3.2.3          Third Party Regulatory Costs Deferral Account. 30

3.2.4          Pension Expense Deferral Account. 31

3.2.5          DARR Mechanism.. 32

3.3          Proposals regarding the Fuel Switch Study and LTRP Deferral Account. 34

3.3.1          Background. 34

3.3.2          Creative Energy’s Proposal 36

3.3.3          Discussion of the Issues. 38

3.4          Setting 2020 Steam Rates. 41

4.0          Setting 2019 Rates for NEFC. 41

4.1          NEFC Hot Water Rates. 41

4.2          Underreporting of PARQ Hot Water Plant Steam Meter. 44

5.0          Setting 2020 Rates for NEFC. 47

5.1          2020 Hot Water Rates. 47

5.2          Proposed Fuel Cost Adjustment Charge Rate Rider. 51

6.0          Additional BCUC Directives and Recommendations. 53

6.1          Historical Pension Accounting Discrepancies. 53

6.2          Panel Recommendations for Future Filings. 55

7.0          Summary of Approvals and Directives. 57

COMMISSION ORDER G-227-20

APPENDIX A     List of Acronyms

APPENDIX B     Exhibit List           

 

 

 

Executive Summary

 

On December 19, 2019, Creative Energy Vancouver Platforms Inc. (Creative Energy) filed its 2019-2020 Revenue Requirements Application (RRA) with the British Columbia Utilities Commission (BCUC) seeking approval to establish permanent rates for 2019 and 2020 for its core steam system (Core Steam System) and Northeast False Creek (NEFC) service areas (Application).

Rates for the Core Steam System and NEFC are currently set on an interim basis for 2019 and 2020. For the Core Steam System, rates (Steam Rates) have been established under a traditional cost of service approach to utility rate setting. For the NEFC, rates (Hot Water Rates) have been established at a levelized rate to recover the costs incurred to install the required infrastructure to serve NEFC customer load while recognizing the revenues from the buildout of that load over time.

As part of this Application, Creative Energy has also applied for related approvals in connection with setting rates, including but not limited to, approval to:

i)                    Establish or continue certain deferral accounts;

ii)                   Establish a rate rider mechanism to recover variances in specified deferral accounts from Core Steam System customers; and

iii)                 Charge NEFC customers a Fuel Cost Adjustment Charge Rate Rider. Creative Energy also seeks BCUC approval of requests related to expenses which have been captured in its Fuel Switch Study and Long-Term Resource Plan (LTRP) Deferral Account.

Key issues

With regards to the Core Steam System and NEFC, the Panel identified the following key issues:

•         Considering whether the use of 2019 actual results for the proposed revenue requirement is appropriate within the context of the rate setting background for the Core Steam System and NEFC, and how variances recorded in various deferral accounts should be treated.

•         Assessing whether the additional steam supplied by the Core Steam System to NEFC at the PARQ Hot Water Plant meter, which was underreporting, should be recognised, and if so, how and when it should be recognised.

•         Determining whether the forecast revenue requirements and forecast load and revenues for the Core Steam System and NEFC are reasonable.

•         Evaluating whether a Deferral Account Rate Rider (DARR) mechanism is appropriate to recover variances captured in certain deferral accounts for the Core Steam System, and if so, the appropriate level of that rate rider for this test period.

•         Reviewing whether the expenses captured in the Fuel Switch Study and LTRP Deferral Account appropriately relate to the Fuel Switch Study and LTRP and determine how much, if anything, should be recovered from Core Steam System customers.

•         Reviewing the treatment of NEFC’s fuel costs and determining if it is appropriate to recover directly from NEFC customers those amounts approved to be recovered from steam customers through a Fuel Cost Adjustment Charge (FCAC) Rate Rider.

 

 

 

2019 Rates for the Core Steam System

 

Creative Energy’s 2019 interim Steam Rates for the Core Steam System (which are maintained at 2018 Steam Rates) are approved as permanent. In general, the Panel does not agree that it is appropriate to set utility rates based on hindsight, using actual results. Rates should be set prospectively based on a reasonable forecast and the utility should be held accountable for its forecast with the exception of those revenue requirement items that the BCUC approves as being appropriate for deferral treatment. The Panel finds it appropriate to maintain the BCUC-approved 2018 Steam Rates and approved forecast for 2018 for setting 2019 permanent rates, including the continuation of variance treatment for Regulatory Costs and Pension Expense. Based on the BCUC’s previous determinations, Creative Energy is also directed to reduce its allowed return for 2019 by $14,862 as it relates to the After-tax Regulatory Pension Asset Account.

 

2020 Rates for the Core Steam System

 

Creative Energy’s request to increase Steam Rates by 4.2 percent, effective January 1, 2020, is denied. Instead, the Panel approves 2020 Steam Rate on a permanent basis with various adjustments.

 

The Panel finds that the inclusion of NEFC in the Massachusetts Formula cost allocation is a practical approach to estimating the NEFC’s costs in serving a separate energy system. However, Creative Energy’s proposed two-factor Massachusetts Formula is denied. Creative Energy is instead directed to use a three-factor Massachusetts Formula which reflects the industry standard.

The Panel disagrees with Creative Energy’s submissions that the proposed DARR mechanism to recover forecast variances in operating and maintenance (O&M) expenses is a “straightforward and accepted means” to recover forecast variances in O&M costs and that it supports transparency. While the Panel agrees that the Fuel Cost Stabilization Account and related rate rider mechanism are a typical and understood approach used to capture and recover fuel cost variances, there is no evidence to support such an approach for pension, regulatory and other recurring non-controllable O&M costs. Since deferral account treatment for the latter group of recurring non-controllable O&M costs is allowed, variances relating to these costs may be recovered in subsequent revenue requirements considering that these applications are filed regularly by Creative Energy.

 

Creative Energy is directed to reduce its allowed return for 2020 by $21,503 as it relates to the After-tax Regulatory Pension Asset Account pursuant to previous BCUC determinations.

 

The Panel finds that variance treatment for third-party regulatory costs and pension expense is consistent with previous BCUC decisions and approves the continuation of the TPRCDA and Pension Expense Deferral Account, respectively. However, the Panel considers that recognizing variances over a one-year period, rather than two years as proposed by Creative Energy, is more consistent with past practice and that 2018 and 2019 pension remeasurement amounts should be offset.

 

The Panel also approves the establishment of a non-rate base Water Cost Deferral Account to capture water cost forecast variances for the 2020 Test Year only and a non-rate base Property Tax Deferral Account to capture property tax forecast variances, as these were demonstrated to be primarily outside of the utility’s control and have been difficult to forecast.

 

Finally, related to expenses which have been captured in a Fuel Switch Study and LTRP Deferral Account, the Panel approves for Creative Energy to write off $103,536 from the balance in the Fuel Switch Study and LTRP Deferral Account as proposed by Creative Energy. However, the Panel denies Creative Energy’s request for approval to recover from customers of the Core Steam System the $214,185 spent in 2016 on enabling low-carbon development and to maintain a balance of $417,502 in the deferral account until such time as a Certificate of Public Convenience and Necessity for a low-carbon energy project is submitted and an assessment of how much of the balance can be capitalized can be made. The Panel finds that it would be inappropriate to allow Creative Energy to recover these costs from current or future ratepayers as this would amount to retroactive ratemaking. Instead, the Panel directs that they be written off from the balance in the Fuel Switch Study and LTRP Deferral Account and the deferral account be closed thereafter.

 

2019 Rates for NEFC

 

Creative Energy’s 2019 interim Hot Water Rates for the NEFC are approved as permanent, effective January 1, 2019. The Panel understands these rates align with the BCUC’s previous decisions, in which levelized rates were set to remain in place until commencing recovery of the RDDA in 2020. However, the Panel disagrees with the use of actuals to determine the amount of variances to be recognized in the RDDA and Variance Deferral Account for 2019, as proposed by Creative Energy. Creative Energy is directed to recalculate the allocation of variances between the approved deferral accounts based on the 2017 approved forecast.

 

With respect to underreported steam supplied by the Core Steam System to NEFC at the PARQ Hot Water Plant meter, the Panel finds that existing mechanisms apply to variances between forecast and actual Steam Service Rates and Fuel Cost charged to NEFC. The Panel notes it is Creative Energy’s preference that NEFC’s customers are not charged for the amount related to underreported steam services due to the ‘controversial impact’ of a large one-time surcharge on customers. The Panel acknowledges these concerns and finds Creative Energy’s proposal to address the matter prospectively in 2020 by recognizing additional steam in the 2020 steam load forecast and to make no adjustments for 2019 to be reasonable for the underreported steam service. However, Creative Energy is directed to account for the NEFC underreported fuel cost charges in the Core Steam System’s Fuel Cost Stabilization Account and to also record the additional fuel costs in the NEFC Variance Deferral Account.

 

2020 Rates for NEFC

 

Creative Energy’s request to increase its 2020 Hot Water Rates in the NEFC service area by 3.7 percent, is denied. Instead, the Panel approves increases to Hot Water Rates by 10 percent, effective January 1, 2020, because the balance in the RDDA now exceeds approximately $1.4 million. Creative Energy is also directed to:

•         Recalculate its Massachusetts Formula-allocated costs to the Core Steam System and NEFC, respectively; and

•         Continue utilization of its RDDA and Variance Deferral Account.

The Panel acknowledges Creative Energy’s submission that it currently does not have sufficient information to determine the longer-term levelized rate increases needed to recover the RDDA over a reasonable time frame and accepts deferring consideration of the recovery of the RDDA until 2021, as proposed by Creative Energy. Until a comprehensive rate design application is submitted, the Panel finds it appropriate to maintain the existing rate structure. Accordingly, the Panel approves the continuation of the RDDA and Variance Deferral Account for 2020 and denies the request for the proposed NEFC FCAC Rate Rider. Given the Panel’s rejection of the NEFC FCAC Rate Rider, which would have otherwise resulted in an overall rate impact of a 23.7 percent rate increase if approved, the Panel considers that an appropriate rate increase for 2020 is 10 percent. This level of increase will reduce the addition to the RDDA while keeping the rate below the level typically associated with rate shock.

1.0              Introduction

On December 19, 2019, Creative Energy Vancouver Platforms Inc. (Creative Energy) filed with the British Columbia Utilities Commission (BCUC) a 2019-2020 Revenue Requirements Application (RRA) for the core steam system (Core Steam System) and Northeast False Creek (NEFC) service areas (Application). This Application seeks approval from the BCUC to establish permanent rates for 2019 and 2020 for Creative Energy’s Core Steam and NEFC system service areas.

This document sets out the key issues to be decided by the Panel, provides an overview of the relevant evidence, considers the positions of the parties and outlines the reasons for the Panel’s decision (Decision).

1.1              The Applicant

Creative Energy is a thermal energy utility that uses gas boilers to produce steam, which is distributed to individual buildings through an underground network of distribution pipes. Creative Energy’s Core Steam System serves approximately 215 customer buildings[1] in downtown Vancouver.

The Core Steam System also supplies thermal energy to Creative Energy’s NEFC hot water system, which serves four buildings in the NEFC neighbourhood of Vancouver. The NEFC system receives steam from the Core Steam System to produce hot water. However, Creative Energy treats steam customers and hot water customers as two separate classes of service (Steam Service and NEFC Service).[2] The NEFC system is thus both a customer of the Core Steam System and a separate service area with its own BCUC-approved revenue requirements and rates for hot water service.[3]

Creative Energy is a wholly-owned subsidiary of Creative Energy Canada Platforms Corp. (Creative Energy Canada). In 2014, Creative Energy Canada acquired all the shares of Central Heat Distribution Ltd. (CHDL) with BCUC approval and renamed the company Creative Energy Vancouver Platforms Inc.[4]

Creative Energy also owns and operates several Thermal Energy Systems (TES) that are not connected to the Core Steam or NEFC systems, some of which are registered as Stream A utilities under the BCUC’s TES Regulatory Framework Guidelines[5] and some of which are regulated as Stream B TES.

1.2              Key Issues

The Panel has identified the following key issues in relation to both the Core Steam System and NEFC:

•         Considering whether the use of 2019 actual results for the proposed revenue requirement is appropriate within the context of the rate setting background for the Core Steam System and NEFC, and how variances recorded in various deferral accounts should be treated.

•         Assessing whether the additional steam supplied by the Core Steam System to NEFC at the PARQ Hot Water Plant meter, which was underreporting, should be recognised, and, if so, how and when it should be recognised.

•         Determining whether the forecast revenue requirements and forecast load and revenues for the Core Steam System and NEFC are reasonable.

•         Evaluating whether a Deferral Account Rate Rider (DARR) mechanism is appropriate to recover variances captured in certain deferral accounts for the Core Steam System, and if so, what level (DARR rate) should be set for this test period.

•         Reviewing whether the expenses captured in the Fuel Switch Study and long-term resource plan (LTRP) Deferral Account appropriately relate to the Fuel Switch Study and LTRP and determine how much, if anything, should be recovered from Core steam customers.

•         Reviewing the treatment of NEFC’s fuel costs and determining if it is appropriate to recover directly from NEFC customers those amounts approved to be recovered from steam customers through a FCAC Rate Rider.

1.3              Organization of the Decision

The remainder of this Decision provides the Panel’s approvals and determinations with respect to Creative Energy’s revenue requirements and establishes permanent rates for the Core Steam System (Steam Rates) and NEFC (Hot Water Rates) service areas for the years 2019 and 2020.

Section 2.0 of this Decision addresses issues related to setting 2019 rates for the Core Steam System.

Section 3.0 examines the issues related to setting 2020 rates for the Core Steam System, including steam load, operating and maintenance (O&M) expenses, capital additions, the After-tax Regulatory Pension Asset account and related returns, deferral accounts and proposals regarding the Fuel Switch Study and LTRP Deferral Account.

Section 4.0 focuses on the issues related to setting 2019 rates for NEFC, including the underreporting of the PARQ Hot Water Plant steam meter.

Section 5.0 addresses issues related to setting 2020 rates for NEFC, including hot water load, O&M expenses and the proposed FCAC rate rider.

 

Lastly, section 6.0 discusses additional BCUC directives and recommendations, including historical pension accounting discrepancies and Panel recommendations for future filings.

Given that Creative Energy’s proposals in this Application include differing approaches to setting rates for each year of the test period, we have organized this Decision by test year (i.e., 2019 or 2020) and service area (i.e. Core Steam System or NEFC) rather than by key issues collectively for both service areas and the entire test period.

1.4              Background

The BCUC has historically established Creative Energy’s Steam Rates according to a traditional cost of service approach to utility rate setting for a considerable time.[6]  In 2017, Creative Energy applied for a multi-year index based ratemaking mechanism for the 2018-2022 period. After an 11-month long proceeding, the BCUC denied Creative Energy’s multi-year application on the basis that Creative Energy’s proposed mechanism had not been adequately designed and sufficiently thought through to persuade the BCUC that approval would be in the interests of its ratepayers. Instead, the BCUC approved permanent 2018 Steam Rates.[7]

On December 14, 2018, Creative Energy applied to the BCUC for approval to set interim 2019 Steam Rates. In that application, Creative Energy requested approval to maintain Steam Rates at existing 2018 rates on an interim basis, effective January 1, 2019. The BCUC approved Creative Energy’s proposal, with the expectation that Creative Energy was to file a permanent rate application shortly thereafter.[8]

The 2016-2017 Core Steam System and NEFC Decision[9] established the revenue requirements, rate design, and rates for the NEFC service area. This rate and rate design approval followed the BCUC’s approval of a Certificate of Public Necessity and Convenience for Creative Energy to serve new developments in the NEFC neighbourhood of the City of Vancouver.[10] NEFC rates have been established on a levelized rate design basis with the Revenue Deficiency Deferral Account (RDDA) in place to record the impact of timing differences between the costs incurred to install the required infrastructure to serve hot water load, and the revenues from the buildout of customer load over time.[11]

1.5              Legislative Authority

This Application is filed by Creative Energy, and is reviewed by the BCUC, pursuant to sections 58 to 60 of the Utilities Commission Act (UCA).  In particular, section 59(5) of the UCA defines what is an “unjust” or “unreasonable” rate while section 59(4) states that the determination of what is “unjust” or “unreasonable” is a question of fact of which the BCUC is the sole judge. Section 60 provides the BCUC the authority to establish rates and includes mandatory considerations, including the requirement that rates not be “unjust, unreasonable, unduly discriminatory or unduly preferential.”

Section 60(1)(b.1) of the UCA states that in setting a rate, the BCUC may use “any mechanism, formula or other method of setting the rate that it considers advisable, and may order that the rate derived from such a mechanism, formula or other method is to remain in effect for a specified period.” The Panel conducts its review of this Application pursuant to this legislative authority. 

1.6              Regulatory Process and Participants

By Order G-7-20A dated January 15, 2020, the BCUC established, among other things, interim rates for the Core Steam System and NEFC, a DARR of $0.29 per thousand pounds of steam for Core Steam System customers and a FCAC Rate Rider of $16.15 per megawatt hour (MWh) to NEFC customers, effective January 1, 2020, on an interim and refundable basis.

Order G-7-20A also established a regulatory timetable for the review of the Application, which included Creative Energy filing an evidentiary update and a proposal for the potential recovery of the balance in its Fuel Switch Study and LTRP Deferral Account, two rounds of information requests (IRs) by the BCUC and interveners, written final arguments and a written reply argument from Creative Energy.

The Commercial Energy Consumers Association of British Columbia (the CEC) registered and participated in the proceeding. The Panel also acknowledges FortisBC Alternative Energy Services Inc. and FortisBC Energy Inc. which registered as an intervener and interested party in the proceeding, respectively.

The regulatory timetable was amended by Orders G-29-20 and G-103-20 dated February 21, 2020 and May 1, 2020, respectively, due to two extension requests by Creative Energy.

By letter dated May 12, 2020, the Panel noted several corrections to the evidence resulting from Creative Energy’s responses to IRs, impacting various financial schedules for Core and NEFC, and requested Creative Energy to provide a summary of:

1.       Approvals sought for each of the Core and NEFC service areas; and

2.       The under-reported steam consumption at the PARQ hot water plant steam meter, including: the cause(s) of the under-reporting; impacts of the under-reported steam on the Core Steam System and NEFC’s 2019 revenue deficiency/surplus; and Creative Energy’s positions with respect to alternatives.

In addition to any other submissions, the Panel invited the parties to discuss the following factors in their final arguments:

1.       The merits of amending the Massachusetts Formula method for allocating general and administrative costs (e.g. the inclusion of NEFC and revising the number and/or type of factors applied) in this proceeding; and

2.       Whether a deferral account to capture steam load variances for the Core Steam System may be warranted considering recent variances between forecast and actual load and the ongoing COVID-19 global pandemic.

In accordance with the amended regulatory timetable established by Order G-103-20 the BCUC received written final arguments from the CEC on May 28, 2020 and Creative Energy’s written reply argument on June 4, 2020.

2.0              Setting 2019 Rates for the Core Steam System

As context for setting 2019 Steam Rates, the Panel first reviews the rate setting background for the Core Steam System. The Panel then considers Creative Energy’s proposals for 2019 Core Steam Rates, including its proposals related to 2018 amounts recorded in the Third Party Regulatory Costs Deferral Account (TPRCDA) and the Pension Expense Deferral Account, and the updates to the After-tax Regulatory Pension Asset Account and related returns.

