ORDER NUMBER

G-59-17

 

IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

 

and

 

Stargas Utilities Ltd.

Application to Vary Delivery Rate, Amend Cost of Service Formula and

Approve Replacement Term Financing/Redemption of Preferred Shares

 

BEFORE:

R. I. Mason, Panel Chair/Commissioner

D. M. Morton, Commissioner

 

on April 27, 2017

 

ORDER

WHEREAS:

 

A.        On September 26, 2016, Stargas Utilities Ltd. (Stargas) filed an application with the British Columbia Utilities Commission (Commission) for interim and permanent approval of a $0.45 per gigajoule delivery rate decrease for all customers, effective November 1, 2016 (Application);

B.        The Application also requests approval to, among other things, replace Stargas’ existing term loan with a $300,000 term loan at an interest rate of prime plus 1.25 percent (Replacement Financing) and to redeem 1,000 Class G preferred shares with a par value of $100,000 using Replacement Financing proceeds (Preferred Share Redemption);

C.        Stargas submitted amendments to its Application on December 8, 2016 with respect to changes to its revenue requirement, on January 9, 2017, with respect to revised application cost estimates, and on January 27, 2017, with respect to various approvals sought in its responses to Commission and intervener information requests (IRs);

D.        By Order G-155-16 dated October 6, 2016, the Commission approved, on an interim and refundable basis, a delivery rate decrease of $0.45 per gigajoule for all customers, effective November 1, 2016, and established a regulatory timetable for review of the Application, which provided for one round of IRs with further process to be determined;

E.         On October 13, 2016, Silver Star Property Owners Association (SSPOA) registered as an intervener in the proceeding;

F.         By letter dated November 29, 2016, Stargas sought advance approval from the Commission on matters related to the proposed Replacement Financing; 

G.        After receiving Stargas and SSPOA submissions, Order G-176-16 dated December 1, 2016, established a Streamlined Review Process (SRP) taking place on December 14, 2016, with further process to be determined;

H.        The SRP was held in Vancouver, BC with Stargas and SSPOA participating by video conference. Subsequent to the SRP, on December 16, 2016, the Commission issued Order G-192-16 approving Replacement Financing and the Preferred Share Redemption; 

I.          By letter dated December 20, 2016, SSPOA requested the Commission establish a regulatory timetable allowing for a further IRs, and by Order G-196-16, dated December 22, 2016, the Commission amended the regulatory timetable to allow for a second round of IRs and written final and reply arguments;

J.          Stargas and the SSPOA submitted their final arguments on February 3, 2017 and February 10, 2017, respectively;

K.         Stargas filed its reply argument on February 17, 2017; and

L.         The Commission reviewed the Application and the related evidence filed in the proceeding and determines that certain approvals and directives are warranted.

 

NOW THEREFORE pursuant to sections 59 to 61 of the Utilities Commission Act and for the reasons attached as Appendix A to this order, the British Columbia Utilities Commission orders as follows:

 

1.         Stargas Utilities Ltd.’s (Stargas) requested permanent delivery rate decrease of $0.30 per gigajoule (GJ) for all customers effective November 1, 2016, is not approved as filed.

2.         Permanent delivery rates for all customers effective November 1, 2016, as modified by the directives in this order, are approved and shall remain in effect until October 31, 2019. Stargas is directed to inform all customers of the permanent delivery rate by way of written notice included with the next customer invoice.

3.       Stargas is directed to refund the difference between the permanent delivery rate approved in this order and the interim rate previously approved by Order G-155-16, with interest based on the interest rate paid on Stargas’ operating line. The Panel directs, for ease of administration, that refunds are to be provided within 60 days of the date of this order by means of a one-time bill credit to all customers.

4.         Stargas’ request to recover the following items from ratepayers, is denied:

a)       Interest paid on shareholder advances at 1 percent above the interest paid on Stargas’ operating line; and

b)       Interest paid on the portion of a $300,000 term loan approved by Order G-192-16 used to finance the redemption of 1,000 Class G preferred shares at a rate of prime plus 1.25 percent.

5.         Stargas is approved to amend the hourly rates as requested for Executive and Accounting services provided by Okanagan Funding Ltd. (OKF) to $144.26 per hour and $69.24 per hour respectively, effective November 1, 2016.

6.         Stargas’ request to amend the hourly rate for Administrative services provided by OKF to $46.16 per hour is denied. Stargas is approved a rate of $24.46 per hour for Administrative services, as outlined in the reasons for decision attached as Appendix A to this order.

7.         Stargas is directed to establish an hourly rate for Bookkeeping services provided by OKF of $46.16 per hour, as outlined in the reasons for decision attached as Appendix A to this order.

8.         Stargas is directed to recover the following number of hours for management services provided by OKF, as outlined in the reasons for decision attached as Appendix A to this order:

a)       Executive services                                            94

b)       Accounting services                                       102

c)       Bookkeeping services                                    226

d)       Administrative services                                 642

9.       Stargas is approved to establish a 2016 Delivery Rate Application Regulatory Account and to record the following costs related to this proceeding in this regulatory account, as outlined in the reasons for decision attached as Appendix A to this order:

a)       Legal counsel costs of $16,500;

b)       Stargas internal time of $13,853;

c)       Commission expenses; and

d)       Participant Assistance/Cost Awards.

The regulatory account is approved to accrue carrying costs based on Stargas’ weighted average cost of capital. Stargas is approved to use a rate rider to recover the balance in the regulatory account from customers over a three-year period. Recovery shall commence once final costs for Commission expenses and PACA have been recorded in the regulatory account and the rate rider and amended tariff pages have been reviewed and accepted by the Commission.

10.   The Commission deems, effective November 1, 2016, Stargas’ default capital structure shall consist of 57.5 percent debt and 42.5 percent common equity. Stargas’ return on equity shall be the Commission’s benchmark return on equity plus 75 basis points to be applied against Stargas’ mid-year rate base. Stargas’ return on debt shall be its weighted average cost of debt to be applied against Stargas’ mid-year rate base. In determining Stargas’ weighted average cost of debt, the interest rate on shareholder loans is approved at a 1 percent premium on the interest rate paid on Stargas’ operating line.

11.   Stargas is directed to refund a total of $6,000 to its current customers related to fiscal 2015 and 2016 preferred share dividend overpayments within 60 days from the date of this order by means of a one-time bill credit.

12.   Stargas is directed to file its next application for a delivery rate with the Commission by July 31, 2019.

13.   Stargas is directed to submit a compliance filing within 30 days from the date of this order and must include its supporting financial schedules for fiscal 2017 and amended tariff pages. Stargas is further directed to submit within 10 days from the date of finalizing the balance in the 2016 Delivery Rate Application Regulatory Account a compliance filing showing the calculation and breakdown of the 2016 Delivery Rate Application Regulatory Account Rider and amended tariff pages with the rate rider.

 

DATED at the City of Vancouver, in the Province of British Columbia, this     27^th        day of April 2017.

 

BY ORDER

Original signed by:

R. I. Mason

Commissioner

 

Attachment

 

 

 

 

 

 

IN THE MATTER OF

 

Stargas Utilities Ltd.

Application to Vary Delivery Rate, Amend Cost of Service Formula and Approve Replacement Term Financing/Redemption of Preferred Shares

 

REASONS FOR

DECISION

 

April 27, 2017

 

 

Before:

R. I. Mason, Commissioner/Panel Chair

D. M. Morton, Commissioner

 

 

 

 

 

 

Table of Contents

Page No.

