decision dated december 8, 2015. this application includes ... … · with directives found in the...

April 1, 2016

Via Email

Ms. Laurel Ross

Acting Commission Secretary

BC Utilities Commission

Sixth Floor, 900 Howe Street, Box 250

Vancouver, BC V6Z 2N3

Dear Ms. Ross:

Re: CE Application – 2016-2017 Revenue Requirements Application and Rate Design for

NEFC Hot Water Service

Creative Energy applies to the Commission for approval to increase steam rates by 6.23%

effective May 1, 2016, on an interim and final basis, and by 6.23% effective January 1, 2017, on

an interim basis, pending a final Commission decision regarding the revenue requirements for

the Test Period 2016 and for the Test Period 2017. Creative Energy also applies to the

Commission for approval of Northeast False Creek (NEFC) hot water rates effective August 1,

2016, on an interim and final basis, and January 1, 2017, on an interim basis, pending a final

Commission decision regarding the revenue requirements for the Test Period 2016 and Test

Period 2017.

Creative Energy continues to be one of the lowest cost suppliers of energy to its customers, and

expects to continue to keep rate increases low and predictable while investments are being made

to provide hot water service to NEFC customers. This Application is being filed in compliance

with Directives found in the 2015-17 RRA Decision dated June 9, 2015 and found in the NEFC

Decision dated December 8, 2015. This Application includes Creative Energy’s updated cost

allocations between the existing steam system and new NEFC hot water system.

By a letter of the same date, Creative Energy has filed a “Compensation Benchmarking Report”

dated March 18, 2016 from HayGroup as Appendix 7 to the Application together with certain

related information. Creative Energy requests the section of the Report identified as “Findings

by Role” be held in confidence because it discloses salary information of senior management

employees. The release of salary information identified by employee could be harmful to both

Creative Energy and the employee. The section of the Compensation Benchmarking Report that

does not disclose salary information by employee, namely, “Background” and “Methodology” is

being filed with this Application. These documents and information are being filed in

accordance with the Rule of Practice and Procedure.

B-1

markhuds

CREATIVE ENERGY 2016-17 RR RD

Yours truly,

Stacey Bernier

President & CEO

cc: Interveners in the 2015-17 Revenue Requirements Proceeding

City Builders

Energy Innovators

Creative Thinkers

2016-2017 REVENUE REQUIREMENTS APPLICATION AND

RATE DESIGN FOR NEFC HOT WATER SERVICE

April 1, 2016

CREATIVE ENERGY VANCOUVER

PLATFORMS INC.

Suite 1 – 720 Beatty Street 604 688 9584 TEL

Vancouver, Canada 604 688 2213 FAX

V6B 2M1 creativeenergycanada.com

CREATIVENERGY’s 2016 Revenue Requirement Application Date

1

Contents

1 INTRODUCTION AND CORPORATE OVERVIEW ................................................................. 5

2 DEMAND FORECAST ..................................................................................................... 17

3 REVENUE REQUIREMENTS AND RATES .......................................................................... 20

Fuel Expense Forecast Methodology .................................................................... 24

Steam Production Expenses ................................................................................. 31

Steam Distribution Expenses ................................................................................ 31

SG&A Expenses ..................................................................................................... 32


2

Municipal Taxes (City of Vancouver Access Fee) .................................................. 34

NEFC Municipal Taxes ........................................................................................... 36

Property Taxes ...................................................................................................... 36

Income Taxes ........................................................................................................ 37

Equity Thickness and Allowed Return on Equity .................................................. 42

Debt Financing ...................................................................................................... 43

4 RATE BASE AND CAPITAL ADDITIONS (Schedule 2) ........................................................ 44

Regular Capital Additions...................................................................................... 45

Allowance for Funds Used During Construction (AFUDC) .................................... 45

Capitalized Overheads .......................................................................................... 45

Plant Retirements ................................................................................................. 46

Accumulated Depreciation ................................................................................... 46

Methodology ........................................................................................................ 48


3

Special Services Deferral Account ......................................................................... 51

Overheads Capitalized – 2016 Study .................................................................... 52

5 NEFC REVENUE REQUIREMENTS ALLOCATION & RATE DESIGN ...................................... 53

NES Fuel Recovery Cost Allocation ....................................................................... 59

NEFC Capital Additions and Associated Costs ...................................................... 60

NEFC Direct O&M ................................................................................................. 61

Variances from NEFC CPCN Proceeding................................................................ 62

6 APPENDIX 1 REVENUE REQUIREMENTS SCHEDULES ..................................................... 66

7 APPENDIX 2 FUEL COST STABILIZATION ACCOUNT ..................................................... 106

8 APPENDIX 3 NEFC MODEL ......................................................................................... 111

9 APPENDIX 4 COMMISSION DIRECTIVES..................................................................... 112

10 APPENDIX 5 DRAFT ORDER – INTERIM RATES ......................................................... 117

11 APPENDIX 6 DRAFT ORDER – FINAL RATES ............................................................... 121

12 APPENDIX 7 HAYGROUP REPORT (SECTIONS: “BACKGROUND” & “METHODOLOGY” ... 124


4


5

1 INTRODUCTION AND CORPORATE OVERVIEW 1

Creative Energy Vancouver Platforms Inc. (Creative Energy or the Company) is a thermal energy 2

utility whose rates are regulated by the British Columbia Utilities Commission (BCUC or the 3

Commission). The Company is a wholly owned subsidiary of Creative Energy Platforms Canada 4

Corp. In 2014, Creative Energy acquired and rebranded Central Heat Distribution Ltd. (CHDL). 5

CHDL was established and began operations of a steam production plant and distribution 6

network in downtown Vancouver under a CPCN granted by the BCUC in 1968. At the time, 7

district energy was well established in many older cities around the globe, and was also common 8

at large institutions in B.C. But the concept was new to downtown Vancouver. At the time, 9

many buildings in downtown were still using fuel oil and some were still using coal. The new 10

system helped improve local air quality. The steam system grew steadily as building owners 11

recognized the benefits of a clean and highly reliable shared heating system. Creative Energy 12

has maintained a reliability rate of 99.9% over its 48 year history. 13

Creative Energy currently provides steam service to approximately 200 customers. With this 14

Application, Creative Energy will commence the next step in its evolution of service to 15

customers. In the third quarter of 2016, Creative Energy will begin providing hot water service 16

to the Northeast False Creek (NEFC) neighbourhood pursuant to a CPCN granted by the 17

Commission on December 8, 2015. Under the terms of a new franchise agreement (the 18

Neighbourhood Energy Agreement or NEA) with the City of Vancouver (CoV or the City), the 19

new hot water system in NEFC will eventually incorporate a new low carbon energy supply. The 20

amended NEA is the subject of a proceeding currently before the BCUC. Planning is underway 21

and low carbon energy is expected as early as 2020 once the initial developments and network 22

are completed. In the meantime, the system will be supplied entirely from the existing steam 23

network via two central steam to hot water converter stations within developments currently 24

under construction. Following the introduction of low carbon energy, the existing steam system 25

will continue to provide peaking and back-up support to NEFC. This approach avoids the need 26

for brand new gas boilers to serve NEFC while also providing benefits to existing steam 27

customers by allocating fixed system costs over a larger customer base. This represents a 28

savings for both existing steam customers and new hot water customers in NEFC. Joining these 29

networks also open up the possibility of exploring more cost-effective community-scale projects 30


6

to provide low carbon energy to customers in NEFC (new developments with mandatory low 1

carbon commitments) along with existing steam customers that may also want or need low 2

carbon energy. 3

NEFC marks the first step to a much longer-term vision that would see hot water service 4

extended to other areas of downtown and the introduction of new low carbon energy sources. 5

The NEFC Hot Water Rates sought in this Application reflect only the introduction of hot water 6

service to NEFC and do not include the introduction of any new low carbon energy sources, 7

which will be the subject of a future application to the BCUC. The Application includes the 8

proposed allocation of existing (embedded) steam costs (shared assets and overheads) between 9

existing steam customers and new customers in NEFC. The rates for NEFC also include all 10

directly assigned costs for serving NEFC (e.g. local hot water network costs, new building energy 11

transfer stations, and direct operations and maintenance costs for NEFC). 12

13

Application for an Increase to the Steam Rates 14

Creative Energy has prepared this Application in support of its request for approval of changes 15

in the existing Steam Rates and for approval of new NEFC Hot Water Rates for 2016 and 2017. 16

The total customer cost for steam service consists of two components: 1) the Steam Rates, 17

which is the portion of costs that are the subject of this Application; and 2) the Fuel Cost 18

Adjustment Charge (FCAC). The Steam Rates are intended to recover all capital-related costs 19

(e.g., depreciation, interest on debt and approved return on equity), all non-fuel operating 20

costs, and a small portion of fuel costs. The existing Steam Rates are levied on each thousand 21

pounds (M#) of steam consumed by a customer, and the Steam Rates decline with the amount 22

consumed, which is intended to reflect the declining amount of fixed costs to serve larger 23

customers vs. smaller customers. The FCAC is also levied on (M#) of steam consumed. The FCAC 24

is intended to recover the remainder of fuel costs (natural gas) required for producing steam 25

and the magnitude of the FCAC does not vary with the amount of steam consumed. Currently 26

the FCAC represents about 55% of customer bills. The FCAC is a flow through of actual fuel 27

costs and is updated from time to timed based on current gas prices and any historical variances 28


7

between actual fuel costs and recovered fuel costs. This Application includes a proposal for a 1

more formal mechanism to track variances in the fuel cost recovery and to update the FCAC. 2

Based on the forecast of steam costs of service, forecast of steam consumption and the existing 3

Steam Rates Creative Energy is forecasting a revenue deficiency of approximately ($709,000) 4

for Test Period 2016 and approximately ($391,000) for Test Period 2017. Given the revenue 5

deficiency for Test Period 2017 is lower than the revenue deficiency for Test Period 2016, 6

Creative Energy proposes to smooth rate changes by recovering a portion of the Test Period 7

2016 revenue deficiency in Test Period 2017. Otherwise, the Test Period 2016 increase 8

(exclusive of Fuel Recovery Adjustment Charge in customer bills) would be approximately 8.85% 9

and the Test Period 2017 rate increase would be 0%. 10

Creative Energy also proposes to recover the Test Period 2016 and Test Period 2017 revenue 11

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. 13

In this manner, Creative Energy will continue to assume the risks associated with load variances, 14

including the weather forecast risk. Creative Energy sought approval for certain regulatory 15

parameters in the NEFC proceeding, and received approval for some of those regulatory 16

parameters by the NEFC Decision dated December 8, 2015. For that reason, amongst others, 17

Creative Energy delayed filing this Application until the Application could incorporate the 18

determinations made in the NEFC Decision that were applicable to this Application. 19

This Application seeks approval for an increase in Steam Rates of 6.23% effective May 1, 2016 20

and 6.23% effective January 1, 2017. The increases for 2016 and 2017 are sharply lower than 21

the rate increases of the previous two years. In 2014, rates increased by 11.3% and in 2015 rates 22

increased by 10%. So as compared to the previous two years, this Application seeks approval of 23

rate increases significantly less than the previous two years. 24

The changes in previous years reflect some unique step changes in cost drivers (e.g., changes 25

in accounting treatment for pensions and changes in capital structure and return on equity for 26

thermal energy systems) and temporary cost items associated with renewal in the senior 27

management team. Many of these cost drivers are unique and one-time events. 28


8

When coupled with the FCAC, which is forecast to remain the same or slightly lower under 1

current forecasts of natural gas prices, total customer bills are actually expected to decrease 2

approximately 3.82 percent in 2016 relative to 2015 and to increase approximately 2.97% in 3

2017 relative to 2016. 4

The principle cost drivers of the Steam Rates increase in the Test Period 2016 over Test Period 5

2015 arise from the amortization of certain deferral accounts (3.46%). The other cost drivers 6

relate to two O&M expense items: labour (increase 1.89%) and third party costs (increase of 7