2.1              Background

As noted above, the BCUC approved interim and refundable rates for the Core Steam System, effective January 1, 2019.[12] In that application for interim rates, Creative Energy proposed to maintain 2019 rates at the approved 2018 rates on an interim basis. While Creative Energy proposed interim rates consistent with the 2018 approved rates, it submitted that the interim revenue requirement for 2019 differed from the 2018 approved revenue requirement. These differences included an inflationary increase of 1.84 percent to certain costs and removal of the amortization expense related to specific deferral accounts. The net impact of the proposed adjustments resulted in a zero percent change in rates.[13]

 

In its approval of 2019 interim rates, the BCUC found that Creative Energy had not provided adequate evidence to support its requested interim revenue requirement for 2019 and directed Creative Energy to maintain Core Steam Rates at the existing approved rates (2018 approved rates) on an interim basis pending a full rate application for 2019 rates. While the BCUC acknowledged that Creative Energy stated in the interim rates application that it intended to file a full rate application for the Core Steam System in 2019, the BCUC stated that an interim rate application “should generally seek to maintain the status quo unless the utility is able to provide compelling evidence for changes to be made. No such evidence was provided in this case.”[14]

 

A summary of the 2018 approved revenue requirement which the BCUC used to set 2018 approved rates is as follows:

 

Table 1 – 2018 Approved Revenue Requirement^[15]

 

 

The 2018 approved load forecast used to calculate 2018 approved rates was 1,098,514 thousand pounds of steam.^[16] Additionally, in the 2018-2022 Core Steam System Decision, the BCUC approved deferral treatment for forecast variances related to regulatory costs and pension expense for 2018.^[17] 

 

The BCUC’s 2018 approval of forecast variance treatment for regulatory costs was consistent with the determinations made in the Creative Energy 2016-2017 Core Steam System and NEFC Decision in which the BCUC approved the establishment of a Third Party Regulatory Cost Deferral Account (TPRCDA). This variance account was approved with a one-year amortization period and a short-term debt carrying cost for a period of five years, at the end of which, Creative Energy would have to apply to the BCUC for renewal of the TPRCDA.[18]  Regulatory costs include third-party expenses related to regulatory filings and proceedings required under the UCA. The 2018 approved forecast for regulatory costs was $135,651.^[19]

 

The approval of deferral treatment for pension expense forecast variances in 2018 was also consistent with the BCUC’s determinations in the Creative Energy 2015-2017 Core Steam System Decision in which the BCUC approved the creation of a Pension Expense Deferral Account to capture the annual variance between forecast pension expenses recovered in rates and pension expenses reported in Creative Energy’s financial statements. This variance account was approved with a one-year amortization period and a carrying cost equal to Creative Energy’s short-term debt rate.^[20] Pension expense relates to Creative Energy’s pension plan covering all unionized employees, including plant and distribution team employees, non-unionized management and administrative staff that started working for Creative Energy before July 2018. The pension plan was closed to non-unionized staff in 2018. Required pension plan contributions are based on actual evaluations as periodically remeasured.[21] The 2018 approved forecast for pension expense was $190,284 (included in Wages and Benefits in Table 1 above).^[22]

2.2              Creative Energy’s Proposal for 2019 Rates

Use of 2019 Actual Results for Proposed Revenue Requirement

 

Creative Energy states that its proposals for permanent 2019 Core Steam System Rates are based on:

•         12 months of 2019 actual results with respect to load, O&M expenses, municipal access fees and property taxes; and

•         9 months of 2019 actual results plus 3 months of forecast information with respect to plant in service and rate base, which impact depreciation, income taxes and the return on rate base.^[23]

Using 2019 actual results, Creative Energy proposes to maintain the approved 2019 interim Core Steam Rates on a permanent basis and to add the difference  of $103,241 between its updated 2019 revenue requirement and the 2019 actual revenues collected to the TPRCDA for future recovery.^[24]  Specifically, Creative Energy proposes to recover the amount, among others, through a DARR beginning in 2020. The Panel addresses Creative Energy’s proposals with respect to the use of a DARR in subsection 3.2.5. The specific amounts recorded in the respective deferral accounts and the related amortization periods are addressed below.

 

On the use of 2019 actual results, Creative Energy states:

Although the timing of this filing for final 2019 rates is uncommon in practice before the BCUC, Creative Energy does not consider that review and approval of final 2019 rates presents any extraordinary considerations for the Panel outside of its existing mandate under the UCA to ensure that Creative Energy’s ratepayers receive safe, reliable and non-discriminatory energy services at just and reasonable rates, and that shareholders are afforded a reasonable opportunity to earn a fair return on their invested capital.^[25]

Given the timing of the Application, Creative Energy explains that it is not seeking an increase in 2019 rates, which may have otherwise been justified on the basis of recovering its updated 2019 revenue requirement.^[26] In its view, a better and far less controversial approach is to record the proposed amount to the TPRCDA in 2019 for prospective recovery.^[27] 

 

Creative Energy states that approximately 87 percent of the increase in 2019 proposed revenue requirement compared to the 2018 approved forecast relates to externally driven cost pressures largely outside of its control, as follows:[28]

• Actual regulatory costs in 2019 compared to 2018 approved forecast[29] increased by $177,349;[30] and

•         Actual water costs from the City of Vancouver increased by $193,945 in 2019 compared to the 2018 approved forecast.[31]

Creative Energy submits that the regulatory costs were reasonably incurred and required to support its applications before the BCUC as a regulated public utility under the UCA. Therefore, they ought to be recoverable.[32] However, it proposed to add only $103,241 of the $177,340 increased regulatory costs to the TPRCDA, representing the difference between Creative Energy’s updated 2019 revenue requirement and the 2019 actual revenues collected. Creative Energy explains this approach provides a beneficial sharing with customers of the higher actual load in 2019 compared to the lower load for an average year, which Creative Energy states it would have forecasted for 2019 (i.e. similar to the 2018 approved load forecast).[33] The 2019 actual steam load was 1,126,060 thousand pounds of steam.^[34]

 

2018 Regulatory and Pension Expense Variances

 

With respect to the BCUC-approved deferral treatment for any forecast variances related to regulatory costs and pension expense for 2018, Creative Energy seeks approval of: $207,659[35] to be added to the TPRCDA; and a net loss of $377,966 to be added to the Pension Expense Deferral Account, as follows:

 

 Table 2 – 2018 Pension Expense Variances[36]

 

 

Creative Energy explains that the variance between 2018 actual and approved forecast regulatory costs was primarily due to BCUC, intervenor, consulting and legal costs for the review of the Creative Energy 2018-2022 Revenue Requirements Application and BCUC fees for the Creative Energy Application for a Certificate of Public Convenience and Necessity for Beatty-Expo Plants and Reorganization (Beatty-Expo CPCN).[38] For pension-related costs, Creative Energy states that current service costs in 2018 were lower than the 2018 approved forecast. However, there was a revaluation of the pension asset resulting in a remeasurement loss of $403,700 as the return on plan asset was not sufficient to cover the interest expense on pension liability.[39]

 

In addition to the $103,241 difference between its updated 2019 revenue requirement and the 2019 actual revenues collected discussed above, Creative Energy proposes to amortize the $207,659 regulatory cost variance and the $377,966 pension expense variance, including interest, over two years to be collected from customers by way of the DARR mechanism, commencing January 1, 2020.[40] Creative Energy states that the proposed two-year amortization period achieves an overall rate impact in 2020 that is less than 10 percent. Creative Energy states that a shorter amortization period (e.g. a one-year amortization period) would result in an overall 2020 rate impact that would exceed 10 percent.[41]

 

Subsequent to filing the Application and the Evidentiary Update, Creative Energy stated that the 2019 actual pension remeasurement gain amount of $446,700 became known.[42] The following table shows a breakdown of the 2019 pension remeasurement gain and the historical gains/(losses) from 2015 to 2019. The Panel notes that the 2019 pension remeasurement gain is $446,200 in this table instead of $446,700:

 

Table 3 – 2015 to 2019 Pension Remeasurement Gains/(Losses)[43]

With respect to how the 2019 actual remeasurement gain should be treated, Creative Energy explained:

The remeasurement gain will be recorded as a reduction in the deferral account balance. The Deferral Account Rate Rider for 2020 and 2021 is currently based on the 2018 balance and the remeasurement loss from that year. Under this lagged approach, the remeasurement gain for 2019 will be refunded through the Deferral Account Rate Rider starting in 2021 and through 2022.[44]

In its final argument, Creative Energy states it would be amenable to the BCUC directing that the DARR be amended for the remeasurement gain in 2019 to remove the timing difference.[45]

 

2019 After-tax Regulatory Pension Asset Account and Related Return

Background

In addition to the Pension Expense Deferral Account, in the 2015-2017 Core Steam System Decision, the BCUC approved the establishment of a rate base mid-year After-tax Regulatory Pension Asset account and determined that the balance for 2015 was $414,012.[46] The BCUC further stated:

 

… the Panel directs that when determining the mid-year After-tax Regulatory Pension Asset in future test periods the opening balance will equal the previous year’s December 31 Pension Asset (after-tax) reported on the audited financial statements.

 

[emphasis in original]

 

The BCUC determined that the opening balance (i.e. the previous year’s December 31 Pension Asset (after-tax) reported on the audited financial statements) is then adjusted for the after-tax variance between forecast employer contributions and forecast pension expense for the test period. The mid-year amount is then determined as an average of the opening and closing balances.[47]

 

In the subsequent 2016-2017 Core Steam System and NEFC proceeding, which followed the 2015-2017 Decision approving only a one-year revenue requirement, Creative Energy explained that the After-tax Regulatory Pension Asset account balance was not updated for 2016 because the company’s financial statements were not finalized at the time that application was filed.[48]

 

For 2018, the After-Tax Regulatory Pension Asset was not addressed in the 2018-2022 Core Steam System Decision and the balance remained at $414,012 for the one-year revenue requirement that the BCUC approved.  There was no forecast amount for contributions provided in 2018 and the approved 2018 forecast pension expense was $190,284. Since Creative Energy did not forecast contributions for 2018 and did not request adjustments to the After-tax Regulatory Pension Asset, in the Panel’s view, this has the effect of setting the 2018 forecast contributions equal to the forecast pension expense. As a result, no adjustments to the After-Tax Regulatory Pension Asset were approved in the 2018-2022 Core Steam System Decision.

 

In summary, the After-tax Regulatory Pension Asset first approved by the BCUC in the 2015-2017 Core Steam System Decision remained at $414,012 for each test period from 2015 to 2018 inclusive. The regulatory asset was not updated to reflect the opening balance equal to the previous year’s December 31 Pension Asset (after-tax) reported on the audited financial statements and did not incorporate any difference between forecast pension expense and contributions for the respective test periods. Based on the BCUC directive in the 2015-2017 Core Steam System Decision, the opening balance for the After-Tax Regulatory Pension Asset for future test years should be equal to the previous year’s December 31 Pension Asset (after tax) reported on the audited financial statements. The Pension Asset (before tax) recorded in Creative Energy’s audited financial statements was $579,600 for 2017 and $367,400 for 2018.[49]

Creative Energy’s Proposal

During the IR process, Creative Energy submitted that the After-Tax Regulatory Pension Asset account should have been increasing each year based on the cash contributions made above and beyond those related to the current service costs. Using the following information, Creative Energy recalculated the additions to the deferral account as follows:

 

 

Table 4 – 2016-2019 Proposed Additions to After-tax Regulatory Pension Asset Account[50]

 

 

Using the 2015 Decision amount of $414,012 as a starting point, Creative Energy recalculated the rate base by adding the amounts in the table above to the After-tax Regulatory Pension Asset account. The recalculated mid-year balances for the year 2015 through 2019 are as follows:

 

Table 5 – 2015-2019 Proposed After-tax Regulatory Pension Asset Account Balances[51]

 

 

The difference between the new mid-year balance of $730,773 above and the $414,012 (which Creative Energy originally used in the Application) results in an incremental increase of $23,523 to the return on rate base in the 2019 test year.[52] The impact on the 2020 proposed revenue requirement is addressed in subsection 3.1.

 

Remote Metering Project

 

The Remote Metering Project is a multi-year project which will allow Creative Energy to gather real time steam consumption data from its customer buildings. Creative Energy states the availability of this data tracking will improve its billing and engineering processes, as well as allowing customers to gain insights into their energy consumption. The annual cost savings from this project are expected to be $68,065.[53] The total expected capital cost of the project, which began in 2017, is approximately $750,000.[54] Initially for 2019, Creative Energy included a $293,666 capital addition for the Remote Metering Project.[55]

 

Through subsequent information requests, Creative Energy sought to update its Application and initial responses related to the Remote Metering Project. Creative Energy confirmed that there are currently no remote metering assets in service and that costs reported in Appendix D in 2019 in the amount of $293,666 should be removed from rate base at this time.[56]

 

Creative Energy has identified two project execution risks related to the Remote Metering Project: 1) unforeseen delays in getting permission from customer buildings for utilization of their data service to transmit metered information; and 2) project cost increases related to remote metering and monitoring cabinet construction and the requirement of some installation locations to require a third-party for installation. Creative Energy states risk is considered low and mitigation measures have been initiated.[57]

Positions of the Parties

The CEC submits it is not appropriate for Creative Energy to present rates on a backwards looking basis and Creative Energy should be discouraged from operating in such a fashion because it makes the potential for rate change more difficult. The CEC submits, “…the Commission should adopt the view that where there is a rate application based on historical data, variances should favour the ratepayer.” [58]  

 

In its review of 2019 costs, the CEC recommends that the BCUC use the same caution it would normally exercise when reviewing test year figures and attribute any cost reductions to the benefit of the ratepayer. On that basis, the CEC notes that the costs incurred in 2019 appear to be “generally acceptable.” However, the amount which Creative Energy proposes to add to the TPRCDA could be reasonably denied in whole, or part, because Creative Energy did not make an effort to conduct an RRA in a timely manner and the risk should be to the shareholder. The CEC notes that Creative Energy acknowledged that the proposed addition to the TPRCDA relates to “incorporating” an allowed return on equity (ROE) of 9.5 percent into the 2019 revenue requirement.^[59] The CEC views that the TPRCDA should not have the purpose of being used for balancing the utility’s ROE.[60]

 

The CEC does not comment on the proposed addition for 2018 or change to the TPRCDA amortization period and does not raise any issues regarding the Pension Expense Deferral Account and account balances.[61]

 

The CEC does not comment on the Remote Metering project nor the After-tax Regulatory Pension Asset Account and related returns.

 

In reply to the CEC, Creative Energy states, “the costs at issue are by their nature necessarily incurred for

utility purposes and the large majority of the costs are not within management’s ability to control and therefore should not be the shareholder’s risk.” Creative Energy submits regulatory costs are undoubtedly recoverable in utility rates, and deferral account treatment of variances between forecast and actual costs is appropriate between forecast and actual costs because it is very challenging to accurately forecast these costs, utility management has limited or no ability to control variances, and the variance can be material.^[62]

 

Panel Determination

Use of 2019 Actual Results for Proposed Revenue Requirement

 

In general, the Panel does not agree that it is appropriate to set utility rates based on hindsight, using actual results. The Panel agrees with the CEC that it is not appropriate for a utility to present rates on a “backwards looking basis”. Rates should be set prospectively based on a reasonable forecast of revenue requirement items, and the utility should be held accountable for its forecast with the exception of those revenue requirement items that the regulator approves as being appropriate for deferral treatment because the items are outside the control of management or are subject to a high degree of forecast uncertainty. If rates are set based on actual results, there is no incentive for a utility to operate efficiently since it is effectively guaranteed its allowed rate of return. This is contrary to the regulatory compact under which a utility is afforded a reasonable opportunity to earn a fair return on its invested capital.

 

Furthermore, while Creative Energy’s rates were set on an interim basis, thereby alerting customers that the rates may change, the Panel agrees with the CEC that Creative Energy did not file its RRA in a timely manner. In the Panel’s view, an unreasonable amount of time (more than a year) passed between the filing for interim rates (December 14, 2018) and final rates (December 19, 2019).

 

As stated above, the Panel views that rates should not be set using actual results, so it must consider alternative bases for setting 2019 rates. The Panel notes that the BCUC found the forecast information filed in the 2019 interim rate application was not adequate for setting interim rates, and therefore, the Panel concludes this information should not be used to set permanent rates. Given that Creative Energy did not provide supportable forecasts for 2019, the Panel finds it appropriate to maintain the BCUC approved 2018 Steam System Rates and approved forecast for 2018 for setting 2019 permanent rates, including the continuation of variance treatment for Regulatory Costs and Pension Expense.

 

In making this finding, the Panel takes into consideration that the evidence indicates that maintaining the 2018 rates and underlying 2018 approved forecast provided Creative Energy with a reasonable opportunity to earn its allowed return on equity. As set out in Table 6 below, the Panel estimates that net earnings achieved based on maintaining the 2018 approved rates, which is equal to the 2019 interim rate, were sufficient to enable Creative Energy to earn its allowed return for 2019. The actual 2019 actual revenues exceed actual 2019 costs, after taking into account the Panel’s decision regarding treatment of regulatory cost and pension expense variances as set out below. For 2019, the Panel estimates that Creative Energy’s achieved rate of return on equity exceeded the allowed rate of return on equity, as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 6 – Estimated 2019 Net Earnings Compared to Allowed Equity ROE^[63]

 

For the reasons outlined above, the Panel approves the 2019 interim rates as permanent. The Panel’s decision regarding treatment of regulatory cost and pension expense forecast variances in 2019 rates is set out below.

 

Regulatory Cost Variances

 

The Panel approves the continuation of the non-rate base Third Party Regulatory Cost Deferral Account for 2019. Variance treatment for third-party regulatory costs is consistent with previous BCUC decisions, and Creative Energy has established that these costs are outside the control of Creative Energy and are difficult to estimate. Therefore, the Panel directs that the following forecast variance amounts be recognized as additions to the TPRCDA:

 

• 2018 forecast variance of $207,659 plus interest; and
• 2019 forecast variance of $177,340 plus interest.

 

Regarding Creative Energy’s request to amortize the 2018 TPRCDA balance over two years, the Panel acknowledges the variance for 2018 is significant relative to the 2018 approved forecast amount. The Panel also notes Creative Energy’s desire to maintain 2019 permanent rates at the same amount as the approved interim rates. While the Panel agrees it is reasonable to amortize this amount over two years, consistent with the Panel’s finding above that it should maintain the 2018 approved rates and forecast for 2019, including the continuation of forecast variance treatment for Regulatory Costs and Pension Expense, the Panel sees no rationale for Creative Energy’s proposal not to record any of the amortization of the 2018 TPRCDA balance in 2019. Using a two-year amortization period for the 2018 balance sufficiently moderates the impact on the 2019 revenue requirement as reflected in Table 6 above. For 2019, Creative Energy is directed to recognize amortization of 50 percent of the 2018 TPRCDA account balance or $103,830, plus interest. The amounts to be amortized for 2020 are addressed in Subsection 3.2.3.

 

Pension Expense Variances

 

The BCUC has previously approved forecast variance treatment for pension expense with a one-year amortization period and a carrying cost equal to Creative Energy’s short-term debt rate. This variance treatment recognizes that pension expense is based on many elements that are outside the control of management and that it is difficult to forecast. Creative Energy explains that pension remeasurement gains and losses cannot be forecast in advance and that the gains and losses experienced in 2018 and 2019 demonstrate the fluctuations can be significant. The Panel agrees that the continuation of deferral treatment for pension expense forecast variances is appropriate.

