EXECUTIVE SUMMARY. i

 

1.0          INTRODUCTION.. 1

1.1          Background. 1

1.2          Application and approvals sought. 1

1.3          Legislative framework. 1

1.4          Regulatory process. 3

1.5          Key Stakeholders. 4

1.6          Approach to this Decision. 5

2.0          CONTEXTUAL ISSUES. 6

2.1          Company in transition. 6

2.2          Capital structure and cost of capital evidence. 7

2.3          Test period for this Application. 8

2.4          Accounting Methods. 8

2.5          Rate impact and bill impact. 8

3.0          LONG TERM RESOURCE PLAN.. 8

4.0          FUEL COST ADJUSTMENT METHODOLOGY AND RATE DESIGN.. 15

4.1          What is the nature and appropriate treatment of the Fuel Cost Stabilization Account?. 16

4.2          Should an increased portion of the fuel costs be recovered in the Steam Tariff rate?. 20

4.3          What degree of reporting and Commission oversight is warranted regarding the
                Fuel Cost Stabilization Account?
                The mechanism by which the Fuel Cost Adjustment charge is periodically adjusted?. 25

5.0          OPERATING EXPENSES. 27

5.1          Management transition costs. 28

5.2          New employee and cost allocations. 31

5.2.1      New employees and cost allocations. 33

5.2.2      Cost allocations from O&M to Capital 35

5.3          General Administrative and Office. 35

5.3.1      Sales Expense. 35

5.3.2      Directors’ Fees. 37

6.0          LOAD FORECAST. 38

7.0          CAPITAL EXPENDITURES. 40

8.0          PENSION ISSUES. 41

8.1          Introduction and Background. 41

8.1          Requested treatment. 42

8.2          Pension expense (operating expense). 43

8.3          After-tax Pension Asset. 44

8.3.1      After-tax Regulatory Pension Asset. 45

8.4          Regulatory Transitional Adjustment. 47

8.5          Deferral account treatment of the transitional adjustment. 51

8.6          Rate base treatment of the After-tax Regulatory Pension Asset. 52

8.6.1      Mid-year After-tax Regulatory Pension Asset. 52

8.7          Request for pension expense variance deferral account. 52

9.0          OTHER iSSUES. 55

9.1          GCOC Impact of 2013-2014. 55

9.1.1      History. 55

9.1.2      Evidence. 55

9.2          NEFC Revenue Offset. 56

9.3          Difference between Interim and Permanent Rates for 2015. 57

9.4          Future RRAs. 57

 

COMMISSION ORDER G-98-15

 

Appendices

Appendix A – List of Acronyms

Appendix B – List of Exhibits

 

 

EXECUTIVE SUMMARY

On November 28, 2014, Creative Energy Vancouver Platforms Inc. (Creative Energy) filed its 2015-2017 Revenue Requirements Application (RRA) with the British Columbia Utilities Commission (Commission), pursuant to sections 59-61, and 89 of the Utilities Commission Act. On February 27, 2015, Creative Energy filed an Evidentiary Update to its 2015-2017 RRA, reflecting numerous corrections, recalculations and reclassifications in response to information requests by the Commission and the Commercial Energy Consumers Association of British Columbia.

 

Creative Energy seeks approval of the following:

•         Increases in the Steam Tariff portion of the rates of 13.5%, 1% and 1.6% effective January 1, 2015, January 1, 2016 and January 1, 2017 respectively. These rates were subsequently revised to be 13.3%, 4.0%, and -0.9%, respectively;

•         Recognition of the After-tax Pension Asset in rate base effective January 1, 2015;

•         Certain new deferral accounts;

•         Former senior management transition costs;

•         Increases in operating costs and  certain capital expenditures; and

•         Incorporation of the impact of the allowed equity component of 42.5% in the capital structure with a 9.5% return on equity (ROE) in rates.

 

Creative Energy operates a natural gas-fired steam district energy system in Vancouver’s downtown business district which serves over 200 customers, including office buildings, condominiums, hotels, etc. The City of Vancouver has selected Creative Energy as its franchisee to pursue low-carbon neighborhood energy systems (NES) in Northeast False Creek (NEFC) and Chinatown. Action plans contemplated include conversion of the Creative Energy system from natural gas to a low carbon energy source, and expansion of neighborhood energy systems to new developments and existing natural gas-heated buildings in high density areas. Due to recent ownership, board and management changes as well as the new plans, Creative Energy clearly is a company in transition, which is embarking on a major transformation. This transition may impact the cost of service provided to the current customers of the core steam system.

 

In this Decision, the Panel endeavours to balance the interests of Creative Energy and its core customers. The utility must be sufficiently compensated for the services it provides and have a reasonable opportunity to earn its allowed return on investment. At the same time, the Panel must to ensure that core customers are not paying rates that are unjust or unreasonable and that they are not unfairly subsidizing business development activities of Creative Energy.

 

The Panel will refer to Creative Energy’s “core” business as consisting of its current mature set of existing customers and related infrastructure. The intent is to differentiate Creative energy’s core business from proposed new neighbourhood district energy systems. Because the review process of the recently filed NEFC CPCN application is still on-going, the Panel takes guidance from section 60(2) of the UCA for the purposes of this RRA Decision. Accordingly, the determinations in this Decision that relate to the

potential approval of the NEFC CPCN consider the future NEFC customers a distinct or special area served by Creative Energy. Some of these considerations are required because the expectation is that at least in the short term the NEFC, should it be approved, will receive its primary energy supply from the core system.

 

Given the utility’s transitional nature and the uncertainty created by it, lack of a clear approach to resource sharing between the core and other businesses, as well as taking into account the inconsistencies, multiple corrections and adjustments found in the evidence, the Panel finds that approval of only a one year test period for 2015 is warranted. Accordingly, the Panel declines to approve the three year test period 2015-2017 sought by Creative Energy.

 

The notable disallowances or additional directives in the revenue requirements include the following:

•         Compensation for the new Vice President, Business Development to be included in the 2015 revenue requirement reduced from 50% to 25%;

•         Transition costs for one of the two former senior executives are denied; and

•         Creative Energy is to apply its weighted average cost of debt to the most current balance of the Fuel Cost Stabilization Account and treat the resultant interest cost (customer credit) as a revenue offset in the 2015 revenue requirements.

 

Key approvals include the following:

•         Final delivery rates for all steam customers effective January 1, 2015, subject to the filing of the adjustments to the 2015 revenue requirements outlined in this Decision;

•         Recognition of the After-tax Pension Asset in rate base effective January 1, 2015 by addition of $414,012, which represents the mid-year Regulatory Pension Asset;

•         A Regulatory Transitional Adjustment Deferral Account (pension related) to amortize the balance of $301,777 over a three-year period, commencing January 1, 2015;

•         The creation of a Pension Expense Deferral Account to capture the variance between the forecast Pension Expense recovered in rates and the Pension Expense reported in financial statements;

•         The amortization of the 2013/2014 Generic Cost of Capital (GCOC) Deferral Account to incorporate the impact of the 9.5% ROE on the 42.5% equity component approved in the GCOC Stage 2 proceeding. The balance of $333,012 is to be amortized and recovered from customers over two years commencing January 1, 2016; and

•         The 2015 load forecast is accepted. However, Creative Energy is directed to consider other methods of load forecasting in its next RRA. If use of customer surveys as the primary methodology continues, Creative Energy should consider adjusting for any inherent bias in the customer driven forecasts.

 

Additional filings and studies directed by the Panel include:

•         A long-term resource plan (LTRP) regarding the existing steam utility to be filed no later than two years following this Decision, and prior to making an investment decision regarding any low carbon fuel switch that may impact the existing steam customers. The LTRP is to include information available from the fuel switch feasibility study;

•         A proposal for the permanent treatment of the Fuel Cost Stabilization Account to be filed with the next RRA;

•         A Phase I rate design application to be filed within one year from the date of this Decision, specifically in regard to recovery of fuel costs. Subject to the pending decision on the NEFC CPCN, a comprehensive rate design study (Phase II) may be required later;

•         Creative Energy is to include an annual reconciliation of the Fuel Cost Stabilization Account with its Annual Report filings and with its Annual Gas Contracting Plan filing;

•         A cost allocation methodology to be filed within two years of this Decision to address resource sharing, cost allocation policies and the Panel’s concern on potential cross-subsidization; and

•         A capitalized overhead study in the next RRA outlining Creative Energy’s policies on allocating costs from O&M to capital.

 

The Panel expects that the compliance filing, which takes into account all approvals and disallowances, will result in an increase to the Steam Tariff portion of the rates. However, the Panel considers that the overall bill impact will still be in the range of reasonableness for Creative Energy’s customers.

 

1.0               INTRODUCTION

1.1               Background

Creative Energy Vancouver Platforms Inc. (Creative Energy, or the Company) operates as a public utility selling energy in the form of steam, serving 200 plus customers[1] in the downtown core in the City of Vancouver (CoV). Creative Energy (formerly Central Heat Distribution Ltd. (CHDL)) was acquired by Creative Energy Canada Platforms Corp. (Creative Energy Canada) in March 2014, which was followed by the appointment of a new Board of Directors and a change in management.

1.2               Application and approvals sought

On November 28, 2014, Creative Energy filed its 2015 to 2017 Revenue Requirements Application (RRA) with the British Columbia Utilities Commission (Commission) seeking to amend its Steam Tariffs for each of the three years (Application). The Steam Tariff changes being proposed are:

•         13.5% increase effective January 1, 2015;

•         1% increase effective January 1, 2016; and

•         1.6% increase effective January 1, 2017.

 

Among other requests contained in the evidence of this proceeding, Creative Energy seeks approval for the rate base treatment of the pension asset, approvals for certain deferral accounts, and an increase in its operating costs and capital expenditures for each of the three years.

1.3               Legislative framework

Rates

Creative Energy filed its 2015-2017 RRA pursuant to sections 59-61 and 89 of the Utilities Commission Act (UCA). Section 59 (1)(a) of the UCA provides that a public utility must not make, demand or receive an “unjust, unreasonable, unduly discriminatory or unduly preferential rate” for its services. The UCA further provides that the Commission Panel is the sole judge of determining whether a rate is unjust or unreasonable, or whether there is undue discrimination, preference, prejudice or disadvantage respecting a rate (s. 59(4)). Specifically, the UCA sets out the parameters for rate setting. It provides that a rate is unjust or unreasonable if it is more than a fair and reasonable charge for service of the nature and quality provided by the utility (59(5)(a)) or if it is “insufficient to yield a fair and reasonable compensation for the service provided by the utility, or a fair and reasonable return on the appraised value of its property” (59(5)(b)).

 

Nature of service

The Definitions section of the UCA defines service as including

(a)    The use and accommodation provided by a public utility,

(b)   A product or commodity provided by a public utility, and

(c)    The plant, equipment, apparatus, appliances, property and facilities employed by or in connection with a public utility in providing service or a product or commodity for the purposes in which the public utility is engaged and for the use of and accommodation of the public;

Pursuant to section 60(1)(c) of the UCA, if the public utility provides more than one class of service, the commission must

(i)                  Segregate the various kinds of service into distinct classes of service,

(ii)                In setting a rate to be charged for the particular service provided, consider each distinct class of service as a self-contained unit, and

(iii)               Set a rate for each unit that it considers to be just and reasonable for that unit, without regard to the rates fixed for any other unit.

Pursuant to section 60(2) of the UCA,

“In setting a rate under this Act, the commission may take into account a distinct or special area served by a public utility with a view to ensuring, so far as the commission considers it advisable, that the rate applicable in each area is adequate to yield a fair and reasonable return on the appraised value of the plant or system of the public utility used, or prudently and reasonably acquired, for the purpose of providing the service in that special area.”

 

Long-Term Resource Plan

Section 44.1(2) of the UCA sets out that “a public utility must file with the commission, in the form and at the times the commission requires, a long-term resource plan including all of the following:

(a) an estimate of the demand for energy the public utility would expect to serve if the public utility does not take new demand-side measures during the period addressed by the plan;

(b) a plan of how the public utility intends to reduce the demand referred to in paragraph (a) by taking cost-effective demand-side measures;

(c) an estimate of the demand for energy that the public utility expects to serve after it has taken cost-effective demand-side measures;

(d) a description of the facilities that the public utility intends to construct or extend in order to serve the estimated demand referred to in paragraph (c);

(e) information regarding the energy purchases from other persons that the public utility intends to make in order to serve the estimated demand referred to in paragraph (c);

(f) an explanation of why the demand for energy to be served by the facilities referred to in paragraph (d) and the purchases referred to in paragraph (e) are not planned to be replaced by demand-side measures;

(g) any other information required by the commission.”

 

Subsection 44.5(3) states:

The commission may exempt a public utility from the requirement to include in a long-term resource plan filed under subsection (2) any of the information referred to in paragraphs (a) to (f) of that subsection if the commission is satisfied that the information is not applicable with respect to the nature of the service provided by the public utility.

 

Subsection 44.1(5) states “[t]he commission may establish a process to review long-term resource plans filed under subsection (2).”

 

Included among the items set out in subsection 44.1(8) that the Commission must consider, are the applicable British Columbia energy objectives and the interests of current and future customers of the utility.

1.4               Regulatory process

Creative Energy filed its original Application on November 28, 2014 requesting, among other things, that its proposed rates for January 1, 2015 be approved on an interim basis. By Order G-198-14, which established the preliminary timetable for review of the Application, the Commission granted approval for an interim rate increase of 7.9%, effective January 1, 2015, subject to adjustments following the review and final decision for this Application.

 

The regulatory review originally encompassed one round of information requests (IRs) and responses. However, after the Commission reviewed the first round of IR responses and subsequent evidentiary update filed by Creative Energy on February 27, 2015 (Exhibit B-1-1), the Commission Panel extended the review to include a second round of IRs. The Panel also accepted the filing of Creative Energy’s 2014 Financial Statements on April 24, 2015[2], which marked the closing of evidence in this proceeding.

 

The sole intervener in this proceeding was the Commercial Energy Consumers Association of British Columbia (CEC). CEC submits that the primary interest group it represents is the Building Owners and Managers Association (BOMA) of British Columbia in this proceeding, which is comprised of owners and/or managers of a significant number of the buildings served by Creative Energy.[3]

 

Final Submissions from the applicant and interveners were received on April 27 and May 4, 2015, respectively. A reply submission from Creative Energy was received on May 11, 2015.

