On December 1, 2021 Creative Energy Vancouver Platforms Inc. (Creative Energy) filed with the British Columbia Utilities Commission (BCUC) its 2021 revenue requirement application (RRA) for the core steam system (Core Steam System), seeking permanent approval of 2021 steam rates (Core Steam Rates). Specifically, Creative Energy seeks approval of Core Steam Rates, effective January 1, 2021 based on an initial annual steam load forecast and March 31, 2021 based on an amended annual steam load forecast, respectively. Creative Energy also seeks certain BCUC approvals related to new and existing regulatory or deferral accounts for the Core Steam System. In addition, Creative Energy seeks approval of an Inter-Affiliate Conduct and Transfer Pricing Policy (IAC/TPP).

In this decision, the Panel addresses setting the 2021 Core Steam Rates. The balance of this application pertaining to the proposed IAC/TPP will be addressed in a separate decision to be issued by the Panel.

Creative Energy owns and operates several Thermal Energy Systems (TES). The Core Steam System is Creative Energy’s largest TES, being a steam production plant at 720 Beatty Street and the associated distribution network serving more than 200 buildings in downtown Vancouver and supplying thermal energy to Creative Energy’s Northeast False Creek (NEFC) hot water system.

Based on the key findings discussed below, the Panel approves a permanent 2021 average steam rate for the Core Steam System of $9.78 per thousand pounds of steam, effective January 1, 2021. The Panel makes the following key findings and determinations:

• The Panel denies Creative Energy’s request for approval of a permanent steam rates based on its initial annual steam load forecast of 1,142,658 thousand pounds of steam, effective January 1, 2021 and permanent steam rates based on the amended annual steam load forecast 971,259 thousand pounds of steam, effective March 1, 2021;

• An amended forecast steam load of 971,259 thousand pounds of steam is reasonable for the purpose of determining the 2021 average steam rate. The amended forecast steam load reflects the best information available at this time;

• Subject to the Panel’s determination regarding the recoverability of financing costs, the amended forecast Revenue Requirements as set out in Table 1 of this decision is a reasonable basis for setting the 2021 average steam rate; and

• The Panel approves Creative Energy including carrying costs based on an interest rate of 3.5 percent in all deferral accounts in the Revenue Requirement for the 2021 Test Year.

The table below sets out Creative Energy’s 2021 forecast revenue requirement, load forecast and resulting average steam rate compared to the 2020 approved average steam rates.

Final Revenue Requirement, Steam Load and Approved Average Steam Rate

2021 Proposed Amended Forecast Revenue Requirement (Table 1 of the Decision)	$ 9,747,889
Adjustment to Disallow Request to Recover Refinancing Costs from Steam Rates	247,957
Approved 2021 Revenue Requirement	9,499,932
2021 Amended Steam Load Forecast (thousand pounds of steam)	971,259
2021 Approved Average Steam Rate	$ 9.78

2020 Approved Average Steam Rate	$ 8.13
Average Steam Rate Increase	20.3%

The table above shows that the permanent 2021 average steam rate for the Core Steam System is equivalent to a 20.3 percent increase above the 2020 approved average steam rate. The Panel recognizes that the approved rate increase is significant, and exceeds the 10 percent typically considered to constitute rate shock. However, in the Panel’s view, it is appropriate to consider rate shock in terms of a ratepayer’s total bill, and not a specific component (the average steam rate) within the bill. Prior to the issuance of this decision, the BCUC approved in March 2021 the cancellation by Creative Energy the Fuel Cost Adjustment Charge (FCAC) Rate Rider of $4.40 per thousand pounds of steam, which is a component of fuel rates, effective February 28, 2021. The Panel notes that the cancellation of the FCAC Rate Rider will offset the steam rate increase. For context, Creative Energy estimated that its proposal for 2021 steam rates would be offset by the cancellation of the FCAC rate rider, resulting in a combined reduction in steam and fuel rates of 9.2 percent compared to 2020 approved rates, which is before adjustments made by the Panel in this decision.

The Panel also approves the following deferral account requests:

• To continue the Third Party Regulatory Costs Deferral Account on an ongoing basis to capture third party regulatory cost forecast variances, with the balance to be amortized over one year;

• To amend the amortization period for the Pension Expense Deferral Account from one year to three years;

• To continue the Water Cost Deferral Account until Creative Energy files its next RRA for the Core Steam System to capture water cost forecasts variances, with the balance to be amortized over one year; and

• To continue the Property Tax Deferral Account on an ongoing basis to capture property tax forecast variances, with the balance to be amortized over one year.

The Panel denies Creative Energy’s request to establish a Refinancing Cost Deferral Account (RCDA) and to include amortization of $247,957 in the 2021 Revenue Requirement. The Panel also denies Creative Energy’s request to use the RCDA to record 2021 credit facility renewal fees. This is based on the following findings:

• The refinancing costs which Creative Energy proposed to capture in the RCDA were a direct result of a specific corporate reorganization approved by the BCUC in 2020, and were not primarily incurred in the ordinary course of business.

• Given that Creative Energy stated the reorganization would not impact rates, the portion of refinancing costs directly attributable to the reorganization should not be recoverable from Creative Energy ratepayers.

Instead, Creative Energy is approved to add $22,436 (plus applicable interest) to the Fuel Cost Stabilization Account and to address the recovery of this amount by November 30, 2021 in an addendum to its next filing pursuant to BCUC Order G-84-21. Since one tranche of Creative Energy’s new HSBC/TD credit facility (Tranche Loan 1) specifically covers the balance of the Fuel Cost Stabilization Account, the Panel considers that the refinancing costs associated with this tranche are related to energy costs and it is appropriate to allocate that portion of the refinancing costs to Core Steam System ratepayers.

1.0 Introduction

On December 1, 2020, Creative Energy Vancouver Platforms Inc. (Creative Energy) filed with the British Columbia Utilities Commission (BCUC) its 2021 revenue requirement application (RRA) for the core steam system (Core Steam System). Creative Energy requests approval in the application of permanent 2021 steam rates (Core Steam Rates) for the Core Steam System based on a forecast cost of service or revenue requirement (Revenue Requirement) and steam load for 2021 (Application).^{^[1]} Creative Energy also seeks certain BCUC approvals related to new and existing regulatory or deferral accounts for the Core Steam System, within the context of setting the 2021 Core Steam Rates.

In addition, Creative Energy seeks approval in the Application of an Inter-Affiliate Conduct and Transfer Pricing Policy (IAC/TPP). Creative Energy states that the IAC/TPP applies to all BCUC-regulated thermal energy systems (TES) in the Creative Energy Group.[2] The Creative Energy Group refers to Creative Energy Developments Ltd. (CEDLP), BCUC-regulated TES owned and operated by Creative Energy, and BCUC-regulated TES that are subsidiaries of CEDLP.^{^[3]}

For clarity, this decision pertains specifically to setting rates for the Core Steam System. Creative Energy owns and operates several TES, of which the Core Steam System is the largest. The Core Steam System refers to the steam production plant at 720 Beatty Street and the associated distribution network serving more than 200 buildings in downtown Vancouver and supplying thermal energy to Creative Energy’s Northeast False Creek (NEFC) hot water system.^{^[4]}

In this decision, the Panel sets out the key issues to be decided, provides an overview of the relevant evidence, considers Creative Energy’s proposals, and outlines the reasons for the Panel’s determinations. Specifically, the Panel addresses the following key issues related to 2021 Core Steam Rates:

The reasonableness of the 2021 forecast Revenue Requirement and the initial and revised steam load forecasts for the purpose of setting the 2021 Core Steam Rates;
The appropriateness of Creative Energy’s requests related to deferral accounts; and
The determination of just and reasonable 2021 Core Steam Rates.

The balance of this Application pertaining to the proposed IAC/TPP will be addressed in a separate decision to be issued by the Panel.

1.1 Background

Organization Structure

On March 5, 2020, the BCUC approved, subject to certain conditions, Creative Energy’s Application for a Certificate of Public Convenience and Necessity (CPCN) for the Expo-Beatty Plants and Reorganization (Expo-Beatty Plants CPCN and Reorganization Decision).^{^[5]} Since that time, Creative Energy has remained a wholly-owned subsidiary of CEDLP. CEDLP is a partnership of Creative Energy Canada Platforms Corps. and Emanate Energy Solutions Inc., which are subsidiaries of Westbank Holdings (Westbank) and InstarAGF Essential Infrastructure Fund (InstarAGF), respectively.^{^[6]}

As noted above, Creative Energy owns and operates several TES, of which the Core Steam System is the largest. In addition to the TES owned and operated by Creative Energy, its parent company CEDLP identifies, develops and finances potential new district energy project opportunities in British Columbia (BC) and Ontario. For those projects that will proceed forward to construction and/or application for regulatory approvals as required, CEDLP establishes a separate wholly owned subsidiary limited partnership or company to pursue the individual project and construct and operate the TES project.^{^[7]}

Figure 1 below shows the current organization chart for CEDLP and Creative Energy:

Figure 1: CEDLP and Creative Energy Organization Chart^{^[8]}

Diagram

Description automatically generated

Although the Core Steam System is not a stand-alone legal entity, its revenue requirement and rates are determined on a separate basis.^{^[9]} The Core Steam System’s rate structure consists of steam rates and a Fuel Cost Adjustment Charge (FCAC) and FCAC Rate Rider. Steam rates are tiered, and customers are charged based on the volume of steam consumed per month. There are four tiers of steam rates priced per thousand pounds of steam on a declining block rate structure (i.e. higher consumption leads to lower price per unit). The FCAC and FCAC Rate Rider are a flat charge to customers per thousand pounds of steam consumed.^{^[10]}

This Application is filed in accordance with the BCUC’s decision on the Creative Energy 2019-2020 RRA for the Core Steam System and Northeast False Creek service areas (2019-2020 RRA Decision) directing Creative Energy to file, by December 1, 2020, a one-year RRA for the Core Steam System.^{^[11]}

COVID-19 Global Pandemic

On May 29, 2020, Creative Energy filed with the BCUC a COVID-19 Deferral Account Application seeking, among other things, approval to establish a COVID-19 Deferral Account for the Core Steam System. The BCUC approved the requested deferral account on August 14, 2020 to record the following:

Any incremental, unplanned expenses and cost savings related to the COVID-19 pandemic that Creative Energy has incurred related to continuing safe and reliable operations, tracked by expense category, including any incremental financing costs;
Any unrecoverable revenues (bad debt) resulting from customers that do not pay their bills due to the impacts of COVID-19 on their financial circumstances; and
Any direct revenue loss resulting from the loss of load from customers due to the impacts of COVID-19 on their operational and financial circumstances. The revenue loss is to be calculated based on the final 2020 steam load forecast for the Core Steam System approved in the Creative Energy 2019-2020 RRA.^{^[12]}

The BCUC directed Creative Energy to file an application for recovery of the amounts that accrue to the COVID-19 Deferral Account in either its next RRA (which is this current Application) or the following RRA at the latest.^{^[13]} Creative Energy does not propose recovery of the COVID-19 Deferral Account in the 2021 RRA, given the ongoing uncertainty and impact of the COVID-19 pandemic.^{^[14]}

FCAC Rate Rider

On October 25, 2019, the BCUC approved an FCAC Rate Rider of $4.40 per thousand pounds of steam, effective November 1, 2019.^{^[15]}

On February 26, 2021, Creative Energy filed with the BCUC an application seeking, among other things, approval of the cancellation of the FCAC Rate Rider, effective February 28, 2020 (FCAC Rate Rider Application). The FCAC Rater Rider Application was reviewed in a separate proceeding.

On March 18, 2021, the BCUC approved, among other things, changing the FCAC Rate Rider from $4.40 per thousand pounds of steam to $0.00 per thousand pounds of steam, as requested.^{^[16]}

1.2 Application and Approvals Sought

As mentioned above, Creative Energy filed the Core Steam System’s 2021 RRA with the BCUC and subsequently supplemented that filing with additional information^{^[17]} and evidence set out in an Evidentiary Update and responses to information requests (IRs).^{^[18]}

Creative Energy seeks permanent approval for 2021 Core Steam Rates, as follows:

Core Steam Rates based on Creative Energy’s 2021 Revenue Requirement proposals and an initial annual steam load forecast of 1,142,658 thousand pounds of steam, effective January 1, 2021;^{^[19]} and
Core Steam Rates based on Creative Energy’s 2021 Revenue Requirement proposals and a revised annual steam load forecast of 971,259 thousand pounds of steam, effective March 1, 2021.^{^[20]}

Creative Energy confirmed its approvals sought above, explaining that it is seeking different permanent rates for each of January 2021 through February 2021 and March 2021 through December 2021.^{^[21]} The utility’s reasons for seeking two different permanent rate approvals is discussed further in Subsection 2.4 of the decision.

Creative Energy also seeks approval of the following related to its non-rate base deferral accounts for the Core Steam System:

A Third-Party Regulatory Cost Deferral Account (TPRCDA) on an ongoing basis to capture the annual variance between forecast and actual third-party costs relating to regulatory filings and proceedings required under the Utilities Commission Act (UCA);
A Water Cost Deferral Account (WCDA) to record variances between total annual actual versus forecast water costs for the Core Steam System for 2021;
A Property Tax Deferral Account (PTDA) on an ongoing basis to record variances between total annual actual versus forecast property taxes for the Core Steam System;
A Refinancing Cost Deferral Account (RCDA) to record in 2020 and recover in 2021 Core Steam Rates the cost to refinance Creative Energy’s debt facilities in 2020;^{^[22]} and

• Changing the amortization period of an existing Pension Expense Deferral Account (PEDA) from one year to three years.^{^[23]}

Finally, Creative Energy filed for approval of an IAC/TPP Policy in respect of all entities in the Creative Energy Group that are subject to regulation by the BCUC.^{^[24]} As noted above in this decision, the BCUC’s final determination on the proposed IAC/TPP will be addressed as part of a separate decision

1.3 Legislative and Regulatory Framework

Creative Energy filed the Application pursuant to sections 58 to 60 UCA. The UCA sets out the framework for approval of rates which includes, in part, the following:

Section 59(5) defines what an “unjust” or “unreasonable” rate is 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;
Sections 58 and 60 authorize the BCUC to establish rates and include mandatory considerations, including the requirement that rates not be “unjust, unreasonable, unduly discriminatory or unduly preferential;” and
Section 60(1)(b.1) 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 conducted its review of the Application based on the legislative authority in the UCA, using a traditional Cost of Service (COS) approach. A COS approach is consistent with the rate setting method used in the 2019-2020 RRA Decision. To apply this COS approach, the Panel must first determine Creative Energy’s total revenue requirement or its “cost of service.” A utility’s revenue requirement reflects the total amount of revenue that must be collected in rates to recover its costs and provide the utility with an opportunity to earn a reasonable return on its invested capital or its return on equity (ROE). This COS approach links rates to recovery of the operating and capital costs based on forecast revenues and costs. The COS elements of a forecast revenue requirement include the following basic components:

• Reasonable and necessary costs;

• Return of investment through recovery of depreciation expense; and

• Return on investment through an allowed rate of return on invested capital.

Under a COS approach, revenue and cost components that are outside a utility’s control may be handled through regulatory accounts and deferral mechanisms designed to capture and flow through forecast variances to future rates.

1.4 Regulatory Process

In accordance with the regulatory timetables established by the BCUC, we reviewed this Application by way of a public written hearing which included two rounds of BCUC and intervener IRs and written final and reply arguments.^{^[25]} Additionally, by letter dated August 18, 2021, the Panel issued IRs (Panel IRs) requesting Creative Energy to provide additional information and further clarification on the refinancing fees and proposed RCDA. The Panel also requested parties to provide written supplementary final and reply arguments related to the responses to the Panel IRs.[26]

The following three interveners registered and actively participated in the proceeding:

Residential Consumer Intervenor Association (RCIA, formerly Residential Consumer Intervenor Group – RCIG);
Commercial Energy Consumers Association of British Columbia (CEC); and
BC Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations of BC, Disability Alliance BC, and Tenant Resource and Advisory Centre (BCOAPO).

The BCUC did not receive any letters of comment.