 

Accordingly, the Panel approves the continuation of the Pension Expense Deferral Account with a carrying cost equal to Creative Energy’s short-term debt rate, until otherwise determined by the BCUC. The Panel directs that the following forecast variance amounts be recognized as additions to the Pension Expense Deferral Account:

 

• The 2018 forecast variance of $377,966 plus interest; and
• The 2019 forecast variance, based on the 2018 approved forecast, plus interest, as set out below.

 

Table 7 – 2019 Pension Expense Variances[64]

 

The Panel is not convinced that the previously approved one-year amortization period remains appropriate for pension remeasurement gains and losses. The magnitude and volatility of the gains and losses, and the likelihood that such variances may continue in the future especially given the expected economic impacts of COVID 19, indicate that a one-year amortization period of these amounts may not be appropriate. While Creative Energy’s proposal to amortize the pension expense variances over two years has the effect of smoothing the 2018 and 2019 remeasurement impacts over a longer period, the fact that the amounts are largely offsetting will result in significant volatility of rates.

 

Creative Energy states it would be amenable to removing the timing difference by offsetting the 2018 remeasurement loss with the 2019 gain. In the Panel’s view, this approach is practical given that the amount of 2019 Pension Remeasurement gain is known. Therefore, Creative Energy is directed to record the following adjustments to the Pension Expense Deferral Account, effective 2019:

 

Table 8 – Offset of the 2018 and 2019 Remeasurement amounts[65]

 

After this adjustment, the Panel estimates that the remaining amounts in the Pension Expense Deferral Account can reasonably be amortized over a one-year period and recognized in 2019 and 2020 rates. Accordingly, Creative Energy is directed to amortize the 2018 current service costs variance of $25,735 recorded in the Pension Expense Deferral Account, plus interest, in 2019. The amounts to be amortized in 2020 are addressed in subsection 3.2.4.

 

Given the significant pension remeasurement gains and losses noted above, to assist the BCUC in determining an appropriate amortization period for Pension Expense Deferral Account in the next RRA, Creative Energy is directed to file information in the next RRA detailing how other BC and Canadian regulated utilities treat pension remeasurement gains and losses for ratemaking purposes.

 

After-tax Regulatory Pension Asset Account and Related Return

 

Based on the BCUC’s determinations in the 2015-2017 Core Steam System Decision, the Panel finds Creative Energy has not calculated the mid-year After-tax Regulatory Pension Asset Account and Related Return correctly for 2019 and 2020. Creative Energy uses the previous year’s approved mid-year balance as the opening balance instead of the previous year’s December 31 Pension Asset (after tax) reported on the audited financial statements as set out in the 2015-2017 Core Steam System Decision.

 

Updated calculations reflecting the BCUC’s determinations in the 2015-2017 Core Steam System Decision are as set out in the following tables:

Table 9 – 2019 After-tax Mid-Year Regulatory Pension Asset

 

Table 10 – Adjustment to 2019 Allowed Return

 

While Creative Energy only provides actual employer contributions for 2019, use of the actual contribution amount is appropriate in this circumstance because the employee contributions are determined based on funding requirements and are outside the control of management.

 

Creative Energy is directed to reduce the allowed return for 2019 by $14,862 based on a mid-year After-tax Regulatory Pension Asset Account balance of $362,670. The Panel’s determination of the impact on the 2020 proposed revenue requirement is addressed in subsection 3.1.

 

Remote Metering Project

 

Since the costs associated with the Remote Metering Project are not capital additions in the current test period and Creative Energy is not requesting section 44.2 UCA expenditure schedule acceptance of the project, the Panel makes no determination on the need for or the costs associated with this project. The BCUC will consider need, prudency and project execution issues if Creative Energy files an expenditure schedule for acceptance or applies to have the project costs included in rates. Accordingly, the Panel makes no determination on the Remote Metering Project or any of the costs associated with this project. Additionally, the Panel notes that Creative Energy has not requested an Allowance for Funds Used During Construction on this capital project in accordance with usual regulatory practice.

3.0              Setting 2020 Rates for the Core Steam System

To review Creative Energy’s proposals for 2020 rates for the Core Steam System, the Panel considers the following:

•         The proposed 2020 revenue requirement;

•         The deferral treatment of certain O&M expenditures and the proposal to establish a DARR to recover related variances; and

•         The proposals regarding the Fuel Switch Study and LTRP Deferral Account.

The Panel provides its overall determination on 2020 rates for the Core Steam System in subsection 3.4.

3.1              2020 Proposed Revenue Requirement

Creative Energy submits, at the time of the Application, that the outlook for 2020 operating conditions is “business as usual.” It explains that the increase in its revenue requirement is driven by increased charges and levies by governmental bodies and general inflationary cost pressures which are offset by modest expected new customer load.[66]

 

Creative Energy summarizes its proposed 2020 revenue requirement reflecting the proposed rate increase of 4.2 percent in the following table:

 

Table 11 – Proposed 2020 Revenue Requirement[67]

Creative Energy seeks approval to increase Core Steam System rates by 4.2 percent, effective January 1, 2020, and proposes to establish a new DARR, effective January 1, 2020, to recover forecast variances on certain O&M items on which it requests deferral treatment.^[68] The request for a DARR mechanism is considered in subsection 3.2.5 and the Panel’s overall determination on 2020 rates for the Core Steam System is in subsection 3.4.

 

Forecast Steam Load

 

Creative Energy seeks approval of a 2020 steam load forecast of 1,140,634 thousand pounds of steam[69] for the purpose of determining the average rate increase in the 2020 RRA test period.[70] Creative Energy explains that steam loads are the essential billing determinants for Core Steam system rate setting since all costs are recovered through the volume of steam sold to customers. In addition to its use in determining the rates for the 2020 test year, the steam load forecast is used for other ratemaking purposes, for example, forecasting the fuel charge, forecasting recovery of Fuel Cost Stabilization Account (FCSA) balances, forecasting the proposed DARR, and implementing the load variance component of the COVID-19 Deferral Account.[71] It should also be noted that the Core Steam system supplies thermal energy to the NEFC system, and therefore, the steam load consists of the load to serve both Core and NEFC customers.

 

The 2020 forecast is normalized for weather and the addition of new customer load as set out in the table below:

 

 

Table 12 – 2020 Forecast Steam Load – Existing and New[72]

 

The total 2020 steam load forecast generally consists of: (i) a base forecast of the Core component of steam load based on the 2018 approved forecast, adjusted for known customer additions; and (ii) a forecast of the NEFC steam load based on 2018 and 2019 hot water consumption (megawatt hours or MWh), adjusted for customer additions known at the time of the forecast, converted to thousand pounds of steam and adjusted for system efficiencies.[73]

 

Creative Energy noted that in the course of preparing the load forecast, it determined that the PARQ Hot Water Plant was underreporting steam flow from around March or April 2018 to March 2020. Creative Energy proposes to address this issue for the 2020 Test Year by recognizing the increased steam supplied to the NEFC system, and therefore, included a higher 2020 steam load forecast based on a calculation of steam usage at PARQ derived using the total forecast MWh of hot water consumption as detailed below.[74] The impact of the PARQ metering issue for the 2019 Test Year is discussed in subsection 4.2.

 

A more detailed account of the methodology for calculating the Core component of the steam load is as follows:[75]

1.       Core customer base load is normalized by adjusting for customer attrition, entire-year consumption, and removing customer load with unpredictable or atypical load shapes using the most recent 5 years of customer data.

2.       The normalized Core Load data set is used to calculate both a simple average and a predictive result based on a linear regression of monthly Heating Degree Days (HDD) and monthly steam load over the last 5 years, inputting the average of HDD over that period.

3.       The customer load removed in step 1 is added back to the dataset to derive the overall base load forecast.

4.       Two additional customers in July 2020 are added.

 

In addition, Creative Energy calculates the NEFC component of the steam load as follows:[76]

1.       Hot water consumption from 2018 and 2019 for existing customers is averaged.

2.       Additional load for one new customer is added scaled on the basis of its floor area compared to similar customers.

3.       The forecast hot water consumption is then adjusted for the measured efficiencies of the distribution system and hot water plants and converted from MWh to thousand pounds of steam using a conversion factor of 3.14 thousand pounds of steam per MWh.

 

Finally, the Core and NEFC components are combined for a total forecast steam load of 1,140,634 thousand pounds of steam.

 

In the previous two revenue requirement applications, Creative Energy was not amenable to establishing a deferral account to capture steam load variances. While the BCUC respected this position, it recommended that the utility consider options to more effectively manage variances within the load forecast.[77] Since the Application did not consider any options, in its letter dated May 12, 2020, the BCUC invited all parties to discuss in their final submissions whether a deferral account to capture steam load variances for the Core Steam System may be warranted in light of the evidence of recent variances between forecast and actual load and ongoing developments regarding the COVID-19 global pandemic.

 

Creative Energy’s response to this request focused on the impacts of COVID-19 and did not provide much in the way of commentary on the general issue of variances between the forecast and actual steam load.[78]

 

Creative Energy outlines that the steam load may vary plus or minus 10 percent in any given year due to the effect of temperature. Creative Energy illustrated the impacts on the revenue requirements and the requested rate increase for the 2020 Test Year under the scenarios that the steam load varies by plus or minus 10 percent, as follows:

 

Table 13 – Impact of Variations in Load[79]

 

 

Regarding COVID-19, the Application was filed prior to the emergence of the pandemic, and as such, the load forecast reflects a business-as-usual outlook in which system load was expected to remain stable for existing customers while including a modest additional steam load for new customers. However, Creative Energy confirms that its business has been affected in various ways since the onset of COVID-19 and cites unplanned costs and a decline in steam load as examples. These unexpected impacts are not accounted for within the 2020 revenue requirements or load forecast and Creative Energy has not made any amendments to its Application regarding these impacts.

 

Instead, Creative Energy stated that it will file a separate application requesting approval to establish a new deferral account to record cost of service and revenue variances that directly result from the impact of COVID-19 on Creative Energy and its customers.[80] By Order G-214-20 issued August 14, 2020, the BCUC approved such request.

 

Creative Energy submits that the 2020 load forecast should be approved as proposed on its own merits assuming that COVID-19 had not arisen. Creative Energy maintains that the forecast has been developed using existing forecasting methodologies, with minor exceptions, and is transparent. Further, Creative Energy believes that approval of the 2020 load forecast as proposed will provide the appropriate basis for comparison of the revenue loss relief that will be sought through the COVID-19 Deferral Account.[81]

 

Forecast O&M Expenses

 

Creative Energy examines its O&M expenses using five categories of cost drivers: 1) wages and benefits, including overtime and pension expense; 2) water and electricity-related expenses; 3) maintenance; 4) special services, including regulatory, audit, legal, and third-party consultant (outside services) costs; and 5) other general and administrative expenses plus sales expenses.[82]

For the Core Steam System, Creative Energy forecasts O&M expenses of $5,121,761 for 2020 compared to 2019 actuals of $4,934,103.[83] It explains that the forecast increase in O&M expenses primarily relates to union-approved wage increases of 1.8 percent and increased wages and benefits pertaining to the expected hiring of a Chief Financial Officer in early 2020, which is a role that was vacant during 2019.[84]

The Panel examines below the following issues with respect to the Core Steam System’s forecast O&M for 2020:

•         Proposed changes to the approved Massachusetts Formula methodology for allocating sales, general and administrative expenses between Creative Energy’s Core Steam System and other areas of business;

•         Forecast outside services costs; and

•         Forecast overtime expense for steam production.

Massachusetts Formula

In the 2018-2022 Core Steam System Decision, the BCUC approved the use of a Massachusetts Formula methodology for allocating sales, general and administrative expenses between the Core Steam System and Creative Energy’s other regulated TES projects, excluding the NEFC. The approved formula is based on the arithmetic average of three factors: the average net book value of capital assets or property, plant and equipment; salaries or direct labour expenses; and operating revenues.[85]

Creative Energy requests the following changes to the approved Massachusetts Formula methodology, commencing in 2020:

1.       Approval to include the NEFC in the cost allocation; and

2.       Approval to modify the Massachusetts Formula to use either:

•         Two out of the three previously approved factors only: salaries or direct labour expenses; and operating revenues (preferred approach or Option 1); or

•         Gross (undepreciated) book values of capital assets or property, plant and equipment in a continued three-factor formula including salaries or direct labour expenses and operating revenues (Option 2).[86]   

Regarding the approval, Creative Energy submits that moving to a formulaic approach to estimating NEFC’s overhead costs is consistent with how Creative Energy’s other energy systems are treated, practical, and is an improvement on how NEFC’s overhead costs are currently determined (i.e. direct allocation) for recovery in rates.[87]

Regarding its preferred approach to the modification of the Massachusetts Formula (i.e. Option 1), Creative Energy submits that the current approved three-factor Massachusetts Formula of allocating costs partly based on depreciated capital assets does not yield the most equitable results because the Core Steam System has comparatively lower embedded costs on a unit basis compared to newer systems. Therefore, while the Core Steam System has significantly more customers, the relative allocation of costs is disproportionately weighted toward newer systems with fewer customers.[88] Creative Energy states that it is not aware of any other jurisdictions using  its proposed two-factor approach as proposed, but it submits that the proposal’s merits are as described above.[89] Notwithstanding, Creative Energy states that it would also be amenable to a three-factor methodology that uses gross or undepreciated capital assets as one of the Massachusetts Formula components (Option 2), replacing the net book value of capital assets or property plant and equipment. Creative Energy considers that this would also serve to improve the fairness in the allocation of costs across all of Creative Energy’s projects and is consistent with standard industry practice to use gross book values in the Massachusetts Formula.[90]

 

During the course of the proceeding, the Panel noted that the Creative Energy stated that approximately half of the forecast special services expenses and half of the insurance costs are directly charged to the Core Steam System. The remaining forecast for these costs and other general and administrative costs is calculated based on the proposed two-factor Massachusetts Formula. However, sales expenses are not included.^[91]

Forecast Outside Services Costs

Outside services costs relate to consulting costs for government advisory services, business development opportunities and the scoping of low-carbon project opportunities and funding sources.[92] These costs are required when Creative Energy considers that its internal staff do not have the capacity or specific expertise required to assist with certain priorities and the additional cost of hiring a full headcount cannot be justified.[93] Forecast outside services costs are included in special services expense,[94] which are both directly charged and allocated to the Core Steam System based on the Massachusetts Formula as discussed above.

Creative Energy’s forecast for outside services costs is $105,466 for 2020, made up of $50,028 for government advisory costs for low-carbon energy development and $55,438 for other advisory and consulting services.[95] Creative Energy submits that the average actual cost from 2015 through 2018 has been approximately $100,000[96] and is the basis for the 2020 test year forecast. Creative Energy submits that 2019 actuals of $112,067, which became known after the 2020 forecast was developed, confirm that the 2020 estimate is reasonable.[97]

Forecast Steam Production Overtime Expense

Overtime expense is a component of Creative Energy’s wages and benefits. Creative Energy states that overtime expense is unpredictable as it is driven primarily by sick days.[98] For operational and safety reasons, Creative Energy explains that a minimum number of staff are required for each shift at the steam plant. This results in overtime to meet the staffing requirement when any staff member is absent on short notice due to sickness. In addition, overtime is used to cover staff absences to complete scheduled plant and distribution projects that cannot be rescheduled and that have minimum personnel requirements for safety reasons.[99]

 

Creative Energy seeks approval for its 2020 forecast overtime expenses of $49,146 for the steam production team based on an average of 2018 and 2019 actual overtime.[100]  

 

Forecast Capital Additions

 

Creative Energy states that forecast capital additions for 2020 are $1.6 million. Creative Energy further states that year-on-year increases to rate base presented in this Application are primarily driven by these projected capital additions.[101]

 

Of this amount, the costs directly associated with the addition of new customers are projected to be $518,382 in 2020.[102] Through responses to information requests, Creative Energy amended the forecast stating that the customer connection to 410 W Georgia is now expected to commence service in 2021 instead of 2020.[103] Accordingly, Creative Energy removed $249,862 from the 2020 forecast capital additions.[104]

 

Forecast After-tax Regulatory Pension Asset Account and Related Returns

 

As discussed in subsection 2.2, during the course of the proceeding Creative Energy recalculated its After-tax Regulatory Pension Asset Account. It recalculated the mid-year balance for 2020 to be $800,780, as follows:

 

 

Table 14 – 2020 Proposed After-Tax Regulatory Pension Asset Account Balances[105]

 

For 2020, the difference between the recalculated 2020 mid-year balance of $800,780 and $414,012 (which Creative Energy originally used in the Application) results in an incremental increase of $28,728 to the return on rate base.[106]

 

Positions of the Parties

Forecast Steam Load

 

The CEC states that it has reviewed the evidence related to the load forecast and does not object to the forecast as a basis for the revenue requirement,[107]agreeing with Creative Energy’s proposal to file a separate application which will address the impacts of COVID-19.[108] In the CEC’s view, impacts from the pandemic are not predictable with any reasonable level of confidence, and as such, addressing the impacts of COVID-19 in this proceeding would increase costs and would not provide definable improvements in forecasts. The CEC submits that a deferral account is or will be necessary to account for COVID-19 impacts and is preferable to attempt to isolate those from business as usual rather than from a mid-pandemic perspective.[109]

 

Forecast O&M Expenses

 

Subject to the comments noted below, the CEC submits that the 2020 Forecast O&M expenses for the Core Steam System are reasonable.[110]

Massachusetts Formula

The CEC submits that both of Creative Energy’s proposed changes to the Massachusetts Formula should be rejected because a two-factor method has no known precedent in any other jurisdiction and would be inappropriate to make significant changes to a Massachusetts Formula model in order to achieve a particular outcome. Similarly, the CEC further submits that moving to a revised three-factor Massachusetts Formula is not appropriate, stating that there is a lack of clarity in the evidence in this respect.[111]

 

In its reply argument, Creative Energy submits that its proposals are non-controversial, unbiased and based on the principle of fairness to the utility customers served. With respect to a three-factor approach, Creative Energy submits that the industry standard is gross book values, as opposed to net book values, of capital assets or property plant and equipment and provides reference to two sources, which were submitted in the proceeding on the 2018-2022 Core Steam System Decision.[112]

Forecast Outside Services Costs

The CEC submits that Creative Energy has not adequately justified the forecast outside services costs and submits that the BCUC should consider denying half of the costs, noting that the 2020 forecast is $54,261 higher than 2018 approved of $51,205.[113]

Creative Energy responds stating that 2018 approved is not representative of ongoing priorities and requirements, whereas the 2015 to 2018 actual outside services costs are representative and have been approximately $100,000 per year. Accordingly, Creative Energy submits the CEC’s suggestion should be disregarded as it is without merit and is unsubstantiated.[114]

Forecast Steam Production Overtime Expense

The CEC submits that Creative Energy should standardize its forecasting approach and that it is “appropriate practice” to use the average of the most recent three years of actuals, instead of two years, in order to avoid applying too much weight to what appears to be an outlier year. The CEC calculates that forecast steam production overtime expense would be reduced by approximately $4,500 based on three years of actuals.[115]

 

In its reply argument, Creative Energy submits that it is amenable to forecast steam production overtime expense as suggested by the CEC, but it does not view that it should adopt a standardized approach to forecasting.[116] In its view, a standardized approach would “remove the transparent accounting and judgement required and would be expected to produce inaccurate forecasts in respect of any cost category with cost pressure in one direction year-after-year and/or where specific outlier effects need to be considered in view of a longer-term average.”[117]

 

Forecast Capital Additions

 

The CEC recommends that the BCUC accept Creative Energy’s capital addition plan as filed.[118]

 

Forecast After-tax Regulatory Pension Asset Account and Related Returns

 

The CEC did not comment on the forecast After-tax Regulatory Pension Asset Account.