 

The Panel has considered all of the evidence filed by the applicant and interveners in this proceeding in making its final determinations as outlined in this Decision.

1.5               Key Stakeholders

The following diagram depicts the key stakeholders, agreements and relationships.

 

1.6               Approach to this Decision

In this Decision, the Panel endeavours to balance the interests of Creative Energy and its core customers. The utility must be sufficiently compensated for the services it provides and have a reasonable opportunity to earn its allowed return on investment. At the same time, the Panel must to ensure that core customers are not paying rates that are unjust or unreasonable and also not unfairly subsidizing business development activities of Creative Energy that may not result in future benefits to the core customers. This is an especially challenging undertaking at the time when Creative Energy is embarking on a major business transformation.

 

A number of important issues arose within this proceeding that provide context for the structured review of this Application. These are:

(i)                  the transitional natural of Creative Energy’s current business;

(ii)                the evidence on capital structure and the appropriate cost of capital;

(iii)               the absence of a long-term resource plan;

(iv)              the length of the test period being sought;

(v)                the forecasting methods employed; and finally

(vi)              consideration of the rate impact versus bill impact to customers.

 

These important issues are discussed in Section 2 of this Decision.

 

Section 3 addresses the requirement to file a long-term resource plan (LTRP). Section 4 deals with Creative Energy’s fuel cost adjustment methodology. An examination of issues related to operations and maintenance expenses is undertaken in Section 5, including a consideration of the management transition costs. In Section 6, Creative Energy’s load forecast is examined, followed by a discussion of capital expenditures in Section 7. Section 8 contains an assessment of Creative Energy’s pension related issues. Finally in Section 9, the Panel examines a number of issues raised within the proceeding and provides determinations or direction where appropriate. A list of recommendations for improvements to the preparation of revenue requirement applications (RRAs) for future proceedings is also provided.

 

In addition, throughout this Decision the Panel emphasizes the concerns related to the cost, benefits, and risk exposure to be shared between the core customers of Creative Energy’s existing system and the new customers of any other future district energy system owned by Creative Energy. These issues are raised in specific applicable parts of this Decision.

 

For clarification, the Panel will refer to Creative Energy’s “core” business as its current mature set of existing customers and related infrastructure in the downtown business district. The intent is to differentiate Creative Energy’s core business with proposed new neighbourhood district energy systems with mandatory connections. As shown in Diagram 1, the expectation is that at least in the short term the NEFC and Chinatown TES proposed projects will receive their primary energy supply from the core system should they be approved. Furthermore, both the core system and the proposed TES projects are legally owned by the same company, Creative Energy. Due to the early stage of the project development, there have been no decisions made regarding how properly

distinguish, for regulatory purposes, the core customers from the future customers of the new TES systems. The Panel notes that in the NEFC CPCN application, Creative Energy is seeking approval of a two part rate design, consisting of a fixed charge and variable energy recovery charge which is comparable to the rate design for other new hot water systems in B.C.

 

Because the review process of the NEFC CPCN application is still on-going the Panel takes guidance from section 60(2) of the UCA for the purposes of this RRA Decision. Accordingly, the determinations in this Decision that relate to the potential approval of the NEFC CPCN consider the future NEFC customers a distinct or special area served by Creative Energy.

 

2.0               CONTEXTUAL ISSUES

2.1               Company in transition

The City of Vancouver has adopted an action plan to reduce greenhouse gas emissions. A high priority strategy of the Greenest City 2020 Action Plan is to pursue low-carbon neighbourhood energy systems (NES) for high-density mixed-use neighbourhoods. The Vancouver Neighbourhood Energy Strategy focuses on high density areas of the city including the downtown, Cambie corridor and central Broadway areas. For the downtown area, the key Neighbourhood Energy Strategy actions are to convert the Creative Energy system from natural gas to a low carbon energy source and to expand neighbourhood energy to new developments and existing gas-heated buildings in high density areas.[4]

 

In 2013, Creative Energy Canada Platforms Corp., the parent company of Creative Energy, entered into a Memorandum of Understanding with the City of Vancouver with respect to:

•         Northeast False Creek (NEFC) and Chinatown: Establishment of a NES for NEFC and Chinatown. A Franchise Agreement was subsequently executed on May 26, 2014 between the City and Creative Energy. In this agreement, Creative Energy has committed to providing heat to new developments in NEFC and Chinatown, and the heat will be required to be from low-carbon sources by 2020. The City has committed to consider enactment of a by-law compelling connection of new developments to the system. A separate application has been submitted to the Commission by Creative Energy for a Certificate of Public Convenience and Necessity (CPCN).

•         Conversion of Downtown Steam System: Creative Energy Canada will conduct the feasibility analysis and business planning for a low carbon conversion of the existing Downtown steam plant.

•         South Downtown: Creative Energy Canada will consider the establishment of a NES for the South Downtown area.

•         Other Expansion Areas: Creative Energy Canada and the City of Vancouver will explore options for neighbourhood energy initiatives in the West End, Downtown Eastside and other potential NES expansion areas.[5]

 

Creative Energy submits the Company is now uniquely positioned to meet expectations of both core customers and customers in areas of the downtown and elsewhere in Vancouver not formerly served by it. Creative Energy further submits those expectations define the objectives of the Company, and are consistent with its obligations under the UCA. Creative Energy believes that the Application achieves a balance between core customers and growth. It states that growth offers the possibility to reduce costs and risks for the core through economies of scale, shared overheads, and lower stranded investment risk for existing Assets.[6]

 

While Creative Energy is embarking on these business development plans, the Panel wishes to ensure that interests of core customers are protected. Resource sharing, rate design, and potential cross‑subsidization are examples of issues that require further consideration.

2.2               Capital structure and cost of capital evidence

By Order G-20-12, the Commission established a Generic Cost of Capital (GCOC) proceeding to review the appropriate cost of capital for a benchmark low-risk utility and to determine the allowed cost of capital for all utilities within its jurisdiction as compared to the established benchmark. The Stage 1 Decision established FortisBC Energy Inc. as the benchmark with an allowed 8.75% return on equity (ROE) effective January 1, 2013.[7] The Stage 2 Decision of the GCOC proceeding divided utilities into three groups. Group 3 included thermal energy system (TES) utilities such as Creative Energy, Corix Utilities Inc., River District Energy Limited Partnership and FortisBC Alternative Energy Services Inc.

 

By Order G-47-14, the Commission determined that the common equity component for small TES utilities, effective January 1, 2013, is a minimum default capital structure consisting of 57.5% debt and 42.5% common equity. The Commission further determined that the minimum default risk premium over the benchmark is 75 basis points (bps). Central Heat was also awarded the default 42.5% equity ratio and 75 bps risk premium as transitional amounts due to its changing business environment. However, Central Heat was directed to file within 12 months of the date of the Stage 2 Decision (March 24, 2015) either a 2016 or multi-year RRA with the Commission, reflecting the new business plan with a comprehensive justification for the equity thickness and equity risk premium.[8] The Commission subsequently extended the Creative Energy’s deadline for the cost of capital related filing to May 1, 2015.

 

When initiating its review of the current RRA the Commission also determined that permanent rates for 2016 and 2017 will be set subject to a final determination on Creative Energy’s ROE and deemed equity thickness.[9]

 

On May 1, 2015, Creative Energy filed with the Commission a document entitled “A Report by Creative Energy Vancouver Platforms Inc. re: Business Risks and Cost of Capital.”^[10] On May 20, 2015, the Commission issued Order G-85-15 which determined that the approved return on equity and deemed equity thickness for Creative Energy will continue to be based on the default equity thickness of 42.5% and equity risk premium of 75 bps for regulated Thermal Energy Systems.

 

In conclusion, the permanent rates for 2015 will reflect the allowed default structure of 42.5% equity ratio and 9.5% ROE.

2.3               Test period for this Application

The current Application is for a multi-year test period, covering the revenue requirements for the years 2015 – 2017. If approved, Creative Energy would incorporate Steam Tariff adjustments effective January 1^st for each of those years, relieving Creative Energy of the need to file further adjustments over the next two years. Although multi-year applications will encompass a certain degree of forecasting risk, this risk is offset by the savings on annual regulatory costs and also allows the utility to focus on its operations rather than regulatory processes.

 

The Panel has considered the evidence submitted in this proceeding, and as a result denies the 3‑year test period sought. In addition to the previous discussion on the utility’s transitional nature, the Panel took into account the inconsistencies, multiple corrections and adjustments found in the evidence of this proceeding which will be further discussed in various sections of this Decision. Accordingly, the Panel finds that approval of only a 1 year test period for 2015 is warranted.

 

While some regulatory efficiencies may be gained with a multi-year test period, the Panel does not find this to be appropriate given the current business circumstances facing Creative Energy. The Panel is concerned that certain regulatory rate making concepts and processes may not have been thoroughly considered. Furthermore, the Panel questions the reliability of information presented in this proceeding, given the multiple corrections and adjustments made throughout the evidentiary period. The Panel encourages Creative Energy to meet with Commission staff for further guidance on regulatory filings and processes. A more detailed discussion on this issue will be addressed in section 9.4.

2.4               Accounting Methods

Utilities have adopted the Generally Accepted Accounting Principles (GAAP) of International Financial Reporting Standards, US GAAP or Accounting Standards for Private Enterprises (ASPE) for financial reporting. Forecasts made to determine a utility’s Cost of Service in a Revenue Requirements Application are not normally prepared on a cash basis but rather on an accrual basis as required under GAAP. Therefore, it is not a typical practice for a utility to base some components of the forecasts on accrual accounting and others on a cash basis unless

specifically provided for under GAAP. For a utility such as Creative Energy, the Commission would expect the Cost of Service forecasts to be prepared under the same principles as used for financial reporting purposes, which for Creative Energy are ASPE. As such, the Panel does not expect any of Creative Energy’s forecast to be on a cash basis unless explicitly allowed under ASPE.

 

The Panel has identified some inconsistencies within Creative Energy’s Application regarding the use of cash or accrual basis of reporting for regulatory purposes. For instance, management transition costs were forecast on a cash basis and certain pension amounts in the original application were initially forecast on a cash basis, but later corrected to an accrual basis. A more detailed discussion on corrections will follow in Section 8.0 but it is important to emphasize that as general practice, the Commission follows the accrual basis approach.

2.5               Rate impact and bill impact

Creative Energy’s steam revenues are derived from two different sources. The Steam Tariff, which is the basis of this Application, represents only 35% of the total bill impact to customers. The remaining 65%[11] is encompassed in the fuel adjustment rider, which is charged outside of the tariff rates. The Panel notes that although the proposed 13.3%[12] rate increase in the tariff portion of the rates is requested for 2015, the overall bill impact to customers is only approximately 4.7%.[13]

 

The Panel considers the context of this overall bill impact when making its determinations on each of the issues raised in the following sections. Further, the Panel does not find a rate smoothing mechanism for 2015 to be warranted in light of the overall bill impact to customers.

 

3.0               LONG TERM RESOURCE PLAN

One of the issues explored in the review of the Application was the possible requirement for Creative Energy to file a long term resource plan and, if required, the timing of such filing. LTRPs typically establish long term planning principles, objectives and provide a framework to ensure the provision of safe, reliable and cost‑effective service to customers.

 

As discussed earlier in this Decision, Creative Energy is a utility going through a business transition which is anticipated to include additional load to be served from the existing steam utility to supply energy for new hot water neighbourhood energy utilities (NEUs) owned by Creative Energy. Initially this service will be as the primary energy supply source for one or more of these new NEUs. Ultimately, this service will only be for peaking and backup load as the new NEUs undergo a potential fuel switch from natural gas to a low carbon

supply source. In addition, Creative Energy’s transition is likely to include switching some or all of fuel supply for the steam plant to low carbon fuel sources. This transition may impact Creative Energy’s existing steam based core customers in a number of respects; including:

•         potentially increased fuel costs;

•         changes in the load shape of the incremental load due to the transition to providing peaking supply only;

•         rate design issues arising from the proposed methodology for recovering the steam utility cost of service and fuel costs from the new hot water NEUs; and

•         cost allocation methodology related to the shared resources.

 

BCUC Resource Planning Guidelines

To augment section 44.1 of the UCA and provide further guidance in regard to long-term resource plans, the Commission in December 2003 issued its Resource Planning Guidelines (Guidelines) which articulate the Commission’s mandate in directing and evaluating the resource plans of energy utilities with the intention to facilitate the cost-effective delivery of secure and reliable energy services. Some of the key statements included in the Guidelines are:

-          Resource planning is intended to facilitate the selection of cost-effective resources that yield the best overall outcome of expected impacts and risks for the ratepayer over the long run.[14]

-          -Key underlying issues and assumptions that inform the planning context should be identified and discussed (e.g. reliability and security issues, risk factors, major uncertainties).[15]

-          The LTRP is to include an action plan consisting of the detailed acquisition steps for those resources …. which need to be initiated over the next four years.[16]

-          The Guidelines provide general guidance regarding the Commission expectations of the process and methods for utilities to follow in developing plans that reflect their specific circumstances. … The Commission will review resource plans in the context of the unique circumstances of the utility in question.[17]

-          In most circumstances, Certificates of Public Convenience and Necessity (“CPNC”) applications should be supported by resource plans ……. The Commission expects that resource plans will help facilitate the review of utility revenue requirements and rate applications.[18]

Creative Energy Position

The Commission requested Creative Energy to discuss when it would be reasonable for the Commission to expect a filing of a LTRP, including the Company’s views on the merits of such a filing. Creative Energy stated that filing a LTRP, “certainly one filed frequently, is an unnecessary burden for a small utility.”[19] Creative Energy also expressed concerns arising from the fact it faces competition within its existing customer base and for new connections for the steam utility, and states that “Capture of smaller infill developments within the existing core, as well as retrofit projects are currently subject to voluntary agreements and as Creative Energy currently faces significant competition it would not be appropriate to identify these specific infill opportunities at this time.”[20]

 

Creative Energy also noted:

[it] is currently conducting a detailed feasibility study for a larger fuel switch serving both existing customers in the core and growth that may be attached to the core. This is a large and complex project that is intended to address City policy drivers, provincial policy drivers, and market needs. The study is being co-funded by the Federation of Canadian Municipalities (through a grant program) and the City of Vancouver.  The results of this study will be available towards at the end of this year. …  Creative Energy submits that many of the issues and outcomes of resource plans will be addressed in individual CPCN applications, as Creative Energy expects to demonstrate in its upcoming NEFC Application. Resource plans would be premature in the absence of actual agreements with the City to secure new loads and/or facilitate alternative energy sources.