On January 13, 2021, the BCUC approved 2021 Core Steam Rates on an interim and refundable/recoverable basis as set forth in Appendix B of the Application and equivalent to a 6.9 percent increase above 2020 Approved rates, effective January 1, 2021.^{^[27]}

On March 22, 2021, the BCUC approved a 17.5 percent increase in Core Steam Rates over existing 2021 interim Core Steam Rates on an interim and refundable/recoverable basis, effective March 1, 2021.^{^[28]}

2.0 2021 Revenue Requirement and Average Steam Rate Increase

In this section, the Panel reviews Creative Energy’s 2021 forecast Revenue Requirement and 2021 load forecast in the context of setting Core Steam Rates. As noted above, the Panel must determine if the forecast Revenue Requirement appropriately reflects the total amount of revenue that must be collected in rates for Creative Energy to recover its forecast costs of service and to provide it an opportunity to earn a reasonable return.

2.1 2021 Revenue Requirement

Creative Energy’s amended forecast 2021 Revenue Requirement^{^[29]} of approximately $9,748,000 for the Core Steam System, is set out in Table 1 below.

Table 1 – 2021 Forecast Revenue Requirement

Component	2020 Approved^{^[30]}	2021 Amended Forecast^{^[31]}	Preliminary 2020 Actual Information^{^[32]}

Operation and maintenance expenses
Wages and benefits	$2,966,181	$3,388,392	$2,957,558
Water and electricity	991,046	929,937	983,021
Maintenance and related functional operations	499,108	535,862	528,750
Special services	313,215	305,604	290,030
Other general & administration and sales expense	324,678	279,846	315,269
Total operation and maintenance expenses	5,094,228	5,439,641	5,074,628

Municipal access fees or taxes	280,287	287,137	263,913

Non-operating and other
Property taxes	763,300	729,600	763,300
Income taxes	291,500	294,500
Depreciation	962,484	967,090	976,643
Amortization of deferral accounts	210,835	332,921	210,835
Interest expense	607,000	617,000	462,631
Allowed ROE	1,061,001	1,080,070
Total non-operating and other	3,896,120	4,021,111

Total Revenue Requirement	$9,270,635	$9,747,889

Creative Energy forecasts an increase in its 2021 Revenue Requirement of approximately $461,000, or 5 percent, compared to the 2020 approved amount. Creative Energy submits that the increase is primarily driven by:

Higher wages and benefits expense of $422,211 to ensure that Creative Energy has the resources and staff complement necessary to meet current and emerging priorities for safe and reliable service and to ensure the resiliency of the utility in the future.^{^[33]} Creative Energy states that three new positions in management category roles (new management positions) are anticipated for 2021, resulting in a net increase in wages and benefits expense $308,000. The remainder of the increase relates to salary increases and a forecast increase in the amount of directly charged time to the Core Steam System for existing staff;^{^[34]} and
Higher amortization of existing and proposed regulatory deferral accounts of $122,086 which relates to variances in regulatory costs between 2020 Approved and Actual and the recovery of deferred refinancing fees captured in a proposed Refinancing Cost deferral account.^{^[35]}

The increase is partially offset by a reduction in water and electricity expenses for steam production of $61,109 which considers the impacts of the COVID-19 pandemic on the 2021 load forecast.^{^[36]}

Below, the Panel reviews issues related to the new management positions, distribution team costs included in wages and benefits, water and electricity expenses, depreciation, property taxes, cost of debt and allowed ROE included in the 2021 forecast Revenue Requirement. The Panel addresses Creative Energy’s proposals regarding a Refinancing Cost deferral account in Subsection 2.2.6 and the 2021 load forecast in Subsection 2.4.

2.1.1 New Management Positions

As noted above, Creative Energy describes three additional management positions included in the 2021 forecast,^{^[37]} as follows:

A “Director of Partnerships” role for the purpose of growing the Core Steam System customer base and retaining existing customers;^{^[38]}
A “Systems Engineer” role to assess maintenance needs and determine opportunities for efficiency improvements for Creative Energy’s TES, including the Core Steam System;^{^[39]} and
An “Accountant” role to support the increased complexity and volume of Creative Energy’s regulatory, operational analysis and financial reporting requirements over the last decade.^{^[40]}

Creative Energy outlines that the Director of Partnerships will liaise with potential new developments or existing buildings in downtown Vancouver to create value propositions and negotiate with potential customers to connect to the Core Steam System.^{^[41]} Creative Energy stated that this position was filled in January 2021 and that 100 percent of the Director of Partnerships’ time and the associated cost is allocated to the Core Steam System.^{^[42]}

With respect to the Systems Engineer, Creative Energy expects to complete the hiring process for this position in April 2021. Creative Energy forecasts that 50 percent of the System Engineer time will be allocated to Creative Energy and proposes that the associated cost be allocated across all Creative Energy TES, including the Core Steam System, using the Massachusetts Formula.^{^[43]}

Creative Energy stated that the Accountant role was filled in December 2020. 80 percent of the Accountant’s time is forecast to be allocated to Creative Energy’s various TES for 2021 and the remaining 20 percent is allocated to CEDLP. Consistent with the treatment of the costs for the Systems Engineer, Creative Energy proposes that the corresponding costs for 80 percent of the Accountant’s time be allocated across all Creative Energy’s TES, including the Core Steam System, using the Massachusetts Formula.^{^[44]}

For 2021, Creative Energy stated the Core Steam System’s portion of allocated costs, as amended, using the Massachusetts Formula is 76.1 percent.^{^[45]} The net increase in wages and benefits expense for the Core Steam System related to the three new positions is $308,000.^{^[46]}

Positions of the Parties

RCIA submits that the three new positions have not been adequately justified and the costs associated with these positions should be excluded from rates as they do not produce a net benefit for ratepayers.^{^[47]}

The CEC submits that it is not appropriate for the utility to be adding employees and requesting a significant rate increase when customers are reducing load due to the COVID-19 pandemic. The CEC recommends that the BCUC deny a significant portion of the costs for staffing overall and, specifically, the addition of the three new staff positions.^{^[48]}

BCOAPO does not comment specifically on the new positions but notes that the primary driver in 2021 steam rate increases flows from forecasted increases associated with staff additions and load decreases.^{^[49]} BCOAPO views that active and proactive management of operating costs is required to alleviate future rate pressures on customers and recommends that the BCUC direct Creative Energy to incorporate, as part of future RRAs, productivity targets and measures for cost control.^{^[50]}

In reply, Creative Energy states that the drivers for the cost increases are business needs and operational requirements and should not be viewed as a producing a direct value for ratepayers.^{^[51]} The objective of the new positions is to ensure safe and reliable service which is independent from the impact of the COVID-19 pandemic on steam load.^{^[52]} Creative Energy submits that it is “a lean organization consisting of a small number of employees” and considers that there is no incremental value to introducing productivity targets and measures for operating costs as BCOAPO suggests.^{^[53]}

Panel Discussion

The Panel finds the forecast costs associated with the new management positions to be necessary to ensure Creative Energy continues to be able to provide safe, reliable service and cost-effective service and the forecast new management position costs provide a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. Creative Energy has adequately outlined the business imperatives driving the requirement for these new management positions. Creative Energy has demonstrated the costs are necessary to appropriately address both longer-term issues that could impact the viability of the utility as well as the increasing complexity and operational requirements of TES within the Creative Energy group.

The Panel disagrees with the CEC’s position that is not appropriate for the utility to be adding employees due to the impacts of the COVID-19 pandemic. As Creative Energy points out, the need for these positions is independent of the expected load reduction resulting from the COVID-19 pandemic.

Further, the Panel disregards RCIA’s view that the justification for the new positions is inadequate since they do not produce a net benefit for ratepayers. Producing net benefits to ratepayers is not the sole determinant of whether the costs are reasonable and necessary for ensuring safe and reliable service.

Regarding BCOAPO’s suggestion to introduce productivity targets and measures for operating costs, the Panel notes that Creative Energy is a small utility with limited resources. This results in a larger cost impact when a few new positions are added. The Panel agrees with Creative Energy that adding targets and measures for a small number of employees would be excessive and unlikely to provide value.

2.1.2 Distribution Team Costs

Gross forecast distribution team wages and benefits costs for Creative Energy are $1,168,489 of which $727,253 has been allocated to the Core Steam System, representing approximately 21.5 percent of forecast wages and benefits for 2021.^{^[54]} A comparison of forecast to actual distribution team wages and benefits and the calculated variances for 2017 to 2021 are set out in the following table.

Table 2 – Forecast and Actual Allocation of Distribution Team Costs^{^[55]}

	2017	2018	2019	2020	2021
Allocation to the Core Steam System
Actual	472,113	592,644	592,563	715,176
Approved Forecast^{^[56]}	451,400	549,834	549,834	662,757	727,253
Variance	20,713	42,810	42,729	52,419
Allocation to Other TES
Actual	45,126	104,741	140,288	198,287
Forecast	88,192	159,400	108,333	238,885	441,236
Variance	(43,066)	(54,659)	31,955	(40,598)
Unallocated Creative Energy Gross Costs
Gross Actual	517,239	697,385	732,851	913,463
Gross Forecast	539,592	709,234	658,167	901,642	1,168,489
Variance	(22,353)	(11,849)	74,684	11,821

Core Steam System % of Total Gross
Actual	91%	85%	81%	78%
Forecast	84%	78%	84%	74%	62%

Creative Energy states that the forecast costs are allocated to each TES based on management’s best estimate of the level of attention each system is expected to require for the next year, which is partially informed by the actual time spent on that system in the previous year. As it has added new TES each year, Creative Energy submits that it takes time to develop a history for how much time those systems will require, particularly in the early years. For 2020, Creative Energy states that it overestimated the amount of time that would be allocated to other TES, resulting in higher actual cost for the Core compared to forecast.^{^[57]}

Compared to the 2020 Approved amount, Creative Energy states that distribution team wages and benefits for 2021 are planned to increase by approximately 10 percent. Approximately 1.8 percent of the increase relates to a union approved annual wage increase and the remainder is driven by the forecast direct allocation of time required to service the Core system in 2021 versus other TES in 2021. Creative Energy points out that a comparison of 2020 actuals to the forecast highlights that more distribution team time was spent on the Core system in 2020 than was approved in the 2020 rate and the 2021 budget has been adjusted on this basis as similar levels of relative effort and attention to the Core system are expected going forward.^{^[58]}

Creative Energy explains that distribution team wages and benefits are forecast assuming that the Core Steam System is the “default” system^{^[59]} in that distribution team members do not prepare timesheets when working on the Core Steam System but prepare timesheets when working on all other TES in the Creative Energy group.^{^[60]}

Creative Energy elaborates on the forecast methodology stating that the gross forecast distribution team labour cost is management’s best estimate of the level of attention each TES is expected to require for the next year as informed by the actual time spent on a system from the prior year.^{^[61]} To determine the amount charged to the Core Steam System, Creative Energy states that the hours worked on other TES are multiplied by an hourly labour rate based on an average distribution team member’s salary and benefits and subtracted from the gross forecast distribution team cost.^{^[62]} In Creative Energy’s view, this is the most efficient way of allocating gross forecast distribution team costs in order for the allocated costs to add up to the total and this approach is reflected in and consistent with the “Directly Assignable Costs” section of the Creative Energy’s proposed IAC and TPP.^{^[63]}

Positions of the Parties

In order to achieve the algebraically required total sum of staff costs, RCIA submits that employees should be required to charge their hours for work done directly on any particular system, including the Core Steam System, and to separately keep track of non-assigned hours and distribute those hours among the different systems on a pro-rata basis. RCIA submits that this will avoid the Core Steam System’s ratepayers’ having to absorb the cost of all non-productive and overhead-related staff operational costs for the entire Creative Energy group of systems.^{^[64]}

The CEC recommends that the BCUC direct Creative Energy to stop utilizing the Core Steam System as a default system.^{^[65]} The CEC submits Creative Energy should provide direct accounting of wages and benefits by documenting direct time to all systems, including the Core Steam System, and proportionally allocating any variance between direct time recorded and total time spent to all systems.^{^[66]}

In reply, Creative Energy submits that requiring the distribution team to track and charge their time working on the Core Steam System would increase costs by making more work for the distribution team and lead to extra reconciliation work for accounting and administration staff.^{^[67]} Creative Energy clarifies the use of the term “default” was to simply explain the budgeting and cost allocation process for Distribution team costs and not the Core Steam System generally.^{^[68]} Accordingly, Creative Energy disagrees with the comments and suggestions of RCIA and the CEC.

Panel Discussion

The Panel finds the forecast distribution team costs provide a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. The amount of forecast distribution team cost allocated to the Core Steam System of approximately $727,000 is comparable to the 2020 actual costs and the proposed increase over 2020 of approximately $12,000 is less than inflation. The Panel notes that while there has been some variation in forecast versus actual costs over the last few years, but for the last three years, actual expenditures have exceeded the forecast amount included in approved Revenue Requirements.

The Panel acknowledges the concerns raised by RCIA and the CEC about using the Core Steam System as the “default” and their suggestions that Creative Energy implement a timekeeping system for distribution team costs that tracks all time so that unassigned time can be proportionately allocated to the different TES. However, the Panel agrees with Creative Energy that such a system would be more costly to administer and may not result in any significant improvement in the reasonableness of the forecast allocation. Accordingly, the Panel considers that directing Creative Energy to implement a timekeeping system to track unassigned time is unwarranted at present.

2.1.3 Water and Electricity Expenses

The amended 2021 forecast water and electricity expenses are $712,192 and $94,009, respectively.^{^[69]} Creative Energy stated that it reduced its forecast to reflect the 15 percent reduction in load due to the impact of the COVID-19 pandemic. ^{^[70]} The Panel reviews the amended load forecast in Subsection 2.4 of this decision.

Forecast water cost increases are driven largely by City of Vancouver water rate increases, which are unknown at the time of the RRA filing. Creative Energy states its water cost forecast method anticipates an increase in City of Vancouver water rates of 8.5 percent, which is the average increase in water rate over the last three years. Creative Energy’s forecast methodology for water expenses is based on historical data from 2018–2020 to project the volume of water required for each thousand pounds of steam sold. Water consumption is projected using the average ratio of pounds of steam sold for every pound of water consumed. The projected volume of water is multiplied by the forecast 2021 City of Vancouver water rate.^{^[71]}

Creative Energy states it has made refinements to the water cost model for the 2021 RRA and believes it is a more accurate estimate than the 2020 RRA.^{^[72]} Regarding its improved water forecasting methodology, Creative Energy states:

The ratio of units of water to [thousand pounds of steam] is not linear. Both models take into account that at certain times of the year the ratio of units of water to [thousand pounds of steam] will be higher and certain times of the year it will be lower. This is important as the rates also differ based on high season and low season and load is seasonal. Having more data points was particularly helpful for determining the impact of seasonality on the ratio.^{^[73]}

Notwithstanding, Creative Energy submits that uncertainty in water costs remains and requests variance treatment on the forecast amount through continuation of the WCDA for 2021.^{^[74]} The Panel addresses Creative Energy’s request for a WCDA to record variances between 2021 actual versus forecast water costs in Subsection 2.2.4.

Forecast electricity costs are based on British Columbia Hydro and Power Authority’s (BC Hydro) Large General Service Rate Schedule 1611 for the 2021 year. Electricity costs consist of demand charges and energy charges. Creative Energy uses an estimate of historical peak demand by month to forecast demand charges, and an estimate of the ratio of electricity consumption to steam production to forecast energy costs.^{^[75]}

To the extent that electricity costs in 2021 are lower than forecast due to the COVID-19 pandemic, Creative Energy submits that it would be reasonable to pass on the savings to customers via the COVID-19 deferral account. Consequently, Creative Energy has not applied for separate approval of a variance deferral account to capture forecast variances in electricity costs for 2021.^{^[76]}

Positions of the Parties

The CEC submits it would be appropriate to modify water and electricity costs to match the load forecast, regardless of whether they are captured in a deferral account or not.^{^[77]} The CEC recommends that, were the BCUC to approve a reduced load forecast for setting rates, it should also approve proportionately reduced electricity and water costs.^{^[78]}

In reply, Creative Energy states that it accepts to the reasonableness of adjusting water and electricity costs in line with the reduction in load forecast for March through December 2021. Creative Energy proposes that the reductions of $125,000 in water costs and $10,000 in electricity costs be confirmed in a compliance filing.^{^[79]}

Panel Discussion

The Panel finds the amended forecast water and electricity expenses reflected in Table 1 provide a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. While there is uncertainty in the forecast amounts as discussed in Subsection 2.2.4, Creative Energy continues to make improvements in its forecast methodology and bases its projections on appropriate historical data and using a forecast 2021 Vancouver water rate.