 

Panel Determination

The Panel approves the 2020 forecast revenue requirement of $9,086,328 subject to the adjustments directed below. 

 

Forecast Steam Load

 

With respect to the steam load forecast, Creative Energy has proposed a forecast load based largely on existing methodologies, apart from some exceptions. Creative Energy proposes a forecast in keeping with previous BCUC directives by incorporating weather normalization, and by obtaining information from significant customers regarding any pertinent changes to their building or operations that could impact demand. The Panel considers this approach to the load forecast methodology for steam customers to be reasonable and appropriate. Regarding the exceptions, Creative Energy has adjusted the NEFC forecast that considers its limited historical data and experience and addresses issues related to the underreporting of steam at the PARQ plant. The Panel considers these changes to be reasonable in light of the lack of available data and alternatives. Therefore, the Panel approves the total 2020 steam load forecast of 1,140,634 thousand pounds of steam as requested by Creative Energy.

 

However, the Panel expects that as more data is available for the NEFC customer load, Creative Energy will use a methodology for the NEFC forecast more similar to that used for the Core customer load forecast. That is, Creative Energy will calculate the forecast based on historical data and information from significant customers regarding changes that may impact the load forecast and will normalize the load in a manner more consistent with methodology used for the Core component of the steam load forecast.

 

Regarding the issue of whether a deferral account to record variances between forecast and actual load is warranted, the Panel has difficulty understanding why a deferral mechanism for forecast variances continues not to be considered. A deferral account mechanism would allow any variances in load forecasts to be corrected and trued up with neither the ratepayer nor the utility having an advantage.

 

While the Panel agrees that the impacts of COVID-19 have been dealt with in a separate proceeding, it points out that it is common utility practice to use a load forecast deferral account in order to avoid the impact of such events that are beyond the control of the utility. For this reason, the Panel encourages Creative Energy to further consider a load forecast deferral account in its next revenue requirements application. The Panel considers it beneficial if Creative Energy were to include in its next revenue requirement application information comparing the forecast, the approved and actual historical demand to assist in the timely review of that application.

 

Forecast O&M Expenses

With respect to 2020 Forecast O&M expenses, the Panel acknowledges the issues raised by the CEC and addresses each in turn.

As for the proposed changes to the Massachusetts Formula, the Panel approves the inclusion of NEFC in the Massachusetts Formula cost allocation. This approach is the same as Creative Energy’s other regulated TES projects, and the Panel is persuaded that this is a practical approach to estimating the NEFC’s costs in serving a separate energy system.

As for the second proposed change involving the proposed modification to the three-factor Massachusetts Formula, the Panel agrees with the CEC that the proposed two-factor formula is “a Creative Energy construct” and is not persuaded that it should be adopted. However, the evidence submitted in Creative Energy’s reply argument shows that a three-factor formula based on gross (undepreciated) capital assets or property plant and equipment reflects the industry standard. Accordingly, the Panel denies Creative Energy’s request for a two-factor Massachusetts Formula and approves the use of a three-factor Massachusetts Formula, beginning in 2020, based on the following factors: the average gross book value of capital assets or property, plant and equipment; salaries or direct labour expenses; and operating revenues.

Creative Energy is directed to recalculate the costs allocated to the Core Steam System and NEFC, respectively, based on the three-factor Massachusetts Formula approved above in a compliance filing due to the BCUC within 30 days of the date of this decision (Compliance Filing), including the rate impact for each service area. The Panel expects that the impacted costs will include sales expenses and general and administrative costs as previously determined by the BCUC in the 2018-2022 Core Steam System Decision. 

Regarding the 2020 forecast outside services costs, the Panel rejects the CEC’s proposal to deny half of the costs as the Panel finds this proposal has no evidentiary basis. The 2020 forecast is comparable to that of previous years and the CEC’s recommendation does not have a material impact on the 2020 forecast revenue requirement overall. Therefore, the Panel approves the 2020 forecast for outside services costs of $105,466 as requested by Creative Energy.

The Panel approves the 2020 forecast steam production overtime expense. The Panel finds that basing the forecast on the average of the 2018 and 2019 actuals is a reasonable approach. The Panel notes the difference in amount based on the CEC’s recommendation is minimal and that there is no real basis for the three-year forecast suggested by the CEC. The Panel finds no issue with Creative Energy’s response regarding a standardized forecast approach and considers it reasonable to have flexibility when preparing forecasts.

Forecast Capital Additions

 

Finally, the Panel notes that throughout the proceeding the intervener has not raised any specific objections concerning Creative Energy’s projected capital additions. The Panel is satisfied that the capital additions as filed and amended during the proceeding are reasonable. However, the Panel has included specific comments earlier regarding the Remote Metering Project in setting 2019 rates.

 

Forecast After-tax Regulatory Pension Asset Account and Related Returns

 

As discussed in section 2.0, based on the BCUC’s determinations in the 2015-2017 Core Steam System Decision, the Panel finds Creative Energy has not calculated the mid-year After-tax Regulatory Pension Asset Account and related return correctly for 2019 and 2020. Creative Energy uses the previous year’s approved mid-year balance as the opening balance instead of the previous year’s December 31 Pension Asset (after tax) reported on the audited financial statements as set out in the 2015-2017 Core Steam System Decision.

 

The updated calculations for 2020, reflecting the BCUC’s determinations in the 2015-2017 Core Steam System Decision, are as set out in the following tables:

 

Table 15 – 2020 After-tax Mid-year Regulatory Pension Asset

 

 

Table 16 – Adjustment to 2019 Allowed Return

 

 

The Panel uses the 2018 December 31 Pension Asset as the opening balance since the 2019 audited Financial Statements are not on the evidentiary record. Further, since Creative Energy did not provide forecast employer contributions for 2020 or otherwise request adjustments to the After-tax Regulatory Pension Asset for 2020, the Panel sets the 2018 forecast contributions equal to the approved forecast pension expense.

 

Creative Energy is directed to reduce the allowed return for 2020 by $21,503 based on a mid-year After-tax Regulatory Pension Asset Account balance of $268,202.

3.2              Deferral Accounts

For the Core Steam System, Creative Energy proposes to recognize certain O&M items on a forecast basis and requests deferral treatment for any forecast variances. This requested treatment means that the variance between forecast and actual cost would be captured in an approved regulatory account and carried forward to be disposed of in future years using an approved amortization period and recovery mechanism. 

In the decisions establishing Core System Steam rates for 2016-2017 and 2018^[119], the BCUC approved deferral treatment of forecast variances for regulatory costs and pension expense with resulting variances to be amortized over one year. For the 2019-2020 test period, Creative Energy seeks continuation of deferral treatment for these items and requests other changes as summarized in the following table.   

Table 17 – Summary of 2020 Deferral Treatment Requests[120]

 

The Panel notes that deferral treatment provides certainty of cost recovery for the utility. Accordingly, to consider Creative Energy’s requests, the key questions for the Panel are:

1. Is the approval of forecast variance treatment for the cost item warranted, and if so, what is the appropriate amortization or recovery period for the variance; and
2. Should the recovery mechanism of the cost variance be through the use of a DARR mechanism as proposed by Creative Energy, or alternatively, should the amount be included in subsequent revenue requirement test periods.

 

In the subsections below, the Panel applies the following criteria to address the first question regarding whether the requested deferral treatment is warranted:

• The extent to which the cost is within the control of management; and  

• The degree of forecast uncertainty associated with the cost.

    

In the Panel’s view, if the cost item is reasonably controllable and capable of forecast then it should form part of the forecast revenue requirement and the utility should bear the risk of variance. In contrast, if a utility has limited control over the item or there is a high degree of forecast uncertainty, it may not be appropriate for the utility to bear the risk of forecast variances. In such a case, the establishment of some form of deferral mechanism may be appropriate. The Panel’s approach is consistent with the BCUC’s Regulatory Accounting Filing Checklist (Checklist), which among other things asks regulated entities applying for a regulatory account to comment on “whether, or to what extent, the item is outside of management’s control” as well as the degree of forecast uncertainty associated with the item.^[121]

Regarding the second key question noted above, the Panel considers Creative Energy’s request for permanent approval to use its proposed DARR mechanism in subsection 3.4.5.

3.2.1        Water Cost Deferral Account

Creative Energy requests approval of a deferral account to track the difference between actual total annual water costs versus forecast total annual water costs (the Water Cost Deferral Account or WCDA). The balance in the proposed WCDA would be amortized over a one-year period on an ongoing basis commencing January 1, 2021, at a carrying cost equal to Creative Energy’s short-term debt rate.

 

The cost of water is one of the major expenses for Creative Energy and water usage primarily consists of:

• Feed water for steam production; and
• Water cooling for the safe discharge of distribution system condensate.^[122]

 

Water is obtained from the City of Vancouver and is subject to water rates and rate design as set by the City of Vancouver. Water rates have increased more than inflation since 2016. The history of water rate increases since 2016 is as follows:^[123]

• 4 percent between 2016 and 2017;
• 6 percent between 2017 and 2018; and
• 10 percent between 2018 and 2019.

 

The internal budget for water costs that Creative Energy used to support the prior RRAs and actual costs is provided below:^[124]

 

 

Actual costs were higher than budget in 2016, 2017 and 2018 by an average amount of approximately $130,000, or 27 percent as detailed in the table above.^[125] 

 

Creative Energy submits that water expenses are challenging to budget and forecast due to the underlying lag and uncertainty in the City of Vancouver’s water rates and the lack of historical data which creates limitations when building a forecast of water volumes.^[126]

 

Creative Energy states that the issue is a persistent, material, and asymmetrical variance from budgeted amounts of the water expense due to factors outside of its control.^[127]

 

Additionally, it argues that the proposed WCDA will not impact the utility’s incentive to improve steam plant efficiency or contain costs and cites previous projects which improved efficiency and safety as evidence of their independence.^[128] Instead, the proposed WCDA will reduce its exposure to a material risk which is beyond its control and will not impact its approved ROE.^[129]

 

No alternatives to the proposed deferral treatment for any water cost variances were submitted during the proceeding, but Creative Energy notes that it has implemented a process to track its water volumes more closely with a view to evaluating and improving the rigor of its water expense forecast in future RRAs.^[130]

 

Position of the Parties

The CEC does not object to the establishment of the WCDA and accepts that there is no requirement to adjust the ROE as a result.^[131]

 

Panel Determination

The Panel approves the establishment of a non-rate base Water Cost Deferral Account to capture water cost forecast variances for the 2020 test year only. Since a process to better track water volumes has been implemented, Creative Energy is directed to address the continued need for the Water Cost Deferral Account and to re-evaluate its water cost forecast methodology in its next revenue requirement application. Creative Energy must provide in that application information comparing the forecast, approved and actual historical water expenses and volumes to assist in the timely review of the application.

 

The Panel also approves Creative Energy’s proposal for a one-year amortization period on the Water Cost Deferral Account commencing January 1, 2021, and a carrying cost equal to Creative Energy’s short-term debt rate, unless otherwise determined by the BCUC. Creative Energy’s evidence demonstrates that water costs are primarily outside of its control and have been difficult to forecast and the Panel agrees that the requested deferral treatment is reasonable. The Panel notes that the CEC does not object to this proposed treatment.

3.2.2        Property Tax Deferral Account

Creative Energy seeks approval to establish a Property Tax Deferral Account to record variances between total annual actual property taxes and forecast property taxes for the Core Steam System.[132] Property taxes are paid to the City of Vancouver for the Core Steam System properties located at 720 Beatty Street and 701 Expo Boulevard.

 

Creative Energy explains that the annual property tax expense is a function of the value of the properties (as assessed annually by BC Assessment) multiplied by various levy rates, which are externally determined and typically changed annually.[133] It submits that property taxes are challenging to forecast due to lag and uncertainty in the levy rates, which are not confirmed until May/June of the applicable year (e.g. mill rates for property taxes for 2020 are not known until May/June 2020).[134]

 

Creative Energy proposes to amortize the Property Tax Deferral Account over one year and accrue a carrying cost based on its short-term interest rate, consistent with other deferral accounts, on the mid-year value.[135]

Position of the Parties

The CEC has no objection to Creative Energy’s proposal for the property tax variance.[136]

Panel Determination

The Panel approves the establishment of a non-rate base Property Tax Deferral Account to capture property tax forecast variances. The Panel also approves Creative Energy’s proposal for a one-year amortization period on the Property Tax Deferral Account commencing January 1, 2021 and a carrying cost equal to Creative Energy’s short-term debt rate on the mid-year value, unless otherwise determined by the BCUC. Creative Energy’s evidence demonstrates that property tax expense is primarily outside of its control and is difficult to forecast. The Panel agrees that the requested deferral treatment is reasonable. The Panel notes that the CEC does not object to this proposed treatment.

3.2.3        Third Party Regulatory Costs Deferral Account

As discussed in section 2.0, the Panel approves the continuation of the TPRCDA for 2019, sets a two-year amortization period for 2018 forecast variances, and allows for the addition of the 2019 forecast variance of $177,340 to the TPRCDA. As a result of these determinations, the following variances remain in the TPRCDA for 2020.

 

Table 18 – 2020 Opening TPRCDA Balance

 

Below the Panel determines whether deferral treatment for 2020 regulatory costs forecast variances remains appropriate and sets the amortization period for the unamortized 2018 and 2019 forecast variances (plus interest) recorded in the TPRCDA. The Panel addresses Creative Energy’s proposals related to the DARR mechanism in subsection 3.2.5.

 

Position of the Parties

The CEC does not comment on the continuation of variance treatment or amortization period for regulatory costs for 2020. 

 

In reply to the CEC’s comments on the TPRCDA, Creative Energy states, “the costs at issue are by their nature necessarily incurred for utility purposes and the large majority of the costs are not within management’s ability to control and therefore should not be the shareholder’s risk.” As noted in subsection 2.2, Creative Energy submits regulatory costs are undoubtedly recoverable in utility rates, and deferral account treatment of variances between forecast and actual costs are appropriate between forecast and actual costs because it is very challenging to accurately forecast these costs, utility management has limited or no ability to control variances, and the variance can be material.[137]

Panel Determination

The Panel approves the continuation of the non-rate base Third Party Regulatory Cost Deferral Account for 2020 to capture third-party regulatory costs forecast variances. As noted in its approvals for 2019 rates, variance treatment for third-party regulatory costs is consistent with previous BCUC decisions and Creative Energy has established that these costs are outside the control of Creative Energy and are difficult to estimate.

 

As discussed in section 2.0, Creative Energy proposes to amortize the TPRCDA balance over two years and the Panel determines this is appropriate for the 2018 variance. While a two-year period was appropriate for 2019 rates for the reasons stated, the Panel considers that it is generally more appropriate to recognize regulatory costs variances over a one-year period, consistent with Creative Energy’s previous treatment. Given the mitigation of the rate impact resulting from the offset of the 2018 and 2019 pension remeasurement amounts, the rate impacts of recognizing the remaining 2018 and 2019 regulatory costs over one year are acceptable. The Panel notes Creative Energy’s estimate that a one-year amortization period would result in an overall 2020 rate impact that would exceed 10 percent^[138] is calculated before the pension remeasurement offset. The Panel estimates the impact of using a one-year period is between 4 and 5 percent.[139] Accordingly, for 2020, the Panel approves a one-year amortization period for the TPRCDA, and Creative Energy is directed to recognize amortization of $281,170 plus interest for 2020.

3.2.4        Pension Expense Deferral Account

Following the Panel’s determinations in section 2.0 related to pension expense variances, the following balances remain in the Pension Expense Deferral Account as at the beginning of the year, including 2019 current service cost variances:[140]

 

Table 19 – 2020 Opening Pension Expense Deferral Account Balance

 

 

Below the Panel determines whether deferral treatment for 2020 pension expense variances remains appropriate and sets the amortization period for the 2020 opening Pension Expense Deferral Account balance. The Panel addresses Creative Energy’s proposals related to the DARR mechanism in subsection 3.4.5.

 

Position of the Parties

The CEC does not raise any issues regarding the Pension Expense Deferral Account.[141]

Panel Determination

The Panel approves the continuation of the non-rate base Pension Expense Deferral Account for 2020 to capture pension expense forecast variances. As noted in its approvals for 2019 rates, variance treatment for pension expense is consistent with previous BCUC decisions, and Creative Energy has established that these costs are outside the control of Creative Energy and are difficult to estimate.

 

In the Panel’s view, given the mitigation of the rate impact resulting from the offset of the 2018 and 2019 pension remeasurement amounts as well as the favourable current service cost variance, amortization of the account over one year, including interest, is appropriate. Recognition of this amount offsets the rate impact of regulatory cost variances as discussed above. Accordingly, for 2020, the Panel approves a one-year amortization period for the Pension Expense Deferral Account, and Creative Energy is directed to recognize amortization of $98,732 plus interest.

3.2.5        DARR Mechanism

In this subsection, the Panel considers whether the establishment of a DARR mechanism is warranted, and if so, what the DARR rate should be in this test period. The DARR rate proposed by Creative Energy is $0.29 per thousand pounds of steam.

 

Creative Energy requests permanent approval to use a DARR mechanism. Creative Energy describes the DARR mechanism as the implementation of a single DARR, which will span the recovery of costs across multiple deferral accounts using the amortization period determined in respect of each account.[142]

 

The deferral accounts which Creative Energy proposes to include in the DARR mechanism are:[143]

 

•         The existing Pension Expense Deferral Account, with refunds/recoveries from this account to be applied through the DARR rate beginning in 2020;[144]

•         The existing TPRCDA, with refunds/recoveries from this account to be applied through the DARR rate beginning in 2020;[145]

•         The proposed Water Cost Deferral Account, with refunds/recoveries from this account to be applied through the DARR rate beginning in 2021;[146] and

•         The proposed Property Tax Deferral Account, with refunds/recoveries from this account to be applied through the DARR rate beginning in 2021.[147]

 

Review of the specifics of these accounts and consideration of whether forecast variance treatment is appropriate and determination of the amortization or recovery period for the variance are set out in subsections 3.2.1 to 3.2.4.

 

Creative Energy submits that the proposed DARR mechanism is a straightforward and accepted means to recover discrete costs approved for deferral account treatment separate from base rates. In its view, the DARR mechanism:

 

•         Supports transparency and rate and revenue stability;

•         Provides the ability to readily adjust the level of the rate rider in response to emergent changes in costs or when subject account balances have been cleared;[148] and

•         Promotes equitable allocation of cost recovery from customers.