 

1.0....... Introduction.. 3

1.1          The applicant. 3

1.2          Regulatory review process. 4

1.3          Purpose of utility regulation. 4

1.4          Approvals sought. 5

1.5          Issues arising. 6

2.0....... Determinations on approvals sought and issues arising.. 6

2.1          Hourly rate and hours for management services. 6

2.2          Regulatory and legal counsel costs. 14

2.3          Earned return. 16

2.3.1          Background. 16

2.3.2          Stargas proposal 16

2.4          Overpayment of preferred share dividends. 22

2.5          Presentation of accumulated unpaid dividends on preferred shares; 22

2.6          Customer connections policy. 23

2.7          Other tariff issues. 23

2.8          Succession planning. 24

2.9          Period of rate approval 25

3.0....... Revenue Requirement and delivery rate. 26

 

 

 

1.0               Introduction

On September 26, 2016, Stargas Utilities Ltd. (Stargas) filed an application with the British Columbia Utilities Commission (Commission) for, among other things, interim and permanent approval of a delivery rate decrease of $0.45 per gigajoule (GJ) from $7.38 per GJ to $6.93 per GJ for all customers pursuant to sections 59 to 61 of the Utilities Commission Act (UCA), effective November 1, 2016 (Application).[1]

 

Additionally, under section 50 of the UCA, Stargas sought approval to replace an existing term loan with an outstanding balance of approximately $200,000 as at May 31, 2016, with a $300,000 term loan at an interest rate of prime plus 1.25 percent (Replacement Financing), and to use Replacement Financing proceeds to redeem 1,000 Class G preferred shares with a par value of $100,000 (Preferred Share Redemption).[2]

 

During the proceeding, Stargas amended the delivery rate sought as a result of various changes to the Application requests made in response to Commission and intervener information requests (IR). As a result of these changes, Stargas’ final request seeks approval for a permanent rate decrease of $0.30 per GJ from $7.38 per GJ to $7.08 per GJ, effective November 1, 2016, for all customers based on a forecast 2017 revenue requirement of $290,902 and deliveries of 41,093.6 GJs for the fiscal year ended May 31, 2017.[3]

1.1               The applicant

Silver Star Mountain (Silver Star) is a year-round resort community located approximately 22 kilometers north-east of Vernon, B.C. Silver Star Mountain Resort Ltd. (Resort) is the primary developer of the resort and operates the ski hill and a number of other commercial operations within Silver Star. In 1999, Stargas was formed by the Resort to own and operate the natural gas distribution system at Silver Star. Stargas acquired the existing propane distribution grid from the Resort and converted it to natural gas. In addition, Stargas expanded the natural gas distribution grid to provide mains to substantially all of the resort property owners which were developed at that time.[4] By Order C-4-00 dated March 30, 2000, the Commission approved a Certificate of Public Convenience and Necessity (CPCN) for Stargas to operate a natural gas distribution system in the resort community of Silver Star. Order G-68-00 approved the transfer of 900 of the 1,000 Class A voting shares in Stargas to the shareholders of the Resort, comprised of Rundle Investments Ltd. (Rundle) and five other parties, effective July 13, 2000.

 

In November 2002, the Commission approved a transfer of shares in the ownership of Stargas, and an acquisition of Stargas by Rundle (50 percent) and CMI Holdings (1998) Inc. (CMI) (50 percent), a limited liability investment holding company owned by Mr. M. A. Blumes and his wife, Mrs. C. M. Iles-Blumes.[5] Subsequently, in August 2011, the Commission approved the transfer of Rundle’s 50 percent interest in Stargas to CMI; as a result, CMI became the sole owner of Stargas.[6]

 

FortisBC Alternate Energy Services Inc. (FAES), previously known as Terasen Energy Services Inc., provides services pertaining to the operation of the utility, including emergency standby and response, system maintenance, leak survey and remedial action, and meter servicing and replacement, as well as certain administrative functions under a ten-year contract expiring November 30, 2019.[7] Okanagan Funding Ltd. (OKF), a subsidiary of CMI, provides administrative and management services on an as-required basis at rates approved by the Commission.[8]

 

As at May 31, 2016, Stargas is a small utility with 287 customers and a rate base of less than $1 million.[9]

1.2               Regulatory review process

On October 6, 2016, Commission Order G-155-16 approved, on an interim and refundable basis, a delivery rate decrease of $0.45 per GJ for all customers, effective November 1, 2016, and established a regulatory timetable for a review of the Application, which provided for one round of IRs with further process to be determined.

 

On October 13, 2016, Silver Star Property Owners Association (SSPOA) registered as an intervener in the proceeding.

 

By letter dated November 29, 2016, Stargas sought advance approval from the Commission on matters relating to the Replacement Financing. By Order G-176-16, the Commission established a Streamlined Review Process (SRP) to be held on December 14, 2016, with further process to be determined. The SRP was held in Vancouver, BC with the Commission and Stargas’ gas consultant attending in-person, and Stargas and SSPOA participating by video conference.[10] Following the SRP, the Commission issued Order G-192-16 on December 16, 2016, approving the Replacement Financing (Approval 2) and Preferred Share Redemption (Approval 3).

 

By Order G-196-16 dated December 22, 2016, the Commission established the remainder of the review process for the Application, which included a second round of IRs and written final and reply arguments.

 

The Commission received letters of comment from Mr. D. Purser on December 22, 2016 and Mr. W. Gruenwald on January 28, 2017.

1.3               Purpose of utility regulation

The Panel finds Section 3.0 of the Hemlock Utility Services Ltd. (Hemlock) Revenue Requirements – Reconsideration of Order G-66-12, Decision dated October 1, 2013 (Hemlock Decision), describing the purpose of utility regulation and how it is applied in British Columbia, to be a succinct and relevant introduction to this decision. The section is therefore quoted in full below:

 

Utility Regulation has existed in North America for decades as a means to allow monopolies to serve customers in situations where economics dictates that the most efficient allocation of society’s scarce resources results from the use of a single service provider as opposed to more than one provider, which would be the case under free market competition.

 

It is the regulator’s function to prevent the abuse of monopoly power, so that customers have access to safe and adequate service at a fair price. At the same time, the utility is to be afforded the opportunity to earn a fair return on its investment so that it can continue to operate and attract the capital required to sustain and/or grow its business.

 

Thus, the regulator must balance the legitimate interests of both customers and investors (owners) by setting rates which are not unjust or unreasonable.

 

The Utilities Commission Act, RSBC 1996 c. 473 provides that “...a rate is “unjust” or “unreasonable” if the rate is

(a)     more than a fair and reasonable charge for service of the nature and quality provided by the utility,

(b)     insufficient to yield a fair and reasonable compensation for the service provided by the utility, or

(c)     unjust and unreasonable for any other reason.”