 

Creative is prepared to file a long term resource plan for the core. However, Creative Energy also believes it would be premature to do so prior to completion of the ongoing fuel switch feasibility study and additional agreements with the City that will be required to establish new loads and enable any fuel switch or new alternative energy sources. Creative Energy also submits the Commission consider the value and scope of a long term resource plan following the submission of Creative Energy’s CPCN application for NEFC.[21]

 

Pertaining to the requirement to include plans for reducing demand through cost-effective demand‑side management (DSM) measures in a LTRP, Creative Energy states it currently has no formal DSM programs for existing customers and does not consider incentive-based DSM programs relevant for a small utility with a limited number of customers each with unique needs and alternatives.[22]

 

In regard to the need for and timing of a LTRP, in its Final Submission Creative Energy submits:

There were a series of information requests regarding the timing of future regulatory filings. In particular, in this proceeding and in the recent proceeding regarding gas purchase plans, the Commission staff made inquiries regarding the preparation and timing of a long-term resource plan, which the former management had never filed and the Commission had never requested. Creative Energy notes the limited supply options for the steam system, the feasibility work currently underway regarding a possible fuel switch (which is a large and complex project), and the considerable uncertainty in new and multiple expansions (which may or may not be connected to the core in all cases and which will utilize hot water networks that have a greater range of supply options). In the responses, Creative Energy provided comprehensive and responsive answers to those inquiries. The succinct answer to those inquires is as follows:

“CE would be willing to consider the pros and cons of long-term resource plans in the specific context of the NEFC CPCN Application later this quarter, which will be the first major expansion initiative by Creative Energy.”[23]

 

As the North East False Creek Certificate of Public Convenience and Necessity Application (NEFC CPCN Application) was filed on April 17, 2015, Creative Energy further submits that this Commission Panel should not consider the filing of the LTRP in this proceeding, and instead leaves the filing date of the LTRP for consideration by the Commission Panel reviewing the NEFC CPCN Application.[24]

 

CEC Final Submission

CEC submits that it “is not persuaded that the appropriate context for determining the filing requirements [for a LTRP] if any is in a CPCN application, which will be primarily focused on a specific project.” CEC also “does not believe the evidentiary record in this hearing is sufficient to result in a Commission direction or order on the subject.”[25]

CEC does not expect that the Creative Energy’s long term resource plan need to be either exhaustively complex nor a frequent review process and is not persuaded by the company’s argument that it should be left to do the planning effectively without the Commission oversight until it has fil[l]ed CPCNs. … the Commission’s oversight of such planning should not trail the key steps of decision making so significantly as to make Commission review and input on the plans of little relevance.[26]

 

In reply, Creative Energy reiterates its position that it is prepared to file an LTRP for the downtown core system however, it would be premature to do so prior to completion of the ongoing fuel switch feasibility study and additional agreements with the City of Vancouver.[27]

 

Commission discussion

A Company in Transition

The Panel acknowledges that Creative Energy has not been required to file a LTRP in the past. Prior to the purchase of the core steam utility by Creative Energy Canada, the operations of the core steam utility had not changed substantively since the original CPCN approval in 1968. However, in light of the significant business expansion plans of Creative Energy, the Panel is of the view that a LTRP for the existing steam utility is a key element of this transition. Further, the timing of the filing is also important to ensure that the review is relevant for informing revenue requirements applications, annual energy supply contracting as well as future CPCNs that impact the existing core steam utility. The Panel agrees with CEC that for the Commission oversight to be beneficial its review of a LTRP should not be preceded by the key decisions made by the utility as Creative Energy’s plan evolves. However, the Panel disagrees with CEC’s submission that the evidentiary record in this proceeding is not sufficient for this Panel to provide direction on the subject of a LTRP.

 

The Panel observes that Creative Energy in its application for a CPCN for a Low Carbon NES for NEFC and Chinatown, the following is being requested:

An exemption from filing a Long-Term Resource Plan (section 44.1 of the UCA) for NEFC and Chinatown until completion of further feasibility work on low carbon energy sources and the filing of a CPCN Application for Energy Supply Phase 2 of this project.[28]

 

Creative Energy describes Energy Supply Phase 1 as follows: the establishment of a new hot water district energy system to serve NEFC and Chinatown. During Energy Supply Phase 1, the entire heating energy needs for the NES will initially be met from Creative Energy’s existing steam plant.[29] The NEFC steam plant load is anticipated to commence in August 2016.[30]

 

Creative Energy is also seeking Commission approval, without conditions, of the Neighbourhood Energy Agreement between Creative Energy and the City of Vancouver dated March 25, 2015 (the NEA). Pursuant to the NEA, in Energy Supply Phase 2:

Creative Energy is required to implement one or more low carbon energy sources to achieve long-term carbon reduction targets for the NEFC development. The NEA contemplates carbon reductions by means of:

1)      The addition of low-carbon sources upstream of NEFC (e.g. a large fuel switch within Creative Energy’s existing steam system), or

2)      The addition of new low carbon energy sources within the NEFC neighbourhood.

Regardless of the low carbon energy source, it is expected that Creative Energy’s existing steam plant would continue to provide peaking and back-up to NEFC. …. Any low carbon energy source would be the subject of a future CPCN. Creative Energy proposes to file a second CPCN … for approval of any future low carbon energy source to meet the NEFC low carbon commitments, currently anticipated to be in-service on January 1, 2020, subject to development timelines, economic considerations and Commission approval.[31]

 

Potential Risks to Core Customers

The LTRP exemption that Creative Energy is seeking in the NEFC CPCN Application exemption is in regard to the NEFC and Chinatown. The Panel leaves the matter of the NEFC and Chinatown LTRP to the discretion of the Commission’s ongoing review of the NEFC CPCN Application. The Panel notes, however, that the nature of the NEA, for which Creative Energy is seeking Commission approval in the NEFC CPCN Application, commits Creative Energy to carbon reduction targets in Energy Supply Phase 2 that will clearly impact Creative Energy’s core steam utility customers. The Panel anticipates that the potential impact of Creative Energy’s commitments regarding the carbon reduction targets set out in the NEA on the existing steam utility customers may be considered during the review of the NEFC CPCN Application. Nevertheless, the extent to which the potential risks to the core steam utility customers associated with these commitments remains uncertain.

 

The Panel further notes that in the NEFC CPCN Application, Creative Energy proposes a cost allocation methodology for the provision of steam energy to the NEFC and Chinatown utilities that does not employ the existing steam utility rate but rather, a new cost allocation method designed specifically for the NEFC utility. This proposed new rate methodology, as well as the anticipated future transition from the steam utility supplying all of the NEFC energy requirements to only peaking and backup energy supply in Energy Supply Phase 2, raises the question of the need for and timing of a comprehensive rate design for the existing core steam utility.

 

The Panel acknowledges Creative Energy’s intention to review the rate structure for the core steam utility but disagrees that this should not be a high priority over the proposed RRA test period. The Panel agrees with Creative Energy that “…changes to the tariff must balance multiple considerations including impacts on customers, allocation of risks, and unintended consequences ...”[32]

 

Timing of the LTRP Filing

The Panel notes that in the NEFC CPCN Application, Creative Energy is not seeking an exemption from filing an LTRP pertaining to the existing core steam utility. Creative Energy’s also asserts that “many of the issues and outcomes of a resource plan will be addressed in individual CPCN applications.” However, it is not apparent to this Panel that such applications will address LTRP issues specific to the existing core steam customers will be addressed. The Panel observes that the approach contained in the NEFC CPCN application suggests that many of the planning issues specific to the existing core steam utility will not be addressed until it files the Energy Supply Phase 2 CPCN sometime in the future. The Panel finds that the suggested delay in filing an LTRP for the existing core steam utility to be unacceptable. The Panel is of the view that the existing core steam utility is clearly part of the broader transition plan and the core steam utility customers are likely to be impacted in a variety of ways including:

•         through rate design issues arising from the methodology for recovering the steam utility cost of service and fuel costs from new hot water NEUs;

•         transfer pricing policies for shared resources;

•         the shape of the incremental load; and

•         the potentially higher costs of low carbon fuel sources that may be required to meet the carbon reduction targets set out in the NEA.

In the absence of a LTRP focussed on the existing core steam utility, these issues are likely to be addressed in a piecemeal fashion as adjuncts to the plans for the new hot water NEUs and as an outcome of Creative Energy’s commitments in the NEA to meet the City of Vancouver’s greenhouse gas emission reduction objectives for which Creative Energy is seeking Commission approval in the NEFC CPCN Application.

 

Commission determination

The Panel finds that the nature and extent of the business transformation contemplated by Creative Energy at this point in the utility’s history warrants a Commission review of the core steam utility LTRP in order to ensure that core steam utility customers continue to receive cost-effective delivery of secure and reliable energy services. The Panel determines that Creative Energy must file a long-term resource plan pertaining to the existing steam utility no later than two years from the date of this Decision and prior to making an investment decision regarding any low carbon fuel switch that may impact the existing steam customers. The LTRP shall include information available from the fuel switch feasibility study. The LTRP should address the impact and timing of a potential switch to a low carbon fuel or other means of meeting the carbon reduction targets set out in the NEA as well as the impact of supplying the load requirements of NEFC and other Creative Energy neighbourhood energy utilities from the existing steam utility. It is not necessary for Creative Energy to provide an in-depth discussion of demand-side measures in this LTRP. With respect to infill plans, Creative Energy may consider filing the details of these plans on a confidential basis and requesting that the Commission keep these plans confidential in accordance with the BCUC Confidential Filings Practice Directive.[33] The LTRP must also address the potential need for and proposed timing of a comprehensive rate design (Phase II) for the existing steam utility. The requirement for this comprehensive study is subject to the pending decision on the NEFC CPCN. Further discussion of the need for a rate design as specifically relating to the Fuel Cost Adjustment methodology (Phase I) will be addressed in Section 4 of this Decision.

 

4.0               FUEL COST ADJUSTMENT METHODOLOGY AND RATE DESIGN

Fuel costs for Creative Energy’s core steam utility are recovered firstly, through the Base Cost recovery of 41 cents per one million B.T.U[34] imbedded in the Steam Tariff, and secondly, through a Fuel Cost Adjustment charge. The nature and magnitude of the Fuel Cost Adjustment charge raises a number of questions in regard to the appropriateness and applicability of the current fuel cost treatment methodology in the future, particularly in light of the contemplated business transformation. Specifically:

•         what is the nature of and appropriate treatment for the account used to track the difference between the total fuel cost and the recoveries of the fuel cost through the Base Cost component of the Steam Tariff rate and the Fuel Cost Adjustment charge (referred to by Creative Energy as the Fuel Cost Stabilization Account)?;[35]

•         should all, or an increased portion, of fuel costs be recovered through the Steam Tariff rate?; and

•         what degree of Commission oversight is warranted regarding the balances carried in the Fuel Cost Stabilization Account and the mechanism by which the Fuel Cost Adjustment charge is periodically adjusted?

 

Given the business transition envisioned for Creative Energy, which will potentially impact the fuel costs for the core steam utility if the steam plant is transitioned to low-carbon fuel, the Panel is of the view these questions should be examined as part of this and future RRA reviews and also through any rate design application.

4.1               What is the nature and appropriate treatment of
the Fuel Cost Stabilization Account?

Creative Energy tracks the difference between the total fuel cost incurred and recoveries of the fuel cost through the Base Cost portion of the Steam Tariff and the Fuel Cost Adjustment charge. The difference is recorded as a liability due to customers and the account functions like a deferral account in Creative Energy’s view. But it is not a deferral account approved by the Commission and appears to carry no interest charge due to customers. Creative Energy describes it as a “non-rate base deferral account and functions more akin to a stabilization account. This may be aptly called a Fuel Cost Stabilization Account.”^[36] In recognition of customer concerns regarding the volatility of the Fuel Cost Adjustment component of the bill, Creative Energy maintains a “buffer” in the account to smooth out rates and to absorb energy price shocks.^[37] Creative Energy maintains that this mechanism “has historically met the needs of the customers, the Commission and Creative Energy with no customer complaints.”^[38]

 

Creative Energy states it determined the appropriate size of the over recovery buffer based on communications with customers who have indicated that it is important to have stable rates to help with the customers’ budgeting processes.[39] As evidence that customers are satisfied with the arrangement, Creative Energy states that the Commission has received no complaints from customers regarding the fuel adjustment.^[40]

 

Creative Energy states it historically maintains a balance of 10 to 15 percent of the overall actual energy costs in the account.[41] For the period from January 2012 through to October 2014, the balance in this buffer account ranged from a high of $2.8 million to a low of $0.3 million.[42] Over the 2013 and 2014 calendar years Creative Energy drew on the balance in this account to mitigate the natural gas price spikes that were experienced over the 2013/2014 winter. The following Table 4.1, highlighting the variations, was prepared by Commission staff from the data provided in this Application[43] and the 2014 Revenue Requirements Application.[44]

Table 4.1 – Fuel Cost Stabilization Account Balances

The same buffer account history is shown graphically as follows:

Graph 4.1: Fuel Cost Stabilization Account Balance (Jan 2012 – Oct 2015)

With regard to this “buffer” account, Note 12 to the 2014 audited financial statements states:^[45]

The Company recovers from its customers the costs of the fuel it uses to produce steam, in accordance with a formula determined by regulation. The fuel cost liability represents the cumulative excess of billings to customers in respect to fuel costs over actual fuel costs incurred. In the absence of rate regulation, the Company would have a similar obligation to provide credits to its customers, as the obligation is not dependent on the rate-setting process. Consequently, the fuel cost liability is not considered a regulatory liability. [highlight added]

 

CEC Final Submission

CEC submits this “is in effect a flow through account mechanism operating as a deferral account.  …. CEC has no objections to flowing through fuel cost adjustments into rates and submits that the Commission should approve the deferral account aspect of this process. … the Commission should have regular oversight of the operation of this account and periodically in RRA hearing should ensure the formula approach is satisfactory in terms of appropriate rate setting.”[46]

 

CEC further submits that “CEC supports use of regulatory accounts to provide smoothing for rates and costs of fuel.” CEC recommends that Creative Energy “work with Commission staff to establish a methodology that is reasonably simple …. to manage cost stabilization of the fuel costs.”[47]

 

Creative Energy Reply Submission

In its Reply Submission Creative Energy submits that CEC “addresses an issue unrelated to the fuel cost adjustment mechanisms when it references managing cost stabilization of fuel costs.” Creative Energy further submits it manages fuel costs for the purposes of “cost stabilization” through the use of hedging contacts for a portion of its winter gas supply and that these contracts are filed confidentially with the Commission as part of it gas contract plans.[48]

 

Commission discussion

The Fuel Cost Stabilization Account or “buffer account” that Creative Energy employs to track the imbalance between fuel costs and recoveries of fuel costs balance is, in the Panel’s view, an unconventional means for a thermal energy utility to manage and recover fuel costs. It is not a Commission approved deferral account and carries no interest. The Panel is concerned that this account, which according to the Notes to the 2014 Audited Financial Statements represents a “cumulative excess of billings to customers” has carried no apparent interest to the credit of customers since its inception. It appears that the customers are taking the full risk yet have been denied any accrued interest on this excess collection.