Creative Energy explains the above are overall benefits relative to recovering the deferral account balances through an adjustment to the Core Steam System’s declining block rate design. In the alternative, it submits that larger customers will receive a relative discount on their contribution to the recovery of the costs recorded in the subject deferral accounts.[149] Creative Energy states that it also considered whether a basic recovery charge which would be the same for each Core Steam System customer would be appropriate (e.g. $/day), but regarded that to be unfair to small customers.[150]

 

Position of the Parties

The CEC does not object to the approach of recovering costs on a per unit basis ($/thousand pounds of steam) as proposed, agreeing that it is more equitable for customers because it is based on steam usage. The CEC also submits a two-year time frame is appropriate for recovery and recommends the BCUC approve the DARR as filed.[151]

 

Panel Determination

In considering whether the establishment of a rate rider mechanism to recover forecast variances in O&M is warranted, the Panel disagrees with Creative Energy’s submissions that the proposed DARR mechanism is a “straightforward and accepted means” [152] to recover the forecast variances related to pension, regulatory and other recurring non-controllable O&M costs. Typically, the type of O&M forecast variances captured in deferral accounts is recovered in subsequent revenue requirements within the existing approved rate structure.

 

In support of its view, Creative Energy references the BCUC directive for Creative Energy to establish a FCSA and rate rider mechanism[153] to record variances between forecast and actual fuel costs and a fuel cost rate rider mechanism.[154] However, it has not provided any evidence that its proposed rate rider mechanism is an accepted means of recovering pension, regulatory and other recurring non-controllable O&M costs variances. While the Panel agrees that the FCSA and related rate rider mechanism is a typical and an understood approach used to capture and recover fuel cost variances, there is no evidence to support this approach for pension, regulatory and other recurring non-controllable O&M costs.

 

Creative Energy also submits that a rate rider mechanism provides the ability to quickly adjust the level of the rate rider and, if applicable, cancel the rate rider when the subject costs have been recovered.[155] Given that a forecast of these costs will form part of a revenue requirement application, the Panel considers that recovery of related variances can be readily accommodated within the ongoing RRA process. Any issues related to rate and revenue stability can also be dealt with within the context of an RRA proceeding and approved rate structure.

 

The Panel disagrees with Creative Energy’s submission that its proposed rate rider mechanism supports transparency.[156] Recovering multiple items through one rate rider is not transparent, lacks clarity and adds complexity.  Rate rider mechanisms can be useful and transparent when designed to recover a specific item or type of cost, but combining various accounts diminishes the comprehension of a rate mechanism.

 

The Panel is concerned with the submissions that the rate rider mechanism results in a more equitable rate design for recovery of certain O&M forecast variances. Creative Energy and the CEC do not address why it is appropriate (i.e. not unjust, unreasonable, unduly discriminatory or unduly preferential) for forecast amounts related to pension, regulatory, water costs and property taxes to be recovered through the existing declining block rate design, but on the other hand, the related variances from forecast would be more equitably recovered through the proposed DARR mechanism. If Creative Energy has identified potential inequities among customers within the existing rate design, it should undertake a cost of service study and assess if its existing rate design reflects the costs of providing steam service to those customers.

 

For the reasons outlined above, the Panel denies Creative Energy’s request for permanent approval of its proposed DARR mechanism. Creative Energy is directed to provide, in its Compliance Filing the calculation of and proposed timing by which customers will be refunded the amounts collected in 2020 on an interim basis, plus interest, by way of bill credits. Creative Energy is also directed to record the amortization of the Pension Expense Deferral Account and Third Party Regulatory Costs Deferral Accounts in the revenue requirement for 2020 Steam Rates.

3.3              Proposals regarding the Fuel Switch Study and LTRP Deferral Account

3.3.1        Background

As part of Order G-7-20A, the BCUC directed Creative Energy to file a proposal for the potential recovery of the balance in its Fuel Switch Study and LTRP Deferral Account for review as part of this Application.[157] The BCUC initially established the Fuel Switch Study and LTRP Deferral Account in the 2018-2022 Core Steam System Decision issued on October 25, 2018, following review of that proceeding.

 

As part of its 2018-2022 RRA, Creative Energy sought approval to include $720,232 of costs incurred on account of its 2017 LTRP Application (LTRP Application) into the TPRCDA, which the BCUC had approved as part of Creative Energy’s 2016-2017 RRA. Those costs included amounts expended on the Fuel Switch Study, which was filed as part of Creative Energy’s LTRP Application. However, the Fuel Switch Study predated the BCUC directive made pursuant to Order G-98-15 on June 9, 2015 directing Creative Energy to file the LTRP and to include the information from the Fuel Switch Study as part of that proceeding. 

 

Following a review of the LTRP Application, the BCUC adjourned the proceeding until the filing of Creative Energy’s 2020-2021 RRA. The BCUC directed Creative Energy “to file a complete and updated LTRP that satisfies all requirements under section 44.1 of the UCA” and adjourned the review of that application pending such filing.[158] In so doing, the BCUC made the following findings:[159]

The Panel finds that it is not reasonable to review Creative Energy’s LTRP at this stage because the Fuel Switch Program, which is central to its LTRP, has not sufficiently progressed and is still in the preplanning stage.  Creative Energy is still in the midst of pursuing enabling mechanisms that would advance the Fuel Switch Program and it will continue to pursue the enabling mechanisms for the next two years.  However, based on its Application, Creative Energy is currently not in the position to commit to the Fuel Switch Study and thus lacks important information regarding details, schedules and impacts that would normally be reviewed within the LTRP.  Absent of the commitments that Creative Energy needs in the next two years, the Fuel Switch Program may not continue.  As such, the Panel does not believe Creative Energy is able to provide the full information required to facilitate a complete review of its LTRP.

During the BCUC’s review of Creative Energy’s 2018-2022 RRA, the BCUC determined in light of the adjournment of the LTRP Application, there was limited evidence which would substantiate whether the Fuel Switch Study was or would be useful in preparing Creative Energy’s LTRP and whether the associated expenditures incurred between 2013 and 2017 were prudently and reasonably incurred for the benefit of Core steam customers such that they ought to be approved for recovery. Accordingly, the BCUC declined to make any determination on the recoverability of the costs proposed for deferral treatment, but noted in doing so the following evidence:

•         In its 2015-2017 RRA, Creative Energy forecast $0 for LTRP costs for 2015;

•         In its 2016-2017 RRA, it forecast $0 for LTRP costs for 2016 and $48,000 for 2017, on account of “Consultants – LTRP”, which amount was approved for inclusion in the approved 2017 forecast for Special Services expenses, with any variances between forecast and actual costs approved to be added to the TPRCDA;

•         By the time of the 2016-2017 RRA, Creative Energy had purportedly spent more than $472,000 on the Fuel Switch Study and LTRP, but this was not disclosed to the BCUC except for the $48,000 forecast expenditure for 2017 for “Consultants – LTRP” referred to above;

•         By the time of the 2018-2022 RRA, the amount claimed for deferral related to the Fuel Switch Study and LTRP costs was $720,232, net of offsetting government grants; and

•         The majority of the costs claimed comprised consulting fees paid to 15 different firms between 2013 and 2017 entailing “hundreds of associated invoices” for which no supporting detail was provided to the BCUC despite its request to Creative Energy to provide same.[160]

In light of this evidence, rather than acceding to Creative Energy’s proposal during the RRA to include all of the associated costs into the TPRCDA, the BCUC directed that Creative Energy transfer all of the costs claimed with respect to the Fuel Switch Study and LTRP, net of all applicable offsetting grants, to a new Fuel Switch Study and LTRP Deferral Account pending the filing of an updated LTRP. The BCUC found that the TPRCDA “is only intended to capture ongoing Third Party Regulatory Costs incurred by Creative Energy in the ordinary course for its regulatory filings, as evidenced by the one-year amortization period approved in the 2016-2017 RRA” and is not meant to capture extraordinary costs of the nature and magnitude claimed on account of the Fuel Switch Study and LTRP, which span four years from 2013 to 2017.[161] 

 

In making this finding, the BCUC also noted that “separation of the Fuel Switch Study costs from the TPRCDA will allow for greater transparency when these costs are being reviewed” by a subsequent panel.[162] The BCUC observed that “it would be appropriate for the subsequent panel assigned to review the updated LTRP to assess the reasonableness of the Fuel Switch Study and LTRP costs, as that panel will have a better understanding of the usefulness and applicability of the Fuel Switch Study to the overall LTRP filing.”[163] This would enable a subsequent RRA panel to assess the recovery mechanism for these costs based on the recommendations and determinations of the panel reviewing the updated LTRP.[164] At the same time, the BCUC approved carrying costs on the balance in the new deferral account at a weighted average cost of debt. The BCUC further directed Creative Energy to submit a proposal for the disposition of that account at the earlier of: (i) the filing of an updated LTRP by December 31, 2019, pursuant to Creative Energy’s stated intentions; and (ii) January 31, 2020 (Directive #5).[165] 

 

In so ordering, the BCUC made the following observations:

 

The Panel observes that Creative Energy ought to have been more forthcoming and transparent about the extent of the Fuel Switch Study and LTRP expenditures when it applied for and obtained approval for the TPRCDA in the 2016-2017 RRA Decision.  In the Panel’s view, it is unreasonable for Creative Energy to withhold relevant information about significant expenditures which it expects ratepayers to bear in subsequent RRAs.[166]

 

The BCUC directed Creative Energy to submit a compliance filing showing:

•         The updated balance in the TPRCDA to reflect the removal of the “Consultants – LTRP” costs which the BCUC had already approved for recovery as part of Creative Energy’s forecast for Special Services in 2017; and

•         The newly established Fuel Switch Study and LTRP Deferral Account and associated cost additions.

On December 11, 2018, Creative Energy submitted a compliance filing showing the updated balance in the latter account totalled $714,880 as of that date.

 

As part of this Application, Creative Energy initially applied for formal relief from Directive #5 of Order G-205-18 along with a request for extension of that Directive to December 31, 2020 for filing of its updated LTRP, along with a proposal for disposition of the new deferral account. It attributes this delay to resource constraints and the ongoing uncertainty with respect to fuel switch planning sources, which prevent it from having an updated LTRP. Instead, Creative Energy proposed to address the recovery of the balance in the Fuel Switch Study and LTRP Deferral Account at the time of the filing of an updated LTRP as part of its 2021 RRA.

 

Following a review of that request, the Panel ordered Creative Energy to file a proposal for the disposition of the balance in the Fuel Switch Study and LTRP Deferral Account for review as part of this Application. In doing so, the Panel found that given the clear wording in Directive #5, Creative Energy’s reasons for the Extension Request did not warrant the length of the requested extension, noting that as of the time of this request, Creative Energy will have had more than 15 months from the issuance of that Directive to either file an updated LTRP or to separately file a proposal to address the potential recovery of the balance in the deferral account. Nonetheless, the Panel exercised its discretion to extend the filing deadline for the proposal from January 31, 2020 to February 21, 2020 in recognition of Creative Energy’s stated resource constraints.[167]

3.3.2        Creative Energy’s Proposal

Pursuant to Order G-7-20A, Creative Energy filed the following proposal on February 27, 2020 for BCUC approval of the disposition of the current balance in the deferral account of $735,223 (before carrying costs) for three categories of costs:[168]

•         That the BCUC approves $214,185 for recovery by Creative Energy from its Core steam customers as part of this Application for costs incurred in 2016 on account of consultant costs to pursue low-carbon development, with approval of the proposed rate mechanism (including billing determinants and recovery period) to be brought forward as part of Creative Energy’s 2021 RRA, taking into account considerations such as customer bill impacts and the context and drivers of the 2021 RRA which are yet to be determined;[169] 

•         That the total costs of the internal project management time and related support currently recorded in the deferral account spanning 2015 to 2016, totalling $64,222 and $39,314 respectively, and $103,536 collectively, be excluded from recovery from ratepayers. Creative Energy makes this concession, stating that the 2015 costs have already been included in the project related costs of $417,502 associated with the Fuel Switch Project (namely, the assessment, definition and preliminary design of the “Green House Project” described in the Fuel Switch Study) which Creative Energy does not intend to proceed with at this time. With respect to the 2016 costs, it is unable to definitively confirm they were on account of the Fuel Switch Project versus other efforts, and whether these costs were necessarily or properly excluded from its revenue requirements and rates at that time;[170] and

•         That the BCUC defer consideration of the disposition of the remaining balance of the deferral account, $417,502, until such time as and when Creative Energy advances “a proposal to capitalize any related development costs into the overall [Green House] project as applicable”.[171] 

As part of its proposal, Creative Energy provided the following table summarizing the current Fuel Switch Study and LTRP Deferral Account balance net of project-related grants.

 

Table 20 – Fuel Switch Study and LTRP Deferral Account Balance Net of Project-Related Grants

As the table above shows, Creative Energy now distinguishes between the costs incurred from 2013 to 2015 which it attributes to costs incurred on account of the pursuit of a Fuel Switch Project and those incurred in 2016 in pursuit of enabling low-carbon development.

 

Creative Energy’s proposal raises the following issues for the Panel:

•         With respect to the first category of costs, totalling $214,185, which Creative Energy now ascribes to the pursuit of low-carbon development in 2016 (see the last column in Table 20 above), do those costs form part of general O&M costs that ought to have been forecast and recovered as part of rates in 2016 such that Creative Energy is now precluded from recovery of those costs from current or future ratepayers? 

•         With respect to the second category of costs totalling $103,536, should these costs be written off as Creative Energy proposes?

•         With respect to the third category of costs totalling $417,502,[172] do these “development” costs warrant deferral treatment until such time if and when Creative Energy brings forward an application to capitalize those costs in connection with an anticipated overall capital project?

3.3.3        Discussion of the Issues

The Panel summarizes below Creative Energy’s and the CEC’s submissions with respect to the above-noted issues.

 

Creative Energy describes the first category of costs as being:

…entirely Creative Energy’s cost for the efforts of its consultants – during the year 2016 only – that were directed toward supporting Creative Energy’s ongoing resource planning efforts in view of it becoming increasingly imperative to decarbonize the energy supply for the Core steam system to meet current load and future customer growth.[173] 

At the same time,

Creative Energy acknowledges that these costs were at one point in time expected to be capitalized as part of the overall development costs of the Fuel Switch Project.  Creative Energy does not intend to proceed with the Fuel Switch Project at this time; however, we continue to study the technical and financial viability of alternative projects for displacing natural gas in the steam plant.  The efforts in 2016 support the ongoing good utility planning and practice and are applicable expenses for recovery from customers.[174]

Creative Energy goes on to explain that the work completed in 2016 focused on two areas of long-term resource planning: consideration of government policy and stakeholder engagement. It distinguishes the nature of these costs in 2016 from the third category of costs (the Fuel Switch Project costs) incurred between 2013 and 2015 in these terms:

The focus in 2016 was on the policy environment, enabling tools, and the opportunities and challenges for decarbonization generally, as distinct from the prior detailed feasibility study of the Fuel Switch Project.[175]

It further points out that one outcome of the work in 2016 is that the “results of stakeholder engagement efforts were incorporated into section 13 of the Fuel Switch Study final report.”[176] 

 

With respect to the first category of costs (the 2016 costs), the CEC notes its concern that the consultant Reshape Infrastructure Strategies (Reshape) was not selected through a Request for Proposal (RFP) process and there is a non-arms-length relationship between the parties in that the principal of Reshape (T. Berry) was a past director and Chair of Creative Energy. As a result, the CEC recommends the write-down of a “good portion” of the costs. At the same time, though, the CEC also states that it does not object to Creative Energy’s proposal and that it finds the Reshape invoices “acceptable”. The CEC, however, goes on to suggest that the BCUC direct Creative Energy to conduct appropriate RFP processes for major expenditures for outside consulting services in the future.[177]

 

In response, Creative Energy submits that the recommendation has no foundation and is unnecessary.[178]

 

As for the second category of costs (2015 and 2016 internal project management and similar costs), the CEC agrees that these costs should be written off as Creative Energy proposes.[179] 

 

The CEC does not specifically address Creative Energy’s proposed disposition of the third category of costs constituting the remaining balance in the Fuel Switch Study and LTRP Deferral Account.

Panel Determinations

2016 Enabling Low-Carbon Development Costs

 

In the 2018-2022 RRA, the BCUC directed the establishment of a new deferral account, the Fuel Switch Study and LTRP Deferral Account, pending review of the disposition of the costs initially proposed by Creative Energy to be recorded in the TPRCDA. The Panel notes that contrary to Creative Energy’s evidence in the previous RRA that all of the costs proposed for deferral into the TPRCDA were on account of the Fuel Switch Study and LTRP, Creative Energy now submits that $214,185 of those amount expended in 2016 relate to consulting costs to enable low-carbon development. Creative Energy describes those 2016 costs as supporting good utility practice and planning with a focus on government policy and stakeholder engagement. 

 

Accepting this revised explanation for this first category of costs, the Panel finds that such costs are more properly characterized as period O&M expenses and that they have no direct relationship to the development of the LTRP Application. Accordingly, Creative Energy should have recorded the $214,185 as part of its O&M expenditures in the 2016 RRA period. The Panel notes these costs were not disclosed to the BCUC or included in forecast O&M in the 2016-2017 RRA and appear to have been tracked separately until Creative Energy proposed to include these costs in the TPRCDA as part of the Fuel Switch Study and LTRP costs in Creative Energy’s 2018-2022 RRA. As already noted, the BCUC denied the approval of Creative Energy’s request, directed that the balance be put into the Fuel Switch Study and LTRP Deferral Account pending the filing of an updated LTRP or RRA.  

 

Creative Energy failed to forecast these 2016 Enabling Low Carbon Development Costs for recovery in 2016 rates. Similarly, it did not apply for BCUC approval of deferral treatment for those expenses in 2016 when it filed its 2016-2017 RRA. For the BCUC to now (four years after the expenditures) to allow Creative Energy to recover them in rates is to engage in retroactive ratemaking, contrary to the well-established regulatory principle against such. As the Supreme Court of Canada stated in ATCO Gas and Pipelines v. Alberta (Utilities Commission) (ATCO): [180]

…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 and as already noted earlier, the BCUC explained in a previous Creative Energy decision that generally, the BCUC sets rates on a prospective basis only and has no authority to allow recovery on a retroactive basis.[181] The Panel notes that 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.^[182]

 

Given this, Creative Energy has not satisfied the Panel that the 2016 consulting expenditures made by Creative Energy in pursuit of enabling low-carbon development ought to be recoverable from current or future ratepayers. The Panel acknowledges that the BCUC, as part of Creative Energy’s 2018-2022 Core Steam System Decision, directed that the costs claimed to be put into the Fuel Switch Study and LTRP Deferral Account, but it did so only in contemplation that the BCUC would subsequently determine the recovery of  those costs in connection with Creative Energy’s filing of an RRA or updated LTRP that would determine the disposition of that temporary regulatory account. Accordingly, the Panel denies Creative Energy’s request for approval to recover from customers of the Core Steam System the $214,185 spent in 2016, plus interest , along with Creative Energy’s request to defer the mechanism and timing for such recovery for determination in the 2021 RRA.  Creative Energy is directed to write off these costs from the balance in the Fuel Switch Study and LTRP Deferral Account.

 

2015 – 2016 Internal Project Management, Executive & Legal Support Costs

 

The Panel agrees with Creative Energy’s proposal to write off all of the costs attributed to “internal project management time, executive and legal support” in 2015 and 2016, and directs Creative Energy to write off the amount of $103,536 plus interest from the balance in the Fuel Switch Study and LTRP Deferral Account as Creative Energy proposes.