 

(ss. 59(5))

 

In British Columbia, rates charged by a utility are generally set based on the utility’s forecast cost required to provide service to its customers over a particular period of time, known as a “test period.” Forecast costs include a fair return on the shareholder’s invested capital or “rate base.” As costs are forecast, there is no guarantee the utility will earn a fair and reasonable return; rather, it is afforded the opportunity to do so. This form of regulation is known as “Return on Rate Base Regulation.” [11]

1.4               Approvals sought

Stargas applies for the following pursuant to sections 50, and 59 to 61 of the UCA:

 

1.         Approval of a permanent delivery rate decrease of $0.30 per GJ from $7.38 per GJ to $7.08 per GJ for all customers, effective November 1, 2016[12] (Approval 1);

2.         Approval to replace Stargas’ existing term loan with a $300,000 term loan at an interest rate of prime plus 1.25 percent[13] (Approval 2);

3.         Approval to redeem 1,000 Class G preferred shares with a par value of $100,000[14] (Approval 3);

4.         Approval to recover interest paid on shareholder advances at 1 percent above the interest rate paid on Stargas’ operating line[15] (Approval 4);

5.         Approval to recover interest paid on the portion of Approval 2 used to finance Approval 3 at a rate of prime plus 1.25 percent[16] (Approval 5);

6.         Approval to include $47,500 of regulatory and legal counsel costs in Stargas’ revenue requirement to be recovered from ratepayers one-third over each of the next three years, commencing in 2017[17] (Approval 6);

7.         Approval to amend the hourly rate charged for management services provided by OKF to the following (Approval 7):

•         Administrative services                       $46.16

•         Accounting services                              $69.24

•         Executive services                              $144.26[18]; and

8.         Approval to record the balance remaining on accumulated unpaid dividends on preferred shares relating to fiscal 2002 – 2006 as a deferred charge and component of equity on Stargas’ balance sheet, effective with Stargas’ May 31, 2017, annual report[19] (Approval 8).

1.5               Issues arising

During the course of the proceeding, a number of issues were identified through Commission and intervener IRs, and in some cases explored in the parties’ final and reply arguments which require further discussion and/or determinations. These issues are listed below:

•         The number of proposed management hours to be recovered from ratepayers;

•         Stargas’ capital structure and earned return;

•         An overpayment of preferred share dividends in fiscal 2015 and fiscal 2016;

•         Stargas’ customer connection policy

•         Various other tariff issues;

•         Stargas’ succession plan; and

•         The period of rate approval sought in this Application.

2.0               Determinations on approvals sought and issues arising

The structure of this section addresses each of the approvals sought and issues arising identified in the previous section of these reasons. Due to the interrelated nature of certain approvals sought with other issues arising, the Panel found combining interrelated items together as one topic of discussion to be efficient and will identify them where appropriate. The Panel ultimately addresses the approval of a permanent delivery rate in Section 3.0 of these reasons for decisions.

 

The Panel reiterates that the Commission provided advanced determinations for Stargas on Approvals 2 and 3 in Order G-192-16 dated December 16, 2016. As such, Approvals 2 and 3 are not addressed in this section.

2.1               Hourly rate and hours for management services

Stargas forecasts fiscal 2017 management fees of $78,173 payable to OKF for administrative, accounting and executive services (management services).[20] Stargas’ forecast is inclusive of the following:

•         A 4.9 percent increase to OKF hourly rates for management services (Approval 7), based on the change in the British Columbia Consumer Price Index (BC CPI) since hourly rates set in 2012. Stargas’ applied for hourly rates for management services are in Table 1 as follows:[21]

Table 1 – Hourly rates for management services

 

•         A budget of 1,115 hours for management services hours as provided in a detailed breakdown of management fees by activity and management role in the attached Attachment 1 to these reasons for decision and summarized by management role in the table below:[22]

 

Table 2 – Hours for management services

 

•         An additional 4 percent contingency on hours for management services to recognize “events of unforetold consequences leading to additional unplanned hours”, which represent a cost of $3,007.[23]

 

Intervener arguments

 

SSPOA objects to Stargas’ forecast fiscal 2017 management fees of $78,173, submitting that Stargas has “carved out tasks for its shareholder and their family members” at what SSPOA considers “inflated rates and volumes”. In SSPOA’s view “management fees should reflect the lower of Stargas’ cost to provide any given service, or a fair market rate where it is more reasonable to use third parties to provide a service.”[24] While SSPOA acknowledges the evidence provided by Stargas with respect to market rates for administrative, accounting and senior KPMG manager services in Vernon,[25] it asserts that the rates provided should not be treated as “independent, impartial evidence” as the associated correspondence “goes out of its way to mention Mr. [M. A.] Blumes’ previous KPMG affiliation.”[26] SSPOA also acknowledges OKF rates were approved by the Commission in 2005 and have subsequently been indexed by inflation; however, in SSPOA’s submission “the Commission should regularly review these rates and correct them if necessary.”[27]

 

Accordingly, SSPOA submits recent Commission decisions are “efficient and useful points of reference” and that the accounting and administrative services hourly rates the Commission should approve instead are the hourly rates approved in the Hemlock Decision and Order G-172-16 of the Superior Propane Rate Application for Seascapes Grid System (Superior Decision).[28] In the Hemlock Decision, the Commission approved an hourly rate of $35 per hour for “functions such as the preparation of GST/PST returns, bank reconciliations, and maintaining accounts payable records” which the Panel considered to be “bookkeeping” functions rather than “accounting” functions.[29] SSPOA submits that depending on the task, Stargas is paying either $46.26 or $69.24 per hour for the same work which the Hemlock Decision deemed worth $35 per hour.[30] The Superior Decision approved a clerical (Clerk 1) rate of $24.46 per hour to handle billing/pricing administration and a range of ancillary services such as setting up new meters, handling customer change of ownerships, and customer communication on pricing and other issues as they arise.[31] Stargas’ response to BCUC IR 16.2 stated:

 

 …the ‘administrative’ services identified in its Application are not the same as the duties and work identified in the [Superior Decision] as ‘clerical’. The clerical elements of Stargas’ monthly billing are handled by [FAES]… The administrative services… which are undertaken by Mr. Iles, include collections, customer queries and coordination of activities of meter exchanges, meter readers, [FAES] employees and consultants…[32]

 

SSPOA disagrees with Stargas’ submission on this issue, submitting that it “fails to see the distinction.”[33] Therefore, SSPOA submits the rates the Commission should approve are $35 per hour for bookkeeping work typically undertaken by Mr. Blumes and $24.46 per hour for billing work typically undertaken by Mr. Iles.[34]

 

SSPOA “does not oppose” an accounting services rate of $69.24 per hour as requested “for actual accounting tasks, such as preparing annual financial statements”, or an executive services rate as applied for “for actual executive-level tasks.”[35]

 

Finally, SSPOA submits its concern related to the volume of fiscal 2017 forecasted management service hours compared to the volume of hours approved for Hemlock. SSPOA makes a number of comparisons between the two utilities[36] and submits for Commission consideration proposed volumes of hours for certain management tasks[37] and an aggregate number of hours for each of “administrative other than accounting”, “billing administration”, “bookkeeping”, “accounting”, and “executive” tasks.[38]

 

Stargas reply argument

 

Stargas responds to SSPOA’s comment regarding the market rates provided and submits that the “SSPOA is completely incorrect in its assertion that [the correspondence is anything] other than ‘unbiased’.” Stargas explains that SSPOA’s issue with the correspondence is actually evidence provided by Stargas and is not contained in the correspondence; therefore, Stargas submits that the Commission must “disregard the SSPOA’s assertion that the evidence provided by Stargas of KPMG rates is unreliable.” Furthermore, Stargas submits the information it has provided “is the only evidence on the record regarding market rates, as the SSPOA has provided none.”[39]

 

Stargas disagrees with SSPOA’s proposal to approve a $35 per hour bookkeeping rate and $24.46 per hour billing rate and provides a number of reasons relating to the interpretation of the management services provided and other considerations such as inflation.[40] Stargas submits instead that a continued utilization of the rates approved in 2005 adjusted only for inflation is a “reasonable, efficient and light-handed approach to setting rates for a small utility.” [41]

 

Finally, Stargas disagrees with the issues raised by SSPOA concerning the volume of forecasted fiscal 2017 management service hours, and its proposed hours for specific management tasks and for an aggregate number of hours. Stargas provides several reasons contesting the comparability and comparison of Hemlock to Stargas[42] and provides further arguments to support its budgeted hours for the management tasks raised by SSPOA including, marketing, resort interfacing, gas price investigation and monitoring, and annual report preparation.[43]

 

Commission determination

 

This section addresses Approval 7 and other related issues that arose during the course of this proceeding.