 

The Panel is not convinced that Creative Energy’s use of the Fuel Cost Stabilization Account to smooth fuel costs is necessarily the most appropriate or most effective approach to price risk management of fuel costs for a thermal energy utility. The Panel also does not agree with Creative Energy that CEC’s reference to “cost stabilization of fuel costs” is an unrelated issue. The Panel considers that a further review of the current fuel cost recovery methodology is warranted at this time. The secondary steps of such a review are discussed further in section 4.2. As an initial step, the Panel finds the establishment of an approved deferral account with appropriate compensation to customers for the interest accrued on the over-collected amounts is required.

 

Commission determination

The Panel directs Creative Energy, in its next revenue requirements application, to propose a permanent treatment of this Fuel Cost Stabilization Account. As a minimum, the proposal must address: 1) whether this account should be established as a non-rate base or a rate base deferral account, or by way of another method; and 2) the appropriate means to compensate customers for the interest to be accrued on the surplus balance or excess of billings to customers in respect to fuel costs over actual costs incurred.

 

As an interim measure, the Panel directs Creative Energy to apply its weighted average cost of debt to the most current balance of this Fuel Cost Stabilization Account (balance as at the date of this Decision). The resulting interest cost (customer credit) shall be treated as a revenue-offset to the 2015 revenue requirements. In the compliance filing arising from this Decision, Creative Energy is to include a schedule showing the reconciliation of the Fuel Cost Stabilization Account in the format of Table 6.1.7.D in Tab 6 of the Application, up to the date of this Decision.

4.2               Should an increased portion of the fuel costs be recovered in the Steam Tariff rate?

The recovery of fuel costs for Creative Energy’s existing core steam utility is largely accomplished through a charge that is not currently reviewed or approved by the Commission in contrast to most conventional thermal energy utilities regulated by the Commission, where the fuel costs are recovered through Commission approved rates. For other thermal energy utilities, including those that compete with Creative Energy, the cost of fuel is typically recorded in a deferral account and the recovery of these costs is included in the thermal revenue requirement in the rate setting process. (FAES Telus Gardens, River District, Corix UBC)

 

The Base Cost of 41 cents per one million British Thermal Unit (B.T.U.), as defined in the Creative Energy Steam Tariff, determines the portion of the fuel cost that is recovered through the Steam Tariff rate. It is also referred to as the Operating Expenses component entitled “Fuel – Net of Recoveries.”[49] As discussed in section 4.1, the remainder of the fuel costs are recovered through the Fuel Cost Adjustment charge which is currently a separate unregulated charge on the customer’s bill.

 

The Creative Energy tariff describes the Fuel Cost Adjustment as follows:

^[50]

 

With regard to the history of the Base Cost, Creative Energy stated: “the base cost of 41.0 cents was initially determined in 1973 and to the best of our knowledge, the 41.0 cents was the cost of energy at that time.”^[51] When asked what percentage it represented when initially established, Creative Energy states “To the best of our knowledge, it represented 100%.”^[52] In 2014, the Base Cost represents only 4.8% of the total fuel cost. ($679,581/$14,147,510 = 4.8%)^[53]

 

The remainder of the cost of the fuel purchased to fuel the boilers to make steam is recovered from customers through the Fuel Cost Adjustment charge. The Fuel Cost Adjustment charge component of the customer bill is significant when compared to the Steam Tariff rate component. As noted earlier in this Decision, the Steam Tariff portion is approximately 35% of the overall customers’ bill with the Fuel Cost Adjustment making up the remaining 65%.^[54] As an example of the magnitude of the Fuel Cost Adjustment component, the total revenue requirement for 2015 that Creative Energy is seeking approval of is $8,547,604,[55] of which $708,848 is fuel costs recovered through the Base Cost. The remaining $11,055,652 of forecast fuel costs for 2015 are to be recovered through the Fuel Cost Adjustment charge.[56]

 

Creative Energy stated “[t]he customer looks at the total cost of Steam to base their decisions on.”[57] Creative describes how there can be large swings in the total cost of steam due to the fluctuating prices of the natural gas commodity and provides the following example for a mid-sized steam customer over the period from 2008 to 2014.

[58]

 

Creative Energy explained the elasticity of demand in response to price is particularly impacted by the Fuel Cost Adjustment component of the bill.

Large buildings typically require major upgrades to improve efficiency (e.g., envelope improvements). These projects require time and are more likely in response to sustained increases in prices (in particular the gas prices reflected in the Fuel Adjustment which comprises a much larger portion of customer bills).[59]

 

In spite of the importance of the Fuel Cost Adjustment component of the bill for customers, Creative Energy has not attempted to project how the Fuel Cost Adjustment might change over the test period despite the Commission’s specific request to provide forward price curves and all natural gas price assumptions.[60] Instead, Creative Energy fixes the total annual cost of natural gas at $11,756,500 for each year in the three year test period,[61] and uses these fuel costs when estimating the overall rate impact for each of the years in the test period.

 

Potential Impact to Licence Fees Collected by City of Vancouver under MAA

Creative Energy responded in confidence to describe the potential for unintended consequences of increasing the Base Cost of 41 cents so that a larger portion of the fuel costs are recovered through the Steam Tariff.[62]

 

Note 11 of the 2014 Audited Financial Statements indicates the CoV has previously disputed the calculation of fees payable to the CoV with respect to the exclusion of  the Fuel Cost Adjustment from the fee calculation.[63]

 

Creative Energy responds that “the Statement of Claim against the company was filed in 1999 and there has been no communication about the claim for a few years. Due to the length of time with no communication, there is no reason to believe that the claim would be followed through now.”[64]

 

Notwithstanding this legal claim from the City, Creative Energy (as CHDL) signed a new 30 year Municipal Access Agreement with the City of Vancouver dated September 1, 1999 (MAA). In the MAA the Licence Fee calculation specifically deducts the Fuel Adjustment Costs before applying the formula based on 1.25% of annual gross revenue excluding the Fuel Cost Adjustment charges plus a flat fee of $100,000 subject to tariff escalations for determining the annual Licence Fee.[65]

 

The MAA further describes the trigger, process and terms of reference for a review in the event the Fuel Cost Adjustment formula is changed by the Commission.

[66]

 

The MAA contemplates the potential for “a change to the Fuel Adjustment Cost formula” as approved by the Commission and sets out a process and terms of reference for any review of the licence fee.

[67]

 

Creative submits that “there has been no change in circumstances, nor any concerns raised by customers about this account, that would suggest a need for more regulatory oversight.”[68]

 

In regard to the small percentage of total fuel costs that is currently represented by the Base Cost, CEC submits that the decrease in the portion of fuel costs that are recovered in the Base Cost “is significant and that the methodology likely warrants updating.”[69]

 

Commission Discussion

Natural gas fuel costs have varied substantially over the past 15 to 20 years. The Panel is of the view that a review of the allocation of the recovery of the fuel costs between the Base Cost in the Steam Tariff and the Fuel Cost Adjustment charge is appropriate and warranted, particularly given the changes to the nature of the fuel costs that may arise from a potential switch to low carbon fuel sources.

 

Although Creative Energy argues that the circumstances have not changed since the inception of the Fuel Cost Adjustment charge, and customers have not raised any concerns in this proceeding, the Panel observes that Creative Energy acknowledges that volatility in fuel costs is a concern to customers. According to the Company this was a factor in determining the appropriate size of the “buffer” to maintain in the account.[70] The Panel further observes that, as illustrated by Graph 4.1, even with smoothing, there remains considerable volatility in fuel costs. Creative Energy also concedes that the Fuel Cost Adjustment charge is a large and important component of the overall cost of the steam service provided by Creative Energy and it significantly impacts customers.

 

The Panel notes that in spite of the significance of the Fuel Cost Adjustment charge portion of the customer bill, Creative Energy does not particularly attempt to forecast the natural gas component of the fuel costs. The Panel is concerned by Creative Energy’s lack of attention to the potential combined impact of the requested Steam Tariff increases and changes to fuel costs over the test period.

 

Creative Energy acknowledges it is entering a transition period. The steam utility will be used to supply energy for the NEFC and Chinatown utilities and the cost of this energy will be an input into the thermal energy rates for these new utilities. The fuel costs for the core steam utility will certainly be expected to be an input into the determination of the rates for Creative Energy’s new utilities. The Panel is of the view that the prospect of these changed circumstances is an important a factor to consider in the assessment of the continued appropriateness of the current methodology.

 

In addition, should the fuel source transition from natural gas to low-carbon fuel sources proceed, it will impact the nature of the fuel costs and by extension the recovery of these costs. Low-carbon fuel can be expected to have different contracting and pricing characteristics and involve a different level of Commission oversight over current energy supply contracts. Natural gas energy supply contracts must be filed for acceptance under section 71 of the UCA as being in the public interest, (as was the case with Creative Energy’s current natural gas energy supply contracts that were accepted via Commission Order E-3-15). Commission acceptance of energy purchase contracts under section 71 of the UCA does not extend to biomass as it is not defined as “energy” under Part 5 of the UCA so a transition to low‑carbon fuel will potentially reduce Commission oversight of fuel purchase contracts and fuel costs if they are not included in the Steam Tariff and reviewed in revenue requirements applications.[71]

 

Commission determination

The Panel directs Creative Energy to file a Phase I rate design application within one year from the date of this Decision specifically in regard to the recovery of fuel costs. This fuel cost recovery rate design application is to include a review of the appropriate Base Cost component of the Steam Tariff and the degree to which the Base Cost should be increased to capture the bulk of the fuel costs in the Steam Tariff, as it originally did when the Base Cost of 41 cents was established and as is the accepted practice with other thermal energy utilities in British Columbia. The rate design should include discussion of any potential adverse impacts on existing core steam utility customers and new customers such as the NEFC utility and how these adverse impacts might be mitigated.

4.3               What degree of reporting and Commission oversight is warranted regarding the Fuel Cost Stabilization Account?
The mechanism by which the Fuel Cost Adjustment charge is periodically adjusted?

Although Creative Energy initially submitted Fuel Cost Adjustment schedules and Fuel Cost Stabilization Account reconciliations to the Commission as set out in the tariff, this practice was discontinued some 15 to 20 years ago.[72] In spite of the significant portion of the customer bill that is represented by the Fuel Cost Adjustment component, the setting of the Fuel Cost Adjustment charge and the management of the Fuel Cost Stabilization Account currently does not involve even the most basic Commission regulatory oversight in the form of reporting.

 

Creative Energy states that there have been no complaints to the Commission from customers in regard to the Fuel Cost Adjustment charge but does note that customers find it important to have stable rates.[73] In practice, the Fuel Cost Adjustment charge is often changed multiple times over the course of a year. Over the period from November 2011 through to February 2015, a period of just over three years, Creative Energy changed the Fuel Cost Adjustment charge seventeen times.[74]

 

With regard to reporting, Creative Energy submits:

{I]n the event the Commission does decide that a change regarding the regulation of this account is necessary, then Creative Energy requests that schedules and reconciliations be filed yearly along with the Utility Commission Annual Report, and that changes to the account be filed every 6 months, and that approval of such changes not be required.[75]

 

CEC Final Submission

CEC submits that it accepts Creative Energy’s suggestion that the Commission oversight can be adequately handled in its Annual Reporting to the Commission but further submits that should costs be higher or volatility becomes more significant, the Commission may need to exercise its oversight more closely.[76]

 

Commission discussion

As noted above, Creative Energy has stated that there have been no complaints from customers but does note the importance of smoothing the Fuel Cost Adjustment charge to provide rate stability to customers. The frequency of changes to this charge suggests this has been difficult to achieve in recent years. The Panel is of the view that, at a minimum, the Commission should be aware of the Fuel Cost Adjustment charge that Creative Energy is charging at any given point in time, and the Commission should be provided with sufficient information to be aware of how the Fuel Cost Stabilization Account is being managed and used to smooth the Fuel Cost Adjustment charge. A potential outcome of future Commission proceedings directed by the Panel earlier in this Decision may be a requirement for Commission approval of the Fuel Cost Adjustment charge and the methodology. The Panel does not find it necessary to require Creative Energy to seek Commission approval of changes to the Fuel Cost Adjustment charge at this time but finds that increased reporting is warranted.

 

Commission determination

The Panel directs Creative Energy to include an annual reconciliation of the Fuel Cost Stabilization Account with its Annual Report to the Commission and also with its Annual Gas Contracting Plan required according to the Commission’s Rules for Natural Gas Supply Contracts.[77] The reconciliation report should be in the form provided in Table 6.1.7C and Table 6.1.7D in Tab 6 of the Application. In its Annual Contracting Plan, Creative Energy should also discuss the extent to which it intends to reduce fuel price volatility through use of the Fuel Cost Stabilization Account in combination with entering into fixed price hedging contracts or other alternative price risk management strategies.

 

The Panel also directs Creative Energy to file with the Commission, for information purposes, a copy of the notice of a change to the Fuel Cost Adjustment Charge and the details showing the amount of the change, the new Fuel Cost Adjustment Charge, effective date, and updated versions of the schedules that are Table 6.1.7.C and Table 6.1.7.D in Tab 6 the Application within 10 business days of the effective date of each change.