1.9%), including costs of increased regulatory activity. Each of these cost drivers will be 8

addressed in more detail later in this Application. In addition to changes in costs, many of 9

which are one time or temporary changes (such as adjustments for changes in pension 10

accounting rules and the recovery of deferrals for pervious changes in capital structure and 11

return on equity approved by the Commission to Thermal Energy Utilities), part of the rate 12

increase is related to decreases in existing steam loads from ongoing building upgrades and new 13

alternative energy systems. These reduced loads for existing customers are offset in part by 14

growth such as the addition of NEFC. The test period for the current Application includes some 15

cost allocations to NEFC but the full benefit of NEFC will not be seen in Steam Rates until more 16

development is completed and occupied. Only 44% of anticipated floor area will be completed 17

by the end of 2018. About 66% of development is expected to be complete by 2020 and the 18

remainder by 2025. 19

Application for New NEFC Hot Water Rates 20

This Application also includes proposed new rates for hot water service in NEFC. The underlying 21

revenue requirement for hot water service in NEFC reflects the general principles approved by 22

the Commission in its recent decision to grant a CPCN for NEFC. The revenue requirement for 23

NEFC includes a proposed allocation of steam costs to NEFC for the use of the existing steam 24

system to provide the source of hot water in the near-term, and peaking and back-up energy in 25

the long-term. This Application includes the proposed allocation of steam costs between retail 26

steam customers and NEFC hot water customers. This allocation to NEFC reduces the amount 27

of the steam revenue requirement that must be recovered in the Steam Rates. The remainder 28

of the NEFC revenue requirement is composed of direct assigned costs for the central steam to 29


9

hot water converter stations, local hot water network, new building energy transfer stations, 1

and direct operations and maintenance costs for the NEFC distribution system. 2

The proposed NEFC Hot Water Rates consist of a fixed charge and variable charge, as approved 3

in principle by the BCUC in Order C-12-15. The forecast revenues from fixed charges and 4

variable charges approximate the forecast share of fixed and variable costs in the underlying 5

revenue requirement (based on interim gas-fired energy and prior to any effect of a future low 6

carbon solution). 7

As with other new thermal energy systems, the Commission has approved a Revenue Deficiency 8

Deferral Account (RDDA) for NEFC (Order C-12-15, C, (v).). This account is intended to address 9

the different timing for the installation of infrastructure and the addition of loads. The 10

projected peak balance of the RDDA for NEFC is much smaller than other new thermal energy 11

systems, reflecting the rapid build out and use of existing assets. Proposed rates and escalation 12

factors will result in full recovery of the RDDA within the first 15 years of the system. Based 13

on the proposed NEFC Hot Water Rates and forecast NEFC revenue requirement, Creative 14

Energy is forecasting additions to the NEFC RDDA of approximately $209,400 for 2016 and a 15

further $504,500 for 2017. 16

17

Trends in Steam Charges and Comparison to Other Heating Benchmarks 18

The requested increases in Steam Rates notwithstanding, Creative Energy’s Steam Rates remain 19

highly competitive with alternatives such as on-site gas boilers. For the latter, Creative 20

Energy’s rates must be compared with the total cost of ownership for an on-site gas-fired system 21

including not only fuel costs (adjusted for conversion efficiency to produce the equivalent 22

amount of heat) but also the capital, operations, maintenance, insurance, and space costs for 23

on-site boilers. Other qualitative benefits of Creative Energy service include simplicity and 24

reliability of heating service. The chart below shows the changes in Creative Energy’s effective 25

Steam Rate and FCAC over time. The effective rate is calculated by converting the average 26

Steam Rate and FCAC per M# to an equivalent amount of customer heat supplied in MWh. This 27

conversion reflects the average extraction of heat energy from customer steam to hot water 28

converter stations. The total effective Steam Rate plus FCAC can then be compared to other 29


10

alternatives to provide an equivalent amount of heating. The charge below shows the historical 1

trends in total steam charges per MWh, together with the proposed and forecast charges for 2

the remainder of 2016 and 2017. . 3

4

Note: all values converted from M# to MWh based on typical energy extraction efficiency. 5

Effective Steam Rate is the system-wide weighted average of the four declining block rates. 6

7

The chart below compares the proposed 2016 steam rate with other recent benchmarks for on-8

site gas, and for other regulated thermal energy systems. Some of the difference in costs among 9

systems can be explained by size and type of system. Some of these other systems are already 10

low carbon (e.g., Telus Garden, Marine Gateway, SEFC and BC Hydro Residential Electricity). 11

A low-carbon version of on-site gas boilers is also shown for comparison, but this required the 12

purchase of more costly biomethane. 13

14

$-

$10

$20

$30

$40

$50

$60

$70

$80

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Total Steam charges

Effective Steam Rate per MWh Fuel Cost Adjustment per MWh


11

1

Note: CE Steam based on current Application. All other values taken from NEFC CPCN 2

proceeding. On-site gas cost is for average high-rise residential building and includes boiler 3

capital cost (or capital reserve contributions), O&M, and space requirements. On-site boilers 4

with blend of gas and RNG has similar GHG intensity as other district energy rates. 5

6

7

Corporate Organization and Budget Process 8

A Board of Directors is responsible for the stewardship of the business and affairs of the 9

Company. Several Board committees have been formed to ensure that business goals and 10

objectives are being met and are in the interest of customers, employees and the shareholder. 11

These Board committees including Finance; Audit; Compensation and Regulatory. 12

The Company’s ability to provide safe and reliable service in a cost effective manner also 13

depends on the management team and management structure. The management team (MT) 14

comprises the President & CEO, VP Customer Relation & Development, Controller, and Director 15

$-

$20

$40

$60

$80

$100

$120

$140

CE Steam On-siteboilers

with 100%gas

On-siteboilers

with 33%gas, 67%

RNG

TelusGarden

MarineGateway

SEFC BC HydroResidential

2016 Effective Rates

Steam Rate Boilers, O&M Fuel Other Rates


12

Engineering. The management team is responsible for both strategic direction and day to day 1

operations. 2

Figure 1 below depicts the Organizational Structure of Creative Energy Vancouver Platforms 3

Inc. 4

Figure 1 – Organizational Chart 5

6

7

CREATIVE ENERGY VANCOUVER PLATFORMS INC. - ORGANIZATIONAL CHART

President & CEO

Admin Assistant

Director

Engineering (2)

VP, Business

Development (2)

CFO/Controller (3) Chief Engineer (12)

Construction

Manager

Engineer In

Training

Accountant Plant Operators (11)

Operations

Manager (5)

Service Line

Crew (4)

Page | 13

O&M and Capital Budgets are prepared by the management team and then approved by the 1

Board. Both O&M and Capital Budgets are prepared using a combination of zero-based budgeting 2

and a review of prior years’ expenses. Incremental O&M expenses and all capital expenditures 3

are prioritized based on the need to provide safe and reliable service at reasonable rates. 4

Variances from budget are then reviewed on a monthly basis in order to identify budget 5

variances early. Where necessary and appropriate, priorities may change and expenses or 6

expenditures may be delayed or directed to projects that are more pressing or provide greater 7

benefits but would not compromise safety and reliability. 8

The responsibility for budget preparation, maintenance and update falls on the shoulders of 9

the Corporate Controller with the assistance from outside consultants and input from operation 10

managers. The budgeting process itself utilizes both elements of zero based/bottom up 11

budgeting and a trended approach. 12

Under zero based/bottom up budgeting there is no “baseline” budget that gets automatically 13

approved and rolled forward. Instead every forecast expenditure, whether ongoing or new, 14

requires justification and approval. An example of this would be non-regular maintenance that 15

could be tied to a specific piece of equipment. Thus, the approved expenses literally build the 16

budget from the bottom up. 17

It is important to note that in creating a zero based budget, prior year actuals/year-end 18

Projected are used as a benchmark to identify the activities (transactions) that need to be 19

budgeted. This is reasonable given that the majority of O&M transactions are recurring in nature 20

and these costs typically change with inflation and also foreign exchange rates. Prior year 21

activities that are not expected to recur are specifically excluded. However, any new recurring 22

or non-recurring activity is included, subject to justification and approval. 23

Zero based budgeting does not always apply. Where this is the case, a trended approach is 24

used. An example of this would be general and ongoing equipment maintenance. Where there 25

is a large number of pieces of equipment involved, it might not be possible to identify the type 26

and amount of maintenance required by each single piece of equipment or whether the 27

maintenance of a particular item will be required at all. It is far more informative and 28

predictive to look at this equipment as a pool and analyze maintenance expenses on a combined 29

and trended basis. 30

Once compiled based on the approach described above, the initial O&M budget is reviewed and 31

modified as necessary by the Management Team. It is then reviewed, evaluated and approved 32

Page | 14

by the Board of Directors taking a holistic approach that looks at the overall year over year 1

trend, assesses for support of Company’s strategic goals and objectives, as well as evaluates 2

the impact it will have on Customers. 3

The outcome of this process is an O&M budget that balances the needs of Creative Energy’s 4

stakeholders while ensuring that Company can successfully deliver on its mandate of providing 5

all of its customers with safe and reliable service at reasonable cost. 6

Approvals Sought 7

In this Application, Creative Energy is seeking an Order of the Commission granting the 8

approvals pursuant to section 58 to 61 of the Utilities Commission Act (the Act) as described 9

below: 10

Interim approval of an increase to Steam Rates of 6.23% effective May 1, 2016 and 11

January 1, 2017 as set forth in Table 4. 12

Final approval of an increase to Steam Rates of 6.23% effective May 1, 2016 as set forth 13

in Table 4. 14

Interim approval of NEFC Hot Water Rates effective August 1, 2016 and NEFC hot water 15

rates effective January 1, 2017 as set forth in Section 5. 16

Final approval of NEFC rates effective August 1, 2016 as set forth in Section 5. 17

Approval of the Special Services Deferral Account to be non-rate base deferral account 18

carrying costs based on short-term debt costs calculated on monthly deferral account balances 19

as detailed in sections 3.4.3.4 and 4.6.1. 20

Approval of the Fuel Cost Stabilization Account (FCSA) to be a non-rate base deferral 21

account with carrying costs at the weighted average cost of debt calculated on monthly deferral 22

account balances. 23

Approval pursuant to section 44.2(3) of the UCA, of the capital expenditures and 24

projects for Test Period 2016 and Test Period 2017 as detailed in section 4. 25

Draft Commission Orders for interim rates and final rates are attached as Appendix 5 and 26

Appendix 6, respectively. 27

As noted above in this Application, Creative Energy is seeking final rates effective May 1, 2016 28

and is seeking steam rates, NEFC hot water rates proposed for Test Period 2017 to be interim 29

Page | 15

and to be made final following an Application to be filed by Creative Energy on or before 1

November 1, 2016. 2

Creative Energy plans to file an Application Update by April 30, 2016 that incorporates the 3

actual year-end balances for 2015 and the flow through effects of deferral accounts on both 4

Test Period 2016 and Test Period 2017. The Application Update may also result in changes to 5

NEFC hot water rates due in part to changes to the NEFC model filed as Appendix 3. The final 6

rates applied for and to be effective May 1, 2016 will be subject to the Application Update. 7

On or before November 1, 2016, Creative Energy proposes to file a simplified application to 8

update the 2017 demand forecast and to update the revenue deficiency for 2016 projected 9

year-end balances, including amortizations for deferral accounts. The simplified application 10

would seek to make steam rates and NEFC hot water rates final as of January 1, 2017. Creative 11

Energy reserves the right to bring forth any material changes in circumstances beyond its 12

control that may significantly impact its 2017 forecast cost of service, fuel costs, and customer 13

rates. 14

This Application provides detailed information in support of Creative Energy’s revenue 15

requirements and the underlying proposed customer rates for Test Period 2016 and Test Period 16

2017. This Application is comprised of two principle components: 1) relevant narrative and 17

schedules providing background and context of the Application, and 2) financial schedules that 18

provide the detailed financial information necessary for determination of the revenue 19

requirements, and the financial analysis necessary to determine rates. 20

Regulatory Process 21

All past regulatory processes have been the subject of a written hearing process (i.e. 2007, 22

2014 and 2015-2017). Given its size, Creative Energy submits that a written hearing process is 23

appropriate. Moreover, Creative Energy submits that any review of this Application should be 24

expected to attract no or very limited participation by customers. Again, given its size, Creative 25

Energy submits that the additional costs of intervener participation are a cost that can be 26

avoided with no loss to an efficient and effective regulatory process. In these circumstances, 27

Creative Energy believes that customers can rely on staff participation in the review of the 28

Application to ensure an adequate record for the Commission to approval fair and reasonable 29

rates. Creative Energy expects to hold a workshop to consult with customers regarding several 30

processes that may be of interest to customers, including this Application and process. 31