 

2013 – 2015 Fuel Switch Project Costs

 

According to the evidence adduced in this proceeding, the third category of costs pertains to costs incurred on account of the Fuel Switch Project between 2013 and 2015. These costs total $417,502. As already noted, Creative Energy acknowledges in this proceeding that these costs were at one point in time expected to be capitalized as part of the overall development costs of the Fuel Switch Project:[183]

…specifically for the assessment, definition and preliminary design of the ‘Green House Project’ described in the Fuel Switch Study included with the 2017 LTRP…

The Fuel Switch Project-related efforts were directed by Creative Energy’s parent company, Creative Energy Canada, upon its acquisition of Creative Energy (then called Central Heat Distribution Ltd.) and were responsive in general to an increasing public policy imperative to consider low-carbon options to serve current and future heating demand in the City of Vancouver.

Creative Energy further acknowledges that it does not intend at this time to proceed with the Green House project and Creative Energy, therefore, proposes not to recover from existing customers any of the amount in the Fuel Switch Study and LTRP Deferral Account related to this project at this time. However, if this or a similar project is pursued in the future, Creative Energy will at that time advance a proposal to capitalize any related development costs into the overall project as applicable. 

 

Creative Energy’s evidence in this proceeding is that these costs were incurred between 2013 and 2015 and relate to research into the feasibility of a Fuel Switch Project. Since these costs were research related and not development or capital expenses in nature, the Panel finds that these costs are 2013 to 2015 period costs.  Creative Energy did not request recovery of these costs in its RRAs for 2013 through 2015 or otherwise request deferral treatment of anticipated feasibility costs related to the Fuel Switch Project in the years in question, and the revenue requirements for those years have been set and long since expired. Therefore, the Panel finds that it would be inappropriate to allow Creative Energy to recover those costs now or continue to hold them in the deferral account for future recovery from ratepayers as that would amount to prohibited retroactive ratemaking. Accordingly, the Panel denies Creative Energy’s request to maintain the balance of $417,502 plus interest in the Fuel Switch Study and LTRP Deferral Account and to defer for consideration the disposition of such costs until such time as a CPCN for a low-carbon energy project is submitted and assessment of how much of the balance can be capitalized can be made. The Panel directs Creative Energy to write off the remaining balance from the Fuel Switch Study and LTRP Deferral Account to the account of the shareholder and further directs Creative Energy to close the deferral account thereafter. 

3.4              Setting 2020 Steam Rates 

Based on the Panel’s determinations above, the Panel denies Creative Energy’s request for a 4.2 percent increase in 2020 Steam Rates. Instead, the Panel approves a rate increase inclusive of the impact of its decision above, including:

•         Directive to recalculate the costs allocated to the Core Steam System and NEFC, respectively, based on the three-factor Massachusetts Formula approved above in its Compliance Filing and including the rate impact for each service area;

•         Directive to reduce the allowed return for 2020 by $21,503, based on a mid-year balance of $268,202 in the After-tax Regulatory Pension Asset Account.

•         Denial of the request for permanent approval of its proposed DARR mechanism; and

•         Directive to record the amortization of the Pension Expense Deferral Account and Third Party Regulatory Costs Deferral Accounts in the revenue requirement for 2020 Steam Rates.

Based on these adjustments, Creative Energy is directed to recalculate the rate increase and include the updated financial schedules in its Compliance Filing.

4.0              Setting 2019 Rates for NEFC

4.1              NEFC Hot Water Rates

Background

 

The BCUC approved the revenue requirements, rate design, and Hot Water rates for the NEFC service area in the 2016-2017 Core Steam System and NEFC Decision. The NEFC rate design was set on a levelized rate design basis for 15 years ending in 2030. The decision also established the Revenue Deficiency Deferral Account (RDDA) to record the impact of timing differences between costs incurred to install the required infrastructure to serve NEFC customer load and the revenues from the buildout of that customer load over time. The RDDA allows for a levelized rate structure to smooth rate increases over time, recognizing that the initial rates will not be sufficient to recover forecast revenue requirements. Shortfalls were approved to be added to the balance of the RDDA to be ultimately recovered through load growth and levelized rate increases over a time horizon of 10 years.^[184]

 

In the 2016-2017 Core Steam System and NEFC Decision, the BCUC approved a recovery period for the RDDA, commencing in 2020 and ending in 2030, given “the relatively small peak balance expected and [the] revenue streams put forward.”^[185]

 

The RDDA is intended to record variances between approved revenue requirements and forecast revenues calculated based on approved rates and load forecast. The RDDA is not approved to capture revenue shortfalls based on differences between actual revenues received and approved forecasts. These variances are addressed separately through the Variance Deferral Account, which was also established in the 2016-2017 Core Steam System and NEFC Decision.^[186] The Variance Deferral Account also captures forecast variances related to the following items outside of management’s control:

 

• Variances between forecast versus actual Steam Service Rates and Fuel Cost charged to NEFC;
• Variances between forecast versus actual Distribution expenses[187]; and
• Variances between forecast versus actual Income Tax expense.

 

The Variance Deferral Account was directed to be amortized over a one-year period and recovered through the hot water rates and was approved for a five-year period ending December 31, 2020, at which time Creative Energy must apply for renewal for the period beginning January 1, 2021.^[188]

 

The BCUC approved the following NEFC Hot Water Rates and the opening balance in the RDDA for 2017 in the 2016-2017 Core Steam System and NEFC Decision:

 

• A fixed Rate of $0.27 per square meter per month;
• A variable Rate of $52.10 per megawatt hour (MWh); and
• An addition to the RDDA in the amount of $373,900.

 

These rates were maintained in 2018, due to Creative Energy not applying for any changes to NEFC rates for 2018. A corresponding increase of $373,900 to the RDDA balance in 2018 was recorded.^[189] At the end of 2018, the balance in the Variance Deferral Account was a surplus of $655,250, which Creative Energy transferred to the RDDA in 2019.^[190] The 2018 deferral account additions and transfers have not yet been approved by the BCUC and are addressed in the Panel determination below.

 

In its approval of 2019 interim rates,^[191] the BCUC denied Creative Energy’s application to increase the variable component of NEFC Hot Water Rates by 1.84 percent. Creative Energy was directed to maintain NEFC’s fixed and variable rates at existing rates on an interim basis, effective January 1, 2019. In the decision on interim rates, the BCUC found that Creative Energy had not provided adequate evidence to support the change and the most reasonable approach was to maintain NEFC rates at the existing approved rates on an interim basis.^[192]

 

Creative Energy’s Proposal

 

Creative Energy proposes to maintain 2019 NEFC interim Hot Water rates on a permanent basis, consistent with the rates set in the 2016-2017 Core Steam System and NEFC Decision.^[193] It proposes that the difference between the 2019 actual revenue requirement and the revenues based on existing rates be added to its existing RDDA for future recovery, submitting that this approach complies with the BCUC direction not to begin recovery of the RDDA balance until 2020.^[194]

 

The proposed revenue deficiency related to 2019 rates is shown in the table below (2018 approved forecast is based on 2017 approved forecast from 2016-2017 Core Steam System and NEFC Decision, since Creative Energy did not apply for changes to 2018 rates):

 

Table 21 – NEFC Revenue Requirements^[195]

 

 

 

Since Creative Energy proposes to capture the difference between the 2019 actual revenue requirement and the revenues based on existing rates in the existing RDDA for future recovery, this implies that the Variance Deferral Account will not be used in 2019 to capture any forecast variances, as originally directed by the BCUC.

 

Based on Creative Energy’s proposals, the balance in the RDDA is set out in the following table.

 

Table 22 – 2017-2018 Actual and 2019 Proposed Revenue Deficiency Deferral Account Balances^[196]

 

At the end of 2018, the balance in the Variance Deferral Account was a surplus of $655,250, which Creative Energy transferred to the RDDA in 2019.^[197] Based on Creative Energy’s proposals, the balance in the Variance Deferral Account is set out in the following table.

Table 23 – 2017-2018 Actual and 2019 Proposed Variance Deferral Account Balances^[198]

Position of the Parties

The CEC did not comment on the proposed transfer of the Variance Deferral Account, the additions to the RDDA or NEFC Hot Water Rates.

 

Panel Determination

The Panel approves Creative Energy’s request for permanent approval of NEFC’s 2019 interim hot water rates. These rates align with BCUC’s previous decisions. Levelized rates were set in the 2016-2017 Core Steam System and NEFC Decision, and the Panel understands that these rates are to remain in place until commencing recovery of the RDDA in 2020, unless determined otherwise by the BCUC.

 

The Panel acknowledges that the 2016-2017 Core Steam System and NEFC Decision also determined that the Variance Deferral Account balance was to be amortized over a one-year period and recovered or refunded through the hot water rates. However, the decision covering 2017 rates did not specify how this would happen in subsequent test periods. Since Creative Energy did not file an RRA for 2018 and no amortization of the Variance Deferral account was approved to be recovered as part of the 2018 hot water rates, the 2017 approved rates remained in effect for 2018.

 

Since Creative Energy did not file an RRA for 2018, the Panel agrees it is appropriate to use the 2017 approved forecast to determine the amount to be added to the RDDA and Variance Deferral Account in 2018. Accordingly, the Panel approves the addition of a $373,900 revenue deficiency plus interest to the RDDA for 2018, consistent with the amount determined by the BCUC in 2017. For 2018, the Panel directs Creative Energy to file as part of its Compliance Filing the amount to be added to the Variance Deferral Account.

 

As for Creative Energy’s request to transfer or amortize an amount from the Variance Deferral Account to the RDDA, the Panel considers this to be inconsistent with the reasons establishing the Variance Deferral Account. The Variance Deferral Account was to capture forecast variances related to non-controllable operating costs that should be recovered over a shorter period and the BCUC determined that period should be one-year. On the other hand, the RDDA was expected to be recovered over ten years. Accordingly, the Panel denies Creative Energy’s request to transfer $661,861 from the Variance Deferral Account to the RDDA in 2019.

 

The Panel also takes issue with Creative Energy’s proposal to record an addition of $9,064 as shown in Table 21 above to the RDDA for 2019 being the difference between the 2019 actual revenue requirement and the revenues based on existing rates. First, consistent with reasons for the Panel’s determinations in section 2.0 on the use of actual results to set rates, the Panel disagrees with the use of actuals to determine the amount of variances to be recognized in deferral accounts. Rates should be set prospectively based on a reasonable forecast of revenue requirement items with deferral treatment for the items are outside the control of management or are subject to a high degree of forecast uncertainty. Second, as noted above, the Panel does not agree with Creative Energy’s proposal to combine the RDDA and Variance Deferral Account. Therefore, the Panel denies Creative Energy’s proposal to add the difference between the 2019 actual revenue requirement and the revenues based on existing rates to the existing RDDA.

 

The Panel notes that the BCUC found the forecast information filed in the interim rate application was not adequate for setting interim rates, and therefore, the Panel concludes this information should not be used to set permanent rates. Since Creative Energy did not provide a supportable forecast for 2019, Creative Energy is directed to recalculate the allocation of variances between the Variance Deferral Account and the RDDA based on the 2017 approved forecast. As part of its Compliance Filing, Creative Energy is also directed to include an updated schedule of the revised amounts in the Variance and Revenue Deficiency Deferral Accounts, reflecting the above and other determinations in this Decision.

4.2              Underreporting of PARQ Hot Water Plant Steam Meter

Creative Energy indicated that the PARQ Hot Water Plant meter was underreporting steam flow from the Core Steam system for the period around March or April 2018 to March 2020. The result of the discrepancy was that the total metered energy consumption of the building connected to the PARQ plant was greater than the energy the PARQ Plant meter indicated was supplied to the buildings for that time period. For added clarity, the revenue meters that measure the energy consumed by the buildings were operating correctly and the issue was limited to the metering of energy delivered from the Core system to the PARQ Hot Water Plant for the NEFC system.[199]

 

The following section discusses the implications of the metering issue as it pertains to the 2019 Test Year. For further discussion on the impact of this issue for the 2020 Test Year please see subsection 3.1 of this decision.

 

Based on the plant and distribution efficiencies of the NEFC system, it was estimated that the meter was recording about 50 percent of the steam that would be expected.[200] The estimated difference between actual metered PARQ plant steam load and the expected amount based on observed system efficiencies is 30,678 thousand pounds of steam.[201]

 

Creative Energy submits that the matter at issue is when and how to recognise the additional steam supplied by the Core Steam system to the NEFC system for the purposes of the revenue requirements.[202]

 

Creative Energy proposes to address the matter prospectively in 2020 by recognizing additional steam in the 2020 steam load forecast and proposes to make no adjustments for 2019.

 

Creative Energy submits that if the underreported steam is incorporated in its 2019 NEFC steam load forecast, then the following impacts would occur:

 

•         The steam load billed from the Core Steam System to NEFC would increase by 30,678 thousand pounds of steam;

•         NEFC’s steam costs would increase by $187,807 and fuel costs would increase by $497,728. The impact on NEFC revenue requirements would be either an increase in the RDDA balance from $7,230 to $692,764, or an average increase of 74% to the variable rate for 2019 on account of the increased cost in 2019; and

^•          Core Steam System revenues would increase as a result of the additional revenues transferred from the NEFC which would either result in a reduction in the 2019 addition to the proposed DARR if current rates are maintained or, alternatively, Steam Rates would be reduced for 2019. [203]

The options provided by Creative Energy to incorporate the underreported steam are either to collect the undercharged amount through a one-time surcharge or by allocating the additional NEFC cost of service to the RDDA for future recovery and correspondingly updating the proposed DARR to incorporate the negative deferral balance addition for the Core over an appropriate amortization period.[204]

 

Creative Energy justifies its proposed option to address the issue beginning in 2020 on the basis that correction to the steam load forecast on a go-forward basis is reasonable and appropriately aligned with a future planned rate design application. Creative Energy further submits that the option to flow the amount into the RDDA (and DARR) is also practical but notes that this approach does not align with accepted ratemaking principles that support the fair allocation of costs that match cost recovery with cost causation. Further, it was noted that the mechanism to recover the RDDA balance and the appropriate amortization of the DARR deferral balance have not been proposed nor determined at this point. Finally, Creative Energy does not support a one-time surcharge arguing that it would be impractical and problematic.[205]

 

Position of the Parties

The CEC states that it is satisfied that the PARQ meter issues have been resolved and accepts Creative Energy’s proposal to address the matter prospectively in 2020.[206]

Panel Determination

The question before the Panel is whether the additional steam supplied by the Core Steam system to the NEFC should be recognised, and, if so, how and when should it be recognised.

 

In subsection 4.1, the Panel approves Creative Energy’s request for permanent approval of NEFC’s 2019 interim Hot Water Rates.  

 

The Panel previously determined in subsection 4.1 that the Variance Deferral Account continues to be approved for NEFC,  and variances in the Steam Service Rates and Fuel Cost charges and other forecast items are captured in this deferral account for 2019.[207]  Given this framework, the variances between forecast versus actual Steam Service Rates and Fuel Cost charged to NEFC, including the underreported volumes of steam delivered to the PARQ hot water plant would flow into the Variance Deferral Account for 2019.

 

Regarding the underreporting of the PARQ Hot Water Plant steam meter, the Panel notes it is Creative Energy’s preference that NEFC’s customers not be charged for the amount related to underreported steam services of approximately $187,807 provided by the Core Steam system due to the ‘controversial impact’ of a large one-time surcharge on customers. The Panel acknowledges these concerns and finds this approach is reasonable for the underreported steam service.

 

However, in stating its preference that the correction be made on a go-forward basis, Creative Energy does not address the fair allocation and recovery of fuel costs among other Core Steam System and NEFC customers.  With respect to fuel costs, the Panel notes that revenues and expenses related to fuel costs for the Core Steam System are not included in its revenue requirements and Steam System Rates. For Core Steam customers, fuel costs are recovered through the FCAC and variances related to the difference between the forecast and actual fuel costs are allocated to the FCSA and recovered from customers through the FCAC Rate Rider. Since NEFC is also a customer of the Core Steam system, this mechanism also applies.

 

Therefore, it follows that, if the underreported PARQ volumes were adjusted, the additional fuel cost charges payable by NEFC would flow into the FCSA. Based on the proportion of steam load attributed to NEFC and Core customers, the Panel observes that if the fuel cost portion is not collected from NEFC customers and the FCSA balance is left unchanged, Core customers will have overpaid for their proportionate share of the FCSA balance.  Creative Energy estimates that this underpayment totals $497,728. The Panel does not agree this result is appropriate and considers that recovery of these costs from NEFC through the FCAC mechanism is necessary.

 

For the above-stated reasons, Creative Energy is directed to account for the NEFC underreported fuel cost charges of $497,728 due to the PARQ metering issue in the Core Steam System’s FCSA. Recording the amount in the FCSA is appropriate since this account records the differences between the forecast and actual fuel costs and the adjustment resulting in Core customers ultimately paying their proportionate share of fuel costs.

 

Creative Energy is also directed to record the additional fuel costs in the NEFC Variance Deferral Account, consistent with other fuel cost variances.

 

As discussed in subsection 4.1, Creative Energy is directed to include in its Compliance Filing the detailed calculations supporting the 2019 Variance Deferral Account balance, including the details of the amount attributed to the PARQ metering issue.

5.0              Setting 2020 Rates for NEFC

5.1              2020 Hot Water Rates

Proposed Hot Water Rate Increase of 3.7 Percent

 

As outlined in section 4.0 above, the 2016-2017 Core Steam System and NEFC Decision approved a recovery period for the RDDA, commencing in 2020 and ending in 2030.^[208] Further, the hot water load forecast that formed the basis of Creative Energy’s NEFC CPCN Application in 2015 and its RRA in 2016 assumed full buildout in the NEFC neighbourhood by 2025, with a total connected floor area of 506,300 square meters and total hot water demand of 48,100 MWh.

 

Creative Energy explains that it has currently a total connected floor area of 162,481 square meters and hot water demand of 19,162 MWh forecast for 2020.^[209] Creative Energy also states that the City of Vancouver (the City) has now extended its connection bylaw to include the future development in the NEFC neighbourhood, meaning that the City will provide service to future developments in the NEFC, rather than Creative Energy. Creative Energy states that while it intends to supply the hot water to serve the City’s loads, the necessary arrangements with the City have not been made yet.

 

As a result of these developments, Creative Energy states that it does not have a consolidated forecast of load growth in the NEFC neighborhood and that the timing of required incremental capacity investments to support that load growth is uncertain. Therefore, Creative Energy submits that there is not a sufficient basis to determine longer-term levelized increases to NEFC rates that recover the RDDA over a reasonable time frame.^[210]

 

In the absence of the above information, Creative Energy is requesting approval to increase the 2020 NEFC rates over the rates currently in effect by 3.7 percent. It states that this is equivalent to a one cent increase in the fixed charge per square meter per month, an approximate $2/MWh increase in the variable charge, and would result in the following rates:^[211]

 

• Fixed rate of $0.28 per square meter per month; and
• Variable Rate of $54.03/MWh.

