CREATIVE ENERGY 2016-17 RR RD FALSE CREEK HOT WATER ... · 7.1.1 If not confirmed, please explain...

Laurel Ross Acting Commission Secretary [email protected] Website: www.bcuc.com

Sixth Floor, 900 Howe Street Vancouver, BC Canada V6Z 2N3 TEL: (604) 660-4700 BC Toll Free: 1-800-663-1385 FAX: (604) 660-1102

Log No. 52519

PF/CE-2016-2017RR-RD_NEFC/GC/A-3_BCUC IR No. 1 to CE

VIA EFILE [email protected] May 11, 2016 CREATIVE ENERGY 2016-17 RR & RD

FALSE CREEK HOT WATER SERVICE EXHIBIT A-3 Mr. Stacey Bernier President and CEO Creative Energy Vancouver Platforms Inc. Suite 1 – 720 Beatty Street Vancouver, BC V6B 2M1 Dear Mr. Bernier: Re: Creative Energy Vancouver Platforms Inc. 2016-2017 Revenue Requirements Application and Rate Design for Northeast False Creek Hot Water Service Project No. 3698872 Further to British Columbia Utilities Commission Order G-49-16 establishing the Regulatory Timetable with respect to the above noted application, enclosed please find the Commission’s Information Request No. 1 to Creative Energy Vancouver Platforms Inc. In accordance with the Regulatory Timetable, please file your responses electronically with the Commission on or before Monday, May 30, 2016. Yours truly, Original signed by: Laurel Ross /yl Enclosure

CE 2016-2017 RRA and Rate Design for NEFC 0 BCUC Information Request No. 1

BRITISH COLUMBIA UTILITIES COMMISSION INFORMATION REQUEST NO. 1 TO CREATIVE ENERGY VANCOUVER PLATFORMS INC.

CREATIVE ENERGY

2016-2017 Revenue Requirements Application and Rated Design for North East False Creek

TABLE OF CONTENTS Page No. CREATIVE ENERGY – CORE STEAM ............................................................................................................................1

A. Rates ..............................................................................................................................................................1

B. Demand Forecast (Sales) ...............................................................................................................................3

C. Fuel Costs and Fuel Cost Adjustment Charge ................................................................................................6

D. Operating and MaintenAnacE - Water Expense ......................................................................................... 10

E. Operating and Maintenance Expense - Other ............................................................................................ 11

F. Taxes ........................................................................................................................................................... 16

G. Depreciation Expense ................................................................................................................................. 17

H. Amortization of Non-Rate Base Deferral Expenses .................................................................................... 18

I. Rate Base Return ........................................................................................................................................ 19

J. Request for New Deferral Accounts ........................................................................................................... 19

K. Rate Base – Plant In Service ....................................................................................................................... 20

NORTH EAST FALSE CREEK (NEFC) HOT WATER ..................................................................................................... 24

A. Rates ........................................................................................................................................................... 24

B. Demand Forecast........................................................................................................................................ 26

C. Operating and Maintenance Expense – Directly Attributable ................................................................... 27

D. Taxes ........................................................................................................................................................... 29

E. Depreciation Expense ................................................................................................................................. 29

F. Allocation of costs – General ...................................................................................................................... 30

L. Steam Cost Allocation – Steam production ................................................................................................ 32

M. Steam Cost Allocations – Steam distribution ............................................................................................. 33

N. Steam Cost Allocations – Corporate Overhead .......................................................................................... 35

O. NES Fuel Recovery Cost Allocation ............................................................................................................. 36

P. Deferral Accounts ....................................................................................................................................... 38

Q. Rate Base – Plant in Service........................................................................................................................ 39

R. Rate Design ................................................................................................................................................. 42


CREATIVE ENERGY – CORE STEAM

A. RATES

Reference: RATES 1.0Exhibit B-1: Section 1.1, p. 7; Section 3.1, pp. 20-21 Recover of 2016 deficiency between January 1 and April 30 - Steam

On page 7 of the Application Creative Energy (CE) states: “Creative Energy also proposes to recover the Test Period 2016 and Test Period 2017 revenue deficiency by increasing rates effective May 1, 2016 and recovering the Test Period 2016 and 12 Test Period 2017 revenue deficiency during the period from May 1, 2016 to December 31, 2017.” Excerpts from Table 3, on page 21 of the Application have been recreated in the table below.

1.1 Please provide details of the calculation for both 2016 and 2017 for:

• “A” Revenues at 2015 Rate; • “B” Estimated Steam Demand. Please also reference any demand forecast to the supporting

Appendix and Schedule; and • “C” Rate Increase Request.

1.2 By year identify the revenue deficiency/sufficiently and the resulting rate increase/decrease without consideration of smoothing.

1.3 For 2016 identify the portion of the deficiency/sufficient related to January 1, 2016 to April 30, 2016.

1.4 For 2016 and 2017 recalculated the revenue deficiency/sufficiently and the resulting rate increase/decrease if the deficiency/sufficiency related to January 1, 2016 to April 30, 2016 was not approved for recovery as requested in the Application. Please show all calculations.


Reference: RATES 2.0Exhibit B-1: Section 1.1, p. 7 Rate Smoothing – Steam

On page 7 of the Application CE states: “Given the revenue deficiency for Test Period 2017 is lower than the revenue deficiency for Test Period 2016, Creative Energy proposes to smooth rate changes by recovering a portion of the Test Period 2016 revenue deficiency in Test Period 2017.”

2.1 Please provide details of the rate smoothing calculation and explain the approach CE has used to achieve the requested rate smoothing concept.

2.2 Typically rate smoothing is achieved by placing the difference between the revenue deficiency/sufficient in the first test year in a deferral account and amortizing the balance into the second test year. The deferral account would also typically attract a carrying cost. Please explain why CE did not propose this approach and explain how CE’s proposed approach differs.

Reference: RATES 3.0

Exhibit B-1, Section 1.5, pp. 14-15 Interim Rates 2017 – Steam and NEFC

On pages 14 and 15 of the Application, CE states: “…Creative Energy is seeking final rates effective May 1, 2016 and is seeking steam rates, NEFC hot water rates proposed for Test Period 2017 to be interim and to be made final following an Application to be filed by Creative Energy on or before 1 November 1, 2016.”

“On or before November 1, 2016, Creative Energy proposes to file a simplified application to update the 2017 demand forecast and to update the revenue deficiency for 2016 projected year-end balances, including amortizations for deferral accounts.”

3.1 Is CE aware of the Commission’s recent Reason for Decision to Pacific Northern Gas Ltd. on its 2016-2017 Revenue Requirements Application for the PNG-West Service Area, marked as Exhibit A-6 to that proceeding for a similar request to have the second year of a test period approved as interim rather than final?

3.2 Please explain why CE is not requesting approval for final 2017 Steam Service rates and NEFC hot water rates?

3.3 Please explain what type of regulatory process CE would anticipate requesting to review the 2017 simplified application for Steam Service and NEFC hot water rates?


Tariff Pages - Steam

4.1 With the addition of NEFC, please confirm, or explain otherwise, that CE intends to request an amendment to the Steam Tariff, p. 17, Rate Schedule, “Applicability” to note that it applies to Steam Service only.


B. DEMAND FORECAST (SALES)

Reference: DEMAND FORECAST 5.0Creative Energy 2015-2017 RRA Decision, p. 40 Exhibit B-1, Appendix 4, p. 2 Other Methods of Load Forecasting for Steam Customers

On page 40 of the CE 2015-2017 RRA Decision, the Panel determined that:

“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.”

On page 2 of Appendix 4 in the Application, CE states:

“Creative Energy has concluded that there has been an inherent bias in the forecasts, and has proposed revisions to the forecast methodology, although it continues to be a customer focused forecast.”

5.1 Please discuss the potential source(s) of this bias identified in the 2016-2017 RRA Decision.

5.2 Please highlight where in the Demand Forecast section of the Application the proposed revisions are described.

5.2.1 Please describe how these proposed revisions differ from CE’s previous method of load forecasting.

Reference: DEMAND FORECAST 6.0

Exhibit B-1, Section 2.1, p. 17 Impact of RRA - Steam

6.1 Please complete the table below and provide both a soft copy [Excel (2) Tab “Demand”] and hard copy response.


6.2 To the best of your knowledge, without consideration of new customers, what is the main driver in the change in actual Demand between 2011 and 2015? (for example is it due to the loss of existing customers to other energy sources or is it a reduction in energy consumed by existing customers due to circumstances such as warmer weather or Demand Side Measures).


Exhibit B-1, Section 2.2, pp. 18-19 Forecasting Process - Steam

On page 18 of the Application, CE states:

“As part of the most recent forecasting process for steam sales, Creative Energy contacted its largest customers (representing 13.7% of total customers and 47% of total demand for steam) and interviewed customer representatives to determine any major changes in building characteristics or operations that would affect baseline steam demand under average weather. This information was used to adjust the baseline demand for 14 customers.”

7.1 Please confirm, or otherwise explain, that the information was used to adjust the baseline demand for only those 14 customers because the other significant customers’ baseline demand needed no adjustments.

7.1.1 If not confirmed, please explain if and how the baseline demand for other significant customers was adjusted.

7.2 For load forecasting in future RRA’s please discuss the benefits and the feasibility for CE of contacting customers that represent up to 75% of total steam demand.


Reference: DEMAND FORECAST 8.0Exhibit B-1, Section 2.2, Table 1, p. 19 Heating Degree Days - Steam and NEFC

8.1 Please complete the table below and provide both a softcopy (Excel Tab “1.Customer Sales Load Demand”) and hardcopy response.


Exhibit B-1, Section 2.1, p. 17 New Customer Additions - Steam

(Sensitivity analysis)


“Creative Energy is anticipating three customer additions in 2016: an office building, a residential building, and a school. The projected consumption for these new customers is based on the type of building, current envelope standards and other unique considerations.”

9.1 Please express the total demand forecasted for these three new customer additions, as a percentage of the (i) actual 2015 steam demand; and (ii) 2016 forecasted demand excluding the new additions.


9.2 Please assume that of the three customers, the customer with the largest forecasted demand experiences delays and does not connect to the steam system until 2017. Please explain, showing calculations, what impact this would have on (i) the demand forecast; (ii) the revenue requirements and rate increase request (please provide an updated version of Table 3 on page 21 of the Application); and (iii) Fuel Cost Adjustment.