Page | 16

In consideration of a written process proposed above for this Application, the table that follows 1

sets out Creative Energy’s proposed regulatory timetable with the dates to be 2

Action Date (all 2016)

Information Requests (First) April 18

Response to Information Requests April 29

Information Requests (Second, if any) May 18

Response to Information Requests (Second) June 1

Intervener Submissions, if any June 7

Creative Energy response to Intervener Submissions June 15

3

4

Principal Contact 5

6

All notices and other communications with this Application should be directed to : 7

Paul Tai 8

Chief Financial Officer 9

Creative Energy Vancouver Platforms Inc. 10

Suite 1-720 Beatty Street 11

Vancouver, BC 12

V6B 2M1 13

14

15

Page | 17

2 DEMAND FORECAST 1

Introduction to Demand Forecast and Revenues 2

This section outlines the demand forecasts for steam and for NEFC hot water sales. The forecast 3

of steam reflects steam sales. Steam production will exceed steam sales because steam is also 4

used to supply the steam to hot water converter stations in NEFC. This steam requirement is 5

captured elsewhere in the underlying cost allocations to NEFC. The demand forecasts here are 6

for the purposes of establishing the Steam Rates and NEFC Hot Water Rates. 7

The demand forecast for NEFC reflects the forecast of connected floor area and the average 8

expected Energy Use Intensity (EUI) for new development in NEFC under average weather. The 9

forecast of NEFC hot water sales has not changed since the NEFC CPCN Application. In its 10

decision granting a CPCN, the Panel in that proceeding found that the NEFC load forecast was 11

reasonable.1 Given the previous record concerning the load forecast in the NEFC CPCN 12

Proceeding, the Panel’s final determination in that proceeding, and the lack of any changes in 13

expected timing or nature of initial customers, Creative Energy adopts the load forecast for 14

NEFC from the NEFC CPCN Proceeding. The forecast for NEFC hot water service in 2016 and 15

2017 is summarized below. 16

The forecast for retail steam sales reflects expected load under average weather conditions. 17

The forecast for retail steam sales reflects historical steam consumption patterns of existing 18

customers, adjusted for significant changes in existing customer buildings (e.g., envelope 19

upgrades and/or new alternative energy systems) together with projected additions of new 20

customers. Currently, Creative Energy is anticipating three customer additions in 2016: an 21

office building, a residential building, and a school. The projected consumption for these new 22

customers is based on the type of building, current envelope standards and other unique 23

considerations. For example, the residential building is part of a larger waste heat recovery 24

project and steam is only expected to be used for peaking and back-up. 25

26

1 NEFC Decision, p. 11

Page | 18

Actual steam demand in 2015 was lower than expected due to 2015 being one of the warmest 1

years on record in Vancouver (2,491 vs 10-year average heating degree days of 2,793). The 2

forecast of retail steam sales for 2016 is 9.8% than 2015. Adjusting for average weather, 3

underlying retail steam sales are expected to remain virtually flat, with the three new 4

customer additions offset by reductions in existing customer loads. 5

6

Steam Sales Forecast 7

Creative Energy serves approximately 200 existing buildings with a wide range of uses and 8

characteristics. For these existing loads, Creative Energy estimated the customer’s weather 9

normalized consumption for each month in the past five years. This was estimated by 10

multiplying the actual monthly customer consumption by the ratio of average to actual heating 11

degree days for Vancouver for that month. For the shoulder months (May to September), no 12

weather normalization was made because demand in these months is dominated by domestic 13

hot water load, which is not weather dependent. 14

The weather normalized monthly load of each customer was then aggregated into an annual 15

consumption for each of the past 5 years. A baseline steam consumption was then calculated 16

as the average annual weather-normalized consumption for the past five years. For the majority 17

of existing customers, this baseline consumption was used to forecast sales. However, for some 18

customers it was necessary to make further adjustments to reflect changes in customer 19

buildings or circumstances that would make it inappropriate to use a simple average of weather 20

normalized consumption to forecast future sales. This would include buildings that have 21

undergone major upgrades, major changes in the type of tenants, major changes in building 22

operation (e.g., summer shut-down of steam converter or a major renovation taking the 23

building off line), or the addition of on-site energy sources. In some cases, Creative Energy was 24

already aware of such changes at customer sites. In other cases, Creative Energy could infer a 25

change from a consistent upward or downward trend or major step change in the historical 26

consumption of a customer (after adjusting for weather). 27

As part of the most recent forecasting process for steam sales, Creative Energy contacted its 28

largest customers (representing 13.7% of total customers and 47% of total demand for steam) 29

and interviewed customer representatives to determine any major changes in building 30

characteristics or operations that would affect baseline steam demand under average weather. 31

Page | 19

This information was used to adjust the baseline demand for 14 customers. For these customers, 1

this adjusted baseline demand was used to forecast sales in place of using the simple five year 2

average customer demand (normalized weather) used for other customers. 3

The sales forecast also reflects new customer additions and for these customers with no 4

historical consumption, Creative Energy has relied on EUIs from comparable new buildings and 5

uses, adjusted for any unique circumstances of the customer such as other on-site heat sources. 6

The table below shows the actual steam sales and heating degree days from 2006 to 2015 and 7

the forecast steam sales for 2016 and 2017 under average weather reflecting the methodology 8

and adjustments described above. 9

Table 1 – Heating Degree Days vs Steam Demand 10

11

NEFC Hot Water Sales Forecast 12

The NEFC Hot Water sales forecast is summarized in the table below. It is the same forecast 13

as filed with and accepted by the Commission in the NEFC CPCN Proceeding. The forecast of 14

connected floor area in the table below reflects the expected floor area as of the end of each 15

year. For loads connected part way through the year, the projected revenues from the fixed 16

portion of the NEFC rates will reflect the average expected number of months for new 17

connections in that year. The heat sales reflect the average expected EUI for new loads, 18

adjusted to reflect new connections partway through a year. 19

Table 2 – Demand Forecast for DHW 20

21

22

1 Table 1 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 10Yr Avg

2 Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Forecst Forecst 2006-15

3 Heating Deg Days 2,721 2,880 3,031 2,927 2,622 2,966 2,853 2,815 2,626 2,491 2,793 2,793 2,793

4 Demand M# 000's 998 1,080 1,158 1,139 1,069 1,226 1,173 1,141 1,058 973 1,068 1,070 1,102

5 YOY increase 9.8% 0.1%

1 Table 2 Floorspace and Load Forecast

2 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

3 Heat Demand - MWh 1,715 9,450 21,295 27,600 31,555 38,900 40,650 43,900 45,370 48,100 48,100 48,100

4 Connected Floor Area m2 18,130 99,680 224,335 290,700 332,280 409,500 427,980 462,300 477,700 506,300 506,300 506,300

5 Percent of Buildout 4% 20% 44% 57% 66% 81% 85% 91% 94% 100% 100%

6

Page | 20

3 REVENUE REQUIREMENTS AND RATES 1

Revenue Requirement Summary 2

This section begins with a summary of the revenue requirement that allows for safe and reliable 3

operation and management of the utility’s assets at a reasonable cost. Table 3 provides the 4

Test Period 2016 and Test Period 2017 revenue requirement for both steam and hot water 5

service. 6

The table identifies the incremental costs and the allocation of costs associated with providing 7

hot water service to NEFC. In section 5, the details of the NEFC revenue requirement are 8

considered in more detail. The revenue requirement increases are either: 9

1. Incremental costs pertaining to the start of commercial operation of NEFC NES; or 10

2. Other cost increases that are over and above the incremental costs to serve NEFC NES. 11

The incremental costs are specific to service to NEFC customers. All other cost increases are 12

driven by other factors as explained throughout this Application, and Creative Energy would 13

have applied for such increases even without the new hot water service. 14

The revenue requirement is comprised of the following components that will be considered in 15

the following subsections: 16

1. Fuel Expense (natural gas and fuel oil expense) – Section 3.2 17

2. Steam Expenses - Water related– Section 3.3 18

3. Operations and Maintenance expenses – Section 3.4 19

4. Taxes – Section 3.5 20

5. Depreciation and Amortization expenses – Section 3.7 21

6. Financing Costs and ROE – Section 3.9 22

23

24

25

26

27

Page | 21

Table 3 below summarises the components of the Revenue Requirement 1

Table 3 – Revenue Requirement Summary 2

3

4

1

2 REVENUE REQUIREMENT Reference Sch Total NEFC Steam Total NEFC Steam

3 Cost Of Service

4 Fuel 10,419,200 51,200 10,368,000 11,921,200 333,500 11,587,700

5 Fuel Recovery 9,720,500 49,000 9,671,500 11,205,100 321,000 10,884,100

6 Net Fuel 698,700 2,200 696,500 716,100 12,500 703,600

7 O&M Sch. 16 (line 63) 4,541,000 92,000 4,449,000 4,642,800 188,300 4,454,500

8 Total Operating and Maintenance 5,239,700 94,200 5,145,500 5,358,900 200,800 5,158,100

9 Municipal Access Fees (MAF) Sch. 18 (line 9) 264,200 1,800 262,400 281,000 10,300 270,700

10 Total Operating and Maintenance (incl. MAF) 5,503,900 96,000 5,407,900 5,639,900 211,100 5,428,800

11 Property Taxes Sch. 17 (line 24) 340,700 - 340,700 357,800 - 357,800

12 Income Taxes Sch. 20 (line 28) 240,400 - 240,400 266,000 27,300 238,700

13 Depreciation Sch. 2 (line 8,9,10) 921,100 - 921,100 1,110,900 177,800 933,100

14 Amortization of Rate Base Deferred Expenses Sch. 12 (2016-line2) 166,500 - 166,500 166,500 - 166,500

15 Amortization of Non-Rate Base Deferred Expenses Sch. 13 (2016-line1) 110,500 8,000 102,500 110,500 8,000 102,500

16 Actual/Proposed Interest Sch. 14 (line 22,23) 622,000 44,100 577,900 713,000 113,500 599,500

17 Actual/Proposed Return on Equity Sch. 14 (line 21) 1,141,000 79,300 1,061,700 1,276,000 204,300 1,071,700

18 Total Revenue Requirement before Allocation 9,046,100 227,400 8,818,700 9,640,600 742,000 8,898,600

19

20 Steam Costs Allocated to NEFC

21 Steam Production 13,000 (13,000) 71,400 (71,400)

22 Steam Distribution 2,600 (2,600) 14,200 (14,200)

23 Total Steam Cost Allocation to NEFC 15,600 (15,600) 85,600 (85,600)

24 Corporate Overhead Allocation using Massachusett Formula

25 Corporate Overhead Allocated to NEFC NES 63,600 (63,600) 177,500 (177,500)

26 Total NEFC NES Transfered Costs 79,200 (79,200) 263,100 (263,100)

27

28 Revenue Requirement After Allocation 9,046,100$ 306,600$ 8,739,500$ 9,640,600$ 1,005,100$ 8,635,500$

Revenues @ 2015 Tariff 8,030,811 8,244,852

Revenue Shortfall (709,000) (391,000)

Estimated Steam Revenue per Demand Schedule 8,296,202 9,078,097

Rate Increase Request 6.23% 6.23%

(443,298) 442,597

2016 2017

Page | 22

1

Table 4: Bill Impact 2

3

1 Overall Impact to Steam Customer Rates 2016 2017

2 Rate Increase 6.23% 6.23%

3 2015 2016 2017

4 Average Tariff 2015 7.50

5 Proposed Increase 2016 and 2017 6.23% 6.23%

6 Average New Tariff 2016 and 2017 7.96 8.46

7 Average Fuel Cost Adjustment Charge - 2015 9.88

8 Forecast Fuel Cost Adjustment Charge - 2016 & 2017 8.75 8.75

9 Total 17.38 16.71 17.21

10 Net Impact to Overall Billing - 2016 vs 2015 -3.82%

11 Net Impact to Overall Billing - 2017 vs 2015 -0.96%

12 Net Impact to Overall Billing - 2017 vs 2016 2.97%

Page | 23

Fuel Expenses 1

The cost of fuel is the Company’s single largest cost, and is recovered from customers in two 2

ways. A portion of the cost of fuel is recovered in the tariff --- a “Base Cost” of 41 cents per 3

one million Btu of fuel consumed; and the remaining portion of the cost of fuel is recovered 4

through a rate rider referred to as the Fuel Cost Adjustment Charge or “FCAC”. 5

In the 2015-17 RRA Decision, the Commission directed Creative Energy to propose a permanent 6

treatment of the Fuel Cost Stabilization Account in its next RRA as follows: 7

“The Panel directs Creative Energy, in its next revenue requirements application, to 8

propose a permanent treatment of this Fuel Cost Stabilization Account. As a minimum, 9

the proposal must address: 1) whether this account should be established as a non-rate 10

base or a rate base deferral account, or by way of another method; and 2) the 11

appropriate means to compensate customers for the interest to be accrued on the 12

surplus balance or excess of billings to customers in respect to fuel costs over actual 13

costs incurred. 14

As an interim measure, the Panel directs Creative Energy to apply its weighted average 15

cost of debt to the most current balance of this Fuel Cost Stabilization Account (balance 16

as at the date of this Decision). The resulting interest cost (customer credit) shall be 17

treated as a revenue-offset to the 2015 revenue requirements. In the compliance filing 18

arising from this Decision, Creative Energy is to include a schedule showing the 19

reconciliation of the Fuel Cost Stabilization Account in the format of Table 6.1.7.D in 20