The Panel agrees with the CEC’s suggestion that it is appropriate for Creative Energy to amend its water and electricity forecast proportionately to reflect the expected reduction in the load forecast due to the continuing effects of the COVID-19 pandemic. Creative Energy did not propose an adjustment for the January and February 2021 COVID-19 impacts but the Panel considers that since the majority of any variance for this period will be recognized in the Water Cost variance account, further adjustment is not necessary. The Panel’s determination on the load forecast is included in Subsection 2.4.

2.1.4 Property Taxes

Property taxes are paid to the City of Vancouver for the properties located at 720 Beatty Street and 701 Expo Boulevard.^{^[80]} For 2021, Creative Energy includes property taxes of $729,600 in the forecast Revenue Requirement which is based on the 2020 actual assessment value of the properties and increasing the 2020 tax rates by 2 percent.^{^[81]}

Creative Energy stated that it has historically considered property taxes to be solely attributable to the Core Steam System and does not allocate any amounts to other affiliates or TES.^{^[82]} Notwithstanding, in this proceeding Creative Energy confirmed that some employees who work at the office located at 720 Beatty Street do allocate time to other systems.^{^[83]} Creative Energy determined that office staff use approximately 4,000 square feet of the space at 720 Beatty Street (which accounts for $26,000 of the gross property taxes) and calculated that $15,990 (of the $26,000) can be allocated to other TES, capitalized to projects or charged to CEDLP.^{^[84]} Creative Energy states that it would be amenable to an adjustment to its 2021 forecast Revenue Requirement to reflect this allocation.^{^[85]}

In 2020, the BCUC approved Creative Energy’s transfer of the development rights of 720 Beatty Street and 701 Expo Boulevard which are surplus to the needs of the utility to a developer for the construction of an office building and related improvements.^{^[86]} Based on the Trust Agreement between Creative Energy and the developer, Creative Energy submitted that property taxes will be equitably apportioned between the parties based on floor space usage and any increase in property taxes as a result of property rezoning will be allocated to the developer.^{^[87]} For 2021, Creative Energy stated that the developer has not yet begun to use any floor space and Creative Energy is not able to estimate the amount of space that will be used by the developer nor the number of months during the year, if any, that the developer will be using that space.^{^[88]} In addition, Creative Energy submitted that the rezoning has not occurred.^{^[89]} Accordingly, there is no adjustment to Creative Energy’s 2021 forecast property taxes for these considerations.

Given that property taxes are challenging to budget, Creative Energy seeks BCUC approval of a Property Tax deferral account for 2021. We discuss Creative Energy’s proposal for forecast variance treatment of property tax variances in Subsection 2.2.5.

Positions of the Parties

RCIA and the CEC support the allocation of property tax to different service areas and affiliates,^{^[90]}and RCIA submits there should be an additional requirement that future allocations be based on actual time allocations.^{^[91]}

The CEC also submits it would be unfair and unreasonable for the developer not to be responsible for some of the property taxes. Therefore, the CEC recommends that the BCUC allocate a portion of the property costs to the redevelopment project, in proportion between the utility and the redevelopment values, and request that this information be provided as part of the final compliance filing.^{^[92]}

In Reply Argument, Creative Energy reiterates that the developer has not initiated any change to the land in relation to its acquisition of the beneficial interest and the Trust Agreement protects Creative Energy from being responsible for any property tax increase due to the change in use or value of the land.^{^[93]} Creative Energy submits it continues to use the land during 2021 for the same utility purposes as it did in previous years.^{^[94]} Creative Energy states its future considerations will include reduction of associated property taxes.^{^[95]}

Panel Determination

The Panel finds the amended forecast property taxes provide a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. The amount included in the proposed 2021 Revenue Requirement of $729,600 is reasonable compared to the 2020 amount of $763,300. The 2021 forecast also appropriately reflects an amendment to allocate a portion of property tax to other affiliated TES. Further, even though the beneficial ownership of the property was transferred to a developer in 2020, no change in use of the land will occur for 2021 and the Core Steam System will continue to use the property as it has in prior test periods. Therefore, the transfer of beneficial ownership will have no impact on Creative Energy’s current use of the property in 2021.

The Panel acknowledges the CEC’s submission that a portion of the property taxes should be allocated to the redevelopment project. However, for the 2021 Test Period, Creative Energy has asserted that the developer is not yet using any of the floor space of the property, rezoning has not yet occurred and there is no expected change of use by the Core Steam System in 2021. Further, the Trust Agreement between Creative Energy and the developer which was filed previously with the BCUC addresses how the property taxes will be apportioned between the parties based on floor space usage as well as how any increase in property taxes because of property rezoning will be allocated to the developer. The Panel notes that that Creative Energy states its future considerations will include reduction of associated property taxes. Accordingly, the Panel directs Creative Energy to address the appropriate allocation of property taxes in its next revenue requirement application.

The Panel notes that the 2021 forecast property taxes are based on the 2020 assessment with an estimated 2 percent increase over the 2020 rate. The Panel addresses the appropriateness of Creative Energy’s request for forecast variance treatment in Subsection 2.2.5.

2.1.5 Depreciation and Capital

Creative Energy forecasts 2021 capital additions of $1,914,085 for the Core Steam System as shown in Table 3 below.

Table 3 – 2021 Forecast Capital Additions^{^[96]}

Table

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Creative Energy submits that the forecast capital additions represent regular upgrades that are a long-term betterment to the property and the Beatty Plant. Creative Energy states that distribution capital additions, which comprise most of the forecast additions in 2021, pertain largely to the rebuilding, insulating and restoration of manholes.^{^[97]}

The impact of the forecast 2021 capital additions on deemed interest and allowed ROE for the 2021 forecast Revenue Requirement is approximately $22,000 and $39,000, respectively.^{^[98]} There is no depreciation expense associated with 2021 capital additions in the 2021 forecast Revenue Requirement.^{^[99]}

Creative Energy submits its capital additions forecast is founded upon an established capital planning process and risk management framework. Creative Energy states it takes a rigorous, formal approach to risk management, in line with best practices established by the Project Management Institute. For each risk Creative Energy assesses likelihood and consequences, implements mitigation measures, and monitors and manages risks and outcomes on an ongoing and iterative basis.^{^[100]}

Creative Energy outlines that the forecast capital additions included in its revenue requirements applications reflect a “snapshot” at a point in time of its capital project planning and prioritization processes. Subsequently, projects continue to advance through the planning process and will often move to implementation sooner or later than originally forecast based on prioritisation, considering factors such as urgency, the customer development schedule, and resource availability. Accordingly, Creative Energy submits that variances between forecast and actual capital additions primarily relate to the timing of when an asset is put into service and are not manifestations of project execution risks. To mitigate the impacts on the forecast revenue requirement, Creative Energy states that it does not commence depreciation on capital additions until the year after the assets are placed into service.^{^[101]}

For 2020, Creative Energy advises that it spent approximately $629,000 less than its 2020 forecast Projected capital additions.^{^[102]} Creative Energy submits that cost savings on ROE and interest of approximately $19,000 that arose from the variance will be returned to customers during the disposition of the existing COVID-19 deferral account. Customers will not receive any depreciation savings because depreciation is only included in the revenue requirement in the year after the addition is made based on actuals.^{^[103]}

Positions of the Parties

BCOAPO ^{^[104]} and RCIA^{^[105]} submit concerns with respect to Creative Energy’s capital planning, cost management and project execution process. RCIA submits the evidence shows there are significant “intra-annual discontinuities” between planned and actual capital spending on budgeted projects which is beyond what may be typical for a mature utility with adequately developed asset management and asset condition assessment practices.^{^[106]} BCOAPO submits there is a lack of a robust and proactive approach to Creative Energy’s asset management priorities. BCOAPO views that a more strategic and focused approach to assessing project prioritization and asset management is required so that Creative Energy’s ratepayers do not bear higher rates from more business development or redevelopment costs than are necessary.^{^[107]}

RCIA recommends that Creative Energy be directed to conduct a gap analysis between its existing asset management and risk management practices and industry best practices as a first step to improving the following areas:

• project planning and execution processes;

• asset condition assessment, asset management and risk management capabilities and processes; and

• ability to produce a longer-term (10 to 20 year) outlook for capital and operations and maintenance (O&M) expenditures.^{^[108]}

BCOAPO recommends that the Panel direct Creative Energy to file a capital spending prioritization report as part of future revenue requirement applications, which should focus on the justification for proposed capital spending, including an asset condition assessment, among other things.^{^[109]}

In reply to RCIA, Creative Energy notes that RCIA makes requests for Creative Energy to improve its business practices but does not support Creative Energy’s request for additional staff. Creative Energy submits that it cannot enhance its business processes without the staff to do so. While Creative Energy considers that its current planning processes and systems are reasonable, it submits that any enhancement must be cost-effective considering the context of Creative Energy and the required staff resources.^{^[110]}

In response to BCOAPO, Creative Energy submits that it is incorrect or unfair to characterize Creative Energy’s capital management plan as “reactive” or otherwise lacking rigour. Creative Energy submits it has 99.9 percent service reliability, which speaks to active, continual management and prioritization of its capital programs to ensure safe and reliable service within an aging system.^{^[111]}

Panel Determination

The Panel finds the forecast depreciation and capital additions provide a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. Creative Energy’s forecast depreciation is consistent with previously approved rates and methodologies.

Regarding Creative Energy’s forecast capital additions, the Panel notes that Creative Energy spent approximately $629,000 less than its 2020 forecast capital additions in 2020 and recorded the related cost savings on ROE and interest of approximately $19,000 in the existing COVID-19 deferral account. Creative Energy plans to increase capital additions by approximately $1.1 million in 2021, largely relating to the rebuilding, insulating and restoration of manholes. The Panel is concerned that the ongoing impacts of the COVID-19 pandemic in 2021 may make achieving this level of capital additions challenging. Accordingly, for the 2021 Test Period the Panel directs Creative Energy to record any ROE and interest savings from underspending on capital additions in the existing COVID-19 deferral account.

The Panel acknowledges interveners’ concerns related to Creative Energy’s capital planning, cost management or project execution processes. The Panel also notes that Creative Energy asserts that:

it has an established capital planning process and risk management framework and that its current planning processes and systems are reasonable;
any enhancement must be cost-effective considering the context of Creative Energy and the required staff resources; and
it has 99.9 percent service reliability, which speaks to active, continual management and prioritization of its capital programs to ensure safe and reliable service within an aging system.

However, the Panel is cognizant of the Core Steam System’s BCUC approved Beatty-Expo Plants CPCN and its recently filed proposed CPCN for the Core Steam System decarbonization project. In the face of these approved and proposed CPCN projects, the robustness of Creative Energy’s capital planning, cost management or project execution processes is critical to ensure capital expenditures are effectively controlled and optimized, prudently incurred and that safe and reliable service is maintained. It is incumbent on Creative Energy to ensure that it has the appropriate people, controls, and processes to manage the risks and deliver its capital projects in a prudent manner.

While a review of Creative Energy’s capital planning and execution may assist the BCUC in determining the reasonableness of Creative Energy’s forecast capital additions or assess the prudence of completed projects, intervener recommendations that the Panel direct Creative Energy to conduct a gap analysis related to its existing asset and risk management practices and to develop a capital spending prioritization report goes beyond the BCUC’s jurisdiction. The BCUC’s mandate is to determine the need for capital expenditures, if planned capital expenditures are in the public interest under sections 44.2, 45 and 46 of the UCA and to only allow for prudently incurred capital additions to be included in rates under sections 59 to 61 of the UCA. Accordingly, the Panel must ensure that Creative Energy’s rates do not include recovery for imprudent capital additions and it is Creative Energy’s responsibility, to manage planning and monitor the implementation of approved projects and the utility’s operations, including controlling costs. Further, while the BCUC has general supervisory powers under section 23(1) of the UCA, the review of Creative Energy’s RRAs, CPCN applications, or expenditure schedules allows the BCUC and interested parties an opportunity to review capital additions and planned capital expenditures.

2.1.6 Interest Expense

Creative Energy seeks approval of a cost of debt of 4 percent for the 2021 year, consistent with the rate previously approved by the BCUC.^{^[112]}

In September 2020, Creative Energy secured new debt financing with HSBC/TD which was approved by the BCUC.^{^[113]} Below is a summary of each credit facility as of December 31, 2020, with the corresponding interest rate.^{^[114]}

Table 4 – Credit Facility Summary^{^[115]}

Table

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Creative Energy states this summary accounts for all Creative Energy borrowing which is used to fund multiple TES.^{^[116]} Creative Energy confirmed Tranche 1 was repaid and cancelled as of February 2021.^{^[117]}

Creative Energy explains the interest rates in its credit facility are not fixed and vary with the Bankers’ Acceptance (BA) rate and debt levels.^{^[118]} Creative Energy submits that 4 percent is the forecasted cost of debt for the 2021 Test Year that reflects interest rate uncertainty.^{^[119]}

Based on this proposed cost of debt, Creative Energy forecasts interest expense for 2021 of $617,000. Creative Energy states that the credit facility is not allocated between different TES. Creative Energy’s forecast interest rate is show below.

Table 5 – Interest Expense and Calculated Interest Rate^{^[120]}

	Allowed 2020	Projected 2020	Forecast 2021
Rate Base^{^[121]}	26,294,182	25,800,973	26,763,585
57.5% Debt Component (A)	15,119,115	14,835,559	15,389,061
Interest Expense^{^[122]} (B)	607,000	462,631	617,000
Calculated Interest Rate(B/A)	4.0%	3.1%	4.0%

Creative Energy’s 2021 interest expense forecast of $617,000 is based on applying a 4 percent interest rate to 57.5 percent of the mid year rate base of $26,763,585.^{^[123]}

Referencing its responses to BCUC confidential IRs, Creative Energy submits the following:

Interest rates under the refinancing with HSBC/TD are higher overall relative to the rates with its previous lender. Under the HSBC/TD agreement, there is a mechanism of stand-by fees and BAs and the interest rate is not fixed, but varies with the prime/BA rate and the level of debt from time to time;
The forecast debt interest rate of 4 percent is reasonable in view of available tranches under the agreement with HSBC/TD, including the mechanism of stand-by fees and BA rates;
The monthly short-term cost of borrowing is currently less than 4 percent, but the 4 percent forecast interest rate is for the entire 2021 Test Year and accounts for interest rate uncertainty; and
Due to the persistent pandemic conditions, the one-year BA rate has consistently been higher than the one-month BA rate, indicating an expectation that interest rates might rise in the later part of this year.^{^[124]}

In addition, Creative Energy submits that 4 percent interest rate is reasonable in the context of three somewhat comparable utility companies that are larger than Creative Energy. Since these utilities are rated entities, an upward adjustment to the yields presented would be appropriate for Creative Energy given it is a small issuer unable to access public debt markets.^{^[125]} Creative Energy states it reviewed bonds for utility companies (natural gas distribution, power generation and distribution, etc.) across North America, all of which were rated BB or BBB. While most of the bonds reviewed were poor proxies due to the size of the issuances, it identified three possible reasonable proxies, all with amounts of debt issued figures that were approximately similar, although still larger than those of Creative Energy. These are summarized below:

Table 6 – Comparable Bond Rates[126]

Table

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Creative Energy submits that its interest rates should be higher than the above noted yields given its position as a small issuer and its inability to access public debt markets, noting its total debt outstanding of approximately $25 million versus issue sizes above of $80 million or greater.^{^[127]}

With respect to the appropriateness of using variance treatment for interest expense, Creative Energy does not support such an approach and states it is not requesting an interest rate variance deferral account. Creative Energy explains that it actively manages its debt balances and has some ability to manage within the forecast. Creative Energy argues that it would be challenging to administer an interest rate variance deferral account as there are multiple moving parts other than just the interest rate including budgeted versus actual capital additions, working capital used throughout the year, and interest capitalized to deferral accounts and projects under construction.^{^[128]}

Positions of the Parties

BCOAPO notes that Creative Energy acknowledges its short-term cost of borrowing is currently less than 4 percent and it uses a 3.5 percent interest rate for the one-year deferral accounts. BCOAPO states a downward adjustment to reflect a more realistic 3 or 3.5 percent would reduce the 2021 revenue requirement by approximately between $78,000 and $155,000. In BCOAPO’s view, Creative Energy fails to provide any evidence to justify the 4 percent proposal and relies on “speculation.” BCOAPO submits a 3.5 percent interest rate, consistent with that assumed for purposes of deferral reconciliation would be more appropriate.^{^[129]}

RCIA does not object to the approval of a debt interest rate of 4 percent in this proceeding but does object to using a rate that is higher than presently available debt rates. RCIA submits that the debt interest rate should be set based upon prevailing economic conditions, with the current interest rates being the preferred indicator of future interest rates on average over the long term as there is always a risk that interest rates will either increase or decrease in the future.^{^[130]}

The CEC comments the difference in interest costs from forecast is not the definition of the interest rate risk and that such risk is embedded in the full interest costs. The CEC submits that in the absence of variance treatment, the ratepayer and the shareholder are equally at risk and an interest rate variance account could provide some comfort for ratepayers under the considerable uncertainty related to the economic recovery and future interest rates.^{^[131]}

In Reply Argument, Creative Energy acknowledges its monthly cost of borrowing is currently less than 4 percent, but states that it effectively explained why its actual interest rate is not the appropriate basis on which to set rates.^{^[132]} In response to both BCOAPO and RCIA, Creative Energy submits the 4 percent debt interest rate is a reasonable forecast of the weighted average cost of debt overall for the 2021 Test Year and the appropriate approach to account for the expectation that interest rates could be higher or lower at any time during the year.^{^[133]}

Panel Discussion

The Panel finds the forecast interest expense calculated using the proposed interest rate of 4.0 percent provides a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. The forecast deemed interest expense is based on the BCUC approved deemed debt component of 57.5 percent. The proposed interest rate of 4.0 percent is within a reasonable range between the short-term borrowing rate in its current debt facilities and other available longer-term interest rate information.