 

As part of its compliance filing for this Decision, Creative Energy must file an amended version of the Fuel Cost Adjustment clause in the tariff to reflect the reporting changes directed above. Creative Energy is to include in the compliance filing schedules in the format of Table 6.1.7.C and Table 6.1.7.D for the 12 month period up to the date of this Decision, showing the closing balance for the Fuel Cost Stabilization Account as of the date of this Decision, the current Fuel Cost Adjustment charge as at the date of the compliance filing and a history of the changes to the Fuel Cost Adjustment charge in 2015 to the date of the compliance filing.

 

5.0               OPERATING EXPENSES

In the Application, Creative Energy states that operating expenses comprise a small allowance for fuel (outside of the Fuel Cost Recovery) and other non-fuel operating and maintenance (O&M) expenses such as labour and administrative costs. Creative Energy submits that the O&M budgets for the test period are required to operate the utility on a safe and reliable basis.[78] These O&M categories are outlined in the table below:

Table 5.1 Forecast Operating Expenses

[79]

 

Commission Determination

The Panel approves the Operating Expenses forecast for 2015, except for those items discussed in this section and specifically identified elsewhere in this Decision.

 

While CEC identified some minor concerns with the Operating Expenses forecast, the Panel has made its determination in light of those concerns, and finds it to be reasonable.

5.1               Management transition costs

As shown in Table 1.6.1 above, the Operating Expenses forecast includes Labour Costs of $2,520,067 for 2015[80] which can be further broken down into 3 employee categories: (i) Plant Wages & Supervision; (ii) Service Line Wages; and (iii) Management Wages. The forecast amounts for each category of Labour Costs are shown in the table below.

Table 5.2 Forecast Labour Costs

[81]

 

Creative Energy Position

As a result of two senior executives leaving the Company, Creative Energy states that arrangements had to be made in order to provide for a smooth transition to the new management team. Creative Energy submits that these “transition costs” are to reflect the transition of the two senior executives from 2014 to 2016[82] and should be considered a normal course of business expense required to ensure the new management team is given the appropriate time to provide a smooth transition.[83]

Being a smaller utility, Creative Energy submits that it operates in a niche industry and the company lacks the back-up resources to prepare itself in the event of a loss of key employees such as retirement. Accordingly, some overlap in management would be expected to ensure a smooth transition, particularly given the long tenure of previous management.[84]

 

Creative Energy provided the detailed amounts for the transition costs included within the Management Wages of the Labour Costs forecast in confidence to the Commission. Accordingly, they are not disclosed in this Decision due to the sensitive nature of the information.

 

Creative Energy submits that the 2014 transition costs, which were not part of the 2014 Revenue Requirements Application, were borne by the shareholder and excluded from the current RRA.[85] Creative Energy also submits that the transition costs for 2014 were treated as an operating expense for accounting purposes and that the total liability was not set up as a payable but is being expensed as incurred over the period 2014 to 2016.[86] Creative Energy is seeking full recovery of the remaining 2015 and 2016 transition costs amounts.

 

Commission Determination

The Panel recognizes that a smooth transition between management teams benefits the ongoing operations of both the Company and the ratepayers. On February 1, 2008, the Company entered into change of control agreements with the two senior executives. The terms of these two agreements provided these two executives with the right to severance pay in the event of termination, or the resignation by the executive, within six months of the date of a change in control of the Company. The agreements did not contain any provisions that precluded the executives from resigning immediately upon a change of control.

 

Change in control provisions, either within or in addition to, more comprehensive employment agreements, are common for a number of reasons. Entitlement to severance offered by these agreements is usually triggered on resignation or termination after a change in control of the Company. Two of the purposes for change of control provisions in the employment agreements or other contracts include a need to:

1.       Retain executives until completion of a sale transaction to ensure the selling price is maximized; and

2.       Ensure continuity of management throughout the commencement and completion of a sale of a company and, in some cases, subsequent to the sale transaction to ensure an orderly transition.

 

The severance or transition costs for the two individuals will be considered individually below.

 

Executive No. 1

Creative Energy provided a copy of the change of control agreement for Executive No. 1, dated February 1, 2008. [87]

 

The change of control agreement provided by Creative Energy did not outline specific job functions to be performed. The agreement generally stated that he had special skills and extensive knowledge of the Company essential for the best interests of the Company, particularly to ensure a successful transition in the event of a change of control.

 

The terms and conditions of the change of control agreement include an entitlement to severance equal to two years’ salary and benefits, including pension benefits. Creative Energy provided a copy of the resignation letter dated May 29, 2014, with an effective date of resignation of June 30, 2014. The Panel finds that the severance liability was crystallized effective June 30, 2014, and further finds no persuasive evidence any of this liability was in the normal course of business providing future benefit to ordinary operations beyond 2014.

 

Creative Energy provided a list of general job functions performed by the former management team, including such skills as accounting and billing support and regulatory history transfer of knowledge.[88] Unlike Executive No. 2, there was no subsequent employment agreement signed by Executive No. 1. The Panel finds that there is a lack of evidence to provide support of the specific services performed by this former executive subsequent to the change of control that provide significant benefit the ongoing operations of the Company. Therefore, the Panel denies the 2015 and 2016 transition costs for Executive No. 1. Creative Energy is to include with its compliance filing a confidential document to the Commission demonstrating the reduction in 2015 O&M due to disallowance of transition costs for Executive No. 1.

 

Executive No. 2

Creative Energy provided a copy of the change of control agreement for Executive No. 2, dated February 1, 2008.[89] The change of control agreement was subsequently replaced by an employment agreement for a term of 12 months effective March 21, 2014, and ending on March 20, 2015.[90] Creative Energy submits that the intent of this employment agreement was to ensure the continuity of his contributions to the Company, such that his original agreement and existing terms of employment were replaced by this new agreement to continue to employ him on a fixed term basis for 12 months.[91]

 

The Panel notes that the amount included in the RRA for 2015 for Executive No. 2 appears to be the amount that would have been payable should the 2008 Change of Control Agreement not have been replaced by the change of control agreement.

 

The Panel conducted a comprehensive review of the detailed information provided in confidence and based on that analysis has come to the following conclusion. The Panel considers the total amount applied for 2015 to be reasonable. The Panel accepts that the transition costs were incurred to ensure a smooth transition between management teams, and that the employment agreement with Executive No. 2 was considered necessary by the new management team in order to do so. The Panel approves the 2015 transition costs for Executive No. 2.

5.2               New employee and cost allocations

Creative Energy states that the increase in the 2015 O&M expense is in part due to the hiring of the following new employees:

1.       VP of Business Development – to assist with the organic growth and new business (budgeted to start in January of 2015);

2.       Project Manager – to assist with the construction and project management of new installs/connections (budgeted to start in April of 2015);

3.       Service Plant Manager – to assist with the expansion of the Utility going forward.

 

Creative Energy indicates that these positions are necessary in order to continue to provide safe, reliable service but also to continue to grow the business.[92] No cost breakdown, description or justifications for these new employees were contained in the Application.

 

During the IR phase of evidence, it was revealed that while 100% of the Project Manager and Service Plant Manager’s salaries are fully included in the revenue requirements, only 50% of the VP Business Development’s salary is included. The remaining 50% is cross charged to another entity and does not form a part of this revenue requirement.^[93]

 

Within the salaries contained in the O&M costs, Creative Energy then allocates a portion to capital projects, depending on the type of work performed. This allocation from O&M to capital reduces the revenue requirements for each particular year because only the carrying cost charged on the capital component and related amortization impact the overall annual revenue requirement.

 

The combination of these allocations and cross-charges is best explained in Creative Energy’s response to BCUC IR 2.7.2 (Exhibit B-5) and copied below ease of reference:

Table 5.3 Allocation of Salaries to Core and Non-Core Capital

 

In addition to salary allocations from O&M to capital, Creative Energy stated that there will also be a further allocation for general overhead (for office support staff) and an indirect labour charge for general administrative support to capital projects.^[94] Several adjustments and corrections to its gross O&M figures were subsequently provided to account for these allocations.

 

Creative Energy confirmed that it does not have any formal policies on allocations from O&M to capital. It states that management salaries are charged out as a direct labour charge based on estimated time spent on each project[95] and that the amount is “based on a loaded rate which includes benefits and associated costs for each individual.”[96] However, for general overheads and indirect labour, there is no indication on how these costs are being charged to capital.

 

CEC Final Submission

CEC considers the Project Manager and the VP Business Development to be more focused on costs and time allocated to new developments rather than to Creative Energy’s stable and existing customer base. CEC is not persuaded that the proposed allocation of the new employees’ costs warrant the increased O&M for core customers and urges the Commission to disallow their costs as it impacts Creative Energy’s core customer base. Specifically, CEC highlights the growing focus of the Project Manager (from 50% in 2015 to 100% in 2017) being dedicated to new project activity and the role of the VP of Business Development which appear to be out of line with the stable nature of core customers.

 

CEC submits that the cost allocations of these new employees appear to be parking costs with the core business until other developments get further defined and underway.[97]

 

Creative Energy Reply

In its Reply, Creative Energy submits it is necessary first to distinguish between “new business expansion activities” that are related to the expansion and growth of the core district energy system (DES), and those activities that are related to development of new district energy systems such as the NEFC. Second, it is necessary to consider if there are any benefits to the core system that may be triggered as a result of the new DES. Creative Energy submits that its involvement in new business expansion activities should be supported by the Commission. However, Creative Energy further submits if only the allocations between core customers and future customers are being considered then all of the costs of the New Project Manager and the New Service Line Manager, plus 50% of the costs of the New VP Development should be to the core customers (the other 50% to future customers).[98]

 

Commission discussion

The Panel considers two important issues pertaining to Creative Energy’s new employee additions and cost allocation processes. The first issue is whether the cost allocation from the core business to the NEFC project is appropriate. In particular, whether the expense related to the three new employees should be allowed in the O&M for core customers? The second issue is whether the cost allocation from O&M to capital within the core business is appropriate. These distinctions are important since (i) the core customers should not be cross-subsidizing development of the NEFC or other future TES projects (ii) 2015 O&M costs for rate setting should not include costs that are more suitably classified as capital costs. These issues will be discussed below in detail, following with the Panel’s determination.

5.2.1          New employees and cost allocations

First, the cost allocation from the core customers to the separate legal entity appears to be arbitrary rather than based on any Commission tested and approved methodology. Creative Energy states that 50% of the new Business Development manager’s salary is cross charged to another entity and do not form part of this RRA.[99] However, there is no clear evidence to support this 50% allocation or even an identification of which legal entity these charges are going to. Creative Energy submits that the appropriate allocation of costs across franchise areas is at an early stage, and that it needs to carefully proceed in a manner that benefits all customer groups. As such, Creative Energy is proposing to continue to consider cost allocation options which it will bring forward in its next RRA or possibly before.[100]

 

Creative Energy further submits that “[m]oving forward in 2015, Creative Energy has implemented a new timesheet process to allocate time spent on capital projects within the downtown core region and other projects that are being pursued.”[101] It is clear to the Panel that allocation methods are still being developed which may impact the cost allocations in 2016 and 2017 revenue requirements. This uncertainty further supports the Panel’s previous determinations to only approve the 2015 revenue requirements at this time.

 

The Panel notes that in its NEFC CPCN application, Creative Energy proposes a methodology to allocate certain fixed costs from the core utility to the NEFC project. This allocation is based on four components: Steam production, steam distribution, corporate overheads and management salaries.[102] This allocation policy is yet to be tested or approved by the Commission.

 

CEC suggests that the Commission should deny the cost allocations of the VP Business Development and Project Manager to the core customers’ O&M because based on the Creative Energy’s “new vision for the utility” those two positions seemed to be more focused on new developments.[103] CEC’s approach is in line with the Panel’s ultimate concern in that the costs related to core customers, and to new developments must be properly

understood and appropriately separated. This issue will become increasing important as Creative Energy pursues other initiatives outside its core service area while still utilizing overhead, business development, and certain fixed costs from its core business unit.

 

In Reply, Creative Energy appears to suggest that consideration must be given to whether there would be benefits to the core system that may be triggered by and be primarily related to any new district energy system. That is, in some cases the core system may benefit from increased efficiencies when employees are involved in “new business expansion activities.”[104] The Panel acknowledge that this may be the case, however there is no evidence in this proceeding which supports this claim or the value that should be placed on these benefits, if any.

 

As a further concern, the Panel notes that there may also be costs incurred to date for corporate functions performed at the parent company which may be allocated to Creative Energy in the future (see Diagram 1 in Section 1.5). This issue was not explored within the scope of this proceeding but should be understood in the context of the corporate group, in developing an appropriate policy to govern the cost allocations to and from Creative Energy’s core customers.

 

Commission determination

The Panel determines that the appropriate expenses to be allocated to the core customers, and therefore, allowed in the core revenue requirements, shall include 100% of the salaries of the Service Plant Manager and 100% of the salaries of the Project Manager in 2015. Further, the Panel determines that given the evidence provided the most it can allow is 25% of the salaries and benefits of the VP Business Development in the 2015 test period.

 

The Panel does not agree with CEC’s concerns that the Project Manager has a growing dedication to new project activity. Based on the description of duties provided by Creative Energy,[105] the Panel is satisfied that this role will be focused on servicing the core customers. The Panel also acknowledges that the core customers may benefit somewhat from the efforts of the VP Business Development, however the extent of these benefits have not been reasonably explored in this proceeding. Based on the record before it, the Panel approves only 25% of the VP Development’s salary to be absorbed by the core. Further, Creative Energy must clarify in the confidential component of its compliance filing the amount by which the O&M is reduced due to this disallowance and how the transfers will be tracked.

 

Creative Energy is also directed to file a cost allocation methodology with the Commission within 24 months of this Decision, to address resource sharing, cost allocation policies and the Panel’s concerns on potential cross subsidization expressed in this Decision.

 

A related issue pertaining to the allocations to the NEFC is also discussed in Section 9.2 of the Decision.

5.2.2          Cost allocations from O&M to Capital

The Panel finds that the cost allocations within the core business from O&M to capital do not appear to be guided by any formal policies, criteria, or guidelines. Without any formal methodology or principles in place, it would be difficult for the Commission, or the utility itself, to assess the accuracy and appropriateness of the gross to net O&M calculations every year. There could be also human errors in estimating or charges omitted altogether – as is the case for this Application. The Panel notes that the resulting impact of potential errors would manifest into the overstatement of gross O&M and ultimately, the rates for any particular year could be set too high.

 

Commission Determination

For these reasons, the Panel directs Creative Energy to file a capitalized overhead study in its next RRA outlining the utility’s policies on allocating costs from O&M to capital. This cost allocation policy should govern costs that are directly charged to capital, any general overhead allocations and indirect labour allocations.