Tab 6 of the Application, up to the date of this Decision.2” 21

22

Creative Energy seeks approval for the Fuel Cost Stabilization Account (FCSA) to be a non-rate 23

base deferral account with carrying costs at the weighted average cost of debt calculated on 24

monthly deferral account balances. Creative Energy proposes to apply its weighted average 25

cost of debt to a forecast of monthly deferral account balances with an adjustment in the 26

following year for variances between the forecast and actual carrying costs of the deferral 27

2 2015-17 RRA Decision, p. 19

Page | 24

account. Creative Energy will follow the reporting requirements in accordance with the 1

directive set forth in the 2015-2017 RRA Decision, p. 26. 2

In the 2015-17 RRA Decision, the Commission directed Creative Energy to file a Phase I rate 3

design application within one year from the date of the decision (June 9, 2016) as follows: 4

The Panel directs Creative Energy to file a Phase I rate design application within one 5

year from the date of this Decision specifically in regard to the recovery of fuel costs. 6

This fuel cost recovery rate design application is to include a review of the appropriate 7

Base Cost component of the Steam Tariff and the degree to which the Base Cost should 8

be increased to capture the bulk of the fuel costs in the Steam Tariff, as it originally did 9

when the Base Cost of 41 cents was established and as is the accepted practice with 10

other thermal energy utilities in British Columbia. The rate design should include 11

discussion of any potential adverse impacts on existing core steam utility customers and 12

new customers such as the NEFC utility and how these adverse impacts might be 13

mitigated. 14

15

In the 2015-17 RRA Decision3, the Commission directed Creative Energy to include an annual 16

reconciliation of the Fuel Costs Stabilization Account with its Annual Report. Creative Energy is 17

also directed to file certain schedules with details of any changes to the FCAC within 10 business 18

days of each change. The Annual Report will be filed by the end of April, 2016. A report of 19

changes to the FCAC has been filed and attached as Appendix 2. 20

Fuel Expense Forecast Methodology 21

The input fuel for steam production is either natural gas or fuel oil. Natural gas is the main 22

fuel used in the production of steam; fuel oil is used only in the event of interruptions in gas 23

deliveries.4 24

25


4 Minimum fuel oil inventory is maintained, so as to provide enough lead time to set in motion the process

of sourcing alternate fuel supplies in case of curtailment in gas supplies. Until this inventory is used it is

included in the working capital requirement and not the fuel costs.

Page | 25

With hot water service to NEFC commencing in 2016, there will be additional demand for steam 1

and thus natural gas. The natural gas consumption forecast is based on: 2

1. The aggregate of the Steam service and hot water service demand forecasts; and 3

2. The gross up of aggregate demand forecasts for overall system efficiency to arrive at 4

the forecast of natural gas required. 5

The energy consumed to meet customer demand (discussed in Section 2) is 1,704,037 MMBtu 6

for 2016 and 1,745,156 MMBTu for 2017. This is arrived at as follows: 7

1. An estimate of demand in M# is first determined; 8

2. The estimated demand is then grossed up for boiler efficiency; and 9

3. Finally, the grossed up amount is then converted to MMBTu by multiplying the conversion 10

factor of 1.196 MMBTU to each M # of steam generated. 11

Based on the energy consumed, the Base Cost included in the revenue requirement and to be 12

recovered through tariff rates is forecast to be $698,700 in 2016 and $716,100 in 2017. 13

The next step is to estimate the total charges that make up the cost of natural gas. The charges 14

include the following components, where the cost of each varies with the volume of natural 15

gas consumed: 16

Fortis Transportation Charges, 17

Natural Gas Commodity Price (including marketer fees), 18

Carbon Tax, 19

Ice Levy, 20

PST, and 21

Clearsky Fees5. 22

23

24

5 Clear Sky charges are driven by the amount of “displaced” energy costs, as opposed to natural gas

consumption.

Page | 26

Fortis Transportation Charges 1

Creative Energy is a customer of FortisBC Energy Inc. (“Fortis”) with an agreement in place to 2

receive firm and interruptible service under Fortis’ Rate Schedule 22. Under the agreement, 3

the Company has reserved 2,000 GJ/day firm capacity on Fortis’ system. Deliveries in excess of 4

this firm capacity are treated as interruptible. 5

Fortis delivery charges are a flow-through cost and any changes to delivery rates are outside of 6

the Company’s control. Creative Energy assumed the following delivery charges for 2016 and 7

2017. 8

Table 5: Forecast Fortis Delivery Charge 9

2016 2017

Basic ($/Month) 3,664.00$ 3,664.00$

Admin ($/Month) 78.00$ 78.00$

Pilot ($/Month) 40.00$ 40.00$

Demand ($/GJ) 10.95$ 10.95$

Transport Charge - Firm ($/GJ) 0.57$ 0.60$

Transport Toll - Interruptible ($/GJ) 0.86$ 0.92$ 10

Natural Gas Commodity Price 11

Currently all natural gas purchases are from a gas marketer (Cascadia Energy Ltd.) on a one 12

year contract. An Annual Gas Contracting Plan, which outlined the process and strategies to 13

mitigate price volatility, was approved by Order E-21-15. 14

For the purpose of this RRA the Company used the January 15, 2016 forward gas strip prices of 15

$3.02/GJ for 2016 and $3.60/GJ for 20176. 16

Carbon Tax 17

The Carbon Tax of $1.49/GJ is a non-discretionary expenditure payable to the Province of 18

British Columbia. This tax is expected to continue in 2016 and 2017; therefore, it is 19

appropriately included in the overall cost of gas for 2016 and 2017. 20

21

22

6 Assuming $1.45 CND to $1 USD exchange rate for both years.

Page | 27

Ice Levy 1

The Ice Levy is a non-discretionary expenditure payable to the BC’s Innovative Clean Energy 2

fund. It is calculated as 0.4% of the gas commodity cost. The Ice Levy is expected to continue 3

in 2016 and 2017; therefore, it is appropriately included in the overall cost of gas for 2016 and 4

2017. 5

PST 6

Company’s gas purchases are subject to the 7% PST tax. It is a non-discretionary expense and 7

is appropriately included in the 2016 and 2017 cost of gas. 8

Clear Sky Charges 9

Creative Energy is subject to the Energy Services Agreement (approved by Order G-125-07), 10

under which the Company has contracted with the Clear Sky Energy Ltd. (Clear Sky) to provide 11

and maintain energy conservation equipment that will reduce energy use at the 720 Beatty 12

Street plant. Under the terms of the agreement, the Company keeps 25% of the savings and 13

remits the payment for the 75% of the savings to the Clear Sky. The Clear Sky’s portion is 14

estimated to be $227,000 for 2016 and $267,600 for 2017, and it is appropriately included in 15

the overall cost of gas for 2016 and 2017. 16

Pursuant to the agreement with Clear Sky, the ownership of the conservation equipment will 17

transfer to Creative Energy on January 1, 2020 at which time 100% of the energy cost savings 18

will begin to accrue to the Company. 19

Water Expense 20

The cost of water is one of the major expenses for the Company. Creative Energy’s primary 21

water usage is twofold: 22

1. feed water as an input in steam production; and 23

2. water cooling applied to distribution condensate so that it can safely be discharged into 24

the CoV’s storm and sewer network. 25

The methodology to forecast the water expense is based on a historic ratio of actual water 26

expense vs actual demand for steam times the forecast demand. 27

Page | 28

The 2015 Unaudited Actual Water Expense of $900,222 was much lower than the 2015 Approved 1

Water Expense of $945,725. This was a result of a warm winter at the beginning of 2015 and a 2

warm October in 2015. 3

The forecast Water Expenses for 2016 and 2017 are $904,200 and $973,300, respectively. The 4

forecast for Water Expenses for 2016 and 2017 are in line with the anticipated demand and 5

reflects an increase of approximately 7% that includes the incremental costs for servicing NEFC 6

NES. 7

Operation and Maintenance Expenses 8

The following section provide details of the O&M Expenses to provide steam service. The O&M 9

Expenses to provide NEFC hot water service are set forth in section 5. In some cases, the O&M 10

Expenses are incurred to provide both steam and hot water service in which case those expense 11

items are discussed in this section. 12

The total O&M Expenses, per Table 5 below, required to provide both steam and hot water 13

service for Test Period 2016 is $3,433,900 and for Test Period 2017 is $3,584,400. 14

Table 5: Operating and Maintenance Expense 15

16

The budget for O&M Expenses is comprised of the sum of two components: “Labour & Benefits” 17

and expenses other non-labour related expenses. Each component is approximately one-half 18

the total O&M budget. Each of these two components will be discussed below. 19

There is a small, dedicated group of employees, who are responsible for day-to-day operations. 20

For that reason, employees perform various functions, and there are no departments and thus 21

no department budgets. Instead, managing to budget is the responsibility of the entire 22

management team. 23

Labour and Benefits - Employee Compensation 24

The labour pool comprises two employee groups: 25

1 Operating & Maintenance Expenses 2011 2012 2013 2014 2015 2015 2016 2017

2 Actual Actual Actual Actual Approved Unaudited Forecast Forecast

3

4 Fuel Expenses 776,987 747,104 713,966 679,578 708,850 516,156 698,700 716,000

5 Steam Expense (Water Related) 803,754 910,797 884,415 924,623 945,725 900,222 904,200 973,300

6 Steam Production - O&M 981,197 1,008,144 1,054,401 1,074,606 1,036,743 1,057,448 1,153,200 1,187,400

7 Total Steam Production Sum(1,2,3) 2,561,938 2,666,045 2,652,782 2,678,807 2,691,318 2,473,825 2,756,100 2,876,700

8 Distribution Expenses - O&M 432,330 561,088 500,888 563,830 710,300 680,653 677,800 707,700

9 Total O&M Expenses Sum(7,8) 2,994,268 3,227,133 3,153,670 3,242,636 3,401,618 3,154,478 3,433,900 3,584,400

Page | 29

1. Management; and 1

2. Unionized Employees, represented by the IUOE union. 2

Attracting and retaining top talent is critical to the business and commercial success of Creative 3

Energy. Challenges facing the labour market such as changing demographics and skilled labour 4

shortages present Creative Energy with both industry specific and Company specific labour 5

risks. 6

Creative Energy must compete with other and typically much larger utilities in BC, Canada and 7

in some cases North America for employees with specialized skill sets that are unique and not 8

widely available. In addition, there are Company specific risks associated with the size of the 9

Company. Given Creative Energy’s small number of employees, there are often one or maybe 10

two employees qualified for certain tasks so the loss of key employees can have a significant 11

impact on business continuity. 12

The Company’s compensation strategy is to strike a balance between offering competitive 13

compensation packages that attract, motivate and retain top talent and skill sets required for 14

key roles, while also aligning the compensation of each management employee to their 15

individual level of responsibility. For the first time in the Test Period 2016, the compensation 16

program will include an incentive program that is designed to complement the compensation 17

strategy. 18

Salaries for management are set based on a policy of offering competitive salaries and benefits, 19

especially for key positions. In the past, the Company has not recovered incentive plan 20

payments to employees. In this Application, the Company now proposes to recover in rates the 21

cost of the incentive plan. 22

Creative Energy has retained HayGroup to benchmark compensation for management 23

employees. As per the cover letter to this filing, the Company has filed the entire HayGroup 24

report, “Compensation Benchmarking Report” dated March 18, 2016, in this proceeding on a 25

confidential basis, and certain sections, “Background” and “Methodology” of the report are 26

attached as Appendix 7. Creative Energy believes the HayGroup report confirms the cost of 27

management salaries, including the cost of the incentive plan, are fair and reasonable costs 28

and should be included in the revenue requirement. 29

Labour costs for unionized employees, primarily working in production and distribution 30

functions, increase during both Test Periods in accordance with a five-year collective 31