The Panel notes that Creative Energy’s actual debt ratio does not match its allowed deemed debt component and its existing credit facility has short-term rates and renewal requirements. Creative Energy states this new credit facility permits the utility to complete the corporate reorganization as approved in the Expo-Beatty Plants CPCN and Reorganization Decision^{^[134]} and that the interest rates under this facility are higher overall relative to the rates with its previous lender. While Creative Energy’s short-term cost of borrowing is currently less than 4 percent, it does point out that there is interest rate uncertainty that is reflected in the higher one-year BA rate compared to the one-month BA rate.

The Panel acknowledges that BCOAPO and RCIA are concerned about setting an interest rate higher than that presently available short-term debt rates. However, Creative Energy’s allowed interest expense and ROE are based on a BCUC approved deemed capital structure and as a result the Panel’s determination on a reasonable interest rate should not be based exclusively on Creative Energy’s existing short-term credit facility or a short-term interest rate. When the BCUC establishes a deemed debt structure, it does so considering an appropriate allocation of debt between short and longer-term facilities. Accordingly, it is appropriate to set a deemed interest rate that considers both short- and long-term rates.

Since the Panel is setting a deemed interest rate considering both short- and long-term rates, it disagrees with the CEC’s suggestion that variance or deferral treatment for interest expense is appropriate. Based on Creative Energy’s audited 2020 financial statements its actual capital structure was 59 percent debt and 41 percent equity.^{^[135]} Other evidence also indicates the credit facility’s interest rate varies at different debt levels.^{^[136]} If the BCUC were to approve variance treatment on interest expense as suggested, then Creative Energy ratepayers would be financing costs associated with Creative Energy’s required equity component. Further, variance treatment for interest rate changes is typically approved when a utility’s actual debt structure closely matches its deemed structure.

2.1.7 Allowed ROE and Rate Base

For 2021, Creative Energy forecasts an allowed ROE of $1,080,070^{^[137]} using the BCUC approved equity component of 42.5 percent and an allowed ROE of 9.5 percent which incorporates an equity risk premium of 75 basis points over the benchmark utility.^{^[138]} The forecast ROE is based on a 2021 forecast mid-year rate base of $26,763,585 which includes $565,525 related to the land located at 720 Beatty Street and 701 Expo Boulevard (land).^{^[139]}

As noted above, in 2020, Creative Energy transferred beneficial ownership of land surplus to the needs of the utility to a developer.^{^[140]} Regarding the inclusion in rate base of the historical cost associated with this land, Creative Energy submits that the recovery of carrying costs through rates continues to be appropriate,^{^[141]} as follows:

The land continues to be used during 2021 for the same utility purposes as it has been in previous years despite the transfer of beneficial ownership;
For accounting purposes Creative Energy continues to carry this value on its books as an asset representing the value of the future plant and airspace;
A return on this cost through rates should be based on actual usage of the land; and
While the value of this asset in rate base may be adjusted when the redevelopment occurs and there is a change in the space utilized by Creative Energy, that change has not occurred yet.^{^[142]}

Positions of the Parties

The CEC submits it is unfair for the developer not to be responsible for some property costs and recommends that the BCUC direct Creative Energy to allocate a portion of the cost to the developer as part of the final compliance filing.^{^[143]}

In reply, Creative Energy submits that future considerations will include removing a portion of the land value currently in rate base due to the redevelopment project, which will reduce interest expense, ROE and associated property and income taxes.^{^[144]} However, for now, Creative Energy submits it remains appropriate to include the full usage of the land in rate base.^{^[145]}

Panel Determination

The Panel finds the forecast allowed ROE provides a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. The forecast allowed ROE is based on the BCUC 42.5 percent approved deemed equity component and 9.5 percent allowed ROE for Creative Energy.

As for the appropriateness of Creative Energy continuing to earn a debt and equity return of approximately $36,000 on the historical costs of land when its beneficial ownership has been transferred to a developer, the Panel accepts that the land will continue to be used in 2021 for the same utility purposes as it has been in previous years. Further, at this time the Creative Energy has not yet received any proceeds or other benefits to offset the historical cost of its investment in land and confirms the amount continues to be recorded as an asset in its financial statements.

However, the Panel notes that Creative Energy states that the value of this asset in rate base may be adjusted when the redevelopment occurs and there is a change in the space utilized by the utility. Further, in the BCUC Decision on the CPCN for the Expo–Beatty Plants and Reorganization,^{^[146]} the BCUC made specific determinations related to the exclusion of land from future recovery in circumstances where land that is no longer deemed used and useful should be removed from rate base with no further return allowed.^{^[147]} Given that Creative Energy suggests there is some uncertainty in how the land will be treated, Creative Energy is directed to address whether the transferred land should remain in rate base as part of its next revenue requirement application.

2.1.8 Overall Determination on 2021 Revenue Requirement

Based on the findings and determinations on the components of the forecast Revenue Requirement set out above, and subject to the Panel’s determination on Creative Energy’s deferral account requests, the Panel finds the forecast Revenue Requirements set out in Table 1 to be reasonable for setting the 2021 steam rates. The forecast Revenue Requirement reasonably reflects Creative Energy’s forecast cost of service and is an appropriate basis on which to establish rates.

2.2 Deferral Account Requests

Creative Energy proposes deferral account treatment for several forecast variances. The requested treatment would allow for the differences between the forecast and actual costs to be captured in approved regulatory accounts and recovered in future years based on approved amortization periods and recovery mechanisms. In this section, the Panel discusses the recovery and regulatory process necessary for the proposed deferral treatment for certain costs.

As part of the BCUC’s Regulatory Account Filing Checklist, the following criteria amongst others, are applied to address whether the requested deferral treatment is warranted:

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

• The degree of forecast uncertainty associated with the cost.

If the cost item is reasonably controllable and capable of reasonable forecasting, then, in the Panel’s view, it should form part of the forecast revenue requirement and the utility should bear the risk of variance. However, if a utility has limited control over an item, or there is a high degree of forecast uncertainty, it may not be appropriate for the utility to bear the cost of the forecast variances. In such a case, the establishment of variance treatment may be appropriate.

In its decision regarding Core Steam Rates for 2020, the BCUC approved four deferral accounts which Creative Energy is seeking to continue in this Application[148]. These four deferral accounts along with a fifth, dealing with Refinancing Costs, are addressed in the following subsections.

2.2.1 2021 Amortization and Interest Rate on Deferral Accounts

The balance of Creative Energy’s deferral accounts is recovered from ratepayers based on approved recovery mechanisms, including carrying costs at an approved interest rate. Creative Energy calculates carrying costs using an interest rate of 3.5 percent for all its deferral accounts, except for the Refinancing Costs Deferral Account which is discussed further in Subsection 2.2.6 below. The amended forecast 2021 amortization of deferral accounts reflected in Table 1 is $332,921.

Panel Determination

Based on the recovery mechanisms previously approved by the BCUC and those approved below in this decision, the Panel finds the amended forecast 2021 amortization of deferral accounts reflected in Table 1 of $332,921, which includes carrying costs based on a 3.5 percent interest rate, provides a reasonable basis for determining the Revenue Requirement for the 2021 Test Year. The Panel approves Creative Energy including carrying costs based on an interest rate of 3.5 percent in all deferral accounts.

2.2.2 Third-Party Regulatory Costs Deferral Account

Creative Energy seeks approval to continue on an ongoing basis the use of an existing third-party regulatory cost deferral account (TPRCDA) to capture the annual variance between forecast and actual third party costs relating to regulatory filings and proceedings on the same terms as previously approved.^{^[149]} The BCUC previously approved in Order G-167-16 the establishment of a TPRCDA for a five year period, with the balance to be amortized over one year at a carrying cost equal to Creative Energy’s short-term debt rate.^{^[150]}

Creative Energy submits deferral account treatment for regulatory costs remains appropriate as these costs are outside the control of the utility and are difficult to estimate.^{^[151]} In its view, it is impractical to request approval and establish the existence and mechanics of a TPRCDA in each test year. Therefore, Creative Energy now requests approval of the continuation of TPRCDA on an ongoing basis.^{^[152]}

Positions of the Parties

BCOAPO does not oppose Creative Energy’s proposals related to the TPRCDA and the CEC agrees that regulatory costs are difficult to forecast accurately and recommends that the BCUC approve the continuation of the deferral account.^{^[153]}

Panel Determination

The Panel approves the continuation of the TPRCDA on an ongoing basis to capture third party regulatory cost forecast variances. Creative Energy has established that these cost variances continue to be beyond its control and difficult to estimate. As in the previous RRA decision for Creative Energy, the Panel approves a one-year amortization period for the TPRCDA.

2.2.3 Pension Expense Deferral Account

Creative Energy requests approval to amend the amortization period of the existing Pension Expense Deferral Account (PEDA) from one year to three years.^{^[154]} For 2021, Creative Energy estimates that the 2020 pension expense variance is $24,926.^{^[155]}

The BCUC previously approved the PEDA on an on-going basis in Order G-98-15 to capture the annual variance between forecast pension expenses recovered in rates and the actual pension expense reported in its financial statements, with the balance to be amortized over one year at a carrying cost equal to Creative Energy’s short-term debt rate.^{^[156]} The recorded variances include expenses related to remeasurement gains and losses.^{^[157]}

In the 2019–2020 Core Steam System RRA, the Creative Energy provided a breakdown of pension remeasurement gains and losses from 2015 to 2019 (shown in Table 7) which demonstrates the volatility in variances recorded in the PEDA over the years.

Table 7 – 2015-2019 Pension Remeasurement Gains/(Losses)^{^[158]}

Table

Description automatically generated

Given the significant pension remeasurement gains and losses year over year, the BCUC directed Creative Energy in Order G-227-20 to provide information detailing how BCUC regulated utilities treat pension remeasurement gains and losses for ratemaking purposes to assist the BCUC in determining an appropriate amortization period for PEDA in its next RRA.^{^[159]}

In Appendix E of this Application, Creative Energy documented that BC Hydro and FortisBC Energy Inc. (FEI) and FortisBC Inc. (collectively, FortisBC) both use deferral account treatment for pension remeasurement gains and losses.^{^[160]} However, BC Hydro amortizes the balance over 18.5 years, which is the Expected Average Remaining Service Life of its employees, while FortisBC uses a shorter three-year amortization period.^{^[161]}

Creative Energy states steam rates can widely fluctuate in each test period with a one-year amortization period for the PEDA, given the volatility of remeasurement gains and loses year over year; therefore, it proposes to change to a three-year amortization period.^{^[162]} Creative Energy submits a three-year amortization period would amortize the deferral balance more slowly and allow for gains and losses to offset each other naturally.^{^[163]}

Positions of the Parties

Interveners did not comment specifically on this issue.

Panel Determination

The applicant asks for approval for a three-year amortization period similar to that approved by the BCUC for FortisBC. None of the interveners objected to this proposal. Given the fluctuations from year to year in these Pension Expenses, the Panel accepts Creative Energy’s proposal and approves a three-year amortization period for the PEDA, effective January 1, 2021.

2.2.4 Water Cost Deferral Account

Creative Energy seeks approval of a Water Cost Deferral Account (WCDA) for the 2021 test year to record variances between actual versus forecast annual water costs.^{^[164]} The BCUC previously approved a Water Cost Deferral Account for the 2020 test year, with the balance amortized over one year at a carrying cost equal to Creative Energy’s short-term debt rate.^{^[165]} Creative Energy states that it has improved its water cost budgeting and expects improvement for its 2021 water cost variances.^{^[166]} Creative Energy states deferral account treatment is still appropriate because the data is still limited, and the model results are variable and asymmetric.^{^[167]}

Creative Energy confirms that it is seeking recovery of its 2020 water cost variances through a 1-year amortization into 2021 rates, in accordance with Order G-227-20. Creative Energy estimates that the 2020 variance was a credit of $3,614 inclusive of water rate variances and load variance.^{^[168]}

Creative Energy proposes that 2021 water cost variances will be captured in the Water Cost Deferral Account and not in the COVID-19 deferral account for simplicity.^{^[169]}

The table below shows Creative Energy overall historical water cost variances:

Table 8 – 2015-2020 Historical Water Cost Variances^{^[170]}

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Creative Energy states it does not have the data to provide historical breakdowns in the attribution of water cost variances due to load and due to City of Vancouver water rates because it did not begin tracking water costs until 2019. For the 2020 variance in water costs, $4,281 were attributed to City of Vancouver water rate variances and ($7,895) were attributed to load variances.^{^[171]}

Positions of the Parties

The CEC is of the view that the WCDA could serve to protect both the utility and ratepayers from significant risk and recommends approval.^{^[172]}

RCIA recommends that all costs deemed by the BCUC to be appropriate for deferral account treatment should be consequently excluded from consideration as incremental risks to justify a premium above the benchmark utility ROE, and further, should be evaluated to determine if they reduce Creative Energy’s risks below those of the benchmark utility.^{^[173]}

BCOAPO does not oppose the creation of the requested deferral accounts.^{^[174]} BCOAPO submits that the proposals with respect to the approval of a number of non-rate base deferral accounts may lower Creative Energy’s risk profile such that a 9.5 percent ROE is higher than required to compensate it for the risk it will accept going forward.^{^[175]}

In reply, Creative Energy notes that the interveners do not oppose creation of the WCDA. Creative Energy states that the RCIA submission appears to assume the benchmark utility has no deferral accounts and is otherwise similar to Creative Energy. Creative Energy states its benchmark utility is FEI. Creative Energy does not see how the request for its deferral accounts changes its risk relative to that of FEI. Creative Energy further states that this issue would be the subject of a Generic Cost of Capital proceeding and out of scope of this proceeding.^{^[176]}

Panel Determination

The Panel approves the continuation of the WCDA to capture variances between forecast and actual water costs until Creative Energy files its next RRA for the Core Steam System. Following the previous rate decision’s directives,[177] Creative Energy has monitored the water cost forecast methodology and has asked for an extension of this account to allow Creative Energy to collect more data to allow it to better forecast water costs. The Panel agrees that the fluctuations in water cost variances over the last five years support Creative Energy’s case. The CEC and BCOAPO do not oppose this request. The Panel accepts Creative Energy’s request to monitor its water usage for an additional year before again considering the elimination of this deferral account. The Panel approves Creative Energy’s proposal for a one year amortization period for the WCDA.

2.2.5 Property Tax Deferral Account

Creative Energy seeks approval to continue the use of the Property Tax Deferral Account (PTDA) on an ongoing basis, to capture the annual variance between forecast and actual property taxes. As noted in Subsection 2.1.4 above, any property taxes variances resulting from the developer using floor space in 2021 and/or any rezoning impact would be included in this deferral account.^{^[178]} The BCUC previously approved the PTDA for the 2020 test year, with the balance to be amortized over one year at a carrying cost equal to Creative Energy’s short-term debt rate.^{^[179]}

Creative Energy submits that deferral account treatment for property taxes continues to be appropriate as mill rates set by the City of Vancouver are difficult to predict (increasing in some years and decreasing in others)^{^[180]} and are not typically confirmed until June of the applicable year, whereas Creative Energy’s revenue requirement applications are filed with the BCUC for approval six months earlier.^{^[181]}

Positions of the Parties

BCOAPO and the CEC do not oppose the continued use of the PTDA and recommend the BCUC approve the PTDA as proposed, respectively.^{^[182]} RCIA does not comment on this issue.