9.2.1 If there is no impact to the revenue requirements or the Fuel Cost Adjustment please explain why.

C. FUEL COSTS AND FUEL COST ADJUSTMENT CHARGE

Reference: FUEL COST 10.0Exhibit B-1, Section 3.2, p. 23 Base Cost - Risk for Forecast

On page 23 of the Application, CE states: “The cost of fuel is the Company’s single largest cost, and is recovered from customers in two ways. A portion of the cost of fuel is recovered in the tariff --- a “Base Cost” of 41 cents per one million Btu of fuel consumed; and the remaining portion of the cost of fuel is recovered through a rate rider referred to as the Fuel Cost Adjustment Charge or “FCAC”.

10.1 Given that CE does not sell ‘gas’ please explain why CE does not include the total forecast Fuel cost in the revenue requirements calculation (tariff) rather than through the FCAC.

10.2 Please confirm, ore explain otherwise, that if CE’s forecast Demand is high than actual Demand CE shareholder benefits from the difference between the forecast cost of fuel and the actual cost of fuel for the Base Cost of 41 cents.

10.3 Please explain in detail how the FCAC work and what amounts are added to the Fuel Cost Stabilization Account.

Reference: FUEL COSTS – VOLUME 11.0

Exhibit B-1, Section 3.2.1, p. 25 Losses in the Energy System – Steam and NEFC


“The energy consumed to meet customer demand (discussed in Section 2) is 1,704,037 MMBtu for 2016 and 1,745,156 MMBtu for 2017. This is arrived at as follows:

1. An estimate of demand in M# is first determined;

2. The estimated demand is then grossed up for boiler efficiency; and

3. Finally, the grossed up amount is then converted to MMBTu by multiplying the conversion factor of 1.196 MMBTU to each M # of steam generated.”

11.1 For 2016 and 2017 please provide mathematical details of the three step calculation.

11.1.1 Please provide the calculation above without consideration of the NEFC load.


11.2 For each of the following, please confirm and quantify, or otherwise explain, that the estimated demand in step 2 of the preamble accounts for:

a. system losses in the NEFC distribution network;

b. losses due to the efficiency of the steam to hot water converters that serve the NEFC; and

c. system losses in the core steam network, including losses that may occur between the steam plant and the NEFC the steam to hot water converters.

11.2.1 If the estimated demand in step 2 of the preamble does not account for any of the losses listed in the previous question, please present an updated forecast of the energy consumed to meet demand and an updated Table 3 of the Application, both of which should account for the losses.

Reference: FUEL COSTS – PRICE 12.0

Exhibit B-1, Section 3.2.1, pp. 25-27 Fuel Expense Components – Steam and NEFC

12.1 Please complete the table below and provide both a softcopy (Excel tab “3.Fuel Expense Components”) and hardcopy response for (i) steam customers alone, (ii) NEFC customers alone and (iii) Steam and NEFC combined.

Reference: FUEL COST – PRICE 13.0

Exhibit B-1, Section 3.2.1, pp. 25-27 Fortis Transportation - Steam

On page 25 of the Application, CE discusses the charges that make up the cost of natural gas. CE states:

“The charges include the following components, where the cost of each varies with the volume of natural gas consumed: Fortis Transportation Charges; Natural Gas Commodity Price (including marketer fees); Carbon Tax; Ice Levy; PST; and Clear sky Fees.”

On page 26 of the Application, CE explains that under the Rate Schedule 22 agreement with FortisBC Energy Inc., CE “… has reserved 2,000 GJ/day firm capacity on Fortis’ system. Deliveries in excess of this firm capacity are treated as interruptible.”


Table 5 on page 26 of the Application shows that the forecasted transport charge for firm and interruptible capacity is $0.57/GJ and $0.86/GJ respectively, for 2016, and $0.60/GJ and $0.92/GJ respectively, for 2017.

13.1 Please explain, with calculations, how CE determined the 2017 transportation rates.

13.2 Based on the 2016 and 2017 rates, please explain, with calculations, if the firm transportation capacity of 2,000 GJ/day should be increased for 2016, 2017 or beyond, given the forecast additions of the NEFC.

13.2.1 Please discuss the benefits, costs and feasibility of increasing firm capacity on the FortisBC Energy Inc. system.

13.2.2 Please use calculations to show the percentage of Fuel Expenses represented by the sum of the forecasted Firm Transportation Charge and the Interruptible Transportation Toll for each of 2016 and 2017.

13.3 Please point to the section of the Rate Schedule 22 that shows the fees for the “Pilot” and “Demand” delivery charges identified in Table 5.

13.3.1 Please explain the nature of the “Pilot” and “Demand” delivery charges.

Reference: FUEL COST – PRICE 14.0

Exhibit B-1, Section 3.2.1, pp. 25-27 Natural Gas Commodity Costs - Steam

On page 26 of the Application, CE explains that currently all natural gas purchases are from a gas marketer on a one year contract. CE elaborates that the Annual Gas Contracting Plan outlines the process and strategies to mitigate price volatility. CE further states that: “For the purpose of this RRA the Company used the January 15, 2016 forward gas strip prices of $3.02/GJ for 2016 and $3.60/GJ for 2017.”

14.1 Please provide the most recent forward gas strip prices for each of 2016 and 2017.

14.1.1 Please provide calculations showing how the updated forward gas strip prices impact the fuel expenses and revenue requirements in the Application.

Reference: FUEL COST 15.0

Exhibit B-1, Section 3.3, pp. 27 Fuel Cost Stabilization Account Additions

Clear Sky Charges – Steam and NEFC

CE’s Application on page 27 states “Creative Energy is subject to the Energy Services Agreement (ESA) (approved by Order G-125-07), under which the Company has contracted with the Clear Sky Energy Ltd. (Clear Sky) to provide and maintain energy conservation equipment that will reduce energy use at the 720 Beatty Street plant.”


In Commission Information Request No. 1 for the Central Heat Distribution Limited (CHDL) 2007 Revenue Requirements Application,1 CHDL responded to question 5.2 saying:

As provided for in the ESA, Central Heat is responsible for the Operating costs under Section 4.1(h). The only operating cost which is allocated to the Energy Connection Equipment would be the electrical costs related to the water circulating pumps and fan drive. That cost is estimated to be a maximum of $10,500, based on operation 365 days a year…

15.1 Please confirm whether CE is still responsible for the Operating costs under Section 4.1(h) of the ESA. If confirmed:

15.1.1 Please provide the forecast and calculation for the 2016 and 2017 Clear Sky expense forecast to be added to the Fuel Cost Stabilization Account.

15.1.2 Please explain how this cost will benefit NEFC?

15.2 Could the Clear Sky expense be considered a type of Demand Side Measure (DSM) expense?

15.2.1 If not, please explain why not.

15.3 Please explain why the costs are included in the Fuel Cost Adjustment Charge and not in the Revenue Requirements (Tariff) as an expense?

15.4 Is CE aware of any other utilities that record DSM costs as a Fuel Cost or Cost of Energy?

15.5 Is there any capital costs, from Clear Sky or any other project, included in the Fuel Cost Stabilization Account balance reported in Appendix 2 of the Application?

15.5.1 If yes, please quantify and explain why this treatment is appropriate.

Reference: FUEL COST 16.0

Exhibit B-1, Section 3.4.1, p. 31; Appendix 2, p. 2; Creative Energy 2015-2017 Revenue Requirement, Exhibit B-5, BCUC IR 2.12.1, pp. 16-17; BCUC IR 2.12.1.1, p. 17; Fuel Cost Adjustment Charge

On page 31 of the Application, CE states: “In the 2015 Approved [budget], fuel costs were estimated at $708,850. However, due to warmer than normal weather and other drivers of reduced consumption, the 2015 Projected is $516,156 or approximately 27% lower than the 2015 Approved.”

Appendix 2 of the Application contains schedules for the Fuel Cost Adjustment Charge and the Fuel Cost Stabilization Account as filed with the Commission on February 11, 2016.

In the Creative Energy 2015-17 Revenue Requirements proceeding the Commission asked how does CE determine the appropriate size of the over recovery buffer developed through the use of the Fuel Cost Adjustment Charge and the Fuel Cost Stabilization Account. CE responded by stating: “…Creative Energy has historically maintained a balance of 10% to 15% of the actual annual energy costs.”

1 BCUC Information Request No.1 for the Central Heat Distribution Limited (CHDL) 2007 Revenue Requirements

Application, Tab 5, p. 2, http://www.bcuc.com/Documents/Proceedings/2007/DOC_16550_B-3_Resps_BCUC_IR-1.pdf.

http://www.bcuc.com/Documents/Proceedings/2007/DOC_16550_B-3_Resps_BCUC_IR-1.pdf


16.1 Please provide a table showing the forecast, approved and actual “Fuel Expense as show on Table 5, lines 4, of the Application for each of the years from 2011 through to 2015.

16.1.1 Please discuss the reason for any significant variances.

16.2 Please update the tables on pages 1 and 2 of Appendix 2 to provide information for each of February 2016, March 2016 and April 2016. Please include with each table a brief explanation of each column included in the tables.

16.3 For the period January 2015 to April 2016, please use a table to show on a monthly basis, the balance of the Fuel Cost Stabilization Account as a percentage of the sum of the actual energy costs for the last 12 months. For example, the balance of the Fuel Cost Stabilization Account at the end of September 2015 should be shown as a percentage of the sum of the energy costs from October 2014 to September 2015.

D. OPERATING AND MAINTENANACE - WATER EXPENSE

Reference: O&M WATER EXPENSE 17.0Exhibit B-1, Section 3.3, pp. 27-28 Water Expense – Account #502

On page 27 of the Application, CE states: “The cost of water is one of the major expenses for the Company. … The methodology to forecast the water expense is based on a historic ratio of actual water expense vs actual demand for steam times the forecast demand.”

17.1 Please complete the table below to provide information regarding water expenses as shown on line 5 of Table 5. Please include the appropriate units of measurement.

2011 2012 2013 2014 2015 2016 2017 Forecast Water Expense Forecast Water Volume Approved Water Expense Approved Water Volume Actual Water Expense Actual Water Volume Forecast Steam Demand Actual Steam Demand

17.1.1 Please discuss the reason for any significant variances between forecast.

17.2 Please explain if the ratio based on actuals is updated periodically based on the historic water expenses and steam demand.