 

The Panel notes that OKF, the company providing management services to Stargas, is a related party to Stargas through common ownership. As the Commission noted on page 5 of the Hemlock Decision:

 

It is not unusual for regulated utilities to be part of larger organizations and, in such cases, the regulated utility may purchase and sell goods and services to and from other parts of the organization which are not regulated. However, non-arm’s length (related party) transactions can be subject to abuse, if the transfer price is too high or too low. Therefore, the Commission scrutinizes related party transactions to ensure that regulated operations pay no more than a fair price for goods or services received from a related party and receive at least fair compensation for goods or services provided to a related party.[44]

 

This Panel has considered the hourly management rates and management fees applied for by Stargas in this light, and considers that it is the role of the Commission to ensure that Stargas pays only a fair price for the management services provided by OKF. In this proceeding, the management services rates (the transfer price referred to in the Hemlock Decision) and the estimated hours of work required are both relevant, since together they determine the amount sought by Stargas from ratepayers.

 

For an overall sense of whether the proposed management fees are fair, the Panel has considered the analogy proposed by SSPOA between Stargas and Hemlock.[45] Stargas, serving 287 customers, is similar in size to Hemlock, who serves approximately 250 customers.[46] While Hemlock operates an electric service and Stargas natural gas, the management functions of the two are similar in nature and scale. So while the Panel has not relied on the Hemlock Decision in its deliberations, it does consider the analogy with Hemlock to be instructive.

 

The Panel agrees with Stargas that the comparable amount the Commission approved in the Hemlock Decision related to management fees was $53,200 in fiscal year 2012.[47] However, for Stargas to be applying for $78,173 in management fees for a similarly-sized operation is a cause for concern, and in the view of the Panel, justifies a detailed examination of the components of the proposed expenses.

 

The Panel agrees with Stargas that the FortisBC Energy Inc. delivery rate is not an appropriate basis for determining administrative costs.[48] The size and scale of the two operations is so dissimilar as to defy meaningful comparison.

 

Notwithstanding these various possible analogies, the Panel has determined that the management fees shall be based on what it considers to be reasonable estimates of specific costs for Stargas to manage its business.

 

Management services rates

 

The Panel finds that rates of $144.26 per hour for executive time and $69.24 per hour for accounting time as proposed by Stargas are reasonable. SSPOA does not object to these hourly rates.[49]

 

Stargas has applied for a rate of $46.16 per hour for administrative services. The Panel rejects this rate for administrative services. The range of responsibilities included in administrative services shown in Attachment 1 to these reasons for decision is too broad to be covered by one rate and ensure a fair rate for ratepayers. Rather, the Panel agrees with the Hemlock Decision that bookkeeping work, consisting of tasks such as maintaining accounting records and performing bank reconciliations,[50] requires a greater level of skill than other duties Stargas considers administrative, such as updating credit card information and emailing bills to customers.[51] Thus, the Panel finds that separate rates are required for bookkeeping and for administrative services.

 

The Panel sets a rate of $46.16 per hour for bookkeeping services. The Panel notes SSPOA’s comparison between Stargas and Hemlock, which was awarded $35 per hour for bookkeeping services in 2013. Inflated to today’s prices, this would be equivalent to a rate of $36.72 per hour.[52] While the Panel agrees that the bookkeeping duties performed for Hemlock are similar in nature to those of Stargas, it concludes that the difference between $46.16 and $36.72 when applied solely to bookkeeping tasks and not to all administrative tasks does not make a sufficient difference to the total management fees to merit a more detailed investigation of the differences in duties performed.

 

The Panel sets a rate of $24.46 per hour for administrative services. This rate was approved by the Commission for billing/pricing administration and auxiliary services tasks performed by Superior Propane, which the Panel considers virtually identical to the majority of the tasks involved in administration at Stargas. In its response to BCUC IR 16.1, the Panel agrees with SSPOA and finds that Stargas provides no compelling reason as to why its administrative tasks are different to the Clerk 1 (clerical) tasks of Superior. The possibility that Mr. Iles, who performs these administrative tasks, has a “broad and valuable understanding of Stargas’ operations” or that he receives and responds to customers inquiries “at odd hours” does not mean that his time should be paid for at a higher rate than the tasks themselves deserve.

 

Management services hours

 

The Panel now turns to the question of the number of hours of management services. Since OKF, the company providing the management services, has a non-arm’s length relationship with Stargas, the Panel has critically considered the management hours applied for and their value to Stargas ratepayers.

 

Overall, the Panel does not find that the total management time estimated by Stargas, 1,115 hours, to be excessive. For example, the Commission approved 70 percent of a staff person for Hemlock, which might account for 1,176 hours.[53] However, the allocation of time between executive, accounting, bookkeeping and administrative tasks bears examination.

 

Further, the Panel rejects the assertion by SSPOA that management fees forecast is not based on specific task estimates,[54] since such an analysis was provided by Stargas in response to BCUC IR 15.1 (Exhibit B-13).

 

Stargas has applied for 171 hours of executive time. This is broken down in Table 3 as follows:

 

Table 3 – Executive time requested

 

The Panel finds that 12 hours for review and supervision of monthly duties and 10 hours for a credit review are appropriate, given the size of the organization.

 

However, the Panel considers that to the extent the 55 executive hours spent on marketing applies to new customer marketing, it does not necessarily provide value to the existing customers unless new customers are added, in which case, there may be an economies of scale benefit. As Stargas noted in the SRP, they have been “singularly unsuccessful” in winning new customers from those homes which are currently using propane, and they “would not be pursuing conversions with time and money, as we had in the past.”[55] However, there is value in ensuring good relationships with existing customers, which in a small utility such as Stargas the executive may play a meaningful role. The Panel finds that 24 hours per year is adequate for maintaining relationships with existing customers, and approves only those hours for executive time.

 

Stargas suggests that in future it may consider a policy whereby it would fund new customer connections, and thus make it more attractive for homes to switch from propane to natural gas provided by Stargas. [56] At that time, the Panel suggests that Stargas apply to the Commission for a corresponding amount of marketing budget, demonstrating the expected financial returns to the existing customers from the marketing investment.

 

The Panel agrees with SSPOA in that it considers 35 hours of executive time for gas price investigation and monitoring to be excessive, given that Stargas already compensates Mr. Ken Fuhr for providing these services. However, the Panel rejects SSPOA’s suggestion of 5 hours per year as being inadequate to maintain a working relationship with Mr. Fuhr.[57] The Panel finds that 24 hours per year is sufficient for the executive time to supervise this task.

 

The Panel agrees with SSPOA that a healthy relationship ought to exist between Stargas and the Resort. The Panel finds SSPOA’s suggestion of 6 hours[58] would not be sufficient considering the travel time for even one visit to Silver Star for Mr. M. A. Blumes,[59] thus the Panel rejects this figure as insufficient. Allowing for travel time for even one visit per year, plus other ongoing contact, 16 hours per year appears reasonable and the Panel approves 16 hours of executive time for this purpose.