Panel Determination

The Panel approves the continued use of the Property Tax Deferral Account on an ongoing basis to capture variances between forecast and actual property taxes. Creative Energy has established that these costs are outside of Creative Energy’s control and are difficult to estimate. The Panel agrees with Creative Energy’s submission and none of the interveners objected to this proposal. The Panel approves a one year amortization period for the Property Tax Deferral Account.

2.2.6 Refinancing Cost Deferral Account

Creative Energy’s Request

Creative Energy seeks approval to establish a Refinancing Cost Deferral Account (RCDA) to capture the refinancing fees associated with executing the refinancing agreement with HSBC/TD described in Subsection 2.1.6.^{^[183]} Creative Energy proposes to record carrying costs based on Creative Energy’s debt rate and to amortize the balance over one year commencing in 2021.^{^[184]}

Creative Energy states the refinancing costs were an unplanned expense in 2020, arising as an “outcome ultimately” of the Expo-Beatty Plants CPCN and Reorganization Decision. As discussed previously, this decision approved the disposition of surplus property and a corporate reorganization involving Creative Energy entities, subject to the approval by the Lieutenant Governor in Council (LGIC).^{^[185]}

Creative Energy identified in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding that it would be necessary to refinance its existing debt, as set out in the Trust and Development Agreement (Trust and Development Agreement) which was filed as Appendix A to that application. Section 1.4(b) of the Trust and Development Agreement states:

The obligation of Creative Vancouver to transfer the Trust Property to the Developer under this Agreement and the Transfer Agreement, and Creative Vancouver’s obligations in respect of, in relation to or arising on or after the Effective Date, shall be conditional upon Creative Vancouver securing financing to ensure the continuity of its operations as a utility provider from the Effective Date until the Stabilization Date, which financing may include conventional financing from a third party institutional lender or support from the Developer in accordance with Section 6.1, or both, all on terms and conditions as are acceptable to Creative Vancouver, in its sole discretion.^{^[186]}

Further, Section 6.1 of the Trust and Development Agreement states that Creative Energy shall not grant a registrable mortgage over its interest in the Lands.^{^[187]}

Creative Energy also stated that the previous financing agreement included mortgages on the property, which would no longer be available once the property was transferred.^{^[188]} Creative Energy explained that Section 1.4(b) of the Trust and Development Agreement was to ensure that the utility had continuity of financing in place.^{^[189]} Creative Energy submitted that it did not foresee any problem fulfilling this condition prior to the date for transferring the Trust Property.^{^[190]}

While the recovery of costs related to the required refinancing was not addressed in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Creative Energy did submit that the proposed reorganization would have no detrimental effect on ratepayers or on the BCUC being able to effectively regulate the utility. In support of this, Creative Energy explained that while there would be effects related to the proposed project, the reorganization would result in:

• No change to utility rate base or rates;

• No change to utility assets, operations or service;

• No change to Creative Energy covenants; and

• No change to the financial integrity of the utility.^{^[191]}

The total amount of refinancing fees incurred in 2020 were as follows:

Table 9 – Refinancing Costs ($)^{^[192]}

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Creative Energy explains that the fee from the new lender consists of a one-time upfront fee of $101,400 and a recurring annual fee of $15,000.^{^[193]} Creative Energy states an additional fee may apply in 2021 related to renewing the facilities, but the amount is currently unknown.^{^[194]} Creative Energy also requests that the RCDA continue to operate into 2021 to recover any 2021 renewal fees.^{^[195]}

For accounting purposes, Creative Energy records the refinancing costs as a reduction in the debt liability on the balance sheet^{^[196]} and amortizes the balance over the one-year term of the loan.^{^[197]} Therefore in 2020, Creative Energy recorded a $91,589 expense for 3 months and 13 days of amortization and in 2021, the remaining $228,528 will be expensed in 2021.^{^[198]} As noted above, for regulatory purposes, Creative Energy seeks approval to record the total costs in the RCDA and to amortize the balance over one year commencing in 2021.^{^[199]}

Regarding concerns related to retroactive ratemaking, Creative Energy submits the BCUC has an established approach that allows for recovery of unplanned incurred costs provided an application for approval to establish a regulatory account is submitted prior to the utility’s fiscal year end.^{^[200]} Creative Energy submits that the application for approval of the RCDA was submitted December 1, 2020 which is the fiscal period in which the unplanned expenses were incurred, and the mechanism of the RCDA will thus allow for recovery of the expenses in rates effective January 1, 2021.^{^[201]}

As described in Subsection 2.1.6, Creative Energy’s credit facility is used to fund the operations of multiple TES.^{^[202]} Creative Energy explains the financing fees are driven by the level of debt required for each system which is partially a function of capital costs.^{^[203]} Creative Energy requests that the refinancing fees be allocated to each TES based on its respective deemed debt as calculated below.^{^[204]}

Table 10 – Deemed Debt Allocation Per Utility^{^[205]}

Creative Energy states it is not aware of having financing fees of this nature in its recent history.^{^[206]} Creative Energy explains previous debt facility had nominal annual fees that would be captured within bank fees recovered as a part of O&M expense.^{^[207]} Creative Energy states it did not consider including the renewal fees in the forecast interest rate expense as the amount of fee to be charged is unknown for 2021.^{^[208]}

Based on the percentage allocations in Table 10, Creative Energy is requesting a deferral account to record 2020 financing fees of $235,452 (73.55 percent x $320,117) plus related interest of $12,505 for the Core Steam System and that the account be amortized and recognized in the 2021 Revenue Requirement.^{^[209]}

Response to Panel IRs

As noted in Subsection 1.4, after the close of the evidentiary record, the Panel issued IRs requesting Creative Energy to provide additional information and further clarification on the refinancing fees and proposed RCDA. According to Creative Energy, the schedule for the Beatty-Expo Plants project was a driver for the timing of the refinancing but the project or its schedule was not the only reason for seeking refinancing.[210] Creative Energy states in 2019, its previous lender, RBC, transferred responsibility for its file from Vancouver to Toronto and RBC began to view Creative Energy’s business and its risk profile differently.[211] As an example, Creative Energy states that RBC expressed a strong reluctance to provide financing for the excess fuel costs Creative Energy incurred during the winter of 2018/2019 in connection with the Enbridge pipeline explosion.

According to Creative Energy, the specific timing of entering into the new Credit Agreement was driven by the schedule for the Beatty-Expo Plants project approved by the BCUC. Creative Energy states:

One of the reasons for refinancing with TD and HSBC was RBC’s unwillingness to extend financing without the 720 Beatty St and 701 Expo Blvd land as security. Proceeding with the project approved by BCUC Order C-1-20 [Expo-Beatty Plants CPCN and Reorganization Decision] involves transferring the beneficial interest in the surplus property (also called the Trust Property) at 720 Beatty and 701 Expo to a developer for development of an office tower. Moving forward with the Beatty-Expo Plants project therefore required CEVP to complete the refinancing with HSBC and TD at that time. [212]

Creative Energy also explains that TD and HSBC were able to better understand that the value of the utility is the cash flow from provision of essential energy services within a regulated environment. Further, the new Credit Agreement also refinanced an existing shareholder loan for excess fuel costs and also funds utility systems that are owned and operated by Creative Energy.[213]

In Creative Energy’s view, the refinancing costs incurred are not costs of the reorganization and it submits that the BCUC agreed with this characterisation in its April 3, 2020 report and recommendation to the LGIC (LGIC Report) in relation to the amalgamation step of the reorganization. Among other things, Creative Energy notes that the BCUC stated:

Creative Energy’s Application for corporate reorganisation and amalgamation is somewhat unique in that its approval will result in no significant benefits to the public or ratepayers related to the corporate reorganization itself. Instead, as outlined in the March 2020 Decision, the benefits derived relate to the Proposed Project which, because it is inextricably connected to the corporate reorganization, will not go forward unless all of the requested approvals related to the Proposed Project and the Proposed Reorganization including the amalgamation are approved. These direct benefits include improved air quality, beautification of Expo Boulevard, the creation of a large plaza and the provision of additional retail space.

The Panel finds these direct benefits to be important, as the completion of these projects will significantly enhance the urban landscape. However, even more important than these improvements are the benefits provided to Creative Energy’s ratepayers. For a cost of $15 million and a relatively modest impact on rates of 4.1 percent, Creative Energy and its ratepayers will be provided with significantly improved plants and facilities. Moreover, this work will provide surety of the costs of required plant upgrades as it shields ratepayers from the risk of potentially higher costs of other alternatives. Therefore, while not directly related to the Proposed Reorganization inclusive of the amalgamation, the Panel finds that the benefits associated with approval of the CPCN and the corporate reorganization are significant and will have a long-term positive impact on ratepayers and the community surrounding the utility.

Creative Energy argues that the 2020 refinancing and associated costs are not directly related to the reorganization, nor did they result solely from the reorganization. Creative Energy submits that the refinancing and associated costs were necessary in the normal course of Creative Energy’s business and ought to be recoverable in rates.[214]

Positions of the Parties

BCOAPO submits that there are sufficient grounds upon which the Panel could determine that the applied for deferral account treatment is not appropriate in the circumstances.^{^[215]}BCOAPO argues the evidence shows that as far back as 2019 RBC had begun to take a much different view of Creative Energy’s risk profile. This should have triggered ongoing discussions with its lender and alerted the utility to a potential problem, before it made representations to the BCUC.[216]

BCOAPO does not consider Creative Energy’s argument persuasive that the Beatty-Expo Plant project and corporate reorganization are completely separate and distinct because Creative Energy previously argued that approvals for the CPCN and reorganization should be considered as a whole.[217] BCOAPO states:

The evidence we have on record supports a finding that all or part of the refinancing expenses CEVP is seeking to recover is indeed a result of the utility’s Reorganization Application and its conjoined twin, the Beatty-Expo CPCN. As such, and in light of the utility’s clear and repeated representations that there would be no increase in rates beyond those identified in the Application, BCOAPO cannot support the Utility’s Application in this regard. [218]

In addition, BCOAPO submits the refinancing costs of $91,589 incurred in 2020 amount to retroactive ratemaking and must therefore be rejected.^{^[219]}

The CEC also does not support the recovery of the 2020 refinancing and associated costs from ratepayers.^{^[220]} The CEC submits that the evidence suggests that at least some portion of the refinancing costs stems directly or indirectly from either the reorganization and/or the Beatty-Expo Plant Project, both of which contain Creative Energy’s assurances that no additional costs would be forthcoming beyond those identified and approved.[221] The CEC states it does not find that the schedule driven by the Expo-Beatty Plants CPCN and Reorganization Decision represents a valid justification for ratepayer absorption of the costs.[222]

In reply, Creative Energy submits BCOAPO and the CEC’s assertions are not correct and unsupported.[223] Creative Energy states there is no connection between RBC’s view of Creative Energy’s risk profile and the conditions of Expo-Beatty Plants CPCN and Reorganization Decision or Creative Energy’s acceptance of those conditions/ability to meet them.[224] Creative Energy confirms that it stated in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding that customers will not bear any costs or risk associated with reorganization, but reiterates that the 2020 refinancing and associated costs are not directly related to the reorganization nor did they result solely from the reorganization.[225]

Creative Energy argues that it did not say that there would be no increase in operating costs as a result of the project, nor it did say that there would be no increases in rates beyond those forecast in the CPCN application.[226] Creative Energy clarifies its argument in support for the project was that the rate and bill impact of the project and the associated risks are lower than any alternative to address the identified issues.[227]

Creative Energy submits that recovery of the Core Steam System’s share of refinancing costs in Core Steam rates as proposed is not contrary to a condition of an applicable BCUC order nor contrary to a prior commitment of Creative Energy. The refinancing and associated costs were necessary in the normal course of business and ought to be recovered in rates as proposed in the RRA.[228] Creative Energy also reaffirms its position that its proposals do not amount to retroactive ratemaking.^{^[229]}

Panel Determination

The key issues for the Panel to determine are:

• Whether or not the refinancing costs are a direct consequence of the reorganization or if the refinancing was done in the ordinary course of business;

• Whether any of the refinancing costs should be recovered from the Core Steam System ratepayers;

• How the allocated portion of the recoverable refinancing costs, if any, should be recovered from the Core Steam System ratepayers; and

• Whether any of the recoverable portion of the refinancing costs, if any, is attributable to NEFC.

Regarding the question of whether or not the refinancing costs are a direct consequence of the reorganization or if the refinancing was done in the ordinary course of business, the Panel considers the following evidence:

• Creative Energy’s 2020 debt refinancing was necessary to give effect to the reorganization that was approved by the BCUC.^{^[230]} Since the beneficial ownership of the property was transferred to a developer in this reorganization arrangement, Creative Energy was no longer able to use the property to secure its financing^{^[231]} and was required to obtain replacement financing.

• Section 1.4(b) of the Trust and Development Agreement was to ensure that the utility had continuity of financing in place^{^[232]} and Creative Energy stated it did not foresee any problem fulfilling this condition prior to the date for transferring the property.^{^[233]}

• RBC advised Creative Energy that it would not extend financing without the 720 Beatty St and 701 Expo Blvd land as security. Creative Energy cites this as one of the reasons for refinancing with TD and HSBC.^{^[234]}

• Creative Energy states it is not aware of having financing fees of this nature in its recent history.^{^[235]} Its previous debt facility only had nominal annual fees.^{^[236]}

• The total costs (before allocation) of obtaining a replacement credit facility were approximately $320,000. In addition to these financing costs, interest rates under the new HSBC/TD credit facility are higher overall relative to the rates with its previous lender.^{^[237]}The benefits of lower financing costs that result from having a property available to provide security to a lender were conferred on the developer when the property was beneficially transferred from Creative Energy to the developer.

The Panel also notes that the recovery of costs related to the required refinancing were not directly addressed in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding. While Creative Energy indicated the refinancing would be necessary, it did not identify the potential for additional refinancing costs as part of the impact on ratepayers that would result from the project and related reorganization. Creative Energy now argues that it did not say that there would be no increase in operating costs as a result of the project or increases in rates beyond those forecast in the Beatty-Expo Plants CPCN.^{^[238]} It points out that the rate and bill impact of the project and the associated risks were lower than any alternative to address the identified issues.^{^[239]} However, in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding, it did state clearly that the reorganization would result in no change to utility rate base or rates.[240] [emphasis added]

The Panel is not persuaded by Creative Energy’s view that the refinancing and associated costs are necessary in the normal course of business and were not costs of the reorganization. All parties in this proceeding accept the view expressed by the BCUC in the LGIC Report that the Beatty-Expo Plants CPCN project and the reorganization were inextricably connected. However, in the Panel’s view, while there is a connection, the refinancing costs are directly attributable to and triggered by the reorganization and the transfer of beneficial ownership of the property. Further, the amount of restructuring costs is significant and unusual compared to the ordinary course loan renewal fees incurred historically when the land was available to secure the credit facility. Accordingly, the Panel finds the refinancing costs are a direct consequence of the reorganization and are not primarily incurred in the ordinary course of business.

Given the above finding, the Panel now considers the extent to which any of the refinancing costs should be borne by the Core Steam System ratepayers.

While Creative Energy refers to the fact that RBC had begun to view it differently, it clearly states that RBC was unwilling to renew the facility or otherwise continue to provide financing without the land for security. Further, as BCOAPO point out, Creative Energy was aware as far back as 2019 that RBC had begun to take a different view of Creative Energy’s risk profile. The Panel agrees with BCOAPO that this should have triggered ongoing discussions with its lender and alerted management that there was a potential problem, including that the reorganization could trigger an unusual level of refinancing costs. Creative Energy made it clear that the reorganization would require it to amend its existing financing arrangement with RBC. Creative Energy, managing prudently, should have also been aware of the potential costs and raised the matter in the Expo-Beatty Plants CPCN and Reorganization Decision proceeding. However, it did not raise this issue and did state clearly that the reorganization would result in no change to utility rate base or rates.^{^[241]} Given that Creative Energy stated the reorganization would not impact rates, the Panel finds the portion of refinancing costs directly attributable to the reorganization should not be recoverable from Creative Energy ratepayers.