17.3 Please provide the 2015 water purchase invoices.

17.4 Please confirm, or explain otherwise, that the steam system currently has provisions in place which allow recycling of water to consequently reduce the water expense. If confirmed, please discuss the recycling process and the related cost savings. Otherwise please provide rationale for why this does not exist currently and if/how could the steam system be modified in the future to recycle the water.


E. OPERATING AND MAINTENANCE EXPENSE - OTHER

Reference: O&M 18.0Exhibit B-1: Appendix 1, Schedule 15; Appendix 8

Additional Data – Steam and NEFC

18.1 Please update Appendix 1, Schedule 15 to show Approved amounts for 2011-2014 and Actuals for 2015.

On page 27 of the Application, CE states: “Creative Energy is subject to the Energy Services Agreement (approved by Order G-125-07), under which the Company has contracted with the Clear Sky Energy Ltd. (Clear Sky) to provide and maintain energy conservation equipment that will reduce energy use at the 720 Beatty Street plant. Under the terms of the agreement, the Company keeps 25% of the savings and remits the payment for the 75% of the savings to the Clear Sky. The Clear Sky’s portion is estimated to be $227,000 for 2016 and $267,600 for 2017, and it is appropriately included in the overall cost of gas for 2016 and 2017.”

18.2 Please explain what Appendix 1, Schedule 15, line 63 “O&M Allocated to Affiliate” in 2016 and 2017 relates to and provide details for the calculation.

18.3 For 2016 and 2017 please identify all costs in Appendix 1, Schedule 15 that have been directly assigned to NEFC and reference how they tie into Appendix 9, Schedule 14.

18.3.1 What methodology was used directly allocated the costs to NEFC?

18.3.1.1 Was it an incremental approach?

18.3.1.1.1 If yes, please explain why the incremental approach is appropriate.

18.4 Please update Appendix 8 to include:

(a) details for Accounts 915 and 924.

(b) 2011-2015 Approved and Actual balances.

18.5 In certain account details in Appendix 8 CE has identified costs that relate to NEFC. Please update the table to identify all cost that have been directly assigned to NEFC and reference how they tie into Appendix 9, Schedule 14.

Reference: O&M – STEAM PRODUCTION EXPENSE – EXCLUDING LABOUR 19.0

Exhibit B-1: Section 3.4.1, p. 31; Appendix 1, Schedule 15 Structure and Improvements (Account #506) - Steam

Structure and Improvement Expense was Approved at $6,300 in 2015, Unaudited 2015 is $3,576 and 2016 and 2017 Forecast are $9,200 and $9,400 respectively.

19.1 Please explain why the Structure and Improvement Actual expense in 2015 is expected to be 43 percent less than the 2015 Approved amount and why it is forecast to increase by 46 percent in 2016 over the 2015 Approved amount.

19.1.1 If any of the forecast increase in 2016 and/or 2017 is due to NEFC please quantify.


Reference: O&M – STEAM DISTRIBUTION EXPENSE – EXCLUDING LABOUR 20.0

Exhibit B-1: Section 3.4.2, pp. 31-32; Appendix 1, Schedule 15 Mains and Service Expense (Account #874 and #887) and Transportation Expense (#933) - Steam

Mains and Services - Operations Expense (#874) was Approved at $11,616 in 2015 while 2016 and 2017 are forecast at $15,700 and $19,100 respectively.

20.1 Please explain why the Mains and Services – Operations Expense is forecast to increase by 35 percent in 2016 and 64 percent over the 2015 Approved amount.


Transportation Expense (#933) was approved at $16,600 in 2015 while 2016 and 2017 are forecast at $24,000 and $24,500 respectively.

20.2 Please explain why the Transportation Expense is forecast to increase by 45 percent in 2016 over the 2015 Approved amount.


Mains and Services - Maintenance Expense (#887) was approved at $40,800 in 2015 while 2016 and 2017 are forecast at $66,000 and $67,000 respectively.

20.3 Please explain why the Mains and Services – Maintenance Expense is forecast to increase by 62 percent in 2016 over the 2015 Approved amount.


Reference: O&M – SALES PROMOTION EXPENSE 21.0

Exhibit B-1, Appendix 1, Schedule 15 Sales Expense (Account #910) - Steam

Sales Expense was approved at $38,064 in 2014 which was consistent with previous years while the 2015 approved amount increased to $56,400. In 2016 and 2017 CE forecasts sales expense to increase to $67,300 and $70,200 respectively.

21.1 The forecast for 2016 and 2017 do not include commission of $12,000 that was approved for recovery in 2015; however, the forecast includes $24,000 for trade shows/marketing and $6,000 for travel/conferences in both 2016 and 2017. Please explain why there is a need for trade shows/marketing and travel/conferences expenses in 2016 and 2017 when there was no need in 2015.

21.1.1 Would all these costs still be necessary if CE was not looking to expand outside of its core Steam Service?

21.1.2 If not, please isolate, or provide a percentage, for the Trade Shows/Marketing and Travel/Conferences Expense necessary for Steam Service.


Reference: O&M – ADMINISTRATION AND GENERAL – EXCLUDING LABOUR 22.0Exhibit B-1, Section 3.4.3, pp. 32-34; Appendix 1, Schedule 15

Special Services (Account #923) and Insurance Expense (Account #924) – Steam and NEGC

Overall Administrative & General – Operations (excluding Admin and General Salaries) was approved at $806,827 in 2015 and is forecast to increase by $358,537 or 45 percent to $1,165,400 in 2016.

The most significant driver to this increase appears to be Special Services (Account #923) which is forecast to increase from $108,000 Approved in 2015 to $418,200 in 2016 and then drop slightly to $307,300 in 2017. The Actual 2015 expense is forecast to be $246,121.

On pages 33 and 34 of the Application CE explains that: “These costs have increased due to increased regulatory activity, as well as, the increase in complexity and requirements of each regulatory activity.”

22.1 Please provide details for the $42,000 in 2016 and $30,000 in 2017 for Communication Expenses in Account #923.

22.2 Please provide details for the $100,000 in 2016 for Consultant Rate Design Expenses in Account #923.

22.3 Appendix 8, Account #923 shows $6,000 and $6,120 for 2016 and 2017 respectively being allocated to NEFC. Please explain the rationale used to allocate regulatory costs and other costs captured in the Special Services Account #923 between Steam Service and NEFC.

22.3.1 If on an incremental basis please explain why CE considers this to be appropriate and how CE defines incremental?

Insurance Expense (Account #924) – was Approved at $106,600 in 2015 and is forecast to increase to $123,900 in 2017.

22.4 Please provide an explanation for the forecast increase in Insurance Expense in 2017.



Reference: O&M - LABOUR 23.0Exhibit B-1: Section 3.4.3.2, p. 33; Appendix 1, Schedule 15 Labour (Accounts #500, 870, 920) - Steam

23.1 Please complete the table below and provide both a softcopy (Excel (2) Tab “Labour”) and hardcopy response.

23.2 Please provide a detailed breakdown for Exhibit B-1, Appendix 1, Schedule 15, Accounts #500,

870, and 920 for 2014 (Approved and Actual), 2015 (Approved and Actual), 2016 and 2017 Forecast.

Reference: O&M - LABOUR 24.0

Exhibit B-1-1, Appendix 7; Exhibit B-1-4, Appendix 7a Labour – Admin and General Salaries (#920)

TABLE 1 24.1 Please update Exhibit B-1-4, Appendix 7a, Table 1, and Confidential Exhibit B-1-1, Appendix 7,

Table 1, to report Approved and Actual Management Salaries for 2011-2015.

24.2 Do the Gross Wages on Exhibit B-1-4, Table 1, line 9 include 100 percent of management salaries?

24.2.1 If not please show what percentage they relate to in reference to the columns in Table 2.

24.3 Exhibit B-1-4, Table 1 reports “Gross Wages (Excludes Ex Exec Wages)”. Please explain what the term in brackets refers too.

24.3.1 Are there any Ex Exec Wages included in the Revenue Requirement for 2016 and 2017?


24.3.1.1 If yes, please explain and disclose the amount and identify which account in Exhibit B-1, Appendix 1, Schedule 15 they are capture in.

24.4 Are any of the forecasts Bonus’ reported on Exhibit B-1-4, Table 1, line 7, charged to Construction/Rate Base? If not please explain?

24.4.1 If yes, please quantify as a percentage of the Bonus reported on line 7.

24.5 Is the Total Wages Charge to Construction/Rate Base reported on Exhibit B-1-4, Table 1, line 8 all charge to Steam Rate Base?

24.5.1 If yes, please explain why?

24.5.2 If not, please breakdown Exhibit B-1-1, Appendix 7, Table 2, column “Total” between Steam Service Rate Base, NEFC Rate Base and other.

24.6 As reported in Exhibit B-1-1, Table 1, line 11, please explain why such a high percentage of the Presidents wages were charged to Rate Base in 2015.

TABLE 2 24.7 Please update Exhibit B-1-4, Appendix 7a, Table 2, and Exhibit B-1-1, Appendix 7, Table 2, to

report the data for 2013, 2014 and 2015.

24.7.1 Please explain what specific projects Project 1 – 6 refers to.

24.8 For each individual identified in Exhibit B-1-4, Table 2, please provide the full job title and a sentence describing their role and responsibilities.

24.8.1 For each individual identified in Exhibit B-1-4, Table 2, please cross reference to the job title in the HayGroup Benchmarking Report.

24.9 For 2016, please reconcile the “Total” wages as reported in Exhibit B-1-1, Table 2, lines 14-21, to the salaries reported in the HayGroup Benchmarking Report.

ALLOCATION BY TIME SPENT 24.10 It appears that 100 percent of management salaries are either charged to GL #920 or capitalized

to Construction/Rate Base. Please explain why no management salaries have been directly allocated to NEFC.

24.11 For 2015, 2016 and 2017 please prepare a table similar to Exhibit B-1-1, Appendix 7, Table 2 showing an allocation by Individual for time spent on Steam Service, NEFC, and Projects 1-6.

HayGroup REPORT 24.12 The HayGroup Benchmarking Report in Appendix 7 of the Application refers to “Actual

Compensation.” Does this refer to the Actual Compensation paid in 2015?

24.12.1 If not, please explain.


24.13 Do the bar graphs on pages 6-12 of the HayGroup Benchmarking Report reflect CE’s employees forecast direct compensation for 2016 and 2017 or actual 2015? If actual 2015, how does this compare to forecast 2016 and 2017.