5.3               General Administrative and Office

5.3.1          Sales Expense

The General Administration and Office expense forecast of $383,346 is included within the total Operating Expenses for 2015. Included within this General Administrative and Office forecast is the Sales Expense of $56,460 as shown in the table below.

Table 5.4

[106]

 

Creative Energy provides the following breakdown for its Sales Expense forecast:

Table 5.5 Forecast Sales Expense

[107]

 

Creative Energy submits that these amounts reflect the Company’s new sales, marketing and customer support initiatives within the core, as well as initiatives required to enhance industry and city relations. Creative Energy also notes that the increased sales expenses are offset in part by reduced expenses for club memberships and other promotional items, which are reflective of a different approach to customer relations and a greater emphasis on information support and industry participation.[108] Professional dues and memberships represent approximately 40% of the sales and marketing costs.

 

CEC raised the concern addressed in the Commission’s previous 2014 RRA Decision in that the cost‑causation relationship of the sales expense to the potential benefits actually attributable to the utility’s customer base must be considered. CEC is not persuaded by Creative Energy’s explanations on how the expenditures would fully benefit core customers, and further submits that the Commission evaluate the expenditures against the 2014 approved amount rather than the actual expenses. CEC submit that the BOMA, IDEA, and Chartered Professional Accountants of British Columbia (CPABC) are appropriately beneficial to core customers but that the QUEST spending of $5,000 for exposure to the development industry may not necessarily be in the core customers’ interest.[109]

 

Commission Determination

The Panel approves the sales expense of $56,460 for 2015.

 

In the Reasons for Decision to Central Heat’s 2014 RRA, CHDL was directed to reduce its 2014 Sales Expense by $37,000. The Commission considered that the average of the last 4 years Sales Expense (2010 to 2013) of $23,000 to be a more reasonable forecast for 2014 and stated that it:

… believes that any marketing efforts incurred for the purpose of raising awareness for or incurred in the development of new and separate district energy systems should not be borne by CHDL’s existing customer base…[1]

 

The Panel has considered the Commission’s previous reductions to Sales Expenses and agrees with CEC, the interpreted intent is to ensure that only those costs attributable to servicing core customers are allowed in the revenue requirements. The Commission’s concerns are related to the potential cross subsidization of costs between core and new service area customers, and it endeavours to ensure that business development costs that should be more appropriately allocated to new projects will be correctly assigned. The Panel has also discussed these concerns elsewhere in this Decision.

 

Notwithstanding the previous intention of the Commission, the Panel also recognizes that Creative Energy operates in a competitive environment with no mandatory connections.^[110] The nature of this impact is apparently observed in Creative Energy’s decreasing sales trends over the past number of years despite the modest increase in new customers to the core. The Panel also takes note that the Commission has previously acknowledged the competitive nature of Creative Energy[111] (then, Central Heat), and therefore hesitates making a determination which may impact the utility’s ability to compete, educate, and attract new customers to the core. For these reasons, the Panel is not prepared to reduce the sales expense.

5.3.2          Directors’ Fees

Included in the General Administrative and Office 2015 forecast, are the Directors’ Fees of $42,000 for 2015. Creative Energy submits its Board of Directors contains five members and is a reasonable size given the increased complexity of the business environment and the new direction of the Company.[112]

 

CEC notes that Directors fees for 2014 were $5,000 or20% higher than the 2014 approved amount of $25,000. For 2015, CEC notes, the proposed Directors’ fees are significantly higher than both the approved and actuals for 2014. CEC submits that the additional expense in Directors’ fees does not represent an appropriate expenditure to be borne by existing ratepayers and that it does not find any clear benefit attached to this expenditure. CEC further submits that the increase in Directors’ fees is appropriately a shareholder responsibility and therefore recommends that the Directors’ fees be reduced to the levels approved for 2014.[113]

 

In Reply, Creative Energy argues that it would be incorrect and inconsistent with past Commission decisions for CEC to suggest that Directors’ Fees should be a shared cost between shareholders and customers.

 

Commission Determination

The Panel approves the applied for Directors’ Fees for 2015 as it considers a board of five directors and the related compensation reasonable to provide oversight for Creative Energy.

 

6.0               LOAD FORECAST

Creative Energy provided its historical steam sales (2011 – 2013) and its forecast load (2014 – 2017) on page 39 of its Application. A calculation of the year over year changes in demand is shown in the following table below:

Table 6.1

[114]

 

There has been a decreasing sales trend for the past number of years, although Creative Energy is forecasting an increasing load growth for this test period. In 2014, the approved forecast was 1,136,141 million pounds, but the latest projection was 1,076,767 million pounds or 5% less than anticipated. Creative Energy states that the sales volume did not materialize because of changes in weather, changes in customer business needs, efficiency upgrades by customers, and delayed customer connections.[115]

 

Creative Energy does not have any deferral accounts for load variances and stated that risk of load variances are borne entirely by its shareholders.[116]

 

For 2015, Creative Energy indicated that the increase in growth was based on connection agreements that have been signed,[117] however Creative Energy appears to suggest that none of these contracts are on a “take or pay” basis.[118] For 2016 and 2017, Creative Energy stated that the forecast of growth of additional customers was based on sales and marketing initiatives “being developed.”[119]

 

CEC Final Submission

CEC accepts Creative Energy’s load forecast and recommends the Commission to enable an annual process of updating forecasts along with the rate adjustments as proposed by Creative Energy. CEC also requests that the Commission direct Creative Energy to take a weather normalized approach to forecasting in each annual update of the forecast and request clarification of the customer count methodology to ensure consistent data.[120]

 

Creative Energy Reply

Creative Energy disagrees with CEC’s submission as it does not believe that these initiatives will “meaningfully forecast statistically” because they are “large and lumpy projects in a very small system,” and therefore its assessment cannot be based on statistical analysis or a weather normalized approach. Further, Creative Energy clarifies that it currently does not adopt a customer count approach and reaffirms that its load forecasting methodology is based on monitoring individual customer plans.[121]

 

Commission Determination

The Panel notes Creative Energy confirms that the largest variance in forecast loads is weather related; however, the Company does not propose to adopt a weather normalized approach to forecasting. Arguably, this is a variable over which the utility has no control. The Panel recognizes that the load in the test period may turn out to be different than what Creative Energy is anticipating, as has been the case in the past. The Panel notes that the historical trend suggests that Creative Energy’s load forecasts have been consistently higher than the actual load recorded.

 

Initially, Creative Energy appears to diminish the importance of the load forecast impact by indicating that “in the absence of a deferral account for sales, [it] bears 100% of the risk for overestimating future load.”^[122] This position becomes less clear to the Panel during the second round of IRs when Creative Energy stated that it “proposes to annually file an update to the load forecast for [each of] the following year.”^[123] It would appear that during a multi-year test period, the utility may be implying a load forecast variance account, which would accommodate the updated load forecasts each year. However, in its Final Submissions, Creative Energy made a decision to “not seek to transfer forecast risk to customers.”[124] Therefore, the Panel is unclear on what the filing of the load forecast update each year would accomplish other than providing information only.

 

A further concern in the area of load forecasting is the method in which the forecasts are derived. Creative Energy explains that it does not rely on econometric modeling and instead relies on information gathered from individual customers.[125] The Panel accepts that Creative Energy does not adopt a weather normalized or customer count approach in its load forecasts, and agrees to some extent that individual customers should have the most reliable information pertaining to their consumption needs. The Panel also rejects CEC’s suggestions that customer count data would be relevant. Despite the customer additions over the past number of years, the load forecast appears to be consistently higher than actual, which as Creative Energy points out, is partly attributable to customers’ implementation of demand side measures, not related to customer count data. Therefore, the Panel considers that customers’ estimates may also contain a level of inherent bias to forecast higher than their actual needs to ensure reliability of supply. It is clear to the Panel that Creative Energy needs to review its forecasting methodology as past actual results indicate that this customer survey method produces results that are too high. The Panel accepts the 2015 load forecast, however Creative Energy is directed to consider other methods of load forecasting in its next RRA. If the same method is to be employed (customer surveys) then Creative Energy should consider adjusting for any inherent bias in the customer driven forecasts.

 

7.0               CAPITAL EXPENDITURES

Creative Energy states that its capital expenditures plan relates to growth from new infill development or retrofitting of potential customers and infrastructure upgrades to the system and is necessary to provide reliability and safety within its core system. It also states that it is embarking to a growth plan to extend its system to services beyond the core through future CPCN applications and that these related capital expenditures are not included in the current rate base.[126] Creative Energy provides the following summary for its capital program for the test period:

Table 7.1 Forecast Capital Expenditures

 

Major expenditures in 2015 include Boiler Plant Equipment for $139,000, Manhole Structures for $480,000 and other Distribution Equipment for $140,000.^[127] In 2014, total capital expenditures approved were $2,293,900[128], while the actual total expenditures were only $1,287,783.

 

Creative Energy calculates returns based on a mid-year rate base figure.[129]

 

CEC submits that given the uncertainties with respect to when capital expenditures will actually be made relative to when they are planned, CEC submits that it is important for the rate base to only be updated with prior year actual capital expenditures. CEC understands that this is what Creative Energy anticipates doing, but recommends that the Commission review prior year capital expenditures to ensure that actual expenditures are used for rate setting adjustments. It does not appear that CEC has any major issues with Creative Energy’s capital expenditures schedule.[130]

 

Commission Determination

The Commission Panel takes no issues with Creative Energy’s rate base recognition method and finds the forecast capital expenditures for 2015 to be reasonable and are therefore approved.

 

8.0               PENSION ISSUES

8.1               Introduction and Background

Creative Energy maintains a registered defined benefit pension plan (DB plan or the plan) covering twenty-two employees.[131] Employee future benefits under the plan are valued by both an accounting valuation and a funding valuation. Actuaries prepare an accounting valuation to determine the pension expense to be recognized in the financial statements (financial reporting Pension Expense). Actuaries also prepare a funding valuation to determine the cash contribution requirements (Cash Contribution).[132] Both the financial reporting Pension Expense (accounting valuation) and the Cash Contribution (funding valuation) recognize the same costs; however, the amount allocated to each year is not the same. The difference between the cumulative Cash Contributions and the cumulative Pension Expense since the inception of the plan is equal to the Pension Asset/Liability, as reported on the financial statements (financial reporting Pension Asset).[133]

 

For ratemaking purposes, a regulated utility is normally entitled to recover pension costs in rates if prudently incurred (Pension Expense for Rates); however, the basis for determining the Pension Expense for Rates can vary from regulator to regulator and from utility to utility. For instance, Pension Expense for Rates can be based on the Cash Contribution, the financial reporting Pension Expense, or certain components of financial reporting Pension Expense such as current service costs.

 

However, it would be unusual for the Pension Expense for Rates to be based on Cash Contributions if GAAP are used as the basis for the utility’s regulatory schedules. However, for utilities who’s Pension Expense for Rates is based on the Cash Contribution, the cash outlay to fund the utility pension plan will equal the amount of cash recovered from ratepayers.[134] Alternately, for utilities whose Pension Expense for Rates is based on the financial reporting Pension Expense, or certain components of it, a discrepancy will exist between the cash outlay to fund the plan and the amount of cash collected in rates (out-of pocket cash outlay). It is not unusual for regulators to allow a utility to be compensated for the carrying costs related to this out-of pocket cash outlay.

 

If the Pension Expense for Rates is equal to the financial reporting Pension Expense, then the out‑of‑pocket cash outlay should equal to financial reporting Pension Asset, and accordingly, no carrying costs need to be compensated for. However, because ratemaking is based on a forecast and rates are often set for multiple years at a time, the Pension Expense for Rate setting will not necessarily equal the Pension Expense for financial reporting purposes, even if the forecast is made on that basis. As such, the actual out-of-pocket cash outlay is not necessarily equal to the Pension Asset reported on the financial statements; rather, the actual out-of-pocket cash outlay will be equal to the difference between the cumulative Cash Contribution to the plan and Pension Expense for Rates (Regulatory Pension Asset).

 

Furthermore, the Cash Contribution and not the Pension Expense that is deductible for tax purposes; therefore, in order to determine the true out-of-pocket cash outlay, the Regulatory Pension Asset must be adjusted for any tax implications (After-tax Regulatory Pension Asset).

8.1               Requested treatment

In the Application, Creative Energy sought approval for recovery of financing costs of its defined benefit pension plan, and proposed that compensation be provided by rate base treatment of the full amount of the After-tax Pension Asset. During the preparation of responses to information requests, another compensation approach was identified that provides for rate base treatment of a portion of the After-tax Pension Asset and deferral account treatment of the remaining portion of the After-tax Pension Asset. Creative Energy believes that this second compensation approach is fair and reasonable.[135]

 

Therefore, Creative Energy requests the following approvals:

o   to recover a Pension Expense of $214,300 in 2015;[136] (Section 8.2)

o   to include in rate base, starting in 2015, the After‐tax Pension Asset with a forecast 2015 balance of $402,283;[137] (Section 8.3 and 8.5)

o   to recover in rates the Regulatory Transitional Adjustment of $301,177;[138] (Section 8.4)

o   for a Weighted Average Cost of Capital (WACC) deferral account with a three year amortization period commencing in 2016 to recover the After-tax Regulatory Transitional Adjustment;[139] (Section 8.6)

o   for an ongoing WACC pension expense variance deferral account with a three year amortization period to capture the annual variance between forecast Pension Expense for Rates and actual financial reporting Pension Expense.[140] (Section 8.7)

8.2               Pension expense (operating expense)

In the Original Application, Creative Energy requests to recover in 2015 rates, a Pension Expense of $229,387.[141] In the Evidentiary Update, the expense was updated to $241,410[142] and updated again in response to IR No. 2 to $214,300.[143] Creative Energy states that the first two forecasts were incorrectly based on Cash Contributions and not the forecast 2015 Pension Expense.[144]

 

Creative Energy states that the final updated forecast 2015 Pension Expense of $214,300 has been prepared by the actuary and is in accordance with ASPE and provided the following detailed calculation: [145]

Table 8.1 – Forecast Pension Expense

 

Commission determination

Creative Energy’s forecast 2015 Pension Expense of $214,300 is accepted by the Panel as it appears to be reasonable and is calculated by an external actuary in accordance with the Pension Expense for financial reporting purposes. The treatment of the difference between the forecast Pension Expense recovered in rates and the actual financial reporting Pension Expense, is addressed in Section 8.7 of this Decision.