The Panel acknowledges that one of the tranches (Loan Tranche 1 in Table 11 below) of the new HSBC/TD credit facility specifically covers the balance of the Fuel Cost Stabilization Account.^{^[242]} Further, in its deemed debt allocation Table 10 above, Creative Energy appropriately allocates 100 percent of the Fuel Cost Loan to the Core Steam System. The Panel acknowledges that since the new credit facility was a replacement of a shareholder -+loan, specifically to cover the balance of the Fuel Cost Stabilization Account, it is appropriate to allocate a portion of the refinancing costs to the Core Steam System ratepayers. In the Panel’s view, a reasonable approach to allocate refinancing costs between the reorganization and energy costs is to attribute the loan facility tranches that replaced the RBC credit facility (Tranches 2–4) to the reorganization and the Fuel Loan (Loan Tranche 1) portion energy costs, as set out below:

Table 11 – BCUC Allocation of Financing Fees based on Credit Facility

Loan Tranche	Credit Facility[243]	Percentage of Total Credit Facility	Allocation of Fees based on Credit Facility
1 (Fuel Loan)	$2,110,599	7.0%	$22,436
2	$5,000,000	16.6%	$53,151
3	$10,000,000	33.2%	$106,303
4	$13,003,129	43.2%	$138,227
Subtotal for Tranches 2-4	$28,003,129	93%	$297,681
Total	$30,113,728	100%	$320,117

Given the Panel’s findings above, the Panel denies Creative Energy’s request to establish the RCDA and to include amortization of $247,957^{^[244]} in the 2021 Revenue Requirement.

As to the Panel’s determination on recovery of the $22,436 (plus applicable interest) allocation of refinancing costs to the Fuel Loan, the Panel considers that since these costs are related to energy costs, the costs can be dealt with as part of the process related to the review of the Fuel Cost Stabilization Account and related Fuel Cost Adjustment Charge. The Panel notes that Directive No. 4 in BCUC Order G-84-21 related to Creative Energy’s Application to Cancel the Fuel Cost Adjustment Charge Rate Rider Charge and for Relief from Quarterly Reporting states:

CEVP is directed to file a report to the BCUC that includes a review of the FCSA balance for each of the previous 12 months and, if necessary, the appropriate amortization of the FCSA and a request to change the FCAC by no later than October 31, 2021.

Accordingly, Creative Energy is approved to add $22,436 (plus applicable interest) to the Fuel Cost Stabilization Account and to address the recovery of this amount by November 30, 2021, as an addendum to its next filing pursuant to BCUC Order G-84-21.

Regarding the allocation of a portion of the refinancing fee to NEFC, the BCUC determined in the decision on Creative Energy Northeast False Creek (NEFC) Rate Proposal and 2021 Revenue Requirement Application^{^[245]}:

Creative Energy is approved to establish a Refinancing Costs Deferral Account, to record the costs allocated to NEFC for Creative Energy’s September 17, 2020 debt refinancing costs. Following the BCUC decision in the review of the 2021 Core Steam RRA, the Panel directs Creative Energy to record the final costs allocated to NEFC in the deferral account, the disposition of which will be determined as part of Creative Energy’s next RRA for NEFC.

The total costs associated with Creative Energy’s debt refinancing and the allocation of these costs to NEFC and other applicable utility systems is the subject of an ongoing, separate BCUC review of the 2021 Core Steam RRA. It is not appropriate to amortize the debt refinancing costs in 2021 NEFC rates, given that the refinancing costs allocated to NEFC may be impacted by the outcome of that separate review. Accordingly, the request to amortize in 2021 NEFC rates the debt refinancing costs of $37,757 is denied. [emphasis in original]^{^[246]}

Given the Panel disallows recovery of the refinancing costs attributable to the reorganization and the recoverable portion is allocated to the Core Steam System, there is no amount to be allocated to NEFC. Accordingly, Creative Energy is directed to remove the amounts recorded in NEFC’s Refinancing Deferral Account and to close the account.

With respect to the fact that replacement financing has higher interest rates than the previous credit facility, the Panel considers that the interest rates under the HSBC/TD credit facility did not drive its determination on an appropriate interest rate as discussed in Subsection 2.1.6. The Panel’s determination that Creative Energy’s proposed interest rate of 4.0 percent is that this rate is reasonable considering the short-term borrowing rate in its current debt facility as well as other available longer-term interest rate evidence.

The Panel also denies Creative Energy’s request to use the RCDA to record 2021 credit facility renewal fees. The Panel acknowledges that Creative Energy has not included forecast renewal fees in its amended Revenue Requirement. However, the Panel considers the known annual renewal fee of $15,000 under its TD/HSBC credit facility to be an amount that can reasonably be accommodated within the forecast interest expense based on the deemed interest rate of 4 percent. Further, if Creative Energy expects to incur additional unknown non-controllable debt renewal costs, it can apply to the BCUC for variance treatment in advance of incurring such costs.

2.3 Other Deferral Account Issues Raised

In the course of commenting on deferral accounts, two interveners raised an issue regarding the appropriate treatment of deferral accounts related to the incremental risks faced by Creative Energy.

Positions of the Parties

RCIA's position is that the use of deferral accounts should be restricted to those areas of spending subject to exceptional cost drivers that are beyond the utility’s reasonable ability to forecast, manage or absorb within the test period.[247] RCIA recommends that all costs deemed by the BCUC to be appropriate for deferral account treatment should be consequently excluded from consideration as incremental risks to justify a premium above the benchmark utility ROE, and further, should be evaluated to determine if they reduce Creative Energy’s risks below those of the benchmark utility.[248]

BCOAPO does not oppose the creation of the requested deferral accounts.[249] BCOAPO submits that the proposals with respect to the approval of a number of non-rate base deferral accounts may lower Creative Energy’s risk profile such that a 9.5 percent ROE is higher than required to compensate it for the risk it will accept going forward.[250]

In reply, Creative Energy notes that the interveners do not oppose creation of the various Deferral Accounts. Creative Energy states that the RCIA submission appears to assume the benchmark utility has no deferral accounts and is otherwise similar to Creative Energy. Creative Energy states its benchmark utility is FortisBC Energy Inc. (FEI). Creative Energy does not see how the request for its deferral accounts changes its risk relative to that of FEI. Creative Energy further states that this issue would be the subject of a Generic Cost of Capital proceeding and out of scope of this proceeding.[251]

Panel Determination

The BCUC currently has an ongoing General Cost of Capital proceeding for public utilities. The Panel finds that determination of risk and the relationship of risk to deferral accounts and Creative Energy’s ROE is out of scope for the review of this Application and is a subject to be addressed in the ongoing Generic Cost of Capital proceeding.

2.4 Load Forecast and Determination on Average Steam Rate Increase

Creative Energy’s amended 2021 annual steam load forecast for the core steam system is 971,259 thousand pounds of steam.^{^[252]} The 2021 amended annual steam load forecast reflects a 15 percent forecast load reduction from the annual steam load forecast of 1,142,658 thousand pounds that is otherwise based on the Creative Energy’s 2020 Approved load forecast plus the forecast new customer load growth for 2021.^{^[253]}

Creative Energy submits a reduction to the forecast load is necessary in order to set steam rates for 2021 that factor in the impacts on the overall customer demand for steam during 2021 of the COVID-19 pandemic.^{^[254]} Creative Energy reduces the 2021 load forecast by 15 percent based on the 15 percent reduction in the weather normalized 2020 actual load during March to December 2020 period that is directly attributable to the COVID-19 pandemic.^{^[255]} If January and February 2020 are included, the weather normalized 2020 Actual load for the entire year would have been 10 percent lower.^{^[256]} Creative Energy acknowledges that a 10 percent forecast load reduction may also reasonably reflect the ongoing uncertainty into the extent and impacts of the pandemic, but submits that it is not in a position to judge which forecast load reduction (i.e. 15 percent or 10 percent) may be more accurate.^{^[257]}

As stated in Subsection 1.1, Creative Energy notes that the BCUC approved the creation of a COVID-19 deferral account in 2020 and that the deferral account was approved to capture any direct revenue loss resulting from the loss of load from customers due to the impacts of COVID-19 on customers’ operational and financial circumstances, among other things.^{^[258]} Specifically, the BCUC directed, “[t]he revenue loss is to be calculated based on the final 2020 Core steam load forecast approved in Creative Energy’s 2019-2020 Revenue Requirements Application (RRA) proceeding.”^{^[259]}

Further, Creative Energy submits that the COVID-19 Deferral Account, which is approved through 2021,^{^[260]} will continue to function as a load variance deferral account.^{^[261]}

The following table sets out the interim average steam rate and rate increases approved by the BCUC on an interim and refundable basis.

Table 12 – Interim Average Steam Rate and Rate Increases

	January 1, 2021 Interim Rates	March 1, 2021 Interim Rates
2021 Preliminary Forecast Revenue Requirement	$ 9,929,194	$ 9,929,194
2021 Annual Steam Load Forecast (thousand pounds of steam)	1,142,658	971,259
Interim Average Steam Rate	$ 8.69	$ 10.22
Percent Increase in Interim Average Steam Rate Above the Previous BCUC-Approved Rate^{^[262]}	6.9%	17.5%

As noted previously, Creative Energy seeks different permanent rates for each of January 2021 through February 2021 based on the initial load forecast of 1,142,658 thousand pounds of steam and March 2021 through December 2021 based on the amended forecast of 971,259 thousand pounds of steam.^{^[263]} Creative Energy submits this approach is reasonable for several reasons, stating that:

It allows for the recovery of costs on a timely basis given its Evidentiary Update on February 26, 2021 which revised the 2021 annual steam load forecast;
It maintains “fidelity to prior approved annual load forecasts for comparison purposes”; and
It recognizes that the Core Steam System has an existing COVID-19 Deferral Account to capture differences between actual and forecast load.^{^[264]}

Creative Energy submits that any differences between interim and permanent rates approved by the BCUC for January 2021 and February 2021 will be applied to each customer’s total invoiced consumption over those months. Likewise, any differences between interim and permanent rates approved by the BCUC for March 2021 through December 2021 will be applied to each customer’s total invoiced consumption over those months. Creative Energy submits that the administration of any recovery or refund in this manner would be straightforward and in keeping with current practice.^{^[265]}

In a separate application to the BCUC, Creative Energy requested the cancellation of the FCAC) Rate Rider, which is a component of fuel rates, effective February 28, 2021. Creative Energy submitted, if approved, that the net change resulting from the two proposals together would be an overall reduction in steam and fuel rates of 9.2 percent compared to 2020 Approved rates based on the forecast 2021 Revenue Requirement before amendments.^{^[266]} On March 18, 2021, the BCUC approved a reduction in the FCAC Rate Rider from $4.40 per thousand pounds of steam to $0 per thousand pounds of steam, effective February 28, 2021.^{^[267]}

Positions of the Parties

The CEC submits that the 15 percent forecast load reduction results in a requested steam rate increase of 25.7 percent^{^[268]} compared to 2020 rates, which is “very high.”^{^[269]} While the cancellation of the FCAC Rate Rider mitigates the overall bill impact of the steam rate increase, the CEC argues that customers had accepted the FCAC Rate Rider as a temporary two-year measure with an expected return to business as usual once the FCAC Rate Rider is cancelled.^{^[270]} In addition, the CEC’s considers that there is a reasonably good chance that customer demand for steam will increase in 2021 as COVID-19 vaccinations proceed and the economy reopens.^{^[271]} The CEC submits that it would not be in the public interest to have an increase in 2021 steam rates only to have it reversed in the following year.^{^[272]} Therefore, the CEC recommends the BCUC approve an annual steam load forecast which is in the absence of the COVID-19 pandemic and use the existing COVID-19 deferral account to capture reductions in load in 2021 related to the pandemic, as intended.^{^[273]}

BCOAPO submits it does not oppose the 15 percent forecast load reduction if load variances are reconciled through the COVID-19 deferral account.^{^[274]}

RCIA submits it has no comment on Creative Energy’s annual steam load forecast or the impact of the COVID-19 pandemic on the forecast steam load.^{^[275]}

Creative Energy replies to the CEC, acknowledging that the requested steam rate increase considering the amended 2021 annual steam load forecast is high. However, it submits, like the circumstances that led to the implementation of the FCAC Rate Rider, the rate impact is due to circumstances outside of Creative Energy’s control. Creative Energy submits that its proposed approach is fair, in that customers who consume steam in 2021, pay for the cost of that service in 2021 and that the approach avoids (to the extent practicable) current costs being recovered in a future period.^{^[276]}

Panel Determination

The Panel finds the amended forecast steam load of 971,259 thousand pounds of steam reasonable for the purpose of determining the 2021 steam rates. Based on the Panel’s determinations above, the Panel also finds the forecast Revenue Requirements of $9,499,931 reasonable for setting the permanent 2021 steam rates.

Using the approved 2021 Revenue Requirement set out in the table below and the amended 2021 annual steam load forecast, the average and percentage average steam rate increase are as follows:

Table 13 – 2021 Approved Average Steam Rate

2021 Amended Forecast Revenue Requirement (Table 1)	$ 9,747,889
Adjustment to Disallow Request to Recover Refinancing Costs from Steam Rates (Subsection 2.2.6)	247,957
Approved 2021 Revenue Requirement	9,499,932
2021 Amended Steam Load Forecast (thousand pounds of steam)	971,259
2021 Approved Average Steam Rate	$ 9.78

2020 Approved Average Steam Rate	$ 8.13
Average Steam Rate Increase	20.3%

In the Panel’s view, Creative Energy’s amended 2021 annual steam load forecast of 971,259 thousand pounds of steam energy is appropriate for setting 2021 steam rates and reflects the best information available at this time. When the BCUC set the 2020 steam rates, the impact of the COVID-19 pandemic on the forecast steam rate was not considered since the impacts were not reasonably predictable at that time and the BCUC had already approved Creative Energy’s COVID-19 deferral account to capture the 2020 impacts. However, for the 2021 test period, Creative Energy can make a reasonable estimate of the weather normalized impacts of the pandemic based on the 2020 impact. While there is still uncertainty, the impact is reasonably foreseeable.

The Panel notes that if, as the CEC suggests, the customer demand for steam increases in 2021 as COVID-19 vaccinations proceed and the economy reopens then the COVID-19 deferral account will capture any load variance. This approach is supported by BCOAPO’s suggestion that load variances be reconciled through the COVID-19 deferral account. In the Panel’s view, continuation of this variance treatment for the 2021 load forecast continues to be appropriate due to the ongoing impacts of the pandemic, which are clearly outside the control of the utility and the outcome. Of which is still uncertain. Accordingly, for 2021 Creative Energy is directed to capture the variance between the 2021 approved steam load forecast and the actual 2021 steam load in the COVID-19 deferral account.

Regarding the ultimate recovery of the COVID-19 deferral account, the Panel notes the BCUC directed Creative Energy to file an application for recovery of the amounts that accrue to the COVID-19 deferral account in either this RRA or the following RRA at the latest.[277] The Panel agrees with Creative Energy decision not to propose recovery of the 2020 amounts in COVID-19 deferral account in this RRA, given the ongoing uncertainty and impact of the COVID-19 pandemic. Based on the previous BCUC directive for Creative Energy to file an application for recovery of the balance of the COVID-19 deferral account by the current RRA or the following RRA at the latest, Creative Energy is directed to file its proposal for recovery of the COVID-19 deferral account in its next RRA.

Further to this topic, in this proceeding Creative Energy provided preliminary actual financial results for 2020 indicating these amounts were provided in advance of an application to recover a 2020 balance in the COVID-19 deferral account and that this information is subject to adjustments including income taxes and finalization of the COVID-19 deferral account recovery.^{^[278]} While the Panel acknowledges this information is preliminary and subject to further adjustment, the Panel is concerned that the preliminary COVID 19 adjustments filed indicate that Creative Energy’s actual earned return after reflecting these preliminary adjustments may exceed its 2020 allowed return. Such an outcome would be contrary to the purpose of establishing a COVID-19 variance mechanism which was put in place to ensure Creative Energy has a reasonable opportunity to earn a fair return considering the impacts of the COVID-19 pandemic. To ensure the COVID-19 adjustments are evaluated in the context of Creative Energy’s allowed ROE, Creative Energy is directed to include in its application for recovery of the COVID-19 deferral account an update to Table 1 in this decision, reflecting the final actual 2020 amounts as well as an explanation of the differences between the 2020 actual earned and allowed ROE in its 2022 RRA.