24.14 In the HayGroup Benchmarking Report it appears that generally CE’s base salaries are slightly higher than the “National Utility Comparison”, while total compensation is slightly lower than the “National Utility Comparison.” Please explain why CE chooses this approach.

24.15 Please explain how CE’s Incentive Plan (Bonus) is designed. What key business goals or superior management performance is CE’ trying to incent?

24.15.1 Please explain how this performance benefits a) rate payers; and b) shareholder.

F. TAXES

Reference: TAXES 25.0Exhibit B-1, Section 3.5.1, pp. 34-36

Municipal Taxes & Steam RR – Adjustment for NEFC

On p. 36 of the Application CE states that “Included in the Variable Portion of the Total Fee above is $1,800 for 2016 and $10,300 for 2017 on account of incremental Municipal Taxes from NEFC. It is calculated as 1.25% of total revenues from all the NEFC customers of $136,000 for 2016 and $768,000 for 2017, respectively. These amounts represent an incremental and directly assignable cost of the NEFC NES.”

25.1 Please explain how the Annual Steam Revenues as reported on Table 9, line 4 on page 35 of the Application tie into the revenue requirements as reported on Table 3, on page 21 of the Application.

25.2 Do the Annual Steam Revenues as reported on Table 9, line 4 on page 35 of the Application include forecast revenues from NEFC?

25.2.1 If not, then please explain why an adjustment for NEFC Municipal Access Fees has been made to the Steam Service revenue requirement as reported on Table 3, line 9, on page 21 of the Application.

Reference: TAXES 26.0Exhibit B-1, Section 3.5, p. 36

Property Taxes

Property taxes are forecast to increase to $442,700 in 2016 and $464,800 in 2017 from $398,658 actual in 2015.

26.1 Please provide an explanation for the forecast property tax increase in 2016 and 2017.

26.1.1 Is the increase driven by forecast increases in the various levy rates or the forecast value of the property?


26.2 Does the forecast value of the property for 2016 and 2017 include any property exclusively related to NEFC?

26.2.1 If yes, for 2016 and 2017 please identify the forecast increase in property tax related to NEFC.

Reference: TAXES 27.0

Exhibit B-1, Section 3.5.4, p. 37 Income Tax

Steam RRA Calculation – NEFC Adjustment 27.1 Is the methodology used to calculate income tax in 2016 and 2017 the same methodology that

was used in 2015?

27.1.1 If not, please explain any change proposed.

27.2 Please confirm, or explain otherwise, that all the reduction in actual income tax expense in 2015 was a result of the demand forecast in 2015 being higher than actual demand.

27.2.1 If not, please quantify the portion of the reduction as a result of the lower than forecast Demand.

27.3 Please confirm, or explain otherwise, that Appendix 1, Schedule 19, line 1 of the Application is the proposed return on rate base for the Steam Division only? If not please explain.

27.4 Please confirm, or explain otherwise, that the income tax expense for 2017 of $266,000 is for Steam Service only?

27.5 If yes, please explain why an adjustment for NEFC income taxes has been made to the Steam Service revenue requirement on Table 3, line 12 on page 21 of the Application.

G. DEPRECIATION EXPENSE

Reference: DEPRECIATION EXPENSE 28.0Exhibit B-1, Section 3.7.1.1, pp. 39-40

Depreciation Policy

On page 40 of the Application CE states:

“For each asset class the annual capital additions are tracked separately and it is the Company’s policy to begin depreciation in the year following their addition.”

“Using prior year’s closing plant balance significantly reduces the risk of forecast error resulting in a minimal difference between actuals and the forecast.”

28.1 Is CE’s depreciation policy used for financial reporting (and therefore approved by the external auditors) the same as the depreciation policy use for regulatory purposes as explained on page 39 of the Application. If not, please explain.


28.2 Please provide the BCUC order number that approved the depreciation rate as set out in Table 14 on page 40 of the Application.

28.3 Are the depreciation rates used for financial reporting the same as the depreciation rates used for regulatory purposes? If not, please explain.

Appendix 1, schedule 5 shows 2015 approved depreciation expense as $942,833 and 2015 unaudited (actual) as $916,215. 28.4 Given that the prior year’s closing balance is used to forecast depreciation expense, please

explain the reason for the variance between approved and actual depreciation expense in 2015?

28.5 For the years 2011-2014 please provide a table that shows both approved and actual depreciation expense.

Reference: DEPRECIATION EXPENSE 29.0

Exhibit B-1, Section 3.7, p. 39; section 3.1, p. 21; Appendix 1, schedule 2; Appendix 9, schedule 4

Steam RRA Calculation – NEFC adjustment

29.1 Please confirm, or explain otherwise, that Appendix 1, Schedule 2, represents rate base for team Service Rate Base only and that the related depreciation expense in Appendix 1, Schedule 5 is also only for Steam Service.

29.2 Please confirm, or explain otherwise that Appendix 9, Schedule 4 represents depreciation expense for NEFC only and is calculated on NEFC’s Rate Base as determined in Appendix 9, Schedule 2 (0$ for 2016 and $177,800 for 2017).

29.2.1 If yes, please explain why an adjustment has been made for NEFC depreciation to the Steam Service revenue requirement on Table 3, line 13 on page 21 of the Application.

H. AMORTIZATION OF NON-RATE BASE DEFERRAL EXPENSES

Reference: AMORTIZATION OF NON-RATE BASED DEFERRAL EXPENSES 30.0Exhibit B-1, Section 3.8, pp. 41

Steam RRA Calculation - NEFC Adjustment

30.1 Given that the amortization of the Revenue Deficiency Deferral Account (RDDA) in 2017 of $8,000 was not included in the $110,500 amortization expense for Steam Service in 2017 please explain why an adjustment of $8,000 has been made to the Steam Service revenue requirement on Table 3, line 15 on page 21 of the Application.


I. RATE BASE RETURN

Reference: RATE BASE RETURN 31.0Exhibit B-1, Section 3.9, p. 42

Steam RRA Calculation - NEFC Adjustment

31.1 Please confirm, or explain otherwise that Appendix 1, Schedule 13, represents the return on rate base for Steam Service only (calculated on Steam Service Rate Base) and does not include the return on rate base as calculated in Appendix 9, Schedule 13 for NEFC.

31.1.1 If yes, please explain why an adjustment has been made for NEFC Interest and ROE to the Steam Service revenue requirement on lines 16 and 17 of Table 3, lines 16 and 17 on p. 21 of the Application.

J. REQUEST FOR NEW DEFERRAL ACCOUNTS

Reference: DEFERRAL ACCOUNTS 32.0Exhibit B-1, Section 3.2, p. 23

Fuel Cost Stabilization Account

“Creative Energy seeks approval for the Fuel Cost Stabilization Account (FCSA) to be a non-rate base deferral account with carrying costs at the weighted average cost of debt calculated on monthly deferral account balances.”

32.1 Given the long term nature of this deferral account please explain why a Weighted Average Cost of Capital would not be a more appropriate carrying cost to be applied to the unamortized balance.

32.2 Please explain the function of the prosed deferral account and the balances that CE request be capture in the account. For example is CE proposing that the deferral account capture the variance between actual and forecast fuel expense or to include the actual Fuel Expense.

32.3 Please explain how CE proposed to amortization the FCSA.

32.4 Please explain why CE requires the deferral account and explain the implications to CE if the Commission was not to approve the request.

32.5 Please explain the advantages and disadvantages of a concept where the forecast Fuel Costs (including the Base Cost of 41 cents) is forecast and set for the test period and recovered in the tariff or as a separate line item (Fuel Cost) on the bill and the FCSA is used to recover the variance between the Forecast Fuel Cost and Actual Fuel Cost through a rate rider (which could be updated quarterly).

32.5.1 In assessing the advantages and disadvantages please address the impacts on the MAA fees and how this could potentially be mitigated.


Reference: DEFERRAL ACCOUNTS 33.0Exhibit B-1; Section 3.4.3, p. 32; Section 4.6.1, p. 51

Special Services Costs Deferral Account

On p. 51 of the Application CE seeks approval of the following deferral account: “Regulatory - Special Services Deferral Account – for expenses related to regulatory proceeding, including BCUC levies and PACA funding.”

33.1 Please confirm, or explain otherwise that, that CE is requesting to capture the variance between forecast and actual cost that relate exclusively to regulatory costs and not all the costs captured in CE’s Special Services Account #923?

33.1.1 Please identify each item as set out in Appendix 8, Account # 923, that CE is requesting the proposed deferral account captures.

33.2 How will ‘Regulatory” costs directly related to NEFC be treated? What criteria will CE use to determine what is a direct NEFC Regulatory costs?

K. RATE BASE – PLANT IN SERVICE

Reference: PLANT IN SERVICE 34.0Exhibit B-1, Appendix 1, Schedule 3, Schedule 4 2015 Forecast/Actual Additions

In Appendix 1, Schedule 3 of the Application CE provides actual, approved, unaudited and forecast costs for the opening gross plant and the closing gross plant.

In Appendix 1, Schedule 3, the closing gross plant for 2015 approved is shown to be $42,757,489 and the opening gross plant for 2015 unaudited/2016 forecast is $42,252,277. On an account by account basis, the following table shows the variance between 2015 approved and actual (2015 unaudited) plant in service additions:

Acct # Account Name Additions 2015 Approved 2015 Unaudited Variance

Steam Production Plant 311 Structures 0 1500 1500

310.1 Boiler Plant Equipment 139,000 70,348 -68,652

312.1 Boiler Auxiliary Equipment 0 119,053 119,053

Distribution Plant 376 Mains 10,000 0 -10,000 378 Manhole Structures 515,000 747 -514,253 380 Services 190,518 86,996 -103,522

382 House Regulators & Meter Installations

0 542,176 542,17

General Plant Misc 0 6,217 6,217

391.1 Office Electronics 16,000 130,065 123,848 TOTAL $870,518 957,100


34.1 Please provide an explanation for all variance +/- $50,000 between 2015 approved and 2015 actual (unaudited).

34.1.1 Please provide a detailed rationale for why steam production plant – boiler auxiliary equipment and distribution plant – house regulators and meters were incurred in 2015 but not approved by the Commission in 2015.

34.2 Could these variances have been foreseen by CE in 2015? Why or why not?

34.3 On an account by account basis, for both 2015 approved and 2015 unaudited, please indicate the percentage that relates to capitalized labor.