Page | 30

agreement that expires in December 2017. In accordance with the collective agreement, wages 1

and benefits increase by 2.25% in the Test Period 2016and by 2.25% in the Test Period 2017. 2

3

The O&M Budget by Function 4

The O&M Budget is presented in the format that reflects the functions performed by the 5

Company and the organization of the Application follows this format. The functions can be 6

broadly defined as follows: 7

Steam Production, 8

Steam Distribution, and 9

Sales, General & Administrative (SG&A). 10

Captured under the Steam Production function are all the O&M Expenses (including labour) 11

related to steam production at the Company’s Beatty Street plant. The O&M Expenses for the 12

Steam Production function is specifically discussed in Section 3.4.1 13

Included in the Steam Distribution function are all O&M Expenses (including labour) that relate 14

to operation and maintenance of the Steam Utility distribution network, and the NEFC hot 15

water service distribution network. The O&M Expenses for the Steam Distribution function are 16

specifically discussed in Section 3.4.2. 17

SG&A captures all other expenditures outside of the Steam Production or Steam Distribution 18

functions. Some of the major items include: 19

1. Management and general salaries, benefits; 20

2. Marketing & sales expenses; 21

3. External services; 22

4. Insurance; and 23

5. Building expenses 24

The O&M budget for the SG&A function is specifically discussed in Section 3.4.3. 25

26

Page | 31

Steam Production Expenses 1

Table 6 below provides the production function expenses. 2

3

The variance between 2015 Unaudited Actuals and 2015 Approved is primarily driven by the 4

fuel and fuel recovery costs. In the 2015 Approved, fuel costs were estimated at $708,850. 5

However, due to warmer than normal weather and other drivers of reduced consumption, the 6

2015 Projected is $516,156 or approximately 27% lower than the 2015 Approved. 7

Steam Distribution Expenses 8

Table 7 below provides the distribution function expenses. 9

10

Total 2015 Unaudited Actuals is lower than 2015 Approved. Mains and Services maintenance is 11

higher as a result of increased preventative maintenance procedures that is in place. Previously, 12

preventative maintenance (PM) on the distribution system PRVs were checked at least once a 13

year and in 2015, Creative Energy was able to perform PM on the distribution system twice on 14

some of the PRVs. 15

1 Production Expenses 2011 2012 2013 2014 2015 2015 2016 2017

2 Account Name Actual Actual Actual Actual Approved Unaudited Forecast Forecast

3 Fuel Expenses 776,987 747,104 713,966 679,578 708,850 516,156 698,700 716,000

4 Steam Production-Operation

5 Supervision and Labour 970,553 999,882 1,049,849 1,062,133 1,030,443 1,053,872 1,144,000 1,178,000

6 Steam Expenses (Water related) 803,754 910,797 884,415 924,623 945,725 900,222 904,200 973,300

7 Total Steam Production-Operation 1,774,307 1,910,679 1,934,264 1,986,756 1,976,168 1,954,094 2,048,200 2,151,300

8 Steam Production-Maintenance

9 Structures and Improvements 10,644 8,262 4,552 12,473 6,300 3,576 9,200 9,400

10 Total Steam Production-Maintenance 10,644 8,262 4,552 12,473 6,300 3,576 9,200 9,400

11

12 Total Production Expenses 2,561,938$ 2,666,045$ 2,652,782$ 2,678,807$ 2,691,318$ 2,473,825$ 2,756,100$ 2,876,700$

1 Distribution Expenses 2011 2012 2013 2014 2015 2015 2016 2017


3 Distribution Expenses-Operation

4 Supervision & Labour 252,184 369,484 354,299 366,071 526,622 475,908 455,000 467,500

5 Mains & Services 14,561 11,951 8,923 14,237 11,616 23,134 15,700 19,100

6 Other Distribution Operation - - - 1,000 2,500 - 5,000 15,300

7 Transportation 15,294 17,605 17,779 10,032 15,600 14,102 24,000 24,500

8 Total Distribution Expenses-Operation 282,039 399,040 381,001 391,340 556,338 513,145 499,700 526,400

9 Distribution Expenses - Maintenance

10 Mains & Services 43,763 33,540 29,273 29,616 40,800 57,968 66,000 67,000

11 Meters & House Regulators 106,115 128,048 90,614 142,874 112,712 109,541 112,100 114,300

12 Other Distribution Maintenance 413 460 - - 450 - - -

13 Total Distribution Expenses-Maintenance 150,291 162,048 119,887 172,490 153,962 167,509 178,100 181,300

14 Total Distribution Expenses 432,330$ 561,088$ 500,888$ 563,830$ 710,300$ 680,653$ 677,800$ 707,700$

Page | 32

As shown on the following chart below, Creative Energy has seen a decrease in customer call 1

outs and less downtime of service to customers. This decrease can be attributed to the 2

proactive preventative maintenance program on building services. The Company’s commitment 3

to customers that call is “same day service”. 4

5

SG&A Expenses 6

Table 8 below provides the Sales, General & Admin expenses. 7

8

The following subsections provide an explanation of material variances amongst the 2015 9

Approved, 2015 Unaudited, 2016 Forecast, or 2017 Forecast. 10

3.4.3.1 Director’s Fees 11

In the past two years, the Board has met more often than expected in order to ensure an orderly 12

transition to a more active Company. For that reason, Director’s Fees were higher than 13

approved and the Board is expected to continue to meet as frequently as in the past two years. 14

1 Sales, General & Admin 2011 2012 2013 2014 2015 2015 2016 2017


3 Sales Expense 25,217 14,970 34,650 38,064 56,460 58,315 67,300 70,200

4 Directors Fees 22,500 26,000 30,000 30,830 42,000 60,815 48,200 49,400

5 Admin & General Salaries 475,326 573,924 562,683 772,641 729,719 455,906 584,600 617,900

6 Office Supples & Exp 161,034 88,533 63,456 95,473 78,786 107,966 97,500 105,200

7 Admin & General Exp - - - 12,071 9,180 18,874 10,800 11,000

8 Special Services 67,581 90,487 121,161 214,159 108,000 246,121 418,200 307,300

9 Insurance 84,815 83,789 83,363 86,854 106,600 105,466 114,100 123,900

10 Injuries & Damages-WCB 8,443 8,672 8,893 10,287 12,074 12,041 14,800 14,800

11 Employee Benefits 236,663 344,972 433,210 190,532 450,187 508,035 461,800 465,100

12 Sales, General & Admin 1,081,579 1,231,347 1,337,416 1,450,912 1,593,006 1,573,539 1,817,300 1,764,800

13 General Plant Maintenance 26,233 14,622 23,597 14,957 26,640 25,287 30,200 49,200

14 Operations & Maint. Expense 1,107,812 1,245,969 1,361,013 1,465,869 1,619,646 1,598,826 1,847,500 1,814,000

15 O&M Allocated to Capital 0 0 0 0 (15,459) (18,000) (19,700) (20,100)

16 O&M Allocated to Affiliate 0 0 0 0 0 0 (22,000) (19,500)

17 Total SG&A 1,107,812$ 1,245,969$ 1,361,013$ 1,465,869$ 1,604,187$ 1,580,826$ 1,805,800$ 1,774,400$

Page | 33

1

3.4.3.2 Administration and General Salaries 2

The Administration and General Salaries as depicted in Table 8, line 5, shows 2015 Unaudited 3

amount of $455, 906 being lower than the 2015 Approved amount of $729,719. This was due to 4

unanticipated projects such as the NEFC CPCN taking more resource time in 2015 than 5

expected. 6

Creative Energy proposes to increase from 25%, which was the amount approved in the 2015-7

17 RRA Decision7, to 35% of the allocation of the VP Customer Relation & Development salary 8

and benefits. The VP of Customer Relation & Development will be supporting retention of core 9

customers and the addition of new customers. Retention of the current customer base is 10

essential to maintain rates. A pro-active plan and program for core customer retention is 11

essential as there are market pressures to customers to implement alternatives to steam 12

service. This work will include account management, strategy development and project 13

implementation. A greater focus on the core retention is necessary for 2016 and 2017 as there 14

continues to be new technologies competing with the traditional service. 15

Concurrently, VP of Customer Relation & Development will be focusing on connecting new 16

buildings to the core. This will involve customer calls, proposals, business case development 17

and project implementation 18

3.4.3.3 Office Supplies and Expenses 19

Office supplies were also greater than forecast as a result of the use of a computer consultant 20

company rather than having an in house IT individual (this would have cost more had Creative 21

Energy hired a dedicated IT employee). 22

3.4.3.4 Special Services (Third Party Contract Costs) 23

These costs have increased due to increased regulatory activity, as well as, the increase in 24

complexity and requirements of each regulatory activity. Creative Energy proposes to include 25

in Special Services: 1) participant funding (PACA), 2) BCUC direct costs for regulatory processes, 26


Page | 34

and 3) fees paid to lawyers and consultants to comply with regulatory requirements, including 1

BCUC regulatory requirements. 2

The regulatory oversight of Creative Energy’s predecessor Company, CHDL, was “light-handed 3

regulation”. For example, in the past CHDL did not seek approval for bank financing, and did 4

not seek approval for the FCAC. Moreover, capitalized overhead studies and employee 5

compensation studies were not necessary to support revenue requirements applications. 6

Nevertheless, Creative Energy acknowledges the need to comply with the UCA with increased 7

regulatory oversight and increased regulatory reporting requirements. Therefore, Creative 8

Energy is seeking approval for a deferral account for Special Services costs. Given Creative 9

Energy’s size and the need for administrative efficiency, Creative Energy is not proposing to 10

establish a deferral account for each regulatory process. 11

Special Services such as legal, audit and outside services were much higher than had 12

anticipated. Increased costs specifically with legal and outside services were a direct result of 13

not having dedicated expertise in house to deal with items such as HR matters; contracts 14

review; Harassment training for all employees; and specifically 2015-17 RRAs review and PACA 15

funding for interveners. 16

Taxes 17

Municipal Taxes (City of Vancouver Access Fee) 18

Creative Energy has a thirty-year Municipal Access Agreement with the City of Vancouver 19

(effective September 1, 1999), which grants the Company a non-exclusive franchise right to 20

continue to operate, construct and maintain its distribution system for supply of steam-heat 21

and hot water services. In exchange for this right, the Company pays an annual Licence Fee 22

which is 1.25% of Tariff Revenues plus a fixed fee which increases in line with Tariff increases 23

as per Table 9. 24

Page | 35

Table 9: Municipal Taxes1

2

The current Municipal Access Agreement (MAA) was approved by the Commission Order C-13-3

00 on June 12, 2000. 4

The following provision taken from the current Agreement governs the calculation of the annual 5

Licence Fee that Creative Energy must pay to the CoV. 6

[“On April 15, 2000 and April 15 of each and every following year of this Agreement the Company will pay 7

the total of the following amounts: 8

(i) 1.25% of the amount obtained by deduction the Fuel Adjustment Costs from the 9