The CEC’s overarching submissions regarding the steam load forecast relate to the fact that the 15 percent forecast load reduction results in a significant impact on the 2021 average steam rate (20.3 percent compared to the 2020 average steam rate as set out in Table 13 above). The Panel recognizes that the approved rate increase is significant, and exceeds the 10 percent typically considered to constitute rate shock. However, in the Panel’s view, it is appropriate to consider rate shock in terms of a ratepayer’s total bill, and not a specific component (the average steam rate) within the bill. Prior to the issuance of this decision, the BCUC approved in March 2021 the cancellation by Creative Energy the FCAC Rate Rider of $4.40 per thousand pounds of steam, which is a component of fuel rates, effective February 28, 2021. The Panel notes that the cancellation of the FCAC Rate Rider will offset the steam rate increase. For context, Creative Energy estimated that its proposal for 2021 steam rates would be offset by the cancellation of the FCAC rate rider, resulting in a combined reduction in steam and fuel rates of 9.2 percent compared to 2020 approved rates, which is before adjustments made by the Panel in this decision.

Regarding CEC’s comments that the principle of rate stability means it is not appropriate to increase the 2021 rates if they will be reversed in the following year, the Panel observes that rate stability is partially achieved due to the offset of the cancellation of the FCAC Rate Rider effective February 28, 2021. Furthermore, there is no guarantee that the increase of rates in 2021 will be reversed in the following year, considering that rates may also need to increase in 2022 to recover the 2020 amounts already recognized in the COVID-19 deferral account plus any additional amounts added to the account in 2021. From a cost causation perspective, the Panel also agrees with Creative Energy’s submission that is just and reasonable for ratepayers who consume steam in 2021 to pay for the full cost of that service in 2021.

The Panel denies Creative Energy’s request for approval of a permanent steam rates based on its initial annual steam load forecast of 1,142,658 thousand pounds of steam, effective January 1, 2021 and permanent steam rates based on the amended annual steam load forecast 971,259 thousand pounds of steam, effective March 1, 2021. Creative Energy has provided no regulatory justification for establishing two different rates for the 2021 Test Period based on the different annual steam load forecasts as at January 1, 2021 and March 1, 2021, and the Panel is not persuaded by its arguments.

For the reasons outlined above, pursuant to sections 58 to 60 of the UCA, the Panel approves a 2021 average steam rate of $9.78 per thousand pounds of steam, equivalent to a 20.3 percent increase above 2020 Approved average steam rates, on a permanent basis effective January 1, 2021. Creative Energy is directed to refund to ratepayers the net difference between the interim steam rates collected and the permanent rates with interest at Creative Energy’s cost of debt in the next billing cycle after this decision. Creative Energy is also directed to file with the BCUC, within 10 days of the date of this order, amended tariff pages in accordance with the terms of this order.

The Panel notes Creative Energy’s submission throughout the proceeding that the final amount for the 2021 forecast Revenue Requirement will be addressed as part of the final compliance filing for this proceeding, subject to the BCUC’s final determinations on the Application and the availability of 2020 audited actual amounts for capital and other items with approved deferral account treatment of 2020 variances. However, as noted above, the Panel makes its final determination on the 2021 average stream rate based on its findings on reasonableness of the 2021 Revenue Requirement of $9,499,931 and the amended forecast steam load of 971,259 thousand pounds of steam. Given that Creative Energy already filed an evidentiary update in this proceeding and that the Panel has made its determinations based on the information in the evidentiary record, it is not appropriate for the proceeding to be extended to allow Creative Energy to further update for the actual audited amounts for capital and regulatory accounts through a compliance filing. Creative Energy is directed to file with the BCUC, within 30 days of the date of this order, finalized financial schedules in accordance with the terms of this order.

Dated at the City of Vancouver, in the Province of British Columbia, this 24^th day of November 2021.

Original signed by:

____________________________________

A. K. Fung, QC

Panel Chair / Commissioner

Original signed by:

____________________________________

K. A. Keilty

Commissioner

Original signed by:

____________________________________

B. A. Magnan

Commissioner

Text, letter

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List of Acronyms

Acronym	Description
Application	Creative Energy Vancouver Platforms Inc. application for permanent 2021 steam rates for the Core Steam System based on a forecast cost of service or revenue requirement and steam load for 2021
BA	Bankers’ Acceptance
BC	British Columbia
BCOAPO	BC Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations of BC, Disability Alliance BC, and Tenant Resource and Advisory Centre
BCUC	British Columbia Utilities Commission
CEC	Commercial Energy Consumers Association of British Columbia
CEDLP	The Creative Energy Group refers to Creative Energy Developments Ltd.
Core Steam Rates	2021 steam rates for the core steam system
Core Steam System	Creative Energy Vancouver Platforms Inc.’s steam production plant at 720 Beatty Street and the associated distribution network serving more than 200 buildings in downtown Vancouver and supplying thermal energy to Creative Energy’s Northeast False Creek hot water system
COS	Cost of Service
Creative Energy	Creative Energy Vancouver Platforms Inc.
Expo-Beatty Plants CPCN and Reorganization Decision	BCUC’s March 5, 2020 decision on Creative Energy’s Application for a CPCN for the Expo-Beatty Plants and Reorganization
FCAC	Fuel Cost Adjustment Charge
FCAC Rate Rider Application	Creative Energy’s application to BCUC on February 26, 2021, seeking, among other things, approval of the cancellation of the FCAC Rate Rider, effective February 28, 2020
FEI	FortisBC Energy Inc
HSBC	Hong Kong and Shanghai Banking Corporation
IAC/TPP	Inter-Affiliate Conduct and Transfer Pricing Policy
InstarAGF	InstarAGF Essential Infrastructure Fund
IR	Information request
land	Land located at 720 Beatty Street and 701 Expo Boulevard
LGIC Report	BCUC’s April 3, 2020 report and recommendation to the Lieutenant Governor in Council
NEFC	Northeast False Creek
New management positions	Three new positions in management category roles anticipated by Creative Energy for 2021
PEDA	Pension Expense Deferral Account
PTDA	Property Tax Deferral Account
RBC	Royal Bank of Canada
RCDA	Refinancing Cost Deferral Account
RCIA	Residential Consumer Intervenor Association (formerly Residential Consumer Intervenor Group – RCIG)
ROE	Return on Equity
RRA	Revenue Requirements Application
TD	Toronto Dominion Bank
TES	Thermal Energy Systems
TPRCDA	Third-Party Regulatory Cost Deferral Account
UCA	Utilities Commission Act
WCDA	Water Cost Deferral Account

IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

and

Creative Energy Vancouver Platforms Inc.

2021 Revenue Requirements Application for the Core Steam System

EXHIBIT LIST

Exhibit No. Description

Commission documents

A-1	Letter dated December 9, 2020 – Appointing the Panel for the review of Creative Energy Vancouver Platforms Inc. 2021 Revenue Requirements Application for the Core Steam System
A-2	Letter dated December 18, 2020 – Request to Creative Energy for further information
A-3	Exhibit removed and replaced with Exhibit A-3-1
A-3-1	Letter dated January 28, 2021 – Amended BCUC Order G-11-21A establishing a regulatory timetable
A-4	Letter dated February 11, 2021 – BCUC Information Request No. 1 to Creative Energy
A-5	Letter dated March 22, 2021 – BCUC Order G-88-21 establishing a further regulatory timetable
A-6	Letter dated April 15, 2021 – BCUC Information Request No. 2 to Creative Energy
A-7	CONFIDENTIAL - Letter dated April 15, 2021 – BCUC Confidential Information Request No. 2 to Creative Energy
A-8	Letter dated August 18, 2021 – Panel Information Request No. 1 to Creative Energy and Further Regulatory Timetable

Commission Staff documents

A2-1	Letter dated February 11, 2021 – BCUC Staff Submitting Aitken Creek Gas Storage ULC, British Columbia Utilities Commission Order G-39-16, Aitken Creek Gas Storage ULC Code of Conduct and Transfer Pricing Policy, Compliance Filing June 30, 2016
A2-2	Letter dated February 11, 2021 – BCUC Staff Submitting FortisBC Energy Inc. Application for Approval of Code of Conduct (COC) and Transfer Pricing Policy (TPP) for Affiliated Regulated Businesses Operating in a Non-Natural Monopoly Environment (ARBNNM), June 27, 2014
A2-3	Letter dated February 11, 2021 – BCUC Staff Submitting FortisBC Energy Inc., British Columbia Utilities Commission Order No. G-65-15 Compliance Filing – All-Inclusive Code of Conduct and Transfer Pricing Policy, June 30, 2016
A2-4	Letter dated February 11, 2021 – BCUC Staff Submitting Pacific Northern Gas Ltd., PNG-West Division – 2018-2019 Revenue Requirements Application, Commission Order G-151-18 Directive 7: Code of Conduct and Transfer Pricing Policy, Compliance Filing January 31, 2019

Applicant documents

B-1	Creative Energy Vancouver Platforms Inc. (Creative Energy) - 2021 Revenue Requirements Application (RRA) for the Core Steam System (Application) dated December 1, 2020
B-2	Letter dated January 6, 2021 - Creative Energy response to Panel request for further information
B-3	Letter dated February 26, 2021 – Creative Energy submitting Load Forecast Update and Request for Approval of a Steam Rate Increase
B-4	Letter dated March 4, 2021 – Creative Energy submitting response to BCUC Information Request No. 1
B-4-1	CONFIDENTIAL - Letter dated March 4, 2021 – Creative Energy submitting confidential response to BCUC Information Request No. 1
B-5	Letter dated March 4, 2021 – Creative Energy submitting response to CEC Information Request No. 1
B-6	Letter dated March 4, 2021 – Creative Energy submitting response to BCOAPO Information Request No. 1
B-6-1	CONFIDENTIAL - Letter dated March 4, 2021 – Creative Energy submitting confidential response to BCOAPO Information Request No. 1
B-7	Letter dated March 4, 2021 – Creative Energy submitting response to RCIG Information Request No. 1
B-8	Letter dated April 29, 2021 – Creative Energy submitting response to BCUC Information Request No. 2
B-9	CONFIDENTIAL - Letter dated April 29, 2021 – Creative Energy submitting response to BCUC confidential Information Request No. 2
B-10	Letter dated April 29, 2021 – Creative Energy submitting response to BCOAPO Information Request No. 2
B-11	Letter dated April 29, 2021 – Creative Energy submitting response to CEC Information Request No. 2
B-12	Letter dated April 29, 2021 – Creative Energy submitting response to RCIA Information Request No. 2
B-13	Letter dated August 25, 2021 – Creative Energy submitting response to BCUC Panel Information Request No. 1 and supplementary final submission is included in the Information Request responses and will not be filed separately

Intervener documents

C1-1	Residential Consumer Intervenor Group (RCIG) - Letter dated January 28, 2021 Request to Intervene by Fredrik Ambrosson, Midgard Consulting
C1-2	Letter dated February 19, 2021 – RCIG Information Request No. 1 to Creative Energy
C1-3	Letter dated April 15, 2021 – RCIG (Now RCIA) Information Request No. 2 to Creative Energy
C2-1	Commercial Energy Consumers Association of British Columbia (CEC) - Letter dated February 4, 2021 Request to Intervene by Christopher Weafer, Owen Bird Law Corporation
C2-2	Letter dated February 18, 2021 – CEC Information Request No. 1 to Creative Energy
C2-3	Letter dated April 15, 2021 – CEC Information Request No. 2 to Creative Energy
C3-1	British Columbia Old Age Pensioners’ Organization et al. (BCOAPO) - Letter dated February 10, 2021 Request for Late Intervener Status by Leigha Worth and Irina Mis
C3-2	Letter dated February 18, 2021 – BCOAPO Information Request No. 1 to Creative Energy
C3-3	Letter dated April 15, 2021 – BCOAPO Information Request No. 2 to Creative Energy

Interested party documents

D-1	Cadillac Fairview – Submission dated October 6, 2021 Request for Interested Party Status by L. Tummonds

[1] Exhibit B-1, p. 4.

[2] Exhibit B-1, p. 7.

[3] Exhibit B-1, pp. 9–10.

[4] Exhibit B-1, p. 9.

[5] Creative Energy Application for a Certificate of Public Convenience and Necessity for Beatty-Expo Plants and Reorganization, Decision and Order C-1-20 dated March 5, 2020.

[6] Exhibit B-1, p. 9.

[7] Exhibit B-1, p. 9.

[8] From Appendix A of the IAC/TPP Policy which is filed in Appendix C of the Application.

[9] Core Steam Rates were most recently reviewed and approved by the BCUC in the Creative Energy 2019-2020 Revenue Requirements Application Decision and Order G-227-20 dated September 2, 2020.

[10] Creative Energy Steam Tariff, Revision 15, p. 17.

[11] Order G-291-20A.

[12] Order G-214-20.

[13] Order G-214-20.

[14] Exhibit B-1, p. 16.

[15] Order G-259-19.

[16] Order G-84-21.

[17] In accordance with Order G-11-21A, on January 6, 2021, Creative Energy filed supplementary information at Exhibit B-2.

[18] On February 26, 2021, Creative Energy submitted evidentiary updates to the Application filed at Exhibit B-3. On March 4, 2021 and April 29, 2021, Creative Energy submitted responses to BCUC and intervener IRs filed as Exhibits B-4 to B-12.

[19] Creative Energy Final Argument, p. 3; Exhibit B-8, BCUC IR 47.3.

[20] Creative Energy Final Argument, p. 4; Exhibit B-8, BCUC IR 47.3.

[21] Creative Energy Final Argument, p. 4, Footnote 3.

[22] Exhibit B-1, pp. 7–8.

[23] Exhibit B-4, BCUC IR 27.2.

[24] Creative Energy Final Argument, p. 3.

[25] Orders G-11-21A, G-84-21 and G-88-21.

[26] Exhibit A-8.

[27] Order G-11-21A dated January 13, 2021.

[28] Order G-88-21 dated March 22, 2021.

[29] Creative Energy amended the following: 1) general and administration expenses by approximately -$50,000 in response to BCUC IR 29.3 to account for the Mount Pleasant TES in the Massachusetts Formula allocation of operating expenses; 2) water and electricity expenses by -$125,000 and -$10,000, respectively, on page 15 of the Creative Energy Reply Argument to reflect a 15 percent lower load forecast considering the impacts of the COVID-19 pandemic on the 2021 load forecast as discussed in Subsection 2.4 of this decision; 3) amortization of deferral accounts by +$8,309 ($24,926/3) to amortize the 2020 pension expense variance in response to BCUC IR 59.1 from the Pension Expense deferral account over three years per Creative Energy Final Argument footnote 1 and -$3,614 to amortize the 2020 water variance from the Water Cost deferral account over one year in response to BCUC IR 57.6; and 4) deemed ROE by -$930 in response to BCUC IR 19.5 after updating the December 31, 20202 pension asset for the rate-base After-tax Pension Asset deferral account.

[30] 2020 Approved per Exhibit B-1, p. 5 except the deemed ROE which was subsequently adjusted by approximately +$21,000 by Order G-322-20 dated December 8, 2020.

[31] Creative Energy’s initial 2021 forecast is presented on page 5 of the Application and was subsequently amended during the course of the proceeding. Details of the amended amounts and proposals are in Footnote 29.

[32] Exhibit B-4, BCUC IR 3.2. In the IR, Creative Energy states the actual financial results for 2020 are still unaudited preliminary figures that are provided in advance of an application to recover a 2020 balance in the COVID-19 Deferral Account. Table 1 excludes certain preliminary non-operating and other expense information provided by Creative Energy since it is subject to adjustments including income tax and the COVID-19 Deferral Account recovery.

[33] Exhibit B-1, p. 5.

[34] Exhibit B-4, BCUC IR 8.2.

[35] Exhibit B-1, p. 5.

[36] Calculated from Table 1 as: $61,109 = $991,046 - $929,937; Creative Energy Reply Argument, p. 15.

[37] Exhibit B-4, BCUC IR 8.2.

[38] Exhibit B-4, BCUC IR 8.3

[39] Exbibit B-4, BCUC IR 8.3.

[40] Exbibit B-4, BCUC IR 8.3.

[41] Exhibit B-4, BCUC IR 8.3.

[42] Exbibit B-1, p. 12; Exhibit B-4, BCUC IR 8.4.

[43] Exbibit B-1, p. 12; Exhibit B-4, BCUC IR 8.4.