Reference: RATE BASE 35.0

Exhibit B-1, Appendix 1, Schedule 4 Plant in Service – Additions NEFC

35.1 Do any forecast plant in service additional of $5,214,287 in 2016 and $3,634,481 in 2017 relate to NEFC?

35.1.1 If yes, please quantify and explain why there are included in steam service plant in service.

Reference: RATE BASE 36.0

Exhibit B-1: Section, 4.2.2, p. 45; Section 4.5.1.4, p. 50; Section 4.5, p. 47 AFUDC and WIP

On page 45 of the Application, where rate base and capital additions are addressed, CE states: “The AFUDC applies where an asset is not part of the rate base, but funds have been invested to finance its construction. The AFUDC recognizes that there are carrying costs arising from such an investment and provides for their future recovery.”

36.1 Please confirm, or explain otherwise, that CE is not adding to rate base AFUDC for any capital projects that are not forecast to be in service in the test year.

36.2 Please explain how CE accounts for capital projects that are under construction (capital expenditure as opposed to capital additions) but are not going into service in the test period (construction in progress).

On page 50 of the Application, CE states “Included in the working capital is mid-year construction work-in-process that is not subject to earning AFUDC. This represents part of Creative Energy’s investment into utility assets and thus is appropriately included in Company’s rate base.”

36.3 Does CE have any work-in-progress that is earning AFUDC?


36.4 Please explain why there is work-in-progress that is not earning AFUDC?

36.5 In the Application on Table 20, p. 47, CE shows work in progress as a component of working capital. In 2016 it represents 77 percent of total working capital and in 2017 it represents 78 percent.

36.5.1 Please provide a detailed calculation for work in progress for 2016 and 2017 and provide an explanation on a project by project basis.

36.5.1.1 Please indicate when each of the work in progress projects is expected to go into service.

36.6 Please explain why work in progress in included in working capital and not held outside of plant in service accumulating AFUDC?

36.7 Does any of the work in progress relate to NEFC capital projects?

36.7.1 If yes, please identify the amount and identify the projects?

Reference: RATE BASE – PLANT IN SERVICE 37.0

Exhibit A-2, Order G-49-16 Exhibit B-1-6, Appendix 11A Additional Information of Capital Expenditure and Additions

Directive 13 of Order G-49-16 issued on April 12, 2016, directed the following:

“…file with the Commission additional information on the capital requirements data filed in Appendix 11 of Exhibit B-1-2 that: (a) summarizes the data by capital project; (b) identifies by capital project if any previous Commission approval was granted for the project; (c) for any capital project not previously approved by the Commission provides a high level summary of the project, the total forecast cost of the project over its life and the expected date of completion; and (d) for any capital project previously approved by the Commission provides an explanation for any variance between approved and forecast.”


In compliance with this directive CE filed Appendix 11A which included a comments column providing a short description of each line item on the spreadsheet, and added four notes on the bottom of the spreadsheet.

37.1 Appendix 11A does not include the information as requested in directive 13 of Order G-49-16. Please file the information as directed for both Steam Plant in Service and NEFC Plant in Service.

37.2 For any project that last more than a year, for both Steam and NEFC, please provide a project continuity schedule showing the capital expenditures by year and identifying the year when the project is added or planned to be added to Plant in Service as a capital addition. For Steam the continuity schedule should reconcile with the Work in Progress balance as reported on Table 20 on page 48 of the Application.

37.3 Does NEFC have any forecast Work in Progress balance? If yes, why has it not been addressed in the Application. If not, please explain.

Reference: RATE BASE – PLANT IN SERVICE 38.0

Exhibit B-1: Section 4.2.3, p. 45; Table 3, p. 21; Section 4.6.2, p, 52; Appendix 1, Schedule 15 Capitalized Overhead

38.1 As set out in Appendix 1, Schedule 15, and recreated above, prior to 2015 CE was not capitalizing any O&M. Please explain the reason for the change.

In the Application on p. 52, CE states that it’s capitalized overhead approach “involves a review of the projects that were completed during the year and assigning a small percentage as overhead capitalization. This percentage in the past had been less than half a percent of the overall corporate overheads.”

38.2 Is CE’s capitalization approach and rate of 0.43% in accordance with ASPE?

38.3 Is the capitalized overhead rate and policy used for regulatory purposes the same as the rate and policy used for financial reporting?

38.3.1 If not, please explain.

38.4 Given that a portion of the total O&M costs of $4.6 million and $4.9 million in 2016 and 2017 respectively have been directly attributed to NEFC in the amounts of $92,400 in 2016 and $200,800 in 2017 please explain why a portion of capitalized overhead has not be allocated to NEFC.


NORTH EAST FALSE CREEK (NEFC) HOT WATER

A. RATES

Reference: RATES 39.0Order G-27-15 TES Framework

Section 2.4.3 and 2.4.4 of the Thermal Energy Systems (TES) Regulatory Framework Guidelines (TES Guidelines) attached to Order G-27-15 outlines the rate setting considerations for applicants of Stream B TES utilities and the requirements for all Stream B TES rate applications.

39.1 Please provide a general discussion on each of considerations listed in Section 2.4.3 of the TES Guidelines as it pertains to the proposed NEFC rates.

39.2 Please provide a discussion and evidence for each of the items listed in Section 2.4.4 of the TES Guidelines governing a Stream B TES rate application. If any items are non-applicable to the NEFC proposed rates and rate design, please explain why.


Exhibit B-1, Section 5.6, p. 64 Tariff

CE is seeking hot water rates to be effective August 1, 2016, on an interim and final basis.

On page 64 of the Application, CE shows a table outlining the Hot Water Rates for NEFC’s, however no draft tariff sheets or draft terms and conditions were filed with the Application.

40.1.1 Please file the draft rate schedule (tariff sheets), showing the fixed and variable rates to be charged.

On page 6 of its Final Argument in the NEFC CPCN proceeding CE states that “the Connection Agreement [which was filed under sections 56-60 of the Utilities Commissions Act (UCA)] sets out the legal framework for the relationship between the utility and the developer of lands and the end use customer that will be connected to the NES. The connection and service agreements are required by all who will be connected to and take service from the NES in NEFC to ensure compatibility of the building systems with the NES, to permit Creative Energy to install infrastructure on developer’s lands to serve only that development and to allow success to Creative Energy.”

In its decision on the NEFC CPCN proceeding the Commission found that it required more information from CE regarding the Connection Agreement and therefore denied its approval.

In Exhibit B-1, of CE’s Application for NEFC Neighborhood Energy Agreement Amendments (NEFC NEA Amendments), CE states that it is currently consulting customer regarding revision to the Connection Agreement, and expects to seek approval of a revised Connection Agreement by the end of March 2016. CE states further that it may submit the Connection Agreement with its next rate application; however, Creative Energy may seek approval in a separate process in order to expedite approval.

40.2 Please confirm, or explain otherwise, that the Connection Agreement sets out the terms and conditions for NEFC service?


40.3 Please confirm, or explain otherwise, that CE is aware that draft terms and conditions of service will need to be filed with the Commission prior to the Commission considering CE’s request for interim rates effective August 1, 2016.

40.4 At this time, does CE anticipate filing the Connection Agreement for review as part of this proceeding or as a separate proceeding?


Exhibit B-1: Section 5.3, p. 55; Appendix 4 Class of Service

In Appendix 4 to the Application, CE proposes a separate class of service for steam service and for hot water service. However on page 55 of the Application CE explains “…Creative Energy only has two rate classes (Steam and NEFC Hot Water Service)…”

41.1 Please confirm, or explain otherwise, that CE understands the difference between a class of service and a rate class.

41.2 Please confirm, or explain otherwise, that CE is applying to have NEFC treated as a class of service as set out in the section 60(1)(c) of the UCA and not as a separate rate class.

41.2.1 If not confirmed, please explain what utility CE is proposing that steam service and NEFC hot water service are separate rate classes of.


Exhibit B-1, Section 1.3, pp. 10-11, Section 5.6, p. 64 2016 Effective Rates – Steam and NEFC

CE’s Application on page 11 shows a chart on 2016 Effective Rates which “compares the proposed 2016 steam rate with other recent benchmarks for on-site gas, and for other regulated thermal energy systems.”

42.1 Please elaborate on the four “Other Rates” show in chart and reference where CE obtained the rates and how they were derived. Please start with the BCUC approved tariff. For utilities with multiple rate classes, such as BC Hydro, please identify which Rate class/schedule CE is referring to. Please identify if the utility is gas, electricity, etc.

42.2 Please explain how the “Other Rates” are comparable to CE Steam and show all calculation made to the units to make the “Other Rates” comparable.

42.3 Please add in an additional bar graph to represent NEFC Hot Water Rates and show the calculation used to make it comparable to Steam Rates.


Reference: GENERAL – RATE SCHEDULES 43.0Exhibit B-1: Appendix 9, Schedule 20; Appendix 12; Appendix 17 Additional Information

43.1 In reference to Appendix 9, Schedule 20, line 3, the commercial sales revenues appear to be hard-coded numbers. Please show the calculations for the commercial sales revenues for each of 2016 and 2017. The calculation should clearly show and link to schedules with any commercial load forecasts multiplied by the sales unit rate.

It appears the figures contained in Appendix 9 (paper model) do not precisely match the figures contains in schedule 12 (electronic model), which also do not precisely match the figures contained in Appendix 17 (cost allocations).

43.2 Please clarify which figures CE are seeking approval for and provide updated models which cross reference accurate figures. (For example, refer to plant in service, total revenue requirement, total revenues, and RDDA balances.)

B. DEMAND FORECAST

Reference: NEFC DEMAND FORECAST 44.0Exhibit B-1: Section 2.3, p. 19; Section 2.1, p. 17; Section 5.6, p. 64; Appendix 9 NEFC Build-out Schedule

On page 17 of the Application, CE states: “The demand forecast for NEFC reflects the forecast of connected floor area and the average expected Energy Use Intensity (EUI) for new development in NEFC under average weather. The forecast of NEFC hot water sales has not changed since the NEFC CPCN Application.”

44.1 Please complete the table below and provide both a softcopy (Excel tab 2. NEFC Demand Forecast and hardcopy response.

44.1.1 Please confirm that at this time, there are still no changes in the expected timing or nature of each of the customers forecasted to connect to the NEFC during 2016 and 2017.