Total System Portion of Gross Revenue for the immediately preceding calendar 10

year, plus 11

(ii) $100,000 adjusted (on a cumulative basis) in each year (commencing with an 12

adjustment to the first such payment on April 15, 200) in proportion to any and all 13

changes made during the prior calendar year to the Company’s prices net of fuel 14

adjustment recoveries for the sale of heat or cold. “]8 15

The 2015 Unaudited Actuals are higher than the 2015 Approved amounts. The 2015 Approved 16

was calculated based on the percentage over revenues for actuals historically and was 17

approximately 3%. For Test Period 2016 and Test Period 2017, these amounts have been 18

calculated in accordance with the terms of the MAA. 19

Based on forecast revenues and proposed rate increases, Table 10 below provides the estimate 20

of Municipal Taxes : 21

22

8 Section 3.2 License Fees, of the Municipal Access Agreement dated September 1, 1999.

1 Municipal Taxes 2011 2012 2013 2014 2015 2015 2016 2017


3 Item

4 Annual Steam Revenues 7,397,807 7,106,093 6,931,468 7,241,719 8,299,898 7,352,630 9,041,100 9,635,500

5 Tax Rate 1.25% 1.25% 1.25% 1.25% 1.25% 1.25% 1.25% 1.25%

6 Municipal Tax on Steam Revenue 92,473 88,826 86,643 90,521 103,749 91,908 113,000 120,400

7

8 Prior Year Flat Fee 116,400 116,400 116,400 129,372 122,567 129,372 142,309 151,200

9 Rate Increase 0.00% 0.00% 0.00% 0.00% 0.00% 10.00% 6.23% 6.23%

10 Escalated Flat Fee 116,400 116,400 116,400 129,372 122,567 142,309 151,200 160,600

11

12 Total Municipal Tax 208,873$ 205,226$ 203,043$ 219,893$ 226,316$ 234,217$ 264,200$ 281,000$

Page | 36

Table 10: Municipal Taxes 1

2

NEFC Municipal Taxes 3

Included in the Variable Portion of the Total Fee above is $1,800 for 2016 and $10,300 for 2017 4

on account of incremental Municipal Taxes from NEFC. It is calculated as 1.25% of total 5

revenues from all the NEFC customers of $136,000 for 2016 and $768,000 for 2017, respectively. 6

These amounts represent an incremental and directly assignable cost of the NEFC NES. 7

Property Taxes 8

Property taxes are paid to the City of Vancouver (CoV), and the subject property is located 9

at 720 Beatty Street. The total property tax expense is a function of the value of the 10

property, as assessed annually by CoV, multiplied by various levy rates which are also set and 11

typically changed annually. The forecast of property taxes is set forth in Table 11 below. 12

Table 11: Property Taxes 13

14

There are two classes of assessed value as well as the applicable levy rates. The two classes 15

are 1) Utility and 2) Business and Other Utility. The levies pertaining to the Utility class have 16

higher rates. 17

As noted in the above Table 11, the 2015 Unaudited Actual Property Tax came in slightly higher 18

than the 2015 Approved amount. The allowance provided for in the 2015-17 RRA was insufficient 19

due to the Actual Property Assessment was higher than prior years. 20

The forecast gross property tax expense for the Test Period 2016 is $442,700 and for the Test 21

Period 2017 is $464,800. The forecast is an estimate based on applying historical trends to 22

both the expected future assessed value of the property as well as the future levy rates. 23

1 Year Total Fee Fixed Portion Variable Portion

2 2016 264,200$ 151,200$ 113,000$

3 2017 281,000$ 160,600$ 120,400$

1 Property Taxes 2011 2012 2013 2014 2015 2015 2016 2017


3 Source: Schedule 17

4 Total for 720 Beatty Street 284,914 358,556 340,956 367,059 385,412 398,658 442,700 464,800

5

6 Reduction for Non Reg (101,140) (85,865) (80,800) (85,258) (89,504) (92,000) (102,000) (107,000)

7

8 PROPERTY TAXES FOR UTILITY PURPOSES 183,774$ 272,691$ 260,156$ 281,801$ 295,908$ 306,658$ 340,700$ 357,800$

Page | 37

Reduced by the non-regulated allocation discussed in the following section the resulting net 1

regulatory property tax expense for the test period 2016 and 2017 are $340,700 and $357,800 2

respectively. This estimate and allocation approach is consistent with the methodology that 3

was applied in the past. 4

3.5.3.1 Allocation to Non-Regulated Operations (NRO) 5

Historically Creative Energy allocated a portion of the total property tax to its non-regulated 6

operations; thus, reducing the amount of its regulated revenue requirement and benefiting 7

customers through lower rates. The Company believes that this allocation continues to be 8

reasonable and fair and should be applied in the 2016 and 2017 revenue requirement. The 9

Company proposes an allocation to its NRO for 2016 Test Period of $102,000 and for the 2017 10

Test Period of $107,000. 11

Creative Energy’s NRO include leasing of non-utility office space to tenants and parking rentals 12

on land that is not used in utility operation. To calculate the appropriate amount to be allocated 13

to NRO, Creative Energy uses the following approach. 14

The levy rates discussed above are applied to the total assessed value of the land and building. 15

Of this amount a portion is then allocated to NRO using building and land square footage as an 16

allocation base.9 17

The allocation of the NRO portion of property tax is collected as part of lease payments. 18

This approach is consistent with the methodology that has been applied in the past. 19

Income Taxes 20

The forecast income tax expense for Test Period 2016 is $240,500 and for Test Period 2017 is 21

$266,000 as calculated in the following table based on the income tax pertaining to regulated 22

operations. The effective tax rate during both test periods is 26%. 23

Income taxes for 2015 Unaudited Actuals is lower than the 2015 Approved due to lower revenues 24

as a result of 2015 being much warmer than normal. 25

9 Please note that this has been rounded up to the nearest thousand dollars reflecting the proposed

treatment on depreciation allocation to NRO and discussed in Section 3.5.3.1

Page | 38

Table 12: Income Taxes 1

2

For the purpose of calculating income tax expense, Creative Energy uses a flow-through or 3

current taxes method. Under this approach the equity portion of the return on rate base, 4

adjusted for permanent and temporary tax differences, and future enacted tax rates (both 5

Federal and Provincial) are used in calculating the total tax expense. 6

It is important to note that on an actual basis, revenues are known, and subsequently used in 7

arriving at the Net Utility Income figure10. With respect to the forecast, the fundamental 8

purpose of the revenue requirement is to determine the amount of revenues required to deliver 9

utility services, cover all the expenses (including income tax) and provide for the allowed return 10

on equity. Since the revenues are not “given”, but the allowed equity return11 is, we can use 11

this percentage together with the rate base to calculate what the after tax equity return would 12

be. Working backwards and adjusting the after tax equity return for tax differences, we can 13

calculate the before tax income and consequently the income tax expense. 14

This format is similar to the one used by other utilities and provides a complete picture of the 15

income tax calculation. This format can be effectively applied to both forecast and actuals. 16

For these reasons, Creative Energy proposes to apply this format to all future revenue 17

requirement as well as annual report filings. 18

Deferral Accounts 19

Where items subject to deferral treatment are also subject to taxation in the current period, 20

they are added/deducted for the purposes of arriving at taxable income. In such cases, the 21

deferral additions (both debits and credits) are recorded on the net of tax basis in the 22

corresponding deferral accounts. 23

10 Utility Revenues less Utility Expenses equal Net Utility Income

11 The equity return is after tax and it is expressed as a percentage.

1 Income Taxes 2011 2012 2013 2014 2015 2015 2016 2017


3 Taxable Income/(Loss) for Tax Purposes (After Tax) 573,653 128,830 (2,239) (74,862) 766,936 210,175 684,320 757,008

4 Tax Gross Up 73.50% 75.00% 75.00% 75.00% 75.00% 74.00% 74.00% 74.00%

5 Taxable Income/(Loss) for Tax Purposes (Before Tax) 780,481 171,773 (2,986) (99,815) 1,022,581 284,021 924,800 1,023,000

6

7 Effective Income Tax Rate 26.50% 25.00% 25.00% 25.00% 25.00% 26.00% 26.00% 26.00%

8 Current Income Tax Expense 206,827$ 42,943$ -$ -$ 255,645$ 73,845$ 240,400$ 266,000$

Page | 39

Consequently, any deferral account amortization that pertains to the deferral accounts 1

previously taken into account for tax calculation purposes, gets reversed in calculating the tax 2

expense for the current period i.e. It gets added/deducted for the purposes of calculating the 3

taxable income. 4

Depreciation and Amortization Expense 5

The depreciation expense is appropriately included as one of the cost of service line items on 6

the Revenue Requirement Schedule (Sch. 1), as well as, the Rate Base Schedule (Sch. 2) where 7

it is referred to as Accumulated Depreciation and its cumulative impact is used in calculating 8

the Net Plant in Service. The Depreciation expense is a function of undepreciated plant 9

balances and applicable depreciation rates. It is calculated as set forth in Table 13 in 10

accordance with the methodology and depreciation rates discussed in the sections below. 11

Table 13: Depreciation 12

13

Creative Energy proposes to apply the existing depreciation methodology as well as the existing 14

rates to determine the revenue requirement. 15

3.7.1.1 Depreciation Approach and Policies 16

Creative Energy uses a “pooled” or asset class depreciation approach, as opposed to 17

depreciating individual assets. Under the asset class approach, all the capital additions to 18

Utility plant are categorized and assigned to a specific asset class with its own specific 19

depreciation rate. This depreciation rate is then applied to the asset class balance at arriving 20

at the total annual depreciation expense for such class. 21

The Company uses a “straight-line” depreciation method for recognizing and recording the 22

annual depreciation expense for each asset class. The depreciation rates are based on an 23

estimated useful life for a “typical asset” in each class. Thus, the rates can either be expressed 24

as a percentage or a number of years. The asset classes and applicable rates are listed in the 25

Table 14 . 26

27

1 DEPRECIATION 2011 2012 2013 2014 2015 2015 2016 2017



4 Opening Accumulated Depreciation (13,386,367) (14,184,531) (15,053,677) (15,928,818) (16,792,216) (16,733,386) (17,649,601) (18,594,525)

5 Closing Accumulated Depreciation (14,184,531) (15,053,677) (15,928,818) (16,733,386) (17,738,973) (17,649,601) (18,594,525) (19,731,695)

6 Depreciation Expense 798,164$ 869,147$ 875,141$ 804,568$ 946,757$ 916,215$ 944,900$ 1,137,200$

Page | 40

Table 14: Asset Classes and Depreciation Rates 1

2

For each asset class the annual capital additions are tracked separately and it is the Company’s 3

policy to begin depreciation in the year following their addition. Furthermore, once the 4

particular annual capital additions have reached the end of their useful life, depreciation is no 5

longer applied. For the depreciation calculation purposes such additions are taken out of the 6

depreciable asset pool10. 7

Using prior year’s closing plant balance significantly reduces the risk of forecast error resulting 8

in a minimal difference between actuals and the forecast. 9

3.7.1.2 Depreciation Allocated to Non-Regulated Operations 10

Historically Creative Energy allocated a portion of building depreciation expense to its non-11

regulatory operations with the corresponding revenue requirement reduction being in order of 12

$706. 13

3.7.1.3 Depreciation of CIAC 14

Depreciation of Contribution-in-Aid-of-Construction reduces the overall depreciation expense 15

and effectively lowers the rates. Creative Energy uses the same approach as discussed above 16

when calculating CIAC depreciation. 17

There is only one CIAC class and its depreciation rate is set at 2.5 percent. The depreciation 18

percentage approximates the overall deprecation rate for distribution plant to which this CIAC 19

pertains. 20

While preparing this Application, the Company has discovered an error in how the CIAC 21

depreciation had been calculated in the past. Instead of applying the CIAC depreciation rate 22

to the gross CIAC balance, the rate was applied to the net balance and resulted in understating 23

Acct.

# Account Name

Dep.

Rate

Acct.

# Account Name

Dep.

Rate

Acct.

# Account Name

Dep.