[44] Exbibit B-1, p. 12; Exhibit B-4, BCUC IR 8.4.

[45] Exhibit B-4, BCUC IR 29.3.

[46] Exhibit B-4, BCUC IR 8.2.

[47] RCIA Final Argument, pp. 6, 8.

[48] CEC Final Argument, p. 17.

[49] BCOAPO Final Argument, p. 2.

[50] BCOAPO Final Argument, p. 4.

[51] Creative Energy Reply Argument, p. 8.

[52] Creative Energy Reply Argument, pp. 12–13.

[53] Creative Energy Reply Argument, p. 6.

[54] Exhibit B-1, Section 3.1.3.3, p. 24; Exhibit B-4, BCUC IR 7.1.1.

[55] Variances derived from information in Exhibit B-8, BCUC IR 49.4.

[56] 2017: Creative Energy Compliance Filing Order G-167-16, Schedule 15, Acct. # 870, p.38; 2018-2019: Creative Energy RRA for Core and NEFC Order G-227-20 Compliance Filing, Attachment 5 – Schedules for RRA filing, Schedule 15, Acct #870.

[57] Exhibit B-4, BCUC IR 7.2 and 7.3.

[58] Exhibit B-1, p. 24.

[59] Exhibit B-5, CEC IR 2.2.

[60] Exhibit B-8, BCUC IR 49.1.

[61] Exhibit B-4, BCUC IR 7.2

[62] Exhibit B-8, BCUC IR 49.1.

[63] Exhibit B-8, BCUC IR 49.2.

[64] RCIA Final Argument, p. 6.

[65] CEC Final Argument, p. 8.

[66] CEC Final Argument, p. 9.

[67] Creative Energy Reply Argument, p. 8.

[68] Creative Energy Reply Argument, p. 14.

[69] Creative Energy Reply Argument, p. 15.

[70] Exhibit B-8, BCUC IR 48.1.2.

[71] Exhibit B-1, pp. 26–27.

[72] Exhibit B-4, BCUC IR 24.1.

[73] Exhibit B-8, BCUC IR 57.1.

[74] Creative Energy Final Argument, p. 16.

[75] Exhibit B-1, p. 28.

[76] Exhibit B-8, BCUC IR 48.1.

[77] CEC Final Argument, p. 19.

[78] CEC Final Argument, p. 21.

[79] Creative Energy Reply Argument, pp. 14–15.

[80] Exhibit B-1, p. 33.

[81] Exhibit B-1, Section 3.3, p. 33; Creative Energy Final Argument, p. 15.

[82] Exhibit B-4, BCUC IR 15.1.

[83] Exhibit B-5, CEC IR 18.1.

[84] Exhibit B-8, BCUC IR 53.10.

[85] Creative Energy Final Argument, p. 15.

[86] Exhibit B-1, p. 10; Order C-1-20.

[87] Exhibit B-4, BCUC IR 15.3.

[88] Exhibit B-4, BCUC IR 15.3.

[89] Exhibit B-4, BCUC IR 15.3.

[90] RCIA Final Argument, p. 9; CEC Final Argument, p. 24.

[91] RCIA Final Argument, p. 9.

[92] CEC Final Argument, p. 24.

[93] Creative Energy Reply Argument, pp. 15–16.

[94] Creative Energy Reply Argument, p. 16.

[95] Creative Energy Reply Argument, p. 15.

[96] Exhibit B-1, pp. 39–40.

[97] Exhibit B-1, p. 40.

[98] Calculated as: ($1,914,085 x 57.5% x 4.0% /2) equals $22,012 or approximately $22,000 and $1,914,085 x 42.5% x 9.5% /2 equals $38,641 or approximately $39,000 per Creative Energy’s capital structure and cost of capital as provided for in Schedule 13 of the 2021 Core RRA Schedules and Creative Energy’s final Argument on page 13.

[99] Exhibit B-1, 2021 Core RRA Schedules, Schedule 5.

[100] Creative Energy Final Argument, p. 6.

[101] Creative Energy Final Argument, p. 6.

[102] Exhibit B-2, p. 4.

[103] Exhibit B-4, BCUC IR 16.2.

[104] BCOAPO Final Argument, p. 5.

[105] RCIA Final Argument, p. 12.

[106] RCIA Final Argument, p. 12.

[107] BCOAPO Final Argument, p. 5.

[108] RCIA Final Argument, p. 13.

[109] BCOAPO Final Argument, p. 5.

[110] Creative Energy Reply Argument, p. 10.

[111] Creative Energy Reply Argument, p. 4.

[112] Order G-227-20.

[113] Exhibit B-1, Section 3.6.2, p. 37; Order G-187-20.

[114] Exhibit B-1, Section 3.6.2, p. 37.

[115] Exhibit B-1, Section 3.6.2, p. 37.

[116] Exhibit B-1, Section 4.2, p. 47; Exhibit B-8, BCUC IR 55.1.

[117] Exhibit B-4, BCUC IR 20.1.

[118] Exhibit B-8, BCUC IR 55.10.

[119] Exhibit B-8, BCUC IR 55.5.

[120] 2019-2020 Core Steam RRA, Exhibit B-9, Schedules for RRA Filing – IR Round 2; Exhibit B-1, 2021Core RRA Schedules – Core Schedule 2.

[121] Approved 2020 – 2019-2020 Core Steam RRA, Exhibit B-9, Schedules for RRA Filing – IR Round 2, Core Schedule 2; Projected 2020 and Forecasted 2021 - Exhibit B-1, 2021 Core RRA Schedules – Core Schedule 2.

[122] Approved 2020 – 2019-2020 Core Steam RRA, Exhibit B-9, Schedules for RRA Filing – IR Round 2, Core Schedule 13; Projected 2020 – Exhibit B-4, BCUC IR 3.2; Forecasted 2021 - Exhibit B-1, 2021 Core RRA Schedules – Core Schedule 13.

[123] Exhibit B-1, 2021 Core RRA Schedules, Schedule 2 Rate Base and Schedule 13 Rate Base; $15,389061 x 0.04 = $617,000.

[124] Creative Energy Final Argument, pp. 13-14.

[125] Creative Energy Final Argument, pp. 13-14.

[126] Exhibit B-8, BCUC IR 55.13.

[127] Exhibit B-8, BCUC IR 55.13.

[128] Creative Energy Final Argument, pp. 13–14.

[129] BCOAPO Final Argument, p. 8.

[130] RCIA Final Argument, p. 8.

[131] CEC Final Argument, pp. 26–27.

[132] Creative Energy Reply Argument, p. 5.

[133] Creative Energy Reply Argument, p. 5.

[134] Creative Energy Vancouver Platforms Inc. Application for Approval of a Credit Agreement Decision and Order G-187-20, Appendix A, p.1; Creative Energy Vancouver Platforms Inc. Application for Approval of a Credit Agreement, p. 3.

[135] Exhibit B-8, BCUC IR 55.2.

[136] Creative Energy Final Argument, p. 13.

[137] Originally forecast to be $1,081,000 in the Application but amended by -$930 in response to BCUC IR 19.5 after updating the December 31, 2020 pension asset for the rate-base After-tax Pension Asset deferral account.

[138] Exhibit B-1, p. 37.

[139] Exhibit B-8, BCUC IR 53.7.

[140] Exhibit B-1, p. 10; Exhibit B-4, BCUC IR 15.2.2.

[141] Exhibit B-8, BCUC IR 53.7.1.

[142] Exhibit B-8, BCUC IR 53.7.1.

[143] CEC Final Argument, p. 24.

[144] Creative Energy Reply Argument, p. 15.

[145] Creative Energy Reply Argument, p. 16.

[146] Decision and Order C-1-20.

[147] Decision and Order C-1-20.

[148] Decision and Order G-227-20, pp. 27–32.

[149] Exhibit B-1, Section 4.1.2, pp. 44–45.

[150] Exhibit B-1, Section 4.1.2, p. 44.

[151] Exhibit B-4, BCUC IR 23.1.

[152] Exhibit B-4, BCUC IR 23.1.

[153] BCOAPO Final Argument, p. 7; CEC Final Argument, p. 28.

[154] Exhibit B-4, BCUC IR 27.2.

[155] Exhibit B-8, BCUC IR 59.1.

[156] Exhibit B-1, Section 4.1.2, p. 44.

[157] Exhibit B-1, Section 4.1.2, p. 44.

[158] Creative Energy 2019-2020 RRA Decision and Order G-227-20, p. 8.

[159] Creative Energy 2019-2020 RRA Decision and Order G-227-20, p. 15.

[160] Exhibit B-1, Appendix E; Exhibit B-4, BCUC IR 27.2.

[161] Exhibit B-1, Appendix E; Exhibit B-4, BCUC IR 27.2.

[162] Exhibit B-4, BCUC IR 27.2.

[163] Exhibit B-4, BCUC IR 27.2.

[164] Exhibit B-1, p. 43.

[165] Order G-227-20.

[166] Exhibit B-1, p. 42.

[167] Exhibit B-1, p. 43; Exhibit B-8, BCUC IR 57.4.

[168] Exhibit B-3, BCUC IR 24.2.

[169] Exhibit B-8, BCUC IR 57.6.1.

[170] Exhibit B-8, BCUC IR 57.3.

[171] Exhibit B-8, BCUC IR 57.4.

[172] CEC Final Argument, p. 28.

[173] RCIA Final Argument, p. 9.

[174] BCOAPO Final Argument, p. 7.

[175] BCOAPO Final Argument, p. 8.

[176] Creative Energy Reply Argument, p. 9.

[177] Order G-227-20.

[178] Exhibit B-4, BCUC IR 15.3.

[179] Exhibit B-1, Section 4.1.4, p. 46; Exhibit B-4, BCUC IR 25.1.

[180] Exhibit B-1, Section 3.3, p. 33.

[181] Exhibit B-1, Section 4.1.4, pp. 46–47.

[182] BCOAPO Final Argument, p. 7; CEC Final Argument, p. 28.

[183] Exhibit B-1, Section 4.2, p. 47.

[184] Exhibit B-8, BCUC IR 58.3 and 58.3.1.

[185] Creative Energy Final Argument, p. 15.

[186] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-1, Appendix A, p. 10.

[187] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-1, Appendix A, p. 25.

[188] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[189] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[190] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[191] Creative Energy Vancouver Platforms Inc. Application for Certificate of Public Convenience and Necessity for the Expo–Beatty Plants and Reorganization - Decision and Order C-1-20, p. 27; Expo-Beatty Plants CPCN and Reorganization Decision proceeding; Exhibit B-1, pp. 107–110.

[192] Exhibit B-1, Section 4.2, p. 47.

[193] Exhibit B-8, BCUC IR 58.5.

[194] Exhibit B-8, BCUC IR 58.5.

[195] Exhibit B-8, BCUC IR 58.5 and 58.6.

[196] Exhibit B-1, Section 4.2, p. 47.

[197] Exhibit B-1, Section 4.2, p. 47.

[198] Exhibit B-1, Section 4.2, p. 47.

[199] Exhibit B-8, BCUC IR 58.3 and 58.3.1.

[200] Exhibit B-4, BCUC IR 26.1.1.1; Exhibit B-8, BCUC IR 58.1.1.

[201] Exhibit B-8, BCUC IR 58.1.

[202] Exhibit B-1, Section 4.2, p. 47.

[203] Exhibit B-4, BCUC IR 26.4.1.

[204] Exhibit B-4, BCUC IR 26.4; Exhibit B-8, BCUC IR 58.8.

[205] Exhibit B-1, Section 4.2, p.48; Utility Key to Organizational Chart: Core = Core Steam District Energy System, M&K = Main & Keefer Heating TES, NEFC = Northeast False Creek Neighborhood Energy System, Kensington = Kensington Gardens Heating and Cooling TES, SODO Cool = Vancouver House Cooling TES; and SODO Heat = South Downtown Heating Thermal Energy System (TES).

[206] Exhibit B-4, BCUC IR 26.3.

[207] Exhibit B-4, BCUC IR 26.

[208] Exhibit B-8, BCUC IR 58.7.

[209] Exhibit B-1, Section 4.2, p. 47.

[210] Exhibit B-13, Panel IR 1.

[211] Exhibit B-13, Panel IR 1.

[212] Exhibit B-13, Panel IR 1.

[213] Exhibit B-13, Panel IR 1.

[214] Exhibit B-13, Panel IR 1.

[215] BCOAPO Supplemental Final Argument, pp. 1–2.

[216] BCOAPO Supplemental Final Argument, p. 2.

[217] BCOAPO Supplemental Final Argument, p. 2.

[218] BCOAPO Supplemental Final Argument, p. 3.

[219] BCOAPO Final Argument, p. 7.

[220] CEC Supplemental Final Argument. p. 3.

[221] CEC Supplemental Final Argument. p. 3.

[222] CEC Supplemental Final Argument. p. 3.

[223] Creative Energy Supplemental Reply Argument, pp. 2–3.

[224] Creative Energy Supplemental Reply Argument, p. 3.

[225] Creative Energy Supplemental Reply Argument, p. 3.

[226] Creative Energy Supplemental Reply Argument, p. 2.

[227] Creative Energy Supplemental Reply Argument, p. 2.

[228] Creative Energy Supplemental Reply Argument, p. 2.

[229] Creative Energy Reply Argument, p. 5.

[230] Creative Energy Final Argument, p. 15.

[231] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[232] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[233] Expo-Beatty Plants CPCN and Reorganization Decision proceeding, Exhibit B-5, BCUC IR 63.1.

[234] Exhibit B-13, Panel IR 1.

[235] Exhibit B-4, BCUC IR 26.3.

[236] Exhibit B-4, BCUC IR 26.

[237] Creative Energy Final Argument, pp. 13–14.

[238] Creative Energy Supplemental Reply Argument, p. 2.

[239] Creative Energy Supplemental Reply Argument, p. 2.

[240] Expo-Beatty Plants CPCN and Reorganization Decision proceeding; Exhibit B-1, pp. 107–110.

[241] Expo-Beatty Plants CPCN and Reorganization Decision proceeding; Exhibit B-1, pp. 107–110.

[242] Exhibit B-8, BCUC IR 58.10.

[243] Exhibit B-1, Section 3.6.2, p. 37.

[244] $297,681 + $22, 436 = $320,117 x Core Steam System’s allocation of deemed debt from Table 10 (73.55 percent) = $235,452 plus $4,120 of interest charged in 2020 and $8,385 charged in 2021 =$247,957.

[245] Order G-104-21 dated April 6, 2021.

[246] NEFC Rate Proposal and 2021 Revenue Requirement Application Decision, pp. 9–10.

[247] RCIA Final Argument, p. 9.

[248] RCIA Final Argument, p. 9.

[249] BCOAPO Final Argument, p. 7.

[250] BCOAPO Final Argument, p. 8.

[251] Creative Energy Reply Argument, p. 9.

[252] Exhibit B-3, p. 2.

[253] Exhibit B-3, p. 2; Exhibit B-4, Response to BCUC IR 2.1.

[254] Exhibit B-3, p. 2.

[255] Exhibit B-3, p. 3.

[256] Exhibit B-3, p. 3.

[257] Exhibit B-3, p. 3.

[258] Exhibit B-1, p. 16.

[259] Order G-214-20 dated August 14, 2020, Directive 1(ii)(c).

[260] Exhibit B-4, BCUC 1.4.2.

[261] Exhibit B-4, BCUC 1.4.7.

[262] For the January 1, 2021 interim steam rates, this is the 2020 Approved average steam rate of $8.13. For the March 1, 2021 interim steam rate, this is the January 1, 2021 interim steam rate of $8.69.

[263] Creative Energy Final Argument, p. 4, Footnote 3.

[264] Exhibit B-8, BCUC IR 47.2.

[265] Exhibit B-8, BCUC IR 47.3.1.

[266] Exhibit B-3, p. 2.

[267] Order G-84-21 dated March 18, 2021.

[268] The CEC’s percentages are before final proposed amendments to the Revenue Requirement.

[269] CEC Final Argument, p. 4.

[270] CEC Final Argument, p. 4.

[271] CEC Final Argument, p. 6.

[272] CEC Final Argument, p. 7.

[273] CEC Final Argument, p. 7.

[274] BCOAPO Final Argument, p. 3.

[275] RCIA Final Argument, p. 6.

[276] Creative Energy Reply Argument, pp. 10–11.

[277] Order G-214-20.

[278] Exhibit B-4, BCUC IR 3.2.

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