 

The Panel disagrees with Stargas that approximately half of the production of the annual report is an executive task,[60] and considers that the financial statement preparation and drafting of the report are more properly classified as accounting tasks. The Panel agrees that there is an executive role in overseeing the creation of the annual report, but considers that the 17 hours proposed by Stargas is excessive to review and edit work that takes 26 hours to create,[61] especially given the “boilerplate” nature of the report, as SSPOA put it.[62] However, the Panel considers that the total of 20 hours, comprised of executive and accounting time, suggested by SSPOA[63] is insufficient to ensure the accuracy and quality of the annual report. The Panel approves 8 hours of executive time for the “review and edit” activity, but rejects the 26 hours for other executive tasks related to the annual report.

 

In summary, the Panel approves the following 94 executive hours (Table 4):

 

Table 4 – Executive time approved

 

Stargas has applied for 302 hours of accounting time, as follows in Table 5:

 

Table 5 – Accounting time requested

 

The Panel considers the tasks listed under “monthly routines” in Stargas’ detailed breakdown of management fees to be bookkeeping tasks, with the exception of the month-end financials. The Panel therefore accepts 36 hours of accounting time for the monthly routines.

 

The Panel accepts the accounting role in the preparation of the annual report. In addition to the 40 hours of accounting time applied for, the Panel considers that the 26 hours of executive time denied for preparation of the annual report should be included, and thus finds 66 hours of accounting time acceptable for the annual report.

 

In summary, the Panel approves the following 102 accounting hours:

 

Table 6 – Accounting time approved

 

As discussed above, the Panel considers that many management activities proposed by Stargas appear to be bookkeeping tasks. The Panel finds that the following 226 hours proposed by Stargas are bookkeeping (Table 7):

 

Table 7 – Bookkeeping time approved

 

Finally, the Panel approves the 642 hours applied for as administration, on the ground that the total effort to manage Stargas is not dissimilar to that approved to manage Hemlock.

 

Contingency

 

Finally, the Panel has considered the matter of the 4 percent contingency applied for on hours for management services. The Panel denies the request for a contingency. All utilities provide forecasts to the best of their abilities and this is the basis of all cost of services or cost-based rate setting mechanisms under regulatory oversight. Thus, it is uncommon for the Commission to approve contingencies for costs that are well within management control or management’s ability to forecast. The Panel notes that if Stargas experiences adverse events that incur costs it believes should be recoverable from ratepayers, it may submit a further application for these specific costs.

 

Summary

 

In consideration of the Commission’s determinations outlined above, the Panel approves the following hours and rates as management fees (Table 8):

 

Table 8 – Approved management fees

 

2.2               Regulatory and legal counsel costs

Stargas forecasts the regulatory and legal counsel costs related to this proceeding to be $47,500 which it proposes to recover evenly from ratepayers over three years, commencing in 2017,[64] which equates to $15,833 in each year. Stargas’ forecast is based on actual costs incurred to-date plus an estimate for future costs to be incurred through the remainder of the regulatory timetable relating to: (i) internal time; (ii) legal time, (iii) reimbursement of Commission (BCUC) expenses; and (iv) payment of SSPOA Participant Assistant/Cost Awards (PACA), if any, as shown in the table provided by Stargas below.[65]

 

Table 9 – Application regulatory and legal costs

 

Stargas submits that these costs are “an integral and legitimate cost” of the provision of utility services and ought to be recoverable through rates.[66]

 

Intervener arguments

 

SSPOA, a non-profit society representing the interests of the property owners of Silver Star and the only registered intervener in this proceeding, makes several assertions in its final argument regarding the conduct and quality of submissions from Stargas and how these have contributed to the regulatory and legal counsel costs of this proceeding. Accordingly, SSPOA submits the costs are “disproportionate to the benefits claimed” and recommends the Commission approve a delivery rate recovery of $8,655 of regulatory costs and $9,000 of legal counsel costs, based on 60 hours of application time at the executive rate and 50 percent Stargas’ legal counsel estimate. SSPOA submits 60 hours at the executive rate is “nearly a 50% increase over the cost of the last delivery rate application” and in its view, “it would be unreasonable to recover a larger proportion of the time spent” by management in preparing the Application.[67]

 

Stargas reply argument

 

Stargas disagrees with SSPOA’s proposal to recover 60 hours of executive time and $9,000 of legal costs for the following reasons:

•         Stargas considers the regulatory timetable, complexity, and level of participation in this proceeding to be “unlike” the last delivery rate application;

•         Stargas considers SSPOA’s assertions regarding the conduct of Stargas to be unsubstantiated; and

•         Stargas’ forecast for legal counsel costs is at rates in accordance with the Commission’s PACA guidelines.[68]

 

Stargas “rejects the suggestion that any of its prudently and reasonably incurred costs” should be disallowed and submits:

 

Given the escalating costs, as well as significant reduction to forecast sought by the SSPOA, Stargas submits that its original proposal that regulatory costs, including the cost of legal counsel, be subject to a true up process is the most reasonable course of action to assess the quantum of costs that ought to be included in Stargas’ revenue requirement. To facilitate this review, Stargas proposes upon receipt of its final costs to file with the Commission a summary with detail of its Application costs for review and approval for inclusion in rates and would propose to bear its own costs in such [a] review process.[69]

 

Commission determination

 

The Panel accepts the Stargas estimate of $16,500 in legal counsel costs. This has been a more complex proceeding than might be expected for a utility of this size, and Stargas’s legal counsel has provided value to the submissions. The Panel disagrees with SSPOA that 50 percent of the applied-for costs would be reasonable, finding that this estimate has no justification.

 

The Panel has sympathy with SSPOA regarding the reasonableness of the estimate of $18,470 for regulatory costs incurred by Stargas. The proceeding has been complex, as already noted; however, the Panel agrees with SSPOA that Stargas has submitted material not directly relevant to the proceeding, and repeatedly changed and corrected its submissions.[70] For these reasons, the Panel finds that only 75 percent of the management effort for regulatory costs should be bourne by ratepayers and accepts $13,853 as an appropriate figure for Stargas’ internal time for the preparation of this Application and participation in the proceeding.

 

SSPOA has not commented on the recovery of BCUC expenses or SSPOA PACA costs. Based on the evidence in this proceeding, the Panel finds no reason to object to the recovery of these costs from ratepayers and approves them in principle.

 

For the aforementioned reasons, the Panel approves the establishment of a 2016 Delivery Rate Application Regulatory Account to record each of the above noted costs, if any, related to this proceeding and the regulatory account is approved to accrue carrying costs based on Stargas’ weighted average cost of capital.[71] The Panel directs that the balance in the regulatory account is to be recovered from ratepayers as a rate rider over a three-year period. Recovery shall commence once final costs for Commission expenses and PACA have been recorded in the regulatory account and the rate rider and amended tariff pages have been reviewed and accepted by the Commission.