 

Below is a summary of Creative Energy’s proposed 2020 revenue requirement reflecting the proposed rate increase of 3.7 percent:

 

Table 24 – Proposed 2020 Revenue Requirement[212]

 

 

In addition to the 3.7 percent rate increase outlined above, Creative Energy is also proposing a FCAC Rate Rider related to a specific portion of fuel cost included in the table above charged directly to NEFC customers, effective January 1, 2020, and discussed in subsection 5.2 below. Creative Energy estimates the average expected bill impact of the NEFC FCAC Rate Rider in 2020 is 20 percent.[213] When taken in addition to the 3.7 percent rate increase outlined above, the total resulting impact is an expected bill increase of 23.7 percent.[214]

 

Creative Energy proposes an addition of the $440,371 revenue deficiency net of the proposed FCAC Rate Rider recovery to the RDDA balance, plus other adjustments of the addition of interest of $25,944, and transfer of amortization from the Variance Deferral Account of $34,539.^[215]

 

Consistent with the proposed approach for 2019, Creative Energy’s proposal does not contemplate any addition to the Variance Deferral Account, but instead proposes the addition of interest of $2,169 and the transfer of amortization of $34,539 to the RDDA.^[216]

 

Creative Energy explains that the increase of 3.7 percent is estimated as a reasonable minimum required based on an indicative estimate of inflation of 2 percent per year in steam, fuel and operating costs and continued recovery of and on the infrastructure capital invested that would target recovery of the RDDA in 15 to 20 years.^[217] Creative Energy also states that the increase is not based directly on the percentage changes in year-over-year O&M costs, but rather it appears reasonable overall in the context of an otherwise increasing balance in the RDDA, and other factors.^[218] Creative Energy also submits that the request for the 3.7 percent increase is aligned with the BCUC’s direction to commence RDDA recovery in 2020, and lowers the rate of addition to the RDDA that would otherwise occur absent a rate increase in 2020.^[219]

 

To clear the RDDA balance by 2030, as contemplated under the original model, Creative Energy states that a rate increase of 5 percent per year over that time frame would be needed (assuming no load growth from additional development due to the uncertainty surrounding development).^[220] Creative Energy also submits that due to the discussions with the City of Vancouver, it is premature at this time to advance a comprehensive proposal for the full recovery of the RDDA by 2030. It confirms that it is currently reviewing the NEFC rate design, and plans to bring forward a comprehensive proposal to support its next RRA for 2021, at which time the allocation and recovery of costs to serve the NEFC and the amounts that get added to the RDDA will be revisited.^[221]

 

The average expected customer bill impact in dollar terms for the proposed rate 3.7 percent increase is shown in Table 25 below.^[222]

 

Table 25 – Average Expected Bill Impact for Proposed NEFC Rate Increase

 

Forecast Hot Water Load

 

For 2020, Creative Energy forecast a hot water load of 19,162 MWh.[223] The hot water load is an essential billing determinant for NEFC rate setting since all costs are recovered through the volume of hot water sold to customers. In addition, the load forecast is used for other ratemaking purposes, for example, forecasting the fuel costs, forecasting steam tariff costs, and implementing the load variance component of the Variance Deferral Account.

 

Creative Energy calculates the 2020 hot water load forecast by taking the average of 2018 and 2019 consumption in MWh for existing customers and adding load for the addition of the ARC building which came on in late 2019. The additional load for the ARC building is calculated based on the ratio of the floor area of the ARC building to an existing, comparable customer.[224]

 

Forecast O&M Expenses

 

For the NEFC system, Creative Energy forecasts O&M Expenses of $161,000 for 2020 compared to 2019 actuals of $117,406.[225]  Creative Energy explains that the largest increase in O&M costs relates to the elimination of a 2019 net insurance recovery of $46,894 for expenses incurred in 2018.

 

Other than a portion of Insurance costs which are directly charged to NEFC as they relate specifically to the NEFC equipment, $106,309 of the 2020 Forecast O&M costs for the NEFC system are allocated to the NEFC using the Massachusetts formula. For 2020, the allocation is based on the proposed two-factor Massachusetts formula methodology.[226] Creative Energy’s proposals regarding the Massachusetts formula are addressed by the Panel earlier in subsection 3.1 of this decision.

 

Positions of the Parties

In general, the CEC submits that a 3.7 percent rate increase is acceptable in the context of having stable rates for the last three years.^[227] The CEC also states that it has no issues with respect to the proposed net additions to the RDDA in 2020 of $440,370, subject to any cost changes arising from its submissions on the Massachusetts formula.^[228]

 

The CEC submits that Creative Energy uses a reasonable methodology for the NEFC load forecast and does not object to Creative Energy’s load forecast for the NEFC.[229]

 

The CEC does not comment on the 2020 Forecast O&M expenses for the NEFC other than as noted in subsection 3.1 with respect to Creative Energy’s proposals regarding the Massachusetts Formula.[230]

Panel Determination

The 2016-2017 Core Steam System and NEFC Decision approved a recovery period for the RDDA, commencing in 2020 and ending in 2030. After reflecting the adjustments to the RDDA directed in this decision, the balance in the RDDA now exceeds approximately $1.4 million. The Panel acknowledges Creative Energy’s submission that it currently does not have sufficient information to determine the longer-term levelized rate increases needed to recover the RDDA over a reasonable time frame. The Panel also notes the current hot water demand is approximately 40 percent of the hot water load forecast that formed the basis of Creative Energy’s NEFC CPCN Application in 2015 and its RRA in 2016 which could indicate the current levelized rate may not be sufficient to recover capital costs incurred to build the system.

 

Creative Energy confirms that it is currently reviewing the NEFC rate design and plans to bring forward a comprehensive proposal in 2021. Given the uncertainties outlined, the Panel accepts deferring consideration of the recovery of the RDDA until 2021 to allow Creative Energy time to complete its comprehensive proposal.  Creative Energy is directed to file a proposal for how rates should be set for 2021 by October 31, 2020. Creative Energy is also directed to file a comprehensive proposal for an NEFC rate design and for setting 2022 rates by June 30, 2021. Among other things, this application must address adjustments to the levelized rate necessary to reflect an updated hot water load forecast as well as the recovery mechanisms for the RDDA and Variance Deferral Account.

 

Until a comprehensive rate design application is submitted, the Panel finds it appropriate to maintain the existing rate structure. In line with the Panel’s determinations in section 4.0 of this Decision and consistent with previous directives, Creative Energy is directed to add any 2020 forecast variances related to the Variance Deferral Account, as follows:

•         Revenue shortfalls based on differences between actual revenues received and approved forecasts;

•         Variances between forecast versus actual Steam Service Rates and Fuel Cost charged to NEFC;

•         Variances between forecast versus actual Distribution expenses; and

•         Variances between forecast versus actual Income Tax expense.

In addition, the Panel approves the addition of variances between the approved revenue requirements and forecast revenues calculated based on approved rates to the RDDA. Further, the Panel extends approval of the Variance Deferral Account (which otherwise ends on December 31, 2020).

 

The Panel approves the forecast revenue requirement of $2,330,926 for 2020 subject to the adjustments directed below. Based on its review and noting that no issues were raised by CEC, the Panel finds the forecast revenue requirement reasonable. As previously discussed in subsection 3.1, the Panel accepts Creative Energy’s methodology for its steam load forecast, which by way of extension includes the hot water load. The Panel finds that Creative Energy’s methodology is reasonable considering the limited historical data and lack of alternatives. However, the Panel expects that Creative Energy will continue to refine its load forecast as more data is available. Therefore, Creative Energy’s request to use a hot water load of 19,162 MWh for revenue requirement purposes is approved.

 

The Panel also approves the NEFC 2020 Forecast O&M expenses, subject to the recalculation of costs which are allocated to the NEFC using the Massachusetts Formula as approved in subsection 3.1 of this decision. In subsection 3.1, the Panel rejected Creative Energy’s proposal for a two-factor Massachusetts formula methodology. The Panel otherwise finds the 2020 Forecast O&M expenses to be reasonable.

 

Regarding Creative Energy’s request for a 3.7 percent rate increase, the Panel agrees with Creative Energy and CEC that a rate increase is reasonable in the current context. Rates have remained at the same level since 2017 and there was an indication that they would increase in 2020 to start to recover the RDDA. However, given the overall rate impact of a 23.7 percent[231] increase when including the impact of the FCAC rate rider, and given the Panel’s rejection of the FCAC rate rider as set out below, the Panel considers 10 percent to be a more appropriate rate increase for 2020. This level of increase will reduce the addition to the RDDA while keeping the rate below the level typically associated with rate shock. Accordingly, the Panel approves a 10 percent rate increase for NEFC for 2020.

5.2              Proposed Fuel Cost Adjustment Charge Rate Rider

Background

The NEFC System is a customer of the Core Steam system and fuel costs are charged to NEFC at the same rate as other customers of the Core Steam system.

 

Creative Energy’s Core Steam service area recovers its fuel expenses from its customers using two methods: i) a Fuel Cost Adjustment Charge (FCAC); and ii) an FCAC Rate Rider.

 

The FCAC is approved by the BCUC and is based on forecast annual fuel costs divided by forecast annual load. Positive or negative variances between forecast fuel costs and actual fuel costs are captured in the FCSA. The FCAC Rate Rider distributes or collects from customers, as applicable, the positive or negative balances in the FCSA. The threshold for the application of a rate rider is when balances in the FCSA exceed plus or minus 5 percent of the most recently approved 12-month forecast of fuel costs. Creative Energy reports to the BCUC the balance of the FCSA quarterly.

 

The FCAC and the mechanism to recover excess balances in the FCSA were first approved by the BCUC by Order G-167-16 and accompanying Decision. Although the mechanism was approved in late 2016, the first FCAC Rate Rider was not approved until March 2019, at which time the balance in the FCSA exceeded the threshold criteria.

 

The current FCAC of $10.70 per thousand pounds of steam and FCAC Rate Rider of $4.40 per thousand pounds of steam, were approved by the BCUC, effective November 1, 2019.[232]

 

Although Core Steam System and NEFC customers are charged the same rate, how the fuel costs are recovered are distinct. This process can be generally described as follows:

•         NEFC customers’ - fuel costs are included within the revenue requirements and are recovered through hot water rates.

•         Core Steam System customers’- fuel costs are excluded from the revenue requirements and instead, the FCAC and FCAC Rate Rider are established in a separate process as described above and are recovered through a separate charge on Core Steam System customer bills.

 

2020 NEFC Fuel Costs and FCAC Rate Rider Proposal

For 2020, Creative Energy requests approval to include in the NEFC revenue requirement $1,061,666 of fuel cost calculated based on the currently approved FCAC and a forecast hot water load.[233] In addition to the FCAC-related fuel costs, Creative Energy request approval to charge an FCAC Rate Rider directly to NEFC customers, effective January 1, 2020, to recover from these customers the amounts the BCUC approved to be recovered from Core Steam customers though the FCAC Rate Rider approved by Order G-226-19.

 

The proposed FCAC Rate Rider of $16.15/MWh is determined based on the NEFC load forecast and the currently approved FCAC Rate Rider and is calculated as follows:

 

Creative Energy estimates the average expected bill impact of the NEFC FCAC Rate Rider in 2020 is 20 percent. Creative Energy provides further details of the customer impacts as follows:[234]

 

 

Creative Energy notes that the 20 percent expected bill impact to NEFC is approximately the same expected bill impact for Core Steam customers under the $4.40 per thousand pounds of steam FCAC Rate Rider currently in effect.[235]

 

Creative Energy also states that the impact in 2020 of the implementation of the direct charging of the FCAC Rate Rider to NEFC customers is a reduction of $309,360 to the amount that would otherwise be proposed to be added to the RDDA.[236] Creative Energy states that adding the amount to the RDDA would be contrary to the BCUC’s findings in the Order G-226-19 Decision in regard to the appropriate time period for recovery of the excess fuel costs incurred to provide service in 2018/19.

Position of the Parties

The position of the CEC regarding the request of a direct charge for the FCAC Rate Rider to NEFC customer is unclear. CEC states that it “does not object to the addition of the Fuel Cost Adjustment Charge to the RDDA,”[237] but does not indicate its view on whether a direct charge (which would mean the amount is not added to the RDDA) is appropriate.

Panel Determination

In setting Hot Water Rates for 2019 above, the Panel determines that fuel cost variances should continue to be recorded in the Variance Deferral Account. In subsection 5.1, the Panel also finds it appropriate to maintain the existing rate structure until a comprehensive rate design application is submitted for 2021 Hot Water Rates and approves Creative Energy’s 2020 revenue requirement. The approved revenue requirement includes a total fuel cost forecast of $1,061,666, of which $309,359 relate to the Creative Energy FCAC Rate Rider to be paid by NEFC.

 

The Panel notes that Creative Energy’s request for an NEFC FCAC Rate Rider payable by NEFC customers for a specific portion of fuel costs is inconsistent with the approved treatment for fuel costs and fuel costs variances in the existing rate structure and with the Panel’s determinations and findings noted above. In the Panel’s view, it would be more appropriate to make changes to the treatment of fuel costs as part of a comprehensive review of rate design.

 

The Panel acknowledges that the rate increase related to the proposed NEFC FCAC Rate Rider is similar in magnitude to the increase experienced by Core Steam customers. However, the rate design for Core Steam Rates and NEFC Hot Water Rates are dissimilar. NEFC rates are predicated on a levelized rate mechanism that is designed to record the impact of timing differences between the costs incurred to install the required infrastructure and the revenues from a buildout of customer load over time.

 

Further, fuel costs are embedded in the NEFC revenue requirements and thus are included in this levelized rate mechanism. As discussed above, NEFC also has a mechanism through the Variance Deferral Account to capture the difference between the forecast fuel costs, as included in the revenue requirements, and the actual fuel cost charged to the NEFC.

 

In the Panel’s view, Creative Energy has not provided sufficient evidence, in the absence of a full comprehensive rate design, to demonstrate that a change to its treatment of fuel cost mechanism is necessary or desirable, especially in light of the expected 20 percent bill impact resulting from that change.[238] Accordingly, the Panel denies Creative Energy’s request for an NEFC FCAC Rate Rider. Creative Energy is directed to provide, in its Compliance Filing, the calculation of and proposed timing, by which customers will be refunded for the interim amounts collected in 2020, plus interest, by way of bill credits.

 

6.0              Additional BCUC Directives and Recommendations

6.1              Historical Pension Accounting Discrepancies

2015-2017 Pension Expense Deferral Account Variances

 

During the evidentiary phase of the proceeding, Creative Energy stated that it did not review any of the entries made with respect to the Pension Expense Deferral Account for the 2015-2017 period when it prepared the Application because those entries were prepared by previous management. However, based on current management’s subsequent review of these entries, Creative Energy states:[239]

… it appears that no additions were made to the [Pension Expense] deferral [account] in Schedule 12 [Non-Rate Base Deferred Expenses] for 2015… Creative Energy agrees that the variance for 2015 should have been added to the deferral account balance.

A breakdown of the entry that should have been made with respect to deferral treatment of pension expenses for 2015 is shown in Table 26 below:

Table 26 – 2015 Pension Expense Variances[240]

 

 

In addition, Creative Energy stated that there is a difference of $8,963 between what current management calculates as the total pension expense variance for the 2015 to 2017 period ($100,300) and what previous management prepared ($91,337). Creative Energy submitted that it appears that the difference relates to 2016 additions.[241] Table 27 below shows the difference between the two calculations for 2016:

 

Table 27 – 2016 Pension Expense Variances[242]

 

 

Position of the Parties

The CEC does not raise any issues regarding the Pension Expense Deferral Account.[243]  

Panel Determination

While the Panel acknowledges that there have been discrepancies in pension calculations related to amounts determined in previous periods, the rates have already been set on a permanent basis for the years impacted.  The Panel finds that if adjustments were made to current or future rates for these amounts this would result in retroactive ratemaking, which as noted previously in this Decision is contrary to well-established regulatory principles. Accordingly, the Panel does not approve the 2015-2017 adjustments related to pension accounting discrepancies.

6.2              Panel Recommendations for Future Filings

After reviewing this Application, IR responses and various submissions, the Panel has identified several recommended focus areas for Creative Energy’s future filings that should result in improvements to the efficiency and effectiveness of its proceedings. In connection with the focus areas identified below, the Panel also discusses a few examples of quality issues identified in this proceeding.

 

Adherence to Fundamental Regulatory Principles

 

In future filings, the BCUC would find it helpful if Creative Energy could explain how its proposals conform with fundamental ratemaking principles, the legislative framework and the approach taken by the BCUC and other comparable regulatory agencies in similar circumstances. Where applicable, Creative Energy should address how its proposals are consistent with the requirements to setting rates prospectively, the regulatory principle against retroactive ratemaking, cost causation principles, considerations regarding rate shock and other fundamental regulatory principles.

 

Following its review of this Application, the Panel has denied a number of Creative Energy’s proposals that it finds would result in retroactive ratemaking, including proposals related to the Fuel Switch Study and LTRP Deferral Account[244] and corrections related to 2015-2017 Pension Expense Deferral Account variances.[245] Among other reasons for the Panel’s denial of Creative Energy’s proposal for the proposed Core Stream DARR mechanism, Creative Energy has not provided any evidence that such mechanism is an accepted means of recovering pension, regulatory and other recurring non-controllable O&M cost variances.[246]

 

Compliance with BCUC Orders and Directives

 

The Panel recommends Creative Energy develop a process and dedicate sufficient resources to ensure BCUC orders are tracked and addressed in a complete and timely manner. If clarification of an order is needed or a request for variance from an order is sought, it should be done in a thorough and transparent way.

 

The Panel notes instances in this proceeding where significant follow-up on previous BCUC orders was required, including:

•         Not addressing the After-tax Regulatory Pension Asset Account as directed.[247]

•         Not initially addressing the Fuel Switch Study and LTRP Deferral Account in the Application as directed;[248]

•         Recording NEFC forecast variances that were directed to be included in the Variance Deferral Account in the RDDA without prior BCUC approval;[249] and

•         Not addressing the Panel’s request for submissions on whether forecast deferral treatment to capture steam load variances for the Core Steam System may be warranted considering recent variances between forecasts and actuals.[250]

 

Holistically and Comprehensively Considering Proposed Rate Design Changes

 

In the absence of a comprehensive rate design application, if Creative Energy proposes incremental rate design changes in future filings, it would be helpful to the BCUC and other parties if Creative Energy considers and communicates the regulatory justification for the proposal having considered cost causation and other rate design principles (eg., Bonbright) holistically, and taking into account the existing approved rate structure that the BCUC has already found to be not unjust, unreasonable, unduly discriminatory or unduly preferential.

 

In this Decision, the Panel finds Creative Energy has not provided sufficient justification for the proposed incremental rate design changes that fundamentally alter the rate treatment of certain Core Steam System O&M cost variances[251] and the treatment of NEFC fuel costs.[252] Furthermore, such rate design changes are not appropriate for consideration within the context of a revenue requirements application.

 

Ensuring the Accuracy, Completeness and Transparency of Accounting, Financial Schedules and Other Information

 

To ensure an effective and efficient review of an application, it is incumbent on Creative Energy to ensure the accuracy, completeness and transparency of the accounting, financial and other information included in an application.

 

The Panel notes instances in this proceeding where significant regulatory time and resources were necessary to follow-up on previous BCUC orders. These include:

•         The calculation and analysis of accounts related to pension expenses;[253]

•         The analysis of Fuel Switch Study and LTRP costs. The lack of transparency and clarity as to the nature and amount of the costs noted by the BCUC in its decision on the 2018-2022 RRA[254] resulted in the BCUC declining to make any determination regarding their recoverability in that proceeding and instead directing that the costs claimed be put into Fuel Switch Study and LTRP Deferral Account pending the filing of an updated LTRP or RRA. While Creative Energy has been more forthcoming and has provided more clarity relating to these costs in this proceeding, the examination of the issue relating to the proper disposition of these costs has taken longer than warranted; and

•         Corrections to capital additions related to the Remote Metering Project. During the proceeding and only in response to BCUC IRs, Creative Energy removed $293,666 of construction in process amounts from rate base and updated related calculations related to that project.[255]

 

Timeliness of Filings

 

By ensuring the timeliness of filings, Creative Energy can assist the BCUC and other parties in the effective and efficient review of applications. Timely filings allow all parties the opportunity to consider proposals prospectively and to ensure a utility is held accountable for its utility operations.