Rate

Steam Production Plant Distribution Plant General Plant

311 Structures & Improvements 1.50% 376 Mains 2.00% 390 Structures & Improvements 1.50%

312.1 Boiler Plant Equipment 2.50% 378 Manhole Structures 1.50% 391 Office Furniture & Equipment 5.00%

312.2 Boiler Tanks Equipment 2.50% 380 Services 2.00% 391.1 Office Electronics 20.00%

312.3 Boiler Auxiliary Equipment 5.00% 381 Meters 3.00% 392 Transportation Equipment 15.00%

315 Accessory Electric Equipment 5.00% 382 House Regulators & Meter Instal. 3.00% 393 Stores Equipment 5.00%

316 Other Steam Production Equipment 5.00% 387 Other Distribution Equipment 5.00% 394 Tools & Work Equipment 5.00%

398 Other General Equipment 5.00%

Page | 41

CIAC depreciation. Going forward, the Company fixed this oversight by appropriately applying 1

the CIAC depreciation rate to the gross CIAC balance. 2

The forecast depreciation expense for the test periods 2016 and 2017 are $944,900 and 3

$1,137,200, respectively, calculated using the above depreciation rates. The rates are the 4

same as approved for 2015 rates. Therefore, the depreciation expense year over year increases 5

for 2016 of $28,700 ($944,900-$916,215) and $192,300 ($1,137,200-$192,300) for 2017 are 6

solely driven by the plant capital additions discussed in Section 4.2.1 7

Non - Rate Base Deferral Amortization (Schedule 12) 8

Order G-98-15, Section 1.d.ii, approved the creation of a “Regulatory Transitional Adjustment 9

Deferral Account” to recover the one time regulatory (pension) transitional adjustment of 10

$301,177. This non rate base Regulatory Transition Adjustment Deferral Account is to be 11

amortized over a three-year period commencing in 2016 and is to attract the carrying cost at 12

the Company’s cost of debt. Table 15 below shows the amount amortized for each test year of 13

2016 and 2017. 14

Table 15 – Non Rate base Deferral Account 15

16

17

1 Non Rate Base Deferral Account 2015 2016 2017

2

3 A) Pension Reg. Transition Adj.

4 Opening Balance 301,177 313,223 214,727

5 Amortized (110,500) (110,500)

6 Net of Recovery Sum(4,5) 301,177 202,723 104,227

7 Carrying Cost - WACD % 4.00% 3.83% 3.92%

8 Carrying Cost $$ (6*7) 12,046 12,004 8,413

9

10 Closing Balance Sum(6,8) 313,223 214,727 112,640

11

12

13 B) Pension Expense Deferral Account

14 2015 Approved Pension Expense

15 2015 Actual Pension Expense

16 Due (to) / from Rate Base -

17 Carrying Cost - WACD % 4.00% 3.83% 3.92%

18 Carrying Cost $$ (15*16) - - -

19

20 Closing Balance Sum(15,17) - - -

21

Page | 42

In accordance with the direction, amortization expense of Regulatory Adjustment Deferral 1

Account included in Test Period 2016 and Test Period 2017 Revenue Requirements is $110,500 2

and $110,500, respectively. 3

The Order G-98-15 also approved the creation of a Pension Expense Deferral Account (non-rate 4

base) to capture the variance between the forecast Pension Expense recovered in rates and the 5

Pension Expense reported in the company’s audited financial statements. The Company 6

anticipates its audited financial statements to become available by the end of April, at which 7

time, Creative Energy will file an evidentiary update, which will include changes required to 8

the Pension Expense. 9

Rate Base Return (Schedule 13) 10

The Rate Base Return represents the “return on” capital invested to provide safe, reliable, 11

regulated utility services. It combines both debt and equity returns based on the capital 12

structure and approved rates. Table 16 below summarises the Rate Base Return as calculated 13

for the 2016 Test Period and the 2017 Test Period: 14

Table 16: Return on Rate Base Summary 15

16

The forecast Rate Base Return for Test Period 2016 and Test Period 2017 is $1,763,000 and 17

$1,989,000, respectively, and it is calculated in accordance with the methodology and rates 18

discussed below. 19

Equity Thickness and Allowed Return on Equity 20

The GCOC Stage 2 Decision, Order G-47-14, issued March 25, 2014, set the equity thickness at 21

42.5% and the ROE at 9.5% subject to a further report and review. By Order G-82-15, “the 22

Commission accepted the report that focuses on the Creative Energy existing system of core 23

1 Return on Rate Base 2015 2015 2016 2017

2 Approved Unaudited Forecast Forecast

3

4 COST OF CAPITAL $

5 Equity 1,044,173 519,146 1,141,000 1,276,000

6 Long tem Debt 226,000 226,000 290,000 409,000

7 Short Term Debt 368,818 369,837 332,000 304,000

8 Return on Rate Base 1,638,991 1,114,983 1,763,000 1,989,000

9

Page | 43

customers to be in compliance with the directive in the Generic Cost of Capital proceeding 1

Stage 2 decision. The return on equity and deemed equity thickness for Creative Energy’s rate 2

setting will continue to be based on the default equity thickness of 42.5 percent and equity risk 3

premium of 75 bps for regulated Thermal Energy Systems”. 4

The Commission’s decision established the equity thickness as appropriate given the business 5

risks faced by the Company; furthermore, the Commission’s determination was that the allowed 6

ROE provides the Company with a reasonable opportunity to earn a fair return on its equity 7

investment. 8

In this Application, Creative Energy is not seeking changes to the allowed equity thickness or 9

the allowed ROE. Now, in accordance with Order G-182-15, the 42.5% equity thickness and 10

9.5% ROE is used to determine the equity portion of the Return on Rate Base of $1,141,000 for 11

Test Period 2016 and $1,276,000 for Test Period 2017. 12

13

Debt Financing 14

By Order G-195-15 dated December 10, 2015, the Commission approved a Credit Facilities 15

Agreement with the Royal Bank with the following four credit facilities: 16

Table 17: Credit Facility Summary 17

18

19

20

21

1 Credit Facility Summary

2 $$ Due Int Rate

3 Facility #1 Revolving Demand 4,500,000$ On Demand RBP + 0.30%

4 Facility #2 Non Revolving 10,000,000$ 31-Aug-16 RBP + 0.50%

5 Facility #3 Non Revolving 3,928,265$ 31-Aug-16 RBP + 0.50%

6 Facility #4 Non Revolving 5,212,000$ 30-Sep-16 RBP + 0.50%

7

8 RBP - Royal Bank Prime

Page | 44

4 RATE BASE AND CAPITAL ADDITIONS (Schedule 2) 1

Introduction 2

The Mid Year Rate Base is forecast to be $28.2 million in the Test Period 2016, and $31.6 million 3

in the Test Period 2017 as set forth in Table 18. 4

5

Table 18: Rate Base Summary 6

7

The Mid Year Rate Base comprises following components, each of which is discussed in 8

subsections below: 9

Net Mid-year Plant in Service (comprising of gross plant in service, accumulated 10

depreciation and adjusted for the timing of major additions) 11

Net Mid-year CIAC (comprising of gross CIAC and accumulated depreciation of CIAC) 12

Mid-year Plant Allocated to NRO (portion of the plant used to support Company’s NRO) 13

Mid-Year Deferral Accounts (representing the Company’s funding of activities where 14

there is a timing difference between cost incurrence and its collection in rates) 15

Mid-Year Working capital (representing Company’s investment into non-capital assets 16

used in support of regulated operations) 17

The year-over-year increases to Rate Base for each of 2016 and 2017 are primarily driven by 18

capital additions for hot water service to NEFC, discussed in Sections 5 below. 19

20

Net Mid-year Plant in Service 21

Net Mid-year Plant in Service is the largest component of the Rate Base and it represent the 22

cumulative undepreciated investment in capital assets. It is Gross Plant in Service (GPIS) net 23

of Accumulated Depreciation. 24

1 Rate Base Summary 2011 2012 2013 2014 2015 2015 2016 2017



4 MID YEAR RATE BASE 24,200,871$ 24,312,663$ 24,456,546$ 24,925,550$ 25,861,873$ 25,909,320$ 28,250,011$ 31,610,178$

5

Page | 45

The GPIS comprises prior year’s closing balance carried over to the current period, plus regular 1

and CPCN plant additions, AFUDC, and capitalized overheads, less plant retirements. Each of 2

the GPIS components is discussed in turn below. 3

Regular Capital Additions 4

Regular capital additions include boiler upgrades to the plant and to the manholes within the 5

distribution system. The boiler upgrades include control upgrades, back up and redundancy 6

instrumentations. The distribution capital additions pertain to restoration of several manholes. 7

Allowance for Funds Used During Construction (AFUDC) 8

The AFUDC applies where an asset is not part of the rate base, but funds have been invested 9

to finance its construction12. The AFUDC recognizes that there are carrying costs arising from 10

such an investment and provides for their future recovery. 11

Capitalized Overheads 12

Creative Energy tracks capital project activity and any and all identified direct cost(s) are 13

recorded under the corresponding project(s). Direct costs include project labour, engineering, 14

consulting or any other cost that can be easily traced back to a specific project. 15

Where a cost cannot be directly traced to a specific project(s), but none the less it can be seen 16

as benefiting such project(s), a capitalized overheads approach is used instead. For example: 17

accounting function (including both labour and non-labour components), telephone, utilities, 18

computer, stationary and such costs cannot be directly traced to any specific projects. 19

However, these costs clearly provide project benefits and therefore it is fair and reasonable to 20

assign portions of such costs to capital projects. 21

12 CPCN is a good example of applicability of AFUDC, while CPCN projects are being constructed they are

not included in rate base thus not earning a return. However, they do represent a Company’s investment

and in the absence of AFUDC, the Company would be denied an opportunity to earn a fair return on its total

invested funds.

Page | 46

Plant Retirements 1

Once an asset comes to the end of its useful life13 or stops being used and useful, it typically is 2

retired and removed from Company books. The retirement transaction credits the historic cost 3

of such asset; thus, removing it from the plant balance. 4

Creative Energy does not forecast any retirements or proceeds from disposition for the Test 5

Periods. 6

Accumulated Depreciation 7

Accumulated Depreciation is a contra asset account that reduces the carrying costs of the 8

underlying asset (such as any plant asset) in recognition of its finite useful life and diminishing 9

economic value with the passage of time. The annual Depreciation expense, discussed in 10

Section 3.7, adds to the Accumulated Depreciation balance whereas plant retirements and net 11

proceeds from disposition reduce it. 12

The Accumulated Depreciation (Table 13) is forecast to be $18.6 million in 2016 and $19.7 13

million in 2017. All of the change is attributable to the annual Depreciation expense discussed 14

in Section 3.7. 15

Net Mid-year CIAC 16

A customer may be required to make a financial contribution referred to as “Contribution-in-17

Aid-of-Construction” (CIAC) in order to extend utility services. This typically happens when the 18

incremental costs of serving such customer exceed the expected incremental revenues. Thus, 19

CIAC has the intent to protect the interest of the existing customers by keeping them “whole” 20

and avoid cross-subsidization. 21

The CIAC serves to reduce rate base and similar to plant to which it pertains, its net balance 22

decreases over time recognizing the effect of depreciation. A Net Mid-year CIAC (“Mid-year 23

CIAC”) is calculated by taking the gross mid-year CIAC and netting against it the mid-year CIAC 24

Accumulated Depreciation. 25

13 As explained elsewhere in this Application a fully depreciated plant may still remained used and useful

and in such case it would not be subject to retirement.

Page | 47

Table 19: CIAC Depreciation 1

2

The Mid-year CIAC balances are forecast at $684,530 for 2016 and $710,180 for 2017. 3

The change in the Mid-year CIAC is driven by the annual CIAC depreciation. Creative Energy 4

does not forecast any new CIAC additions during the test period used in this Application. 5

Plant Allocated to NRO (Schedule 8) 6

Creative Energy allocates a portion of building and land costs to non-regulated operations 7

(NRO). The allocation to NRO lowers the overall regulated rate base and consequently lowers 8

the amount of the revenue requirement to be collected through rates. 9

To arrive at the NRO allocated amount, the Company first calculates the unit costs (per square 10

foot). The unit costs are calculated by taking the mid-year depreciated costs for the building 11

and historic cost for the land divided by the corresponding total square footage. The unit costs 12

are then multiplied by the respective square footage of the land and the building that pertain 13

to the NRO, yielding the amount to be allocated. 14

The allocation to NRO is $27,698 for the 2016 Test Period and $26,992 for the 2017 Test Period. 15

Working Capital (Schedule 10) 16

The working capital represents Creative Energy’s investment in non-capital assets14 17

Furthermore, it represents the timing differences between payment of current period’s 18

expenses (cash outlay) and their collection in revenues. Table 20 below provides a summary of 19

Schedule 10: 20

21

14 Only exception is construction work-in-process which is capital asset related, but historically has been

included under the working capital requirement.