44.1.1.1 If not confirmed, please provide a detailed update of the situation as well as an updated NEFC demand forecast and identify any changes to the corresponding NEFC revenue requirement schedules as set out in Appendix 9 of the Application.

44.2 Please explain the impact, if any, on the rates as proposed on page 64 of the Application, and the RDDA, if the NEFC demand forecast was to (a) increase or (b) decrease during 2016 and 2017.

44.3 Please explain the impact, if any, to steam customers, if the NEFC loads do not materialize as expected in 2016 and 2017.

44.4 If the in-service date for the NEFC is delayed and there are additional costs incurred, how does CE propose to handle any incremental costs above the currently proposed revenue requirements for NEFC? For 2016? For 2017?

44.5 How, if at all, will the outcome of the NEFC NEA amendments proceeding currently before the Commission impact the ability of the NEFC TES to move forward and/or any of the forecasts for NEFC put forward in the Application?

44.6 Please update Table 2 on page 19 of the Application to include a row showing how much demand in M# of steam will be required for NEFC based on the current Demand Forecast for NEFC.

C. OPERATING AND MAINTENANCE EXPENSE – DIRECTLY ATTRIBUTABLE

Reference: O&M 45.0Exhibit B-1: Appendix 9, Schedule 14; Exhibit B-1, Section 5.4.2, p. 61; Section 5.5.1, p. 62; Appendix 1, Schedule 15 Exhibit B-1-3, Appendix 12, Schedule 14 Operation and maintenance expenses

Page 68 of the NEFC CPCN decision2 states: “The Panel makes no determination on Creative Energy’s forecasts for direct operating costs at this time. While the Panel finds the various categories of direct operating costs to be reasonable, it considers it most appropriate to review the forecast amounts, and methods for determining these amounts, in the context of a rate application. Accordingly, the Panel directs Creative Energy to file an updated forecast for direct operating costs, as well as a detailed explanation of the proposed method for determining each type of operating cost, as part of the rate application for the NEFC.” [Underline added]

On page 61 of the Application, CE provides an estimate of the NEFC direct O&M costs as $92,000 for 2016 and $188,294 for 2017.

2 BCUC Decision for CE NEFC NES CPCN Application, p. 68,

http://www.bcuc.com/Documents/Proceedings/2015/DOC_45224_12-08-2015_CreativeEnergy_NES-NEFC-CPCN_Decision.pdf




45.1 Please comment on whether or not CE considers that it has fully complied with the Commission’s NEFC CPCN directive on O&M given that CE has not provided a detailed explanation of the proposed method for determining each type of direct O&M cost for NEFC nor provided details or the methodology for allocating the costs.

45.1.1 Please provide the direct O&M information as directed in the NEFC CPCN decision.

45.1.2 Please ensure that you address schedule 14 of Appendix 9. For each line item that is greater than $5,000 for each of 2016 or 2017, please provide a general description of the costs, what are the cost drivers, and provide additional explanations for any costs that increases more than 10 percent from 2016 to 2017.

45.1.2.1 In your response, please provide additional breakdown of the following cost items and further explanation and justification:

• Acct# 870 Supervision and Labour;

• Acct# 880 Other Distribution Operations;

• Acct# 910 Sales Expense;

• Acct# 932 Maintenance of General Plant.

Exhibit B-1, Appendix 1, Schedule 15, show total O&M of $4,541,000 and $4,642,800 in 2016 and 2017 respectively.

45.2 Please confirm, or explain otherwise, that the $92,000 and $188,000 NEFC costs are included in the total O&M of $4,541,000 and $4,642,800 in 2016 and 2017.

In the NEFC CPCN application on page 75 under Table 19, CE forecasts that the non-fuel operating costs will increase from $63,000 in the initial year 2016, to $101,000 in 2017, and finally to $181,000 by year 20203. In the current Application on page 62, costs from the NEFC CPCN application listed as “Other O&M” costs are recalled to be $65,000 in 2016 and $108,000 in 2017.

45.3 Please confirm that Other O&M costs and non-fuel operating costs are the same items.

45.4 Please provide an explanation for the variance between O&M costs provided in this Application versus the CPCN application.

45.5 Please provide an updated O&M costs table as was done under Table 19 in the NEFC CPCN application showing the forecast costs from 2016 to 2020.

3 Creative Energy CPCN Application for NEFC, Exhibit B-1, p. 75,

http://www.bcuc.com/Documents/Proceedings/2015/DOC_43609_B-1_CreativeEnergy_NES-NEFC-CPCN-Appl.pdf



D. TAXES

Reference: TAXES 46.0Exhibit B-1, Appendix 9; Section 3.5.2, p. 36; Appendix 17 Municipal Taxes

On page 36 of the Application CE states that “Included in the Variable Portion of the Total Fee above is $1,800 for 2016 and $10,300 for 2017 on account of incremental Municipal Taxes from NEFC. It is calculated as 1.25% of total revenues from all the NEFC customers of $136,000 for 2016 and $768,000 for 2017, respectively. These amounts represent an incremental and directly assignable cost of the NEFC NES.”

46.1 Please explain why none of the fixed portion of the Municipal Taxes has been allocated to NEFC in 2016 and 2017?

46.2 Please discuss the municipal tax rate and whether there is any anticipation that this may change throughout the period of which the levelized rates are being calculated in Appendix 17.

46.3 Please discuss the possibility that the fixed portion of the Municipal Taxes my increase due to NEFC over the period of which the levelized rates are being calculated in Appendix 17.

E. DEPRECIATION EXPENSE

Reference: DEPRECIATION EXPENSE 47.0Exhibit B-1, Section 3.7.1, pp. 39-40, Section 5.4, p.60 Useful Life of NEFC Equipment

On page 39 of the Application, CE states: “Creative Energy uses a ‘pooled’ or asset class depreciation approach, as opposed to depreciating individual assets. Under the asset class approach, all the capital additions to Utility plant are categorized and assigned to a specific asset class with its own specific depreciation rate. This depreciation rate is then applied to the asset class balance at arriving at the total annual depreciation expense for such class.”

On page 60 of the Application, CE states “Direct assignment costs to NEFC include depreciation and earned return (for converter stations, hot water distributions and energy transfer stations)…”

47.1 Is CE requesting Commission approval for the depreciation rates for NEFC’s plant in service or is CE proposing to use the steam service’s pooled assed depreciation rates as shown on page 40 of the Application?

47.1.1 If not using the rates shown of page 40, how was the expected life of each NEFC asset determined? Specifically, what is the expected life of the converter stations, hot water distributions and energy transfer stations, and any other NEFC specific asset?

47.1.2 If using the rates shown of page 40 which class is CE proposing the converter stations, hot water distributions and energy transfer stations, and any other NEFC specific asset fall under?


F. ALLOCATION OF COSTS – GENERAL

Reference: ALLOCATION OF COSTS – GENERAL 48.0Exhibit B-1: Section 5.3, p. 55 Stream A TES Cost

On June 18, 2015 via Order G-101-15,4 the Commission granted CE’s 188 Keefer Street TES a Stream A status per the TES Guidelines.

48.1 Given that CE has only identified two classes of service, please explain where the costs of the 188 Keefer Street Stream A TES (Keefer TES) are recorded.

48.1.1 Are any of the costs for the Keefer TES included in the revenue requirements ‘Totals’ shown on page 21 of the Application?

48.1.1.1 If yes, please explain why and quantify.

48.1.2 Are any of the capital assets for the Keefer TES included in steam services’ plant in service or NEFC’s plant in service?

Reference: ALLOCATION OF COSTS – GENERAL 49.0Exhibit B-1: Section 5.3, pp. 55-59; Section 1.0, pp. 5-6

Page 55 of the Application states that “Steam Costs Allocation of NES can be calculated based on… Steam Production… Steam Distribution… and Corporate overheads.”

Page 59 of the Application shows the following total allocation to NEFC:

• Steam production $13,000 in 2016 and $71,400 in 2017;

• Steam distribution $2,600 in 2016 and $14,200 in 2017;

• Corporate overheads $63,600 in 2016 and $177,500 in 2017.

49.1 Based on these same classifications what is the total (entire steam system and NEFC included) steam production cost, steam distribution cost, and corporate overheads cost for 2016 and 2017?

49.1.1 What would they have been in 2015 without consideration of NEFC?

On page 56 of the Application CE states that it has uses ‘Steam Consumed by NEFC’ as the cost driver for Steam Production and of page 57 of the Application CE states that is has used ‘Energy Delivered’ for Steam Distribution. Further on page 56 of the Application, CE states its methodology allocates costs to NEFC for Steam Production based on NEFC’s share of steam production at the Beatty Street plant gate.

49.2 Please explain the difference between steam consumer, steam production and energy delivered?

4 BCUC Order G-101-15, http://www.ordersdecisions.bcuc.com/bcuc/orders/en/120220/1/document.do

http://www.ordersdecisions.bcuc.com/bcuc/orders/en/120220/1/document.do


49.2.1 Please explain the potential other cost drivers explored by CE to be reasonable for allocating distribution costs and production cost. For example, why not the length of distribution line or some other cost driver?

49.3 Please discuss if CE’s allocation methodology for steam production, steam distribution, corporate overhead and NES Fuel Recovery Cost Allocation is based purely on incremental costs.

49.3.1 If yes, is CE proposing that any other costs, in addition to incremental costs, be allocated to NEFC.

49.3.1.1 If not, please explain why a pure incremental approach is appropriate in the context of fairness to steam service customers.

CE states on page 5 of the Application that “This approach avoids the need for brand new gas boilers to serve NEFC while also providing benefits to existing steam customers by allocating fixed system costs over a larger customer base.”

49.4 If CE is proposing an incremental cost allocation approach for NEFC, please explain how steam customer will benefit.

49.5 Please explain how NEFC Hot Water is different from any other customer requiring steam service.

On page 6 of the Application, CE states” “NEFC marks the first step in a much longer-term vision that would see hot water service extend to other areas of downtown and the introduction of new low carbon energy sources.”

49.6 In the near term future, does CE anticipate adding additional classes of service in addition to NEFC?

49.7 If CE is planning of expanding its business and likely adding on more classes of service such as Chinatown, how sustainable is CE proposed allocation methodology under a multiple class of service utility?