8.3               After-tax Pension Asset

Creative Energy states that its Cash Contributions have exceeded its financial reporting Pension Expense since 2004, resulting in a growing cumulative difference between its annual Cash Contributions and the Pension Expense.[146] Creative Energy further states that the Cash Contributions in excess of the financial reporting Pension Expense have been funded by the shareholders and they currently receive no compensation or the financing costs related to the excess.[147]

 

Creative Energy is of the view that the cumulative difference between the annual After‐tax Cash Contributions and the financial reporting Pension Expense should be accorded rate base treatment as has been approved for other utilities regulated by the Commission, including Pacific Northern Gas Inc. (PNG), British Columbia Hydro and Power Authority and all of the Fortis utilities. Creative Energy states that the funding applied for in this Application follows a similar application by PNG, approved by the Commission in Order G‐89‐13.[148]

 

In the Original Application Creative Energy forecast the December 31, 2013 After-tax Pension Asset to be $1,076,127 ($1,513,400 before-tax), and requested that this amount be included in rate base in each of 2015, 2016, and 2017.[149] Through the first round of IRs it was revealed that Creative Energy was in fact requesting the December 31, 2014 balance to be included in rate base which it forecast at $727,627 ($602,800 before-tax).[150]

 

During the second round of IRs it was revealed that Creative Energy made an error in calculating the after-tax value of the financial reporting Pension Asset at December 31, 2014, and updated the calculation After-tax Pension Asset from $727,627 to $402,283 (the before-tax amount of $602,800 remained unchanged).[151]

 

The table below details the December 31, 2013 and 2014 before-tax and after-tax calculation of financial reporting Pension Asset (before the update for the after-tax 2014 closing balance).[152]

Table 8.2 – Pension Asset as at December 31, 2014

 

Creative Energy has requested to be compensated for costs to finance the after-tax difference between the Cash Contributions and the Pension Expense (After-tax Pension Asset) which it forecasts to be $402,283 in 2015.

 

Commission determination

The Panel finds that it has a duty to approve rates that provide Creative Energy with a reasonable opportunity to earn a fair return on its invested capital, which is consistent with the regulatory compact. Accordingly, the Panel determines that Creative Energy is entitled to be compensated for the carrying costs related to the out-of-pocket cash outlay to finance its DB plan starting in 2015.

 

Creative Energy requests that the out-of-pocket cash outlay be equal to the financial reporting After‑tax Pension Asset on the basis that it was approved by the Commission for other utilities, and specifically referred to the Commission’s determination on the application by PNG for the 2012 Pension and Non-Pension Benefits (PNG Pension Decision).

 

 

 

On page 8 of the PNG Pension Decision, the Commission determined that PNG was entitled to earn a return on the capital it reasonably requires to carry out its operations and therefore, was entitled to earn a return on the out-of pocket cash outlay required to finance the DB plan. The Panel determined that the out-of pocket cash outlay was to be equal to the after-tax cumulative difference between the Cash Contributions and the Pension Expense for Rates, also known as the After-tax Regulatory Pension Asset.

 

In the particular case of PNG, the value of the After-tax Regulatory Pension Asset was not materially different than the financial reporting After-tax Pension Asset, because the Pension Expense for Rates was not materially different than the financial reporting Pension Expense. As a result the Panel found that the incremental costs of using the financial reporting After-tax Pension Asset outweighed the benefits of using the After-tax Regulatory Pension Asset and for PNG determined that it represented the out-of pocket cash outlay required to finance its pension plan.

 

For Creative Energy the Panel finds that the out-of-pocket cash outlay required to finance its DB plan is not necessarily equal to the financial reporting After-tax Pension Asset. Rather, similar to the Commission’s findings on PNG, the Panel determines that the out-of-pocket cash outlay required to finance its pension plan is equal to the (mid-year) after-tax difference between the cumulative Cash Contributions to the plan and Pension Expense for Rates ( i.e. the After-tax Regulatory Pension Asset).

 

The calculation of the mid-year After-tax Regulatory Pension Asset, rationale for its determination, and the alternatives treatments considered are further addressed below.

8.3.1          After-tax Regulatory Pension Asset

Creative Energy confirms that the Pension Expense for financial reporting purposes for the years 2004-2013 was not equal to the Pension Expense for Rates.[153] The two tables below shows that as at December 31, 2014, After‑tax Regulatory Pension Asset or the after-tax out-of-pocket cash outlay is $703,460 ($1,010,218 before‑tax). At December 31, 2014, the After-tax Regulatory Pension Asset is $301,177 greater than the financial reporting Pension Asset of $402,283.

Table 8.3 Before-tax Regulatory Pension Asset

[154]

 

Table 8.4 – After-tax Regulatory Pension Asset

[155]

 

The Panel determined that the After-tax Regulatory Pension Asset at December 31, 2014 is $703,460. However, unlike PNG who reports under US GAAP, Creative Energy applied a new pension accounting standard in 2014 which required a transitional adjustment (Transitional Adjustment) to be made to the financial reporting Pension Asset. Before the Panel makes a final determination on the regulatory treatment of the After-tax Regulatory Pension Asset it will address the regulatory impact of the Transitional Adjustment.

8.4               Regulatory Transitional Adjustment

8.4.1.1    Pension accounting standard 2014 changes

Creative Energy is required to prepare its financial statements under ASPE. In May 2013 the Accounting Standards Board issued ASPE Canadian Institute of Chartered Accountants (CICA) HB Section 3462 Employee Future Benefits (Section 3462) which replaces ASPE HB Section 3461 Employee Future Benefits (Section 3461) for annual financial statements relating to fiscal years beginning on or after January 1, 2014.[156]

 

Creative Energy explains the change as follows:

Recent changes to the financial reporting standards, as specified in generally accepted accounting principles, regarding the reporting of benefit obligations and plan assets are also a contributing cause for this Application.[157]

 

Effective January 1, 2014, Creative Energy adopted Section 3462 – Employee Future Benefits when accounting for its DB pension plan. The most significant changes to the standard are as follows:

Table 8.5 – Comparison of CICA 3461 and CICA 3462

[158]

 

The standard requires retroactive application in accordance with CICA Section 1506 resulting in an adjustment to retained earnings (Transitional Adjustment) of the amounts previously included in the Pension Asset relating to the unamortized actuarial gains and losses and past service costs as at January 1, 2014. For financial reporting purposes Creative Energy’s actuary has calculated the Transitional Adjustment in 2014 as $1,164,900 as follows:[159]

Table 8.6 – Calculation of Transitional Adjustment

 

The Transitional Adjustment of $1,164,900 reported by Creative Energy is consistent with the balances reported in the audited December 31, 2014 financial statements.[160] The Transitions Adjustment of $1,164,900 was taken into consideration in calculating the $602,800 financial reporting Pension Asset shown in Table 8.5 above.

 

Commission determination

Because the Transitional Adjustment is a retained earnings adjustment required under GAAP there is a strong argument that for regulatory purposes a utility is entitled to recover the Transitional Adjustment in the test period as part of Pension Expense (or some other method of recovery in rates). For example, if the utility relies on GAAP to prepare its regulatory schedules and if the Regulatory Pension Asset was equal to the financial reporting Pension Asset before considering the Transitional Adjustment it would have been fair to allow the utility to recover the Transition Adjustment in rates in the test period the adjustment was made.

 

Given that the Creative Energy follows GAAP for regulatory purposes, and GAAP required the Transitional Adjustment to be made, the Panel determines that Creative Energy is entitled to recover in rates a portion of the After-tax Regulatory Asset associated with the Transitional Adjustment.

 

 

However, because the After-tax Pension Asset and the After-tax Regulatory Pension Asset are not equal, the Transitional Adjustment for regulatory purposes (Regulatory Transitional Adjustment) will not be equal to the financial reporting Transitional Adjustment of $1,164,900. A determination on how much of the $703,460 After‑tax Regulatory Pension Asset is allocated to the Regulatory Transition Adjustment follows.

8.4.1.2    Adjusting the After-tax Pension Asset for the transitional adjustment

The value of the Regulatory Transitional Adjustment allocated to the After-tax Pension Asset will reduce the out‑of‑pocket cash outlay financing costs that Creative Energy is entitled to be compensated for.

 

Creative Energy requests that the Regulatory Transitional Adjustment be equal to $301,177 with the remaining balance (After-tax Regulatory Pension Asset) equal to $402,283.[161] The rationale was that this would result in the After-tax Regulatory Pension Asset being equal to the financial reporting After‑tax Pension Asset of $402,283.

 

If the Pension Asset for regularity purposes were to equal the financial reporting Pension Asset, the financial reporting Pension Asset (which has been determined by an actuary and audited by an accounting firm) would become the basis to forecast the test year’s Regulatory Pension Asset. Because of the complexities in forecasting pension balances, significant regulatory efficiencies can be achieved if reliance can be placed on the financial reporting Pension Asset.

 

Commission determination

Because the Regulatory Pension Asset and the financial reporting Pension Asset are not equal, there is no clear way to determine how much of the After-tax Regulatory Pension Asset should be allocated to the Regulatory Transitional Adjustment.

 

The Panel considered calculating the Regulatory Pension Asset on a similar percentage basis as the financial reporting Transition Adjustment, resulting in a Regulatory Transitional Adjustment of $541,849 and a Regulatory Pension Assets of $161,611 ($703,460-$541,849).[162] However, if the Pension Asset for financial reporting purposes were to equal the Pension Asset for ratemaking purposes, as requested by Creative Energy, there would be significant regulatory efficiencies and the amount currently eligible for recovery in rates would be lower than under the percentage methodology.

 

Therefore, for regulatory efficiency purposes and because no superior allocation method has been identified as an alternative, and no parties objected, the Panel approves Creative Energy’s request to allocate $301,177 to the Regulatory Transitional Adjustment. The Regulatory Transitional Adjustment is eligible for recovery in rates starting in 2015.

 

As shown in the table below, this results in the After-tax Regulatory Pension Asset being equal to the $402,283 financial reporting After-tax Pension Asset.

Table 8.7 – Transitional Adjustment

8.5               Deferral account treatment of the transitional adjustment

Creative Energy states that the impact of recovering the full Regulatory Transitional Adjustment balance of $301,177 would result in a one year rate increase of 4.0% and a decrease in rates of an equal amount in the following year.[163] Creative Energy requests that the Regulatory Transitional Adjustment be recovered in rates over time to smooth out the rate impact and requests approval for a Transitional Adjustment deferral account to be amortized over three years commencing in 2016 with a WACC carrying cost on the unamortized balance.[164] Creative Energy proposes that amortization commence in 2016 to eliminate any further rate pressure in 2015.[165]

 

Creative Energy stated that if amortization commenced in 2015, over three years the rate impacts would be approximately 1.3% in 2015, 0.02% in 2016, (0.1) in 2017, and a decrease in 2018 of 1.4% once the balance is fully amortized. According to Creative Energy, under a WACC, the total carrying costs over the three years would be $19,095 if they were calculated on the opening balance.[166] If amortization was to commence in 2016 rather than 2015, the rate impact would simply be pushed out one year and be the same other than a slight 0.02% increase in the first year. However the total carrying costs over the three years would be $38,190.[167] Creative Energy also showed that if the balance was amortized over 10 years, the rate impact in 2015 would be 0.9% and would last for 10 years.[168]

 

Commission determination

The Panel has determined that Creative Energy is entitled to recover the Regulatory Transitional Adjustment of $301,177 in rates starting in 2015. Given the size of the balance and the already forecast rate increase in 2015, the Panel finds the deferral account treatment requested to be an appropriate mechanism to smooth out the rate impact of 4% that would occur if the balance was fully recovered in 2015. Therefore, the Panel approves Creative Energy’s request to establish a Transitional Adjustment deferral account to be amortized over three years.

 

Given the medium term nature of the approved deferral account, the Panel finds it unlikely that Creative Energy will require any equity to finance the unamortized balance. As such, the Panel does not consider that the WACC is an appropriate return for a medium term deferral account of this nature and for this reason determines that the carrying cost is more appropriately Creative Energy’s weighted average cost of debt (WACD). Further, the Panel directs that the carrying costs on deferral accounts are to be calculated on the mid-year balance and not the opening balance.

 

The Panel notes that if amortization were to commence in 2016 rather than 2015, as requested by Creative Energy, the rate impact in the first year would only be 0.2% higher. The additional carrying costs as identified by Creative Energy would be lower than forecast as the Panel has not allowed for a WACC return and has determined that interest is to be calculated on the mid-year balance. On balance, the Panel finds that allowing Creative Energy to defer commencing amortization until 2016, and incurring slightly higher financing costs, will achieve the rate smoothing that is necessary and will not put any additional upward pressure on the 2015 rate increase.

 

In summary, the Panel approves a Regulatory Transitional Adjustment Deferral Account to capture the one time addition of $301,177. The deferral account is to be amortized over a three year period commencing on January 1, 2016, and a carrying cost on the mid-year unamortized balance at Creative Energy’s WACD rate.

8.6               Rate base treatment of the After-tax Regulatory Pension Asset

The Panel has already found that Creative Energy is entitled to be compensated for the out-of-pocket cash outlay required to finance its DB pension plan, which the Panel has determined to be equal to the mid-year After-tax Regulatory Pension Asset. Creative Energy has requested a rate base return on the balance which it

considers appropriate in order to be compensated for the out-of pocket cash outlay required to finance its DB pension plan.[169] Rate base treatment implicitly means that the balance is added to rate base thereby earning a WACC return, with the return being recovered in rates annually.

 

Commission determination

The Panel determines that the After-tax Regulatory Pension Asset is a long term asset which the shareholders will likely have to fund with a portion of equity. If Creative Energy is not compensated for the equity required to fund the mid-year After-tax Regulatory Pension Asset, then its opportunity to achieve its allowed return on equity will be diminished. For those reasons the Panel approves Creative Energy’s request for rate base treatment of the After-tax Regulatory Pension Asset commencing in 2015.

8.6.1          Mid-year After-tax Regulatory Pension Asset

The Panel has determined that the year end 2014 After-tax Regulatory Pension Asset is $402,283 after being adjusted for the Regulatory Transitional Adjustment which the Panel has approved Creative Energy to recover in rates over three year. The approved test period for the Application is 2015; therefore, it is the 2015 mid-year After-tax Regulatory Pension Asset of $414,021, as calculated in the table below, that is to be added to rate base in 2015.