2.3               Earned return

2.3.1          Background

In 2002, the Commission approved for Stargas the issuance of $400,000 of cumulative preferred shares, and established that the deferred dividend rate on the preferred shares be calculated using the Commission’s benchmark return on equity (ROE) plus 75 basis points.[72] In 2006, the Commission stated Stargas’ shareholders are allowed to earn a return on the preferred shares and directed Stargas to pay a dividend on its outstanding cumulative preferred shares at a rate of 9.55 percent (the 2006 benchmark return on equity of 8.80 percent plus 75 basis points) in fiscal 2007 in order to provide a return to its shareholders.[73] In 2012, the Commission approved the inclusion of forecast preferred share dividends of $41,000 in Stargas’ fiscal 2013 revenue requirement, having considered the points outlined below:

 

•         Stargas submitted that they intend to continue this rate setting mechanism in future applications to the Commission, stating it “has and would continue to provide a reasonable surrogate for returns that would have been generated in the conventional model”;

•         Stargas’ 2002 and 2006 history with respect to the Commission’s approval for the issuance of $400,000 of cumulative preferred shares and determination on an allowed return on preferred shares; and

•         Including the forecast preferred share dividends of $41,000 in the fiscal 2013 revenue requirement as compared to an equity and debt return on Stargas’ rate base does not result in a higher delivery component of rates.[74]

2.3.2          Stargas proposal

In the Application Stargas forecasts fiscal 2017 preferred share dividends in the amount of $28,500 which are paid on $300,000 of cumulative outstanding preferred shares at the Commission’s current benchmark rate of return of 8.5 percent plus 75 basis points or 9.5 percent. Stargas submitted its Application is based on Commission approval of Stargas’ Preferred Share Redemption request (Approval 3) and assumes the annual dividend “as if the [Preferred Share Redemption] were to have occurred on June 1, 2016.” Stargas elected to do so acknowledging that otherwise including the actual amount of preferred share dividends paid in fiscal 2017 would result in “an overstatement of that element” in its revenue requirement in subsequent years.[75]

 

In addition, Stargas seeks Commission approval (Approval 5 noted in Section 1.2 of these reasons for decision) to recover interest paid on a specific portion of Replacement Financing proceeds at a rate of prime plus 1.25 percent. On this matter, Stargas forecasts fiscal 2017 interest of $3,910 to be recovered from ratepayers.[76]

 

Finally, in Approval 4 noted in Section 1.2 of these reasons for decision, Stargas seeks Commission approval to recover interest paid on shareholder advances at a rate of 1 percent above the interest rate paid on its operating line. Stargas stated during the SRP that this rate is currently 4.5 percent (on a 3.5 percent operating line).[77] Therefore, Stargas forecasts fiscal 2017 interest to be $1,800 related to this request.[78] Stargas submits interest paid on shareholder advances is recoverable through rates on the basis that the shareholders’ advances “are necessary to meet cash flow requirements in the shoulder season/analogous to the included interest incurred on our operating line.”[79] Stargas submits a return of “1 percent greater than that charged on its operating line” is equitable given that shareholder advances are “subordinated to the bank’s interest.”[80]

 

During the proceeding, Stargas provided its forecast mid-year rate base and capital structure for fiscal 2017 and information on its debt costs in the following tables:[81]

 

Table 10 – Fiscal 2017 forecast mid-year rate base

 

 

Table 11 – Fiscal 2017 forecast mid-year capital structure

 

Table 12 – Fiscal 2017 debt costs

 

That being stated, Stargas’ Application request is for approval of a return of $32,410 (calculated as $28,500 in dividends on $300,000 preferred shares plus $3,910 in interest certain Replacement Financing proceeds), stating:

 

…[its] return on long term debt and equity $32,410 ($28,500 and $3,910) is not materially different than a calculated return using a more conventional mechanism of a deemed debt and equity return on rate base. At a 42.5% equity/57.5% debt ratio, on [forecast mid-year] rate base of $502,928, the equivalent return is $31,729 ($213,744 [mid-year common equity] @ 9.5% plus $289,184 [mid-year long term debt] @ 3.95%).[82]

 

Stargas identifies its proposal “while unconventional, is in accordance with the Commissions’ prior orders G 80-02 and G 163-06, reflects a reduction in delivery rate equivalent to conventional methods and continues to afford Stargas investors a reasonable return on their invested capital.”[83]

 

Intervener arguments

 

SSPOA does not oppose fairly compensating shareholders for the cost of advancing capital to the utility, but submits “the 1% premium seems high, and is inconsistent with the 0.75% the Commission has consistently applied to other shareholder equity advanced to [Stargas] (the preferred shares).” Accordingly, the SSPOA submits a premium of 0.75 percent should be applied instead of 1 percent.[84]

 

However, SSPOA does submits its concern that Stargas’ current methodology of calculating a fair investor return is “idiosyncratic and unduly complicated” and submits it should be replaced with “something standardized that minimizes the regulatory burden on the Commision and customers:”[85]

 

Understanding where Stargas shareholders invested funds and the extent to which the payment of debt principal through amortization provides a return of capital is unusually complex. Understanding the fairness of Stargas’ return on capital is also complicated as the shareholders’ return does not decline as the associated capital assets are amortized. The same is true of understanding which interest costs are included in the cost of service. The utility is small and the time cost of processing its applications high, making the costs of the status quo methodology disproportionate of the benefits, if any, of retaining it.[86]

 

SSPOA notes paragraphs 16 and 17 of Stargas’ Final Argument state that moving to a deemed debt/equity ratio of 42.5 percent equity would produce an investor return comparable to the status quo and is reasonably close to Stargas’ actual capital structure.[87] Thus, SSPOA recommends the Commission replace the current methodology of calculating the investors’ earned return as doing so appears to be relatively fair to Stargas’ shareholders, and supports “the suggestion in BCUC IRs of applying the BCUC’s standard 42.5% equity ratio for small utilities.”[88]

 

SSPOA did not address the issue of Approval 5 in its final argument.

 

Stargas reply argument

 

Stargas does not agree with SSPOA regarding the proposed rate of interest on shareholder advances. Stargas submits: “it accepted a reduction in its current 6% [interest rate on shareholder advances], based on it being provided a meaningful premium over the cost of funds provided in its operating financing. It is usual for secondary and postponed debt (where the bank must approve any reduction in these advances) that the provider be allowed a premium over the bank rate.”[89]

 

In addition, Stargas does not agree with SSPOA’s recommendation to move Stargas to a conventional earned return model for several reasons relating to Stargas’ historical operating performance and the determinations of past Commission orders.[90] Stargas submits it has “struck an equitable balance” between its “unusual” history and the conventional model, and it would be “folly to entertain changes that would be necessary” to revert Stargas to a conventional rate setting basis.[91]

 

Commission determination

 

The Commission sets rates under sections 59 to 60 of the UCA to allow utilities to recover approved costs and to allow utilities the opportunity, but not the guarantee, of a return on invested capital. Investors in utilities risk their capital, and if the utility makes a higher or lower return than that allowed by the Commission, investors do correspondingly better or worse. The Commission considers a rate is just and reasonable if it allows utilities to recover a fair and reasonable return on capital invested in assets serving ratepayers; in general, capital raised by the utility but not invested for approved purposes does not earn a return from ratepayers. Related to the matter of the return on capital is the return of capital. The Commission, after review, approves the inclusion of depreciation of invested capital it considers necessary and reasonable in rates. By this method, ratepayers return to the utility over time the amount of capital the utility has invested to serve those ratepayers in the form of depreciation expense in the revenue requirement. It is the decision of management whether or not the returned invested capital, received by the utility from ratepayers, is then returned to investors or applied to other uses. If a utility chooses to retain its returned invested capital and does not invest it to serve ratepayers, then investors may not earn a return on that capital.

 

To provide a utility the opportunity to earn a fair return, the Commission has provided a deemed capital structure for regulated utilities. Thus, a utility is considered by the Commission to be funded by a particular ratio of equity and debt and is allowed to earn deemed rates of return on both its deemed equity and debt. If a utility differs from the ratio deemed by the Commission, or pays more or less for its equity or debt than the deemed return, ratepayers are not affected.