49.8 For any costs that are not directly attributable, please discuss the possibility of allocating the corporate overhead costs between the steam class of service and the hot water class of service and then treating the core steam customer as one customer class and NEFC hot water as another customer class serviced out of the steam class of service division. For clarity that would mean performing a simplified cost of service allocation between the core steam customer class and the NEFC class out of the steam class of service’s revenue requirement. NEFC would then be charged a steam rate based on the rate for its class of customer, which would be treated as an expense in NEFC’s revenue requirements.


49.8.1 In discussing this possibility please address how this would impact the shifting of any

NEFC forecasting risks from core steam customers to NEFC hot water customers.

49.9 Please explain how CE proposed utility structure and allocation methodology compares to Corix Multi-Utility Services Inc. who operates as one utility with multiple classes of service?

49.10 Is CE aware of any other TES who has a utility structure and allocation methodology similar to the one it is proposing in the Application?

49.11 Does CE anticipate summarizing and formalizing the allocation methodology in a standalone document once approved?

49.12 Is CE requesting approval for the proposed allocation methodology indefinitely (i.e. until a change is applied for) or for the 2016 and 2017 test periods only.

L. STEAM COST ALLOCATION – STEAM PRODUCTION

Reference: ALLOCATION OF COSTS 50.0Exhibit B-1, Section 5.3, pp. 56-57; Appendix 17 Steam Production

On page 56 of the Application, CE lists various items that are included in the steam production cost pool.

50.1 How is NEFC’s share of the steam production at the Beatty Street plant gate determined?


50.2 Please explain what “component” of CE’s general plant is allocated to steam production (as stated in footnote 21 and 22).

50.3 In Appendix 17, the production unit cost for steam appears to be $2.32/M#. Please provide the calculation for the unit production cost for the hot water system. Please explain why this should not be the same.

50.4 Please provide a formula and corresponding numerical values showing how the steam production cost of $13,000 in 2016 and $71,400 in 2017 was arrived at.

M. STEAM COST ALLOCATIONS – STEAM DISTRIBUTION

Reference: STEAM COST ALLOCATIONS 51.0Exhibit B-1, Section 5.3, p. 56 Steam Distribution Map and Losses

On page 56 of the Application, CE states: “For the Steam Production, the appropriate cost allocation driver is steam consumed by NEFC. Because steam network losses are a function of steam system length, the addition of the NEFC hot water network does not add incremental losses to the steam system.”

51.1 Please provide a map containing both CE’s existing Steam Service area and the NEFC hot water service area. On the map, please highlight:

51.1.1 The Beatty Street steam plant;

51.1.2 The location of each of the two NEFC steam to hot water converter stations;

51.1.3 The pipeline connections from the steam plant to each of the two steam to hot water converter stations; and

51.1.4 The length, in metres of the pipeline from the steam plant to the hot water converter stations.

51.2 Please indicate on the map, the losses that occur along the pipeline between the Beatty Street steam plant and the steam to hot water converter stations.

51.3 Please confirm that the length from the steam production plant to the two steam and hot water converters is too short to incur steam losses. If not confirmed, please provide reasons.


Reference: STEAM COST ALLOCATIONS 52.0Exhibit B-1, Section 5.3, p. 58 Steam Distribution Map and Losses

On page 58 of the Application, CE includes Table 22 which provides the allocation of distribution costs for the steam distribution pool. Table 22 is shown below.

52.1 Please confirm, or otherwise explain, that the total pounds of steam consumed that was grossed up to the plant gate production, accounts for the losses in the steam network for existing customers.

Reference: STEAM COSTS ALLOCATIONS 53.0

Exhibit B-1, Section 5.3, pp. 57-58; Appendix 17 Steam distribution

CE states that “allocating NEFC customers the full unit cost of steam distribution service, plus 100% of the cost of the new hot water network infrastructure in NEFC, would constitute pancaking and would not be a fair allocation of costs.”

53.1 Please further explain the above statement concerning pancaking of costs for NEFC. What is CE’s definition of “pancaking”?

53.2 What is CE’s response to concerns that there may be unfair cost retained by steam customers if the full unit cost of steam distribution is NOT allocated to NEFC? Provide numeric calculations to support your response and justification of “pancaking”.

CE explains that alternative distribution cost allocation methodology is, first determine the share of distribution system used to serve NEFC Hot Water network; then second, determine the share of steam consumption within those lines which pertain to NEFC … Set NEFC’s cost allocation as [total distribution system costs] x [% of system relied on 9 by NEFC] x [NEFC steam flow through relevant lines / total steam flow in relevant lines]

53.3 Given that the first step in the methodology is to determine the “share of distribution system used to serve NEFC Hot Water network,” is it not reasonable then to preclude that all of the steam consumption of those lines are directly related to NEFC? Why is it necessary to further determine the “share” of steam consumption within those lines? Please explain and provide a numeric example for support your explanation.

53.4 In Appendix 17, the distribution unit cost appears to be $0.46/M#. Please provide the calculation for the unit distribution cost for the hot water system. Please explain why this should not be the same?


53.4.1 What would the unit cost ($/M#) be if the full unit cost of steam distribution was allocate to NEFC?

Table 22 on page 58 of the Application shows that of the total 1,073,629 pounds of steam consumed, NEFC only consumed 5,629 Pounds, equivalent to 0.52% of total.

Commission Staff interprets the NEFC cost allocation to be [Share of Distribution System Used by NEFC * Steam Consumption of NEFC within Relevant Lines * Total Distribution Systems Costs], or expanded to be the following formula:

𝑁𝑁𝑁𝑁 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑁𝐷𝐷𝐷 𝐴𝐴𝐴𝐷𝐴𝐴𝐷𝐷𝐷𝐷

= �𝐷𝐷𝐷𝐷𝐴𝐷𝐴𝐷 𝐷𝑜 𝑅𝐷𝐴𝐷𝑅𝐴𝐷𝐷 𝐿𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐷𝐴𝐷 𝐷𝑜 𝑇𝐷𝐷𝐴𝐴 𝐿𝐷𝐷𝐷𝐷

∗ 100%�

∗ �𝑁𝑁𝑁𝑁 𝑆𝐷𝐷𝐴𝑆 𝑁𝐴𝐷𝐹 𝑇ℎ𝐷𝐷𝐷𝑟ℎ 𝑅𝐷𝐴𝐷𝑅𝐴𝐷𝐷 𝐿𝐷𝐷𝐷𝐷𝑇𝐷𝐷𝐴𝐴 𝑆𝐷𝐷𝐴𝑆 𝑁𝐴𝐷𝐹 𝑇ℎ𝐷𝐷𝐷𝑟ℎ 𝑅𝐷𝐴𝐷𝑅𝐴𝐷𝐷 𝐿𝐷𝐷𝐷𝐷

∗ 100%�

∗ (𝑇𝐷𝐷𝐴𝐴 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑆𝑆𝐷𝐷𝐷𝑆 𝑁𝐷𝐷𝐷𝐷)

53.5 Please confirm the above formula is correct.

53.5.1 If confirmed, please provide the numerical values of each input to the formula for 2016 and 2017.

53.5.2 If formula is incorrect, please provide the correct formula along with the appropriate numerical values of each input to the formula for 2016 and 2017.

N. STEAM COST ALLOCATIONS – CORPORATE OVERHEAD

Reference: STEAM COST ALLOCATIONS 54.0Exhibit B-1, Section 5.3, pp. 58-59 Corporate overhead

On page 65 of the NEFC CPCN decision, the Commission directed CE to provide more clarity on the cost causation of the parameters of the Massachusetts formula, including a confirmation of whether the proposed methodology has been reviewed by its auditors.

54.1 Please clarify whether the Massachusetts formula and its cost drivers have been reviewed by any external party such as CE’s auditors.

54.1.1 Is so, please provide any opinions or comments CE received.

54.2 In the NEFC CPCN CE was directed to provide more clarity on the cost causation of components in corporate overhead, CE’s explanation on page 58 of the Application appears to be the same as that previously provided in the CPCN proceeding. Please explain how each of the cost drivers (relative size of utility plant, relative size of revenues, and relative size of direct labour distribution) are appropriate cost drivers for the corporate overhead cost pool.

54.2.1 Please explain why the average of the 3 cost drivers is appropriate versus, say, any one particular cost driver that is mostly attributable?

54.2.2 To the best of CE’s knowledge is it standard practice to average the Massachusetts formula’s cost pools? If yes, please provide examples.


54.2.2.1 If not, please provide CE’s rationale for using such an approach.

54.3 Please provide the detailed calculation for corporate overheads of $63,600 in 2016 and $177,500 in 2017 as set out on page 59 of the Application.

In IR 15.9 (Exhibit B-6 in the NEFC CPCN proceeding), CE explains that corporate costs are “dedicated resources such as IT Support, Financial Reporting, Human Resources, Insurance and General Building Maintenance, etc. that provides process or knowledge-based services to each business unit within the Company.”

On page 58 of the Application, CE states that the “Corporate Overheads Pool” can be thought of as a “catch all bucket” that captures all other revenue requirement items (excluding direct NEFC costs.”

54.4 Please explain whether there is a fundamental change in the methodology of the corporate cost pool since the NEFC CPCN.

O. NES FUEL RECOVERY COST ALLOCATION

Reference: NES FUEL RECOVER COST ALLOCATION 55.0Exhibit B-1, Section 5.3.1, pp. 59-60; Creative Energy NES NEFC CPCN proceeding, Exhibit B-6, BCUC IR 1.14.8, pp. 39-41; BCUC IR 1.14.9, pp. 41-42; Exhibit B-6-1, Appendix 4, p. 8; Exhibit B-22, BCUC IR 2.91, p. 23; BCUC IR 2.10.3, pp. 29-31; BCUC IR 2.10.4, p. 31 Formula

55.1 CE appears to uses NES and NEFC interchangeably. Please explain why.

55.1.1 Specifically, please explain why the allocator is called NES and not NEFC? Please consider amending.

55.2 How is the $.41 cent Base Costs Fuel Expense allocated to NEFC?

55.2.1 If NEFC actual demand is different from forecast demand in either of the test years who absorb the cost difference for the Base Cost Fuel Expense: (a) steam customers; (b) the shareholder; or (c) NEFC customers through the RDDA?

55.2.1.1 If not (c) please explain.

On pages 59 and 60 of the Application, CE states: “The allocation is based on using a formula to calculate the incremental amount of fuel consumed at the Beatty Street plant to serve NEFC. For any period, this formula calculates a volume of fuel in GJ. This fuel volume is multiplied by the total unit cost of fuel at Beatty Street, including all carbon taxes, delivery charges, etc. and before the allocation of a share of fuel costs to the Steam Rates (as has been historically done).”