Table 8.8 – Mid-year After-tax Pension Asset as at December 31, 2015

[170]

 

Commission determination

The Panel determines that the mid-year After-tax Regulatory Pension Asset which represents the out-of-pocket cash outlay required to finance its DB pension plan in 2015 is $414,012, and approves this amount to be added to rate base.

8.7               Request for pension expense variance deferral account

Creative Energy confirms that under the new financial reporting standard, the financial reporting Pension Asset will be equal to the funded status of the plan and will continue to represent the difference between the cumulative Cash Contributions and the Pension Expense for financial reporting purposes. [171]

 

If the Regulatory Pension Asset equals the Pension Asset for financial reporting purposes (which can be achieved if the Pension Expense for Rates equals the financial reporting Pension Expense) then reliance can then be placed on the Pension Asset prepared by the actuary and reported in the audited financial statements and significant regulatory efficiencies are gained.

 

To ensure that the Regulatory Pension Expense and the financial reporting Pension Asset remain the same, Creative Energy is requesting a deferral account to capture the variance between the forecast Pension Expense approved for recovery in rates and the actual Pension Expense reported on the financial statements. Creative Energy seeks a three year amortization period commencing in 2018 and a WACC carrying costs on the unamortized balance.[172]

 

Commission determination

The Panel approves Creative Energy’s request for a Pension Expense Deferral Account in order to ensure that the Regulatory Pension Asset equals the financial reporting Pension Asset, which will provide significant regulatory efficiencies in future test periods. Further, given the volatility of the pension expense that may result from the new accounting standard and the significant size of the pension expense, a deferral account will ensure that Creative Energy’s shareholders and ratepayers are not exposed to this volatility.

 

However, the Panel does not consider a three year amortization period to be an appropriate recovery period. Variance deferral accounts should normally be recovered in the following test period to ensure intergenerational equity is preserved.

 

Further, given the short term nature of the deferral account, the Panel does not consider that the WACC is the appropriate carrying cost. The Panel finds that Creative Energy would likely finance the variance with short term debt and for this reason determines that the carrying costs on the mid-year unamortized balance will be Creative Energy’s short term debt rate.

 

Accordingly, the Panel approves a Pension Expense Deferral Account to capture the variance between the forecast Pension Expense recovered in rates and the Pension Expense reported in the company’s audited financial statements. The deferral account is to be amortized over a one year period (in the following test period) with a carrying cost on the mid-year unamortized balance at Creative Energy’s short term debt rate.

 

Further, the Panel directs that when determining the mid-year After-tax Regulatory Pension Asset in future test periods the opening balance will equal the previous year’s December 31 Pension Asset (after-tax) reported on the audited financial statements. The test periods ending balance will be calculated in accordance with Table 8.9 of this Decision.

 

Should the Pension Asset become a Pension Liability at any point in the future, Creative Energy must continue to include the Pension Liability in rate base as a credit.

 

9.0               OTHER iSSUES

9.1               GCOC Impact of 2013-2014

9.1.1          History

The Commission’s GCOC Stage 2 Decision was issued on March 24, 2014, which approved a capital structure of 42.5% equity and an equity risk premium of 75 bps for Creative Energy (then Central Heat), and raised the approved ROE to 9.5%. The Commission considered that this would apply “for the time being” and directed Central Heat to file “within the next 12 months either a 2016 or multi-year revenue requirement application….reflecting a new business plan with a comprehensive justification for the equity thickness and equity risk premium.”[173]

 

On June 12, 2014 by Order G-73-14, the Commission approved Creative Energy’s request for a GCOC Stage 2 Deferral Account, subject to rate base treatment and financing. At that time, Central Heat calculated the cumulative deferred gross revenue requirement for 2013 and 2014 to be $329,484.

9.1.2          Evidence

In its original application, Creative Energy included a revenue requirement line item labelled “Cost of Equity 2013/2014” totalling $333,477 and amortized in 2016 and 2017, with no supporting explanation or calculation in the Application.

 

In its IR No. 1 response, Creative Energy revised this amount to be $335,447. In its Evidentiary Update, Creative Energy further revised this amount to be $400,452, with no supporting evidence. In its IR No. 2 response, Creative Energy then suggests that the amount should be $364,681 shown in its revised Table 1.3.1, but the supporting calculations in IR 2.1.1 shows a figure of $333,012, which is the figure also shown in Creative Energy’s Final Submission.[174]

 

Creative Energy proposes to amortize the GCOC impact over 2 years, in 2016 and 2017 however, it has indicated that 3-year amortization would also have merit.[175] Part of the rationale is that the rate increase in 2015 is already fairly significant, and Creative Energy wishes to delay this impact. Creative Energy attempted to calculate the rate impacts for various scenarios in IR No. 1 and IR No. 2.[176]

 

Commission determination

Given the numerous adjustments to the calculation of the actual balance contained in the GCOC Stage 2 deferral account, the Panel’s confidence in Creative Energy’s calculations in this RRA have deteriorated significantly. The Panel notes that notwithstanding the inconsistent numbers shown, there were also errors in the GCOC impact calculation which included an incorrect rate base amount for 2014. The Panel notes that the actual 2014 rate base amounts shown in the revised Table 1.3.1 (revised in IR No. 2), should be the accurate starting point. Creative Energy is directed to make this correction in its subsequent compliance filing. The allowed rate base financing shall be calculated on the mid-year unamortized balance.

 

Further, the Panel finds that the most appropriate amortization period for this deferral account is two years, 2016 and 2017.

9.2               NEFC Revenue Offset

In its Application, Creative Energy included a forecast for the revenue requirement offset of $20,000 in 2016 and $90,000 in 2017, relating to the NEFC project without any supporting evidence. Throughout the evidentiary phase, it was revealed that this costs offset is based on forecast loads and an assumed fixed cost allocation rate for the NEFC, a project which will initially be served from Creative Energy’s existing steam plant and which will continue to receive long term peaking and backup support. The cost offset is meant to recover the energy production from the existing steam plant and a proportionate share of the fixed steam plant costs and corporate overheads.[177]

 

Creative Energy initially appeared to suggest that it would take forecast risk on these cost offsets[178] but then submits that after reflection, it decided to seek approval for a deferral account to accommodate the variances between these estimates and the actual costs.[179]

 

Creative Energy provided a calculation to support its derivation of its forecast cost offset and indicates that the fixed cost allocations in 2016 and 2017 were based on certain assumptions. However, it also conceded that the proposed allocation methodology has not yet been reviewed or approved by the Commission, but it plans to file a “preliminary allocation proposal” as part of that upcoming CPCN application.[180]

 

Commission Determination

In consideration of the previous Panel determination to approve a 1-year revenue requirement for 2015 only, the Panel makes no determination on the NEFC cost offset sought in 2016 and 2017. Further, the Panel makes no determination on the proposed deferral treatment to recognize forecast and actual allocations.

 

Notwithstanding, the Panel is aware that Creative Energy filed its NEFC CPCN for review on April 17, 2015. In that application currently before the Commission, the Panel notes that Creative Energy appears to be seeking approval for a cost allocation from the core revenue requirements of $77,000 in 2016 and $234,000 in 2017,[181] amounts of which are substantially different than what is being applied for this is RRA. This inconsistency further supports the Panel’s previous determination that only a 1‑year test period should be approved at this time.

9.3               Difference between Interim and Permanent Rates for 2015

Creative Energy proposes that the difference between the interim rates and the final delivery rates approved for 2015, be collected by way of a one-time bill adjustment for each customer based on each customer’s consumption during the interim period.

 

The Panel finds this approach to be reasonable but is unclear of whether a more gradual recovery would be appropriate. The Panel directs Creative Energy to collect the difference between the interim rates and final rates from customers by way of one-time billing adjustment for each customer based on each customer’s consumption during the interim period. Alternatively, Creative Energy is to propose different options for the recovery of the difference between the 2015 interim rates and the final rates in its compliance filing.

9.4               Future RRAs

As discussed in various sections in this Decision, the Panel finds that the Application provided by Creative Energy was deficient. Understanding that Creative Energy is in a period of new management and transition, Commission staff attempted to supplement the evidentiary record with two rounds of lengthy IRs. The Panel takes note that significant efforts have been expended in the review of this Application, and in all likelihood on Creative Energy’s part in responding to Commission requests as well. These efforts should be reasonably mitigated in the future with a more fulsome Application. For future RRAs, the Panel directs that Creative Energy must take into account the following minimum requirements:

•         Revenue Requirement summary table followed by supporting schedules for each major line item. Supporting schedules should contain cross references to related schedules and must be accurate to the best of the applicant’s knowledge;

•         Each major revenue requirement line item must contain a description, explanation and/or justification in the body of the application;

•         Previous 5 year actuals along with forecasts for the test period. Comparison of previous year’s actuals to approved amounts are also necessary;

•         All financial schedules must be reported on an accrual basis rather than cash basis and must match the financial schedules for accounting purposes. Any discrepancies must be fully explained and reconciled;

•         A working excel model of the revenue requirement calculations and schedules are ideal and may be filed confidentially along with the application;

•         The need to continually file a full set of Terms of Conditions should be evaluated. Creative Energy should consider whether a revision only to the tariff page can be accommodated;

•         List of previous Commission directives along with references/notes on the status of compliance. Reasoning must be provided for any items that the applicant is non-compliant with.

The Panel encourages Creative Energy to meet with Commission staff prior to the filing of the next RRA in order to gain a better understanding of the minimum filing requirements and standard regulatory processes.

 

 

Dated at the City of Vancouver, in the Province of British Columbia, this                9^th                 day of June, 2015.

 

 

 

                                                                                                                Original signed by:

 

                                                                                                                ____________________________

                                                                                                                L. A. O’Hara

                                                                                                                Commissioner

 

 

 

                                                                                                                Original signed by:

 

                                                                                                                ____________________________

I. F. MacPhail

                                                                                                                Commissioner

 

 

 

 

List of Acronyms

 

ASPE	Accounting Standards for Private Enterprises
bps	basis points
B.T.U.	British Thermal Unit
BOMA	Building Owners and Managers Association
CEC	Commercial Energy Consumers of British Columbia
CHDL	Central Heat Distribution Limited
CPCN	Certificate of Public Convenience and Necessity
Commission	British Columbia Utilities Commission
CPABC	Chartered Professional Accountants of British Columbia
CoV	City of Vancouver
Creative Energy, the Company	Creative Energy Vancouver Platforms Inc.
DES	district energy system
DB Plan or the plan	defined benefit pension plan
DSM	demand‑side management
GAAP	Generally Accepted Accounting Principles
GCOC	Generic Cost of Capital
Guidelines	Resource Planning Guidelines
IRs	Information Requests
LTRP	Long Term Resource Plan
MAA	30 year Municipal Access Agreement with the City of Vancouver dated September 1, 1999
NEFC	Northeast False Creek
NEFC CPCN Application	Northeast False Creek Certificate of Public Convenience and Necessity Application
NES	neighborhood energy systems
NEU	neighbourhood energy utilities
O&M	operating and maintenance
PNG	Pacific Northern Gas Inc.
ROE	Return on Equity
RRA	2015-2017 Revenue Requirements Application
Section 3461	ASPE HB Section 3461 Employee Future Benefits
Section 3462	ASPE CICA HB Section 3462 Employee Future Benefits
TES	thermal energy system
the NEA	Neighbourhood Energy Agreement between Creative Energy and the City of Vancouver dated March 25, 2015
UCA	Utilities Commission Act

 

IN THE MATTER OF

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

 

and

 

Creative Energy Vancouver Platforms Inc.

2015-2017 Revenue Requirement Application

EXHIBIT LIST

 

Exhibit No.                                                     Description

 

Commission Documents

 

A-1	Letter dated December 4, 2014 - Appointing the Commission Panel for the review of the Creative Energy 2015-2017 Revenue Requirement Application
A-2	Letter dated December 15, 2014 – Commission Order G-198-14 establishing a regulatory timetable with reasons
A-3	Letter dated January 20, 2015 – Commission Information Request No. 1 to Creative Energy
A-4	Letter dated January 30, 2015 – Notice of member extension
A-5	Letter dated March 2, 2015 – Regulatory Timetable with reasons
A-6	Letter dated March 3, 2015 – Commission request clarification of CEC intervention
A-7	Letter dated March 12, 2015 – Commission Information Request No. 2 to Creative Energy
A-8	Letter dated March 12, 2015 – CONFIDENTIAL Commission Information Request No. 2 to Creative Energy
A-9	Letter dated March 27, 2015 – Commission response to Creative Energy extension request to file Information Request No. 2
A-10	Letter dated April 9, 2015 – Order G-56-15 Regulatory Timetable

 

Commission Staff Documents

 

 

Applicant Documents

 

B-1	Creative Energy Vancouver Platforms Inc. (Creative Energy) Letter Dated November 28, 2014 - 2015-2017 Revenue Requirement Application
B-1-1	Letter dated February 27, 2015 – Creative Energy Submitting Evidentiary Update
B-2	Letter dated February 19, 2015 – Creative Energy Submitting response to BCUC IR No.1
B-2-1	Confidential Letter dated February 19, 2015 – Creative Energy  Submitting Confidential response to BCUC IR No.1
B-3	Letter dated February 19, 2015 – Creative Energy Submitting response to CEC IR No.1
B-4	Letter dated March 26, 2015 - Creative Energy Request for Extension
B-5	Letter dated March 30, 2015 – Creative Energy Submitting response to BCUC IR No. 2
B-5-1	Confidential Letter dated March 30, 2015 – Creative Energy Submitting response to BCUC IR No. 2
B-6	Letter dated March 30, 2015 – Creative Energy Submitting response to CEC IR No. 2
B-7	Letter dated December 31, 2014 – Creative Energy Submitting Financial Statements

 

Intervener Documents

 

C1-1	Commercial Energy Consumers Association of British Columbia (cec) Letter Dated January 12, 2015 – Request for Intervener Status
C1-2	Letter Dated January 23, 2015 – CEC Submitting Information Request No. 1 to Creative Energy
C1-3	Letter Dated March 4, 2015 – CEC Submitting clarification of representation
C1-4	Letter Dated March 12, 2015 – CEC Submitting Information Request No. 2

 

 

Interested Party Documents

 

D-1

 

 

Letters of Comment

 

E-1