 

The Panel is aware of previous Commission decisions regarding Stargas’ return on investors’ capital, and what Stargas refers to as the “unconventional” approach taken in the past. Whatever the possible merits of these previous decisions, the Panel agrees with SSPOA that it is preferable to use methods which minimize the regulatory burden and improve transparency. In addition, the Panel agrees with Stargas’ submission that its proposed return on invested capital in fiscal 2017 is “not materially different” than if it had been calculated using a more “conventional mechanism.” [92] Therefore, the Panel considers that this is an appropriate time to consider a transition to such a conventional mechanism, since the similarity in amounts reduces the need to make special considerations for Stargas or its ratepayers. The Panel considers that using a conventional method of calculating Stargas’ return on capital will be more transparent, efficient, and easier for all parties to understand. In future applications, the mechanism will adjust the return on capital with the declining balance of capital invested without the need to consider yet more unconventional methods to simulate a fair return for the investor. The remaining unamortized capital invested in assets serving ratepayers will be recovered from those ratepayers and returned to Stargas.

 

Regarding Stargas’ submission that a conventional earned return model is not available without addressing its outstanding preferred shares and the dividends thereon,[93] the Panel finds that the choice of what types of financing a utility will use is the responsibility of management, subject to approval by the Commission under section 50 of the UCA. The test the Commission uses in approving the issue of securities is whether the issuance is “necessary or desirable in the public interest.”[94] Therefore, the Panel disagrees with Stargas’ submission that a proposal to move to a conventional method of calculating a return on capital needs to address how Stargas would redeem its preferred shares.[95] The mix of different forms of debt and equity to finance a utility is the decision of that utility. Stargas chose to issue preferred shares rather than common equity, for instance. Stargas is free, subject to approval under section 50 of the UCA, to issue other forms of debt and equity in order to fund the redemption of its preferred shares. This Panel, in Order G-192-16, approved exactly such a transaction when Stargas applied to raise capital via a term loan to fund the redemption of $100,000 of its outstanding preferred shares.

 

Stargas does not comment on the differences that might occur in future years as a result of adopting a conventional mechanism, but SSPOA notes that the current method produces a constant return to Stargas, “unaffected by the declining net book value of its capital assets.” [96] This is a concern to the Panel, since, unaddressed, it raises the risk of ratepayers overcompensating Stargas in future years compared to what the Commission would determine to be a fair return on capital. During the SRP, Stargas agreed that: (i) over time, as a utility collects amortization from its customers, the value of its rate base decreases; and (ii) over time, the return that a utility collects from its customers should decrease as its rate base decreases.[97]

 

As noted above, Stargas is a small utility with a rate base of less than $1 million. In the Panel’s view, the deemed capital structure for a utility of this size should align with the deemed capital structure of other similarly-sized utilities with respect to rate base and number of customers served. One recent example is from the Superior Decision, the Commission set a capital structure of 57.5 percent debt and 42.5 percent equity for Superior.[98] Superior has a capital rate base of approximately $266,000, and serves a 100 townhome development.[99] Based on these attributes, the Panel finds Superior is an appropriate comparable in size to Stargas.

 

Finally, the Panel recognizes in 2012, considering that no return on equity was included in Stargas’ revenue requirement from fiscal 2002 to fiscal 2006, the Commission approved the amortization of accumulated unpaid dividends of $135,887 relating to those years into Stargas’ revenue requirement over a period of twenty years, and directed Stargas to declare and pay $6,794 in cumulative preferred share dividends in each fiscal year commencing in fiscal 2013.[100] Since the preferred share dividend was the proxy for its return on capital, Stargas omitted to include a return on capital in its rate calculation for the fiscal 2002 to 2006 periods. As such, this Panel notes that the amount of $6,794 included in Stargas’ Application revenue requirement does not relate to a return on capital in fiscal 2017. Further, since the remaining unamortized balance of deferred dividends will only be fully recovered by 2033, it is appropriate that $6,794 annually continues to be recovered from ratepayers for the period fiscal 2017 to 2019.

 

For these reasons, the Panel finds that Stargas’ earned return, effective November 1, 2016, shall be calculated on a conventional basis, as set forth below, and rejects Stargas’ application relating to changes to its revenue requirement with respect to interest on shareholder advances [Approval 4 referenced in Section 1.2] and interest on the portion of the Replacement Financing used to fund the Preferred Share Redemption [Approval 5 referenced in Section 1.2]. Specifically, the Panel rejects the following amounts in the fiscal 2017 revenue requirement: the annual dividend ($28,500), the interest payable to shareholders ($1,800), and the interest on term debt ($3,910). In their stead, the Panel calculates Stargas’ return on capital as follows.

 

The Panel finds that a deemed capital structure of 57.5 percent debt and 42.5 percent equity, and ROE of the Commission’s benchmark cost of capital plus 75 basis points, are appropriate for Stargas. The Panel notes the Commission recently issued Order G-129-16 dated August 10, 2016, which maintained the rate of return on equity for the benchmark utility at 8.75 percent. Therefore, Stargas’ ROE for fiscal 2017 shall be 9.5 percent, calculated as 8.75 percent plus 75 basis points.

 

The Panel calculates Stargas’ fiscal 2017 weighted-average cost of debt (WACD) to be 4.0 percent, based on the following:

 

Table 14 – WACD calculation

 

The Panel agrees with Stargas and accepts a 1 percent premium over its operating line is an appropriate return on its shareholder loans. The Panel rejects the 75 basis point premium suggested by SSPOA[103] as being not materially different.

 

The Panel thus finds that the deemed return on debt for Stargas is $11,567[104] and the deemed return on equity is $20,306[105], for a total return of $31,873[106] for the 2017 fiscal year. The Panel notes that this is not dissimilar to the $32,410 requested by Stargas in its final submission.[107]

2.4               Overpayment of preferred share dividends

During the proceeding, Stargas acknowledges that it calculated its return on preferred shares incorrectly in two prior fiscal years. Specifically, Stargas erroneously used a rate of 10.25 percent instead of 9.5 percent when calculating dividends on $400,000 of preferred shares in fiscal 2015 and 2016. [108] The total overpayment is therefore $6,000.[109]

 

SSPOA submits in its final argument that the overpayment of dividends in fiscal 2015 and 2016 “must be refunded or otherwise accounted for going forward.”[110]

 

Commission determination

 

The Panel agrees with SSPOA and directs Stargas to refund a total of $6,000 to its current customers within 60 days from the date of this order by means of a one-time bill credit. For additional clarity, this amount has no bearing on the current year’s earned return calculation. Since the dividend on preferred shares was used in past fiscal years as a proxy for Stargas’ return on capital, this overpayment has also been over collected from ratepayers.

2.5               Presentation of accumulated unpaid dividends on preferred shares;

As stated above, in 2002 the Commission approved the issuance of $400,000 of cumulative preferred shares with a dividend rate equal to the Commission’s annual benchmark return on equity plus 75 basis points.[111] In 2012, the Commission approved the amortization of accumulated unpaid dividends on these preferred shares of $135,887 related to fiscals 2002 to fiscal 2006, commencing in fiscal 2013.[112]

 

Stargas requests approval to “effective with our May 31, 2017 annual report, record the balance remaining as a deferred charge and component of equity within our balance sheet rather than by supplementary note disclosure”[113] (Approval 8).

 

Stargas stated as of May 31, 2016, $108,711 of the original $135,887 remains to be paid.[114] When asked in the SRP whether the request is in accordance with Canadian accounting standards for private enterprises, Stargas responded as follows:

 

[Stargas has] reviewed this accounting with our account partner at KPMG, and have their concurrence that it would be in accordance with accounting practice. It merely is putting on the face of the balance sheet that which otherwise appears buried in the notes to the financial statements. Again, I think it’s largely a disclosure of some consequent, and useful to the reader… of our financial statement. But I think in the interest of both fair and plain disclosure, it’s better on the face of the balance sheet than hidden or less obvious in a note to the financial statements.[115]

 

Panel discussion

 

The Panel declines to take the action sought by Stargas in its request to record the balance remaining on accumulated unpaid dividends as a deferred charge and component of equity [this addresses Approval 8 referenced in Section 1.2 of these reasons for decision]. The Panel finds that the approval sought pertains to management’s accounting policies, and is therefore not within the scope of the Commission’s legislative authority under the UCA.