CE then presents the formula as follows:

In Exhibit B-6 of the Creative Energy NES NEFC CPCN proceeding, CE provided information regarding the NEFC Fuel Recovery Cost Allocation. The following formula was provided in response to BCUC IR 1.14.8 on page 39.

55.3 Please confirm, or update with explanations where necessary, that the following information from the CEVP NES NEFC CPCN proceeding remains true.

55.3.1 Exhibit B-6, BCUC IR 1.14.8, pp. 39-41.

55.3.2 Exhibit B-6-1, Appendix 4, p. 8, NEFC NES Metering Concept.


55.3.4 Exhibit B-22, BCUC IR 2.9.1, p. 23.


55.3.6 Exhibit B-22, BCUC IR 2.10.4, p. 31.

55.4 Please provide step-by-step calculations using both formulas outlined in the preamble to show how CE determined:

(i) the amounts of GJ to be allocated to NEFC NES to be 8,500 GJ in 2016 and 45,100 GJ in 2017 as shown on page 60 of the Application; and

(ii) the corresponding NES Fuel Recovery Cost Allocation for each of 2016 and 2017.

55.5 Please confirm, or otherwise explain, that a portion of the savings from the Clear Sky energy conservation equipment is proposed to be allocated to the NEFC system.

55.5.1 Please provide details of the amount allocated to NEFC and what the allocation was based on.

55.6 Please explain why the base cost of $.41 and the amount recorded in the Fuel Cost Stabilization Account cannot be allocated to NEFC as part of one allocation.


P. DEFERRAL ACCOUNTS

Reference: DEFERRAL ACCOUNTS 56.0Exhibit B-1, Section 5.6, p. 63; Appendix 9, Schedule 12 Revenue Deficiency Deferral Account (RDDA) Controllable and non-Controllable Costs

On page 59 of the NEFC CPCN decision, CE’s RDDA was to smooth rates during the initial years in which revenue shortfalls will be recorded. Then, as the load develops and revenues grow, the accumulated balance in the RDDA will be drawn down to zero. At the time of the CPCN proceeding, the RDDA was anticipated to grow to a peak balance of $1.1 million in year 2020 and be fully recovered over a 15-year period (by the year 2030).

If the NEFC CPCN CE’s proposal was to use the RDDA to accumulate forecast revenue shortfalls, but not to allow recovery of variances in controllable costs, such as “typical maintenance and operator costs.” Variances between forecast and actual non-controllable costs were proposed to be recorded in the RDDA. CE suggested that non-controllable costs would include “capital costs, loads, allocated costs, taxes and sustaining capital costs.”

On page 64 of the Application, CE states that it “now proposes that the difference between forecast revenue requirements, adjusted for actual fuel expenses, and actual revenues be recorded in the RDDA.”

56.1 Please clarify whether CE is seeking to vary or reconsider of the Commission determination of the RDDA in accordance with section 99 of the UCA?

56.2 Please explain the reason for the fundamental changes in the RDDA method currently being sought in the Application.

56.3 Given CE’s new proposal to record the difference between “forecast revenue requirements, adjusted for actual fuel expenses, and actual revenues be recorded in the RDDA” doss this imply that CE is requesting that there be a full true up of all costs incurred by CE other than fuel costs? Please discuss.

56.4 Is CE aware of any other district energy system, with levelized rate calculations, which utilizes an RDDA treatment to levelize costs and capture all variances as request by CE in the Application?

In response to BCUC IR 25.1 (Exhibit B-6 in the NEFC CPCN proceeding), CE provided a list of controllable and non-controllable cost items in the NEFC revenue requirement. It appears that only 2 cost items were previously considered “controllable” (equipment and maintenance and administration) while 1 cost item (Insurance) was considered semi-controllable.

On page 60 of the NEFC CPCN decision the Commission acknowledged CE’s proposed treatment and classification of controllable and non-controllable costs with regards to recording variances between forecast and actual amounts in the RDDA; however, the Commission deferred any determination on this issue to the rates application.

56.5 If the Commission were to approve a separate deferral account to capture variances in non-controllable costs, rather than using the RDDA, specifically what non-controllable costs should the variance deferral account capture? For each item, please explain why the cost is considered to be non-controllable.


56.6 What would be an appropriate amortization period and carry cost for such a NEFC variance deferral account?

56.7 Please discuss the pros and cons of having a separate variance deferral rather than using the RDDA.

Appendix 9, Schedule 12, show the RDDA continuity schedule. It appears that CE annual amortization of the RDDA is equivalent to the annual Interest/AFUDC addition.

56.8 Please explain why the amortization on the RDDA is forecast to be equal to the annual interest/AFUDC addition in each of the test years.

56.9 Please confirm, or explain otherwise, that the interest/AFUDC on the RDDA is bases on CE’s WACC as directed on p. 59 of the CPCN Application.

Q. RATE BASE – PLANT IN SERVICE

Reference: RATE BASE - PIS 57.0Exhibit B-1, Appendix 1, Schedule 4; Exhibit B-1-3, Appendix 12, Schedule 3; Exhibit B-1-6, Appendix 11A NEFC Plant Additions

Appendix 12, Schedule 3 shows the NEFC Plant in Service forecast expenses for 2016 and includes Account Names: Intangible Plant, Steam Production Plant, Distribution Plant, General Plant, and Undistributed Plant. Appendix 12, Schedule 3 for NEFC Plant in Service shows the same Account Names as in Appendix 1, Schedule 4 of the Application for the Steam Plant in Service.


In the NEFC CPCN application for NEFC on page 60, CE explains that there are three major capital costs for the NEFC: the S2HW converter stations, the hot water distribution pipe system (DPS) and the energy transfer stations (ETS). There are also 90 m of incremental steam line constructed from existing steam mains to each of the two S2HW converters.5 In Tables 6 and 7, the capital cost estimates are provided in 2015 dollars and in nominal dollars.

From the above tables, the estimated total NEFC capital cost for 2016 is $3,326,000. On page 33 of the NEFC CPCN decision, the Commission found that “the Project capital cost estimates are acceptable.”6

57.1 Please explain why the NEFC Plant in Service spreadsheet and the Steam Plant in Service spreadsheets have the same Account Names.

57.2 Please confirm that NEFC’s Plant in Service totals are not also included in Steam’s Plant in Service.

57.3 Please explain why the NEFC Plant in Service spreadsheet does not include Account Names and additions under its own equipment categories such as S2HW Converter Stations, Steam Line Extensions, distribution pipe system, energy transfer stations, etc.

Under Appendix 11A NEFC Plant Additions, the 2016 and 2017 forecast NEFC Plant Additions totals come from accounts 107376 and 107387. For 2016, account 107376 is said to be $593,767 and account 107387 is said to be $2,615,020. The total NEFC NES Plant Additions are shown to be $3,208,787.

Appendix 12 Schedule 3 shows the 2016 NEFC Plant in Service with Additions to Distribution Plant – Mains as $601, 692 and Distribution Plant – Other Distribution Equipment as $3,315,158. The total Additions expected in 2016 are said to be $3,916,849.


http://www.bcuc.com/Documents/Proceedings/2015/DOC_43609_B-1_CreativeEnergy_NES-NEFC-CPCN-Appl.pdf 6 BCUC Decision for CE NEFC NES CPCN Application, p. 33,






57.4 Please confirm that estimated total NEFC capital cost for 2016 accepted in the NEFC CPCN decision ($3,326,000), the Total NEFC Plant additions referred to in Appendix 11A ($3,208,787), and the Total Additions calculated in Appendix 12 Schedule 3 ($3,916,849), are all referring to the same item.

57.4.1 If confirmed, please explain the dollar variance in these items.

57.4.2 If not confirmed, please explain how each of these items is different.

57.5 For 2016, please confirm Appendix 11A’s account numbers 107376 ($593,767) and 107387 ($2,615,020) are referring to Distribution Plant – Mains ($601,692) and Distribution Plant – Other Distribution Equipment ($3,315,158) in Appendix 12 Schedule 3 respectively.

57.5.1 If confirmed, please explain the dollar variance in these items.

57.5.2 If not confirmed, please explain how each of these items is different.

Reference: ACCUMULATED DEPRECIATION 58.0

Exhibit B-1, Appendix 1, Schedule 5; Exhibit B-1-3, Appendix 12, Schedule 4 NEFC NES Plant Additions

Appendix 12, Schedule 4 shows the NEFC Accumulated Depreciation forecast expenses for 2016 and includes Account Names: Intangible Plant, Steam Production Plant, Distribution Plant, General Plant, and Undistributed Plant. Appendix 12, Schedule 4 for the NEFC Accumulated Depreciation shows the same Account Names as in Appendix 1, Schedule 5 of the Application for the Steam Accumulated Depreciation.

In the NEFC CPCN application on page 60, CE explains that there are three major capital costs for the NES: the S2HW converter stations, the hot water distribution pipe system (DPS) and the energy transfer stations (ETS). There are also 90 m of incremental steam line constructed from existing steam mains to each of the two S2HW converters.7

58.1 Please explain why the NEFC Accumulated Depreciation spreadsheet and the Steam Accumulated Depreciation spreadsheets have the same Account Names.

58.2 Please explain why the NEFC Accumulated Depreciation spreadsheet does not include Account Names and additions under its own equipment categories such as S2HW Converter Stations, Steam Line Extensions, distribution pipe system, energy transfer stations, etc.





R. RATE DESIGN

Reference: RATE DESIGN 59.0Exhibit B-1, Section 5.6, p. 63 Fixed and Variable

On page 68 of the NEFC CPCN decision, the Commission approved the proposed two-part rate design consisting of a 37 percent fixed charge and a 63 percent variable energy recovery charge based on a share of fixed and variable indicative costs. In this Application, CE proposes to adopt a more simplistic approach of 50 percent fixed/50 percent variable rate as “this is reasonable close to the underlying cost structure and is simple to communicate to customers.”

59.1 What is CE’s rationale for concluding that a simplistic 50 percent fixed/50 percent variable rate design is appropriate?

59.2 For 2016 and 2017 please provide a detailed calculation to support the NEFC hot water rates set out in the table on page 64 of the Application. Please ensure that the numbers tie into the revenue requirement on page 61 of the Application, the demand forecast for NEFC, and the RDDA as set out in the Application.

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