 

In addition to the comments above, in making its determination on the 2019 Core Steam Rates, the Panel finds, among other things, an unreasonable amount of time passed between Creative Energy’s filing for interim rates (December 14, 2018) and final rates (December 19, 2019).[256]

 

In consideration of the Panel’s comments in subsection 2.2 that rates should be set prospectively based on forecasts, the Panel directs Creative Energy to file its next two-year revenue requirements application for the Core Steam System by November 1, 2020 in order for the BCUC to review the application before the start of those years. As directed in subsection 5.1, Creative Energy must file a proposal for how rates should be set for 2021 for the NEFC by October 31, 2020 and a comprehensive proposal for NEFC rate design and for setting 2022 rates by June 30, 2021.

7.0              Summary of Approvals and Directives

This summary is provided for the convenience of readers. In the event of any difference between the directions in this summary and those in the body of the decision, the wording in the decision shall prevail.

	Directive	Page
1.	For the reasons outlined above, the Panel approves the 2019 interim rates as permanent.	13
2.	The Panel approves the continuation of the non-rate base Third Party Regulatory Cost Deferral Account for 2019.	13
3.	Therefore, the Panel directs that the following forecast variance amounts be recognized as additions to the TPRCDA:   2018 forecast variance of $207,659 plus interest; and 2019 forecast variance of $177,340 plus interest.	14
4.	For 2019, Creative Energy is directed to recognize amortization of 50 percent of the 2018 TPRCDA account balance or $103,830, plus interest.	14
5.	Accordingly, the Panel approves the continuation of the Pension Expense Deferral Account with a carrying cost equal to Creative Energy’s short-term debt rate, until otherwise determined by the BCUC. The Panel directs that the following forecast variance amounts be recognized as additions to the Pension Expense Deferral Account:   The 2018 forecast variance of $377,966 plus interest; and The 2019 forecast variance, based on the 2018 approved forecast, plus interest, as set out below.   Table 7 – 2019 Pension Expense Variances	14
6.	Therefore, Creative Energy is directed to record the following adjustments to the Pension Expense Deferral Account, effective 2019:   Table 8 – Offset of the 2018 and 2019 Remeasurement amounts	15
7.	Accordingly, Creative Energy is directed to amortize the 2018 current service costs variance of $25,735 recorded in the Pension Expense Deferral Account, plus interest, in 2019.	15
8.	Creative Energy is directed to file information in the next RRA detailing how other BC and Canadian regulated utilities treat pension remeasurement gains and losses for ratemaking purposes.	15
9.	Creative Energy is directed to reduce the allowed return for 2019 by $14,862 based on a mid-year After-tax Regulatory Pension Asset Account balance of $362,670.	16
10.	Accordingly, the Panel makes no determination on the Remote Metering Project or any of the costs associated with this project.	16
11.	The Panel approves the 2020 forecast revenue requirement of $9,086,328 subject to the adjustments directed below.	24
12.	The Panel approves the total 2020 steam load forecast of 1,140,634 thousand pounds of steam as requested by Creative Energy.	24
13.	The Panel approves the inclusion of NEFC in the Massachusetts Formula cost allocation.	25
14.	Accordingly, the Panel denies Creative Energy’s request for a two-factor Massachusetts Formula and approves the use of a three-factor Massachusetts Formula, beginning in 2020, based on the following factors: the average gross book value of capital assets or property, plant and equipment; salaries or direct labour expenses; and operating revenues.	25
15.	Creative Energy is directed to recalculate the costs allocated to the Core Steam System and NEFC, respectively, based on the three-factor Massachusetts Formula approved above in a compliance filing due to the BCUC within 30 days of the date of this decision (Compliance Filing), including the rate impact for each service area.	25
16.	Therefore, the Panel approves the 2020 forecast for outside services costs of $105,466 as requested by Creative Energy.	25
17.	The Panel approves the 2020 forecast steam production overtime expense.	25
18.	Creative Energy is directed to reduce the allowed return for 2020 by $21,503 based on a mid-year After-tax Regulatory Pension Asset Account balance of $268,202.	26
19.	The Panel approves the establishment of a non-rate base Water Cost Deferral Account to capture water cost forecast variances for the 2020 test year only.	29
20.	Creative Energy is directed to address the continued need for the Water Cost Deferral Account and to re-evaluate its water cost forecast methodology in its next revenue requirement application. Creative Energy must provide in that application information comparing the forecast, approved and actual historical water expenses and volumes to assist in the timely review of the application.	29
21.	The Panel also approves Creative Energy’s proposal for a one-year amortization period on the Water Cost Deferral Account commencing January 1, 2021, and a carrying cost equal to Creative Energy’s short-term debt rate, unless otherwise determined by the BCUC.	29
22.	The Panel approves the establishment of a non-rate base Property Tax Deferral Account to capture property tax forecast variances. The Panel also approves Creative Energy’s proposal for a one-year amortization period on the Property Tax Deferral Account commencing January 1, 2021 and a carrying cost equal to Creative Energy’s short-term debt rate on the mid-year value, unless otherwise determined by the BCUC.	30
23.	The Panel approves the continuation of the non-rate base Third Party Regulatory Cost Deferral Account for 2020 to capture third-party regulatory costs forecast variances.	31
24.	Accordingly, for 2020, the Panel approves a one-year amortization period for the TPRCDA, and Creative Energy is directed to recognize amortization of $281,170 plus interest for 2020.	31
25.	The Panel approves the continuation of the non-rate base Pension Expense Deferral Account for 2020 to capture pension expense forecast variances.	31
26.	Accordingly, for 2020, the Panel approves a one-year amortization period for the Pension Expense Deferral Account, and Creative Energy is directed to recognize amortization of $98,732 plus interest.	32
27.	For the reasons outlined above, the Panel denies Creative Energy’s request for permanent approval of its proposed DARR mechanism. Creative Energy is directed to provide, in its Compliance Filing the calculation of and proposed timing by which customers will be refunded the amounts collected in 2020 on an interim basis, plus interest, by way of bill credits. Creative Energy is also directed to record the amortization of the Pension Expense Deferral Account and Third Party Regulatory Costs Deferral Accounts in the revenue requirement for 2020 Steam Rates.	34
28.	Accordingly, the Panel denies Creative Energy’s request for approval to recover from customers of the Core Steam System the $214,185 spent in 2016, plus interest , along with Creative Energy’s request to defer the mechanism and timing for such recovery for determination in the 2021 RRA. Creative Energy is directed to write off these costs from the balance in the Fuel Switch Study and LTRP Deferral Account.	40
29.	[The Panel] directs Creative Energy to write off the amount of $103,536 plus interest from the balance in the Fuel Switch Study and LTRP Deferral Account as Creative Energy proposes.	40
30.	Accordingly, the Panel denies Creative Energy’s request to maintain the balance of $417,502 plus interest in the Fuel Switch Study and LTRP Deferral Account and to defer for consideration the disposition of such costs until such time as a CPCN for a low-carbon energy project is submitted and assessment of how much of the balance can be capitalized can be made. The Panel directs Creative Energy to write off the remaining balance from the Fuel Switch Study and LTRP Deferral Account to the account of the shareholder and further directs Creative Energy to close the deferral account thereafter.	41
31.	Based on the Panel’s determinations above, the Panel denies Creative Energy’s request for a 4.2 percent increase in 2020 Steam Rates. Instead, the Panel approves a rate increase inclusive of the impact of its decision above, including: Directive to recalculate the costs allocated to the Core Steam System and NEFC, respectively, based on the three-factor Massachusetts Formula approved above in its Compliance Filing and including the rate impact for each service area; Directive to reduce the allowed return for 2020 by $21,503, based on a mid-year balance of $268,202 in the After-tax Regulatory Pension Asset Account. Denial of the request for permanent approval of its proposed DARR mechanism; and Directive to record the amortization of the Pension Expense Deferral Account and Third Party Regulatory Costs Deferral Accounts in the revenue requirement for 2020 Steam Rates. Based on these adjustments, Creative Energy is directed to recalculate the rate increase and include the updated financial schedules in its Compliance Filing.	41
32.	The Panel approves Creative Energy’s request for permanent approval of NEFC’s 2019 interim hot water rates.	44
33.	Accordingly, the Panel approves the addition of a $373,900 revenue deficiency plus interest to the RDDA for 2018, consistent with the amount determined by the BCUC in 2017. For 2018, the Panel directs Creative Energy to file as part of its Compliance Filing the amount to be added to the Variance Deferral Account.	44
34.	Accordingly, the Panel denies Creative Energy’s request to transfer $661,861 from the Variance Deferral Account to the RDDA in 2019.	44
35.	Therefore, the Panel denies Creative Energy’s proposal to add the difference between the 2019 Actual revenue requirement and the revenues based on existing rates to the existing RDDA.	44
36.	Creative Energy is directed to recalculate the allocation of variances between the Variance Deferral Account and the RDDA based on the 2017 approved forecast. As part of its Compliance Filing, Creative Energy is also directed to include an updated schedule of the revised amounts in the Variance and Revenue Deficiency Deferral Accounts, reflecting the above and other determinations in this Decision.	44
37.	For the above-stated reasons, Creative Energy is directed to account for the NEFC underreported fuel cost charges of $497,728 due to the PARQ metering issue in the Core Steam System’s FCSA.	46
38.	Creative Energy is also directed to record the additional fuel costs in the NEFC Variance Deferral Account, consistent with other fuel cost variances.	46
39.	Creative Energy is directed to include in its Compliance Filing the detailed calculations supporting the 2019 Variance Deferral Account balance, including the details of the amount attributed to the PARQ metering issue.	47
40.	Creative Energy is directed to file a proposal for how rates should be set for 2021 by October 31, 2020. Creative Energy is also directed to file a comprehensive proposal for an NEFC rate design and for setting 2022 rates by June 30, 2021. Among other things, this application must address adjustments to the levelized rate necessary to reflect an updated hot water load forecast as well as the recovery mechanisms for the RDDA and Variance Deferral Account.	50
41.	Creative Energy is directed to add any 2020 forecast variances related to the Variance Deferral Account, as follows: Revenue shortfalls based on differences between actual revenues received and approved forecasts; Variances between forecast versus actual Steam Service Rates and Fuel Cost charged to NEFC; Variances between forecast versus actual Distribution expenses; and Variances between forecast versus actual Income Tax expense.	50
42.	In addition, the Panel approves the addition of variances between the approved revenue requirements and forecast revenues calculated based on approved rates to the RDDA. Further, the Panel extends approval of the Variance Deferral Account (which otherwise ends on December 31, 2020).	51
43.	The Panel approves the forecast revenue requirement of $2,330,926 for 2020 subject to the adjustments directed below.	51
44.	Creative Energy’s request to use a hot water load of 19,162 MWh for revenue requirement purposes is approved.	51
45.	The Panel also approves the NEFC 2020 Forecast O&M expenses, subject to the recalculation of costs which are allocated to the NEFC using the Massachusetts Formula as approved in Subsection 3.1 of this decision.	51
46.	Accordingly, the Panel approves a 10 percent rate increase for NEFC for 2020.	51
47.	Accordingly, the Panel denies Creative Energy’s request for an NEFC FCAC Rate Rider. Creative Energy is directed to provide, in its Compliance Filing, the calculation of and proposed timing, by which customers will be refunded for the interim amounts collected in 2020, plus interest, by way of bill credits.	53
48.	Accordingly, the Panel does not approve the 2015-2017 adjustments related to pension accounting discrepancies.	55
49.	The Panel directs Creative Energy to file its next two-year revenue requirements application for the Core Steam System by November 1, 2020.	57
50.	As directed in subsection 5.1, Creative Energy must file a proposal for how rates should be set for 2021 for the NEFC by October 31, 2020 and a comprehensive proposal for NEFC rate design and for setting 2022 rates by June 30, 2021.	57

 

 

 

Dated at the City of Vancouver, in the Province of British Columbia, this              2^nd            day of September 2020.

 

 

 

 

Original signed by:____________________________________

A. K. Fung, QC

Panel Chair / Commissioner

 

 

 

Original signed by:____________________________________

K. A. Keilty

Commissioner

 

 

 

Original signed by:____________________________________

E. B. Lockhart

Commissioner

 

Creative Energy Vancouver Platforms Inc.

2019-2020 Revenue Requirements Application for the

Core Steam System and Northeast False Creek Service Areas

 

2015-2017 Core Steam System Decision	Creative Energy 2015-2017 Revenue Requirements Application Decision and Order G-98-15 dated June 9, 2015
2015-2017 RRA	Creative Energy 2015-2017 Revenue Requirements Application
2016-2017 Core Steam System and NEFC Decision	Creative Energy 2016-2017 Revenue Requirements Application and Rate Design for NEFC Hot Water Service Decision and Order G-167-16 dated November 18, 2016
2016-2017 RRA	Creative Energy 2016-2017 Revenue Requirements Application and Rate Design for NEFC Hot Water Service Application
2018-2022 Core Steam System Decision	Creative Energy 2018-2022 Revenue Requirements Application Decision and Order G-205-18 dated October 26, 2018
2018-2022 RRA	Creative Energy 2018-2022 Revenue Requirements Application
Application	2019-2020 Revenue Requirements Application for the Core Steam System and Northeast False Creek Service Areas
ATCO	ATCO Gas and Pipelines v. Alberta (Utilities Commission)
BCUC	British Columbia Utilities Commission
Beatty Plant	Beatty Street Plant
Beatty-Expo CPCN	Creative Energy Application for a Certificate of Public Convenience and Necessity for Beatty-Expo Plants and Reorganization
CPCN	Certificate of Public Convenience and Necessity
CEC	Commercial Energy Consumers Association of British Columbia
CHDL	Central Heat Distribution Ltd.
Compliance Filing	Compliance filing due to the BCUC within 30 days of the date of this decision
Core Steam System	Core steam system
Creative Energy	Creative Energy Vancouver Platforms Inc.
Creative Energy Corp.	Creative Energy Platforms Canada Corporation
DARR	Deferral Account Rate Rider
FAES	FortisBC Alternative Energy Services Inc.
FBC	FortisBC Inc.
FCAC	Fuel Cost Adjustment Charge
FCSA	Fuel Cost Stabilization Account
HDD	Heating Degree Days
IR	Information Request(s)
LTRP	Long-Term Resource Plan
LTRP Application	2017 LTRP Application
M#	Thousand pounds
MW	Megawatt(s)
MWh	Megawatt hour(s)
NEFC	Northeast False Creek
O&M	Operating and Maintenance
RDDA	Revenue Deficiency Deferral Account
Reshape	Reshape Infrastructure Strategies
RFP	Request for Proposal
ROE	Return on Equity
RRA	Revenue Requirements Application
TES	Thermal Energy Systems
TES Regulatory Framework Guidelines	Thermal Energy Systems Regulatory Framework Guidelines established by Order G-127-14 and revised by Order G-27-15
TPRCDA	Third Party Regulatory Costs Deferral Account
UCA	Utilities Commission Act

 

 

 

 

IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

 

and

 

 

Creative Energy Vancouver Platforms Inc.

2019–2020 Revenue Requirements Application for

the Core Steam System and Northeast False Creek Service Areas

 

EXHIBIT LIST

 

Exhibit No.                                                                         Description

 

Commission documents

 

A-1	1.       Letter dated January 2, 2020 - Appointing the Panel for the review of Creative Energy Vancouver Platforms Inc. 2019–2020 Revenue Requirements Application for the Core Steam System and Northeast False Creek Service Areas
A-2	Exhibit removed and replaced by Exhibit A-2-1
A-2-1	Letter dated January 22, 2020 – Amended BCUC Order G-7-20A with reasons for decision establishing interim rates and regulatory timetable for the review of the Application
A-3	Letter dated February 21, 2020 – BCUC Order G-29-20 amending the regulatory timetable
A-4	Letter dated March 5, 2020 – BCUC issuing Information Request No. 1 to Creative Energy
A-5	Letter dated March 12, 2020 – BCUC issuing Information Request No. 1 for Fuel Switch Study and LTRP Deferral Account to Creative Energy
A-6	Letter dated April 21, 2020 – BCUC issuing Information Request No. 2 to Creative Energy
A-7	Letter dated May 1, 2020 – BCUC Order G-103-20 amending regulatory timetable
A-8	Letter dated May 12, 2020 – BCUC requesting information from Creative Energy regarding Final Arguments

 

 

Commission Staff documents

 

A2-1	Letter dated March 5, 2020 – BCUC staff filing Creative Energy Notes to Financial Statements dated December 31, 2018

 

Applicant documents

 

B-1	Creative Energy Vancouver Platforms Inc. (Creative Energy) - 2019–2020 Revenue Requirements Application for the Core Steam System and Northeast False Creek Service Areas dated December 19, 2019
B-1-1	Letter dated February 21, 2020 – Creative Energy Submitting Evidentiary Update to the Application
B-2	Letter dated February 20, 2020 – Creative Energy request extension to file proposal regarding Fuel Switch Study and LTRP Deferral Account
B-3	Letter dated February 27, 2020 – Creative Energy Submitting proposal regarding Fuel Switch Study and LTRP Deferral Account
B-4	Letter dated April 2, 2020 – Creative Energy Submitting responses to BCUC Information Request No. 1
B-5	Letter dated April 2, 2020 – Creative Energy Submitting responses to BCUC Information Request No. 1 on Fuel Switch Study and LTRP Deferral Account Proposal
B-6	Letter dated April 2, 2020 – Creative Energy Submitting responses to CEC Information Request No. 1
B-7	Letter dated April 2, 2020 – Creative Energy Submitting responses to CEC Information Request No. 1 on Fuel Switch Study and LTRP Deferral Account Proposal
B-8	Letter dated April 30, 2020 – Creative Energy Submitting an extension request to file Final Argument
B-9	Letter dated May 5, 2020 – Creative Energy Submitting responses to BCUC Information Request No. 2
B-10	Letter dated May 5, 2020 – Creative Energy Submitting responses to CEC Information Request No. 2

 

 

Intervener documents

 

C1-1	FortisBC Alternative Energy Services Inc. (FAES) – Letter dated January 23, 2020 request for Intervener Status by Grant Bierlmeier
C2-1	Commercial Energy Consumers Association of British Columbia (CEC) – Letter dated February 12, 2020 request for Intervener Status by David Craig and Christopher Weafer
C2-2	Letter dated March 12, 2020 – CEC Submitting Information Request No. 1 to Creative Energy
C2-3	Letter dated March 19, 2020 – CEC Submitting Information Request No. 1 to Creative Energy on Fuel Switch Study and LTRP Deferral Account Proposal
C2-4	Letter dated April 21, 2020 – CEC Submitting Information Request 2 to Creative Energy

 

 

 

Interested party documents

 

D-1	FortisBC Energy Inc. (FEI) - Submission dated January 23, 2020 Request for Interested Party Status

 

 

Letters of comment

 

E-1