2.6               Customer connections policy

In its final argument, SSPOA requests the Commission consider an issue related to Stargas’ new customer connection fees, requesting that the Commission “direct Stargas to reduce the level of customer contribution required to install a new meter, to reduce the financial disincentive for new customers to sign up.”[116] SSPOA submits “Stargas’ policies require a 100 [percent] customer contribution for a new customer meter, at about $1,700, as well as a 10 [percent] mark-up,” and that new customers will only “break even” after 1.5 – 2.5 years of steady use.[117] In SSPOA’s view, these policies “contrast with the common utility practice of ‘rolling’ in some or all of new capital additions into rate base,” noting the customer connection charge for FortisBC Energy Inc. is $25. SSPOA submits a change in Stargas’ policies in this matter will help grow the utility, promote fuel-switching towards natural gas, and spread management costs over more customers.[118]

 

Stargas responds to SSPOA in its reply argument stating it is “not opposed to implementing a policy for new connections that would have the utility fund the costs of new connections with capital costs included in rate base, up to a maximum investment level, with installation costs in excess of that level paid by the new customer.”[119] Stargas submits that it “will make application to the Commission to accommodate any tariff or rate amendments necessary in this regards” in advance of the coming construction season.[120]

 

Panel discussion

 

While the Panel is sympathetic to the issues raised by SSPOA regarding Stargas’ current policy, customer connection fees are outside the scope of a delivery rate application proceeding. In addition, the current evidence is not sufficiently complete to direct Stargas to reduce the level of customer contribution required to install a new meter to any specific amount. 

 

However, the Panel notes Stargas’ statement that it is not opposed to revising its customer connections policy for new connections and that it will make an application to the Commission. The Panel encourages Stargas to file the proposed application with further process to be initiated at that time.

2.7               Other tariff issues

In its final argument, SSPOA states “there is confusion about whether Stargas can charge customers fees that are not included in its tariff”, noting the following:

 

•         A 2005-era 10 percent mark-up fee on installation costs, which Stargas charges that “was not specifically included in Order G-93-09, and its removal accompanied a material increase in installation costs in the 2009 Order”;

•         A $300 charge Stargas “levied for a ‘manifold’ [which] comes from a superseded tariff; and

•         A “practice of assigning rental residential suites into the ‘commercial’ rate class so as to charge PST, and changing the basic charge from $15 per month to $25 per month, as a result.”[121]

SSPOA submits the Commission should “make clear to Stargas that items that are not authorized by the tariff should not be charged, and should issue refunds for things like unauthorized $300 manifold charges.”[122] In addition, SSPOA submits “[r]ental status does not drive consumption patterns or other factors that determine cost allocation. A new separate rate class to facilitate tax remittance may make sense, but increasing the basic charge by 67 [percent] absent a change in cost causation does not. There may be other remittance compliance options available too. ” SSPOA recommends the Commission “direct Stargas to consider the associated administrative cost and proceed with the lowest cost solution for customers” with respect to this matter. [123]

 

Stargas reply argument

 

Stargas submits the following in response to SSPOA:

 

•         The 10 percent mark-up fee on installation costs “is and continues to be a permitted fee as ruled on by the Commission in Order G-118-05”;

•         Stargas has, consistent with the balance of installation costs charged by FAES, “the right to collect same from the customer, or to, under a revised program, defer and amortize these costs over time.” However, Stargas “will respond to the issue of installation costs as a barrier to customer acquisition and, in doing so, redress the manifold issue”; and

•         Stargas is “neutral” to the issue raised with respect to reclassification of residential customers to commercial since “the revenue derived in basic charges [is] credited to cost of service” but submits management “did provide customers the opportunity to avoid the reclassification and charging of PST, with the corresponding higher monthly basic charge, during the period following the assessment.” [124]

 

Panel discussion

 

The Panel declines to take any action on the requests made by SSPOA and makes no determinations. The Panel agrees with Stargas that Order G-118-05 specifically approved the 10 percent administrative fee on the installation of new services added to the schedule of rates and charges, applying to all applications for new service, effective December 1, 2005. The Panel also agrees with the positions taken by Stargas in its reply argument relating to the manifold charge. Finally, the Panel finds that the issue of assigning rental residential suites into the commercial rate is outside the scope of this proceeding because it pertains to rate design proceeding; accordingly, no determinations shall be made.

2.8               Succession planning

In its final argument, SSPOA requests the Commission consider an issue related to the succession planning of Stargas, requesting that the Commission “direct Stargas to present a management continuity plan at its next delivery rate filing (beyond pulling out shareholder equity).”[125] SSPOA submits “regulatory duties are the current responsibility of Mr. M. A. Blumes, but despite being 73 years old there is no regulatory successor for him now, or any firm plan in place… That fact represents a cost risk to Stargas customers.”[126]

 

Stargas responds to SSPOA in its reply argument submitting it does not agree that succession planning issues have not been considered in the management of the utility. Stargas submits “the owner of all of the preferred and common shares of Stargas continues to examine succession on an iterative basis” but that Stargas “does not object to present a management continuity plan at its next delivery rate application.”[127]

 

Panel discussion

 

The Panel finds that this issue is outside the scope of this proceeding. Succession planning is within the purview of management of operations, rather than an issue to be addressed by the Commission. Therefore, while the Panel encourages Stargas to continue to plan for management succession, it makes no determinations in this regard.

2.9               Period of rate approval

When asked to confirm the anticipated timing of filing Stargas’ next delivery rate application, Stargas responded as follows:

 

Stargas anticipates that the rate established pursuant to this proceeding will apply through the balance of the test year and its fiscal years ending May 31, 2018 and 2019. Stargas expects to enter into negotiations with FortisBC Alternate Energy Services Inc. in the spring/summer of 2019 (our current service contract runs to November 30^th, 2019)… As well, Stargas, from June 1^st, 2019 forward will record sharply reduced amortization in its accounts. Accordingly, Stargas expects to file an application to amend its delivery rate together with a refinancing application, to establish rates effective from June 1, 2019.[128]

 

Commission determination

 

Consistent with Stargas’ stated intention referred to above, the Panel finds the permanent delivery rate approved in this proceeding to be effective from November 1, 2016, to October 31, 2019.

 

The Panel directs Stargas to submit an application for a revised delivery rate by July 31, 2019.

 

 

3.0               Revenue Requirement and delivery rate

Commission determination

 

For the reasons set out in Section 2 these reasons for decisions, the total approved revenue requirement for the period November 1, 2016 to October 31, 2019 is $237,125, per Table 15.

 

Table 15 – Approved Revenue Requirement

 

The Panel does not approve Stargas’ requested delivery rate of $7.08 per GJ as filed. As modified by the adjustments to the 2017 revenue requirement resulting from the Panel’s determinations on management fee and earned return, the Panel approves a permanent delivery rate decrease of $1.61 per GJ from $7.38 per GJ to $5.77 per GJ ($237,125 / 41,093.6), effective November 1, 2016.

 

The Panel directs that Stargas refund all customers any amounts owing as a result of the difference between permanent and interim delivery rates approved by Order G-155-16 within 60days of this order by means of a one-time bill credit.

 

 

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