1 CIAC Depreciation 2011 2012 2013 2014 2015 2015 2016 2017


3 NET CIAC

4 Opening Balance (740,499) (721,986) (703,937) (686,338) (663,278) (669,180) (646,080) (722,980)

5 Closing Balance (721,986) (703,937) (686,338) (669,180) (638,649) (646,080) (722,980) (697,380)

6 Net Mid-Year CIAC (731,243) (712,962) (695,138) (677,759) (650,964) (657,630) (684,530) (710,180)

7

Page | 48

Table 20: Working Capital Requirements 1

2

The working capital requirement forecast for 2016 and 2017 is $1.42M and $1.45M, respectively. 3

It is calculated in accordance with the methodology described below, and using Commission’s 4

previously approved lead/lag days. 5

Including the working capital requirement in the rate base is appropriate and it allows Creative 6

Energy an opportunity to earn a fair return on its total investment. The Company, respectfully 7

request Commission’s approval of its working capital requirement as filed. 8

Methodology 9

To arrive at the working capital requirement, the Company takes its forecast expenses and 10

multiplies them by lead/lag days to arrive at the average amount of funding (investment) 11

needed to pay for such expenses. This together with other prepaids (such as oil inventory and 12

work in process) forms the total working capital requirement. 13

The following Lag days are used for calculating the working capital. 14

Table 21: Lag Days 15

16

17

1 WORKING CAPITAL REQUIREMENTS 2011 2012 2013 2014 2015 2015 2016 2017


3

4 Natural Gas & Oil Purchases 2,732 2,240 2,867 3,268 3,194 2,287 0 0

5 Operation & Maintenance Expense 176,256 199,069 205,660 236,136 250,187 233,643 253,558 261,196

6 Other 0 0 0 0 0 0 0 0

7 Municipal Taxes (141,874) (139,397) (137,913) (149,356) (153,709) (159,085) (179,449) (190,859)

8 Income Tax Expense (80,986) (16,815) 0 0 (100,087) (28,914) (94,128) (104,150)

9 Insurance 42,408 41,895 41,682 43,427 53,300 52,733 57,050 61,950

10 Property Taxes 78,354 109,964 90,576 113,549 119,391 114,997 127,763 134,175

11 Total 76,890 196,955 202,872 247,025 172,275 215,661 164,794 162,312

12 Oil Inventory 194,421 189,189 186,633 181,761 175,000 167,556 161,556 155,556

13 Customer Deposits 0 0 0 0 0 0 (3,500) (3,500)

14 Work in Proccess 371,509 264,839 227,668 536,076 354,000 882,879 1,098,996 1,136,496

15 TOTAL WORKING CAPITAL REQUIREMENT 642,819 650,983 617,173 964,861 701,275 1,266,096 1,421,846 1,450,864

1 NET LAG/(LEAD) DAYS 2015 2015 2016 2017

2 Approved Unaudited Forecast Forecast

3

4 Natural Gas & Oil Purchases 0.10 0.08 0.09 0.09

5 Operation & Maintenance Expense 21.79 20.73 20.91 21.10

6 Other 136.88 136.88 136.88 136.88

7 Municipal Taxes (247.90) (247.92) (247.91) (247.91)

8 Income Tax Expense (142.90) (142.92) (142.91) (142.91)

9 Insurance 182.50 182.50 182.50 182.50

10 Property Taxes 136.88 136.88 136.88 136.88

Page | 49

4.5.1.1 Conceptual Change 1

In preparing this Application, Creative Energy has discovered that historic practice has been to 2

include balances from “Account 409 - Income Taxes” and “Account 409.1 - Future Income 3

Taxes” in the working capital calculation. Conceptually this is incorrect as included under the 4

Account 409 are also taxes pertaining to Company’s NRO and account 409.1 is non-cash item 5

thus it does not have any impact on the actual working capital requirement. 6

Going forward, Creative Energy proposes to change the methodology so that only the regulatory 7

expenses are used in calculating the working capital requirement. Specific to the income tax 8

expense, it will be the amount as calculated on Schedule 19 (“Income Taxes”) and shown in 9

Section 3.5.4. 10

This approach more accurately reflects the Company’s regulated operations. Since, Creative 11

Energy recovers only the approved “regulated” expenses from its customer base, it only makes 12

sense to use those same approved “regulated” expenses in calculating the “regulated” working 13

capital requirement. 14

4.5.1.2 Customer Deposits 15

On occasion, the Company requires a customer deposit. Going forward, Creative Energy 16

proposes to include such customer deposits as a reduction to the working capital requirement. 17

Since funds provided by customers can be used to offset a portion of the investment otherwise 18

required from the Company, it is only fair to include this offset in calculating the “net” 19

investment amount required by Creative Energy. Conceptually this treatment is similar to the 20

treatment of CIAC discussed in Section 3.7.1.3 above. 21

The reduction to working capital on account of customer deposits is $3,500 for both years. 22

4.5.1.3 Presentational Change 23

In addition to the changes discussed above, Creative Energy proposes to change the 24

presentation of the working capital requirement. The proposed change lays out the working 25

capital particulars in a manner that allows easy year over year comparison. 26

Furthermore, instead of showing lead/lag days for each expense line item it now shows “net 27

lead/lag” days. The net is being calculated as the Commission’s previously approved revenue 28

Page | 50

lag days minus the previously approved lag days for each expense item. Essentially this 1

calculation combines into one, two steps that were shown separately before. 2

This format is used by other utilities regulated by the Commission (i.e. Fortis Utilities) and 3

Creative Energy expects it will provide better clarity and understanding. 4

4.5.1.4 Work-in-Process (Not Earning AFUDC) 5

Included in the working capital is mid-year construction work-in-process that is not subject to 6

earning AFUDC. This represent part of Creative Energy’s investment into utility assets and thus 7

is appropriately included in Company’s rate base. 8

The work-in-process contribution to rate base is $1.099M for 2016 and $1.136M for 2017. 9

Non-Rate Base Deferrals 10

The following sections detail the existing and proposed deferral accounts. 11

GCOC Deferral Account 2013/2014 12

By Order G-98-15, the balance of $333,012 of this deferral account is to be amortized over two 13

years commencing in 2016, with a weighted average cost of capital. In the 2016 and 2017 Test 14

Period the amortized amount is $166,500 as per Schedule 11. 15

Regulatory Transitional Adjustment Deferral Account 16

By Order G-98-15, the balance of $301,177 of this deferral account is to be amortized over 17

three years commencing in 2016 with a weighted average cost of debt carrying cost. In the 18

2016 and 2017 Test Period the amortized amount is $110,500 as per Schedule 12. 19

Pension Expense Deferral Amount 20

By Order G-98-15, Commission approved the creation of a Pension Expense Deferral Account 21

capturing the variance between the forecast Pension Expense recovered in rates and the 22

Pension Expense reported in the Company’s audited financial statements. The opening balance 23

in this deferral account is to be amortized in the following test period. Additionally, this 24

deferral is to attract a carrying cost on the mid-year unamortized balance at Creative Energy’s 25

short term debt rate. 26

As previously mentioned, the Company expects its audited financial statements to become 27

available by the end of April 2016. Upon which time Creative Energy and by way of evidentiary 28

Page | 51

update, will update the deferral balance as well as any resulting carrying charges and 2016 1

amortization. 2

Special Services Deferral Account 3

Creative Energy anticipates that there will be an increase in third party costs to assist with its 4

transition and be more compliant with its regulatory reporting function. This was demonstrated 5

in the past couple of years where the regulatory proceedings of the 2015-17 RRA and the NEFC 6

CPCN had placed unanticipated demands on staff and resources which had not existed 7

previously. 8

The Company still maintains that the regulatory requirements for a small utility should not be 9

the same as the regulatory requirements of a large utility. Especially in the circumstances of 10

Creative Energy where the load has been declining for several years reflecting increased 11

competitive pressures on the utility and the need to ensure competitive rates. Nevertheless, 12

Creative Energy will embrace this regulatory oversight and work with the Commission as well 13

as Interveners to ensure that value to all of customers as well as the shareholder is preserved 14

and maximized. 15

Accordingly, Creative Energy is seeking approval of the following deferral account: 16

Regulatory - Special Services Deferral Account – for expenses related to regulatory 17

proceeding, including BCUC levies and PACA funding. 18

The Special Services Deferral Account would include third party expenses to assist with the 19

regulatory filings that are required in accordance with the UCA, including: 20

1. Annual Gas Contracting Plan; 21

2. Financing Plan (if there are any significant change in financing structure); and 22

3. Fuel Recovery Adjustment Account, when there are changes to the Fuel Recovery Charge 23

Rate. 24

4. Annual Report. 25

5. Rate Design for the steam service 26

6. LTRP 27

Creative Energy acknowledges that larger utilities create a deferral account for each regulatory 28

proceeding or project. Instead of this approach, Creative Energy requests that this deferral 29

Page | 52

account capture the annual variance between the forecast and actual third party expenses for 1

regulatory proceedings or regulatory filings. Creative Energy proposes that the balance in this 2

account be amortized over one year with a carrying cost equal to the Company’s short term 3

debt rate. 4

Overheads Capitalized – 2016 Study 5

In the 2015-17 RRA Decision15, the Commission directed Creative Energy to file a capitalized 6

overhead study in its next RRA. The Company has never before prepared or filed such a study. 7

For this reason and given the costs involved, industry practice was considered. Based on recent 8

RRA filings of both Fortis and PNG, the common practice is to engage an external auditor to 9

conduct a study reviewing the company’s capitalization policies and methodology. Creative 10

Energy had enquired with its own auditors about the costs of such studies and was quoted, at 11

a minimum, an amount of $50,000 and could run upwards of $250,000 (1,000 hours at an average 12

of $250 per hour) and above. Based on these findings, Creative Energy, currently, does not 13

think it is reasonable to have ratepayers bear the costs of such a capitalized overhead study. 14

Therefore, the Company does not intend to engage an external auditor to conduct an overhead 15

capitalization study and have not accounted for any such expenses in the 2016 RRA O&M costs, 16

unless specifically instructed by Commission to do so in this proceeding. 17

In the interim, the same overhead capitalization approach has been applied this year. This 18

approach involves a review of the projects that were completed during the year and assigning 19

a small percentage as overhead capitalization. This percentage in the past had been less than 20

half a percent of the overall corporate overheads. 21

22

23

24


Page | 53

5 NEFC REVENUE REQUIREMENTS ALLOCATION & RATE 1

DESIGN 2

3

NEFC Introduction 4

By Order C-12-15, the Commission granted the NEFC CPCN whereby Creative Energy will be 5

providing energy to NEFC. NEFC will have a different distribution energy system which is a 6

closed hot water loop system that is provided through a Steam to Hot Water (S2HW) heat 7

exchanger. In the Order C-12-15, Commission directed Creative Energy in this Application to: 8

a. Include a discussion on whether the rates for both the core (going forward will now be 9

labelled “steam”) and NEFC should be considered as a separate class of service under 10

section 60(1)(c) of the UCA. 11

b. Provide more clarity on the cost causation of the parameters of the Massachusetts 12

formula, including a confirmation of whether the proposed methodology has been 13

reviewed by the auditors.16 14

Allocation of Costs between the Steam Rates and the NEFC Hot Water Rates 15

In the NEFC NES and CPCN proceeding, Creative Energy sought approval of certain regulatory 16

parameters in anticipation of this Application and future rate applications, including allocation 17

principles. As noted in the NEFC CPCN Decision, Creative Energy proposed an allocation of all 18

incremental costs specific to hot water service to the NEFC NES customers, together with a fair 19

contribution by NEFC NES customers to fixed costs and overheads. 20

21

In the NEFC NES Decision, the Commission approved the principle of cost allocation from the 22

core business given that a portion of the core infrastructure, corporate overhead and 23

16 NEFC Decision, p. 66; the allocation of the fuel costs between the Base Cost in the Steam Tariff and the

Fuel Cost Adjustment charge will be the subject of the RDA for the core and NEFC to be filed by June 9, 2016

Page | 54

management will be used to provide service to NEFC.17 Further, the Commission stated that 1

the approval of the proposed allocation rates requires consideration of the regulatory principles 2

of fairness, understandability and the recovery of revenue requirements.18 3

In order to give effect to this cost allocation approach, Creative Energy proposed in the NEFC 4

proceeding and now again proposes a two-part cost allocation methodology: 5

Steam Cost Allocations to NES19 6

NES Fuel Recovery Cost Allocation 7

There are two key ideas used in Creative Energy’s allocation methodology. Firstly, Creative 8

Energy has sought to avoid subjecting NEFC Hot Water customers to “pancaking”. The nature 9

of the interconnection between the existing Steam system and the NEFC hot water network 10

means that NEFC Hot Water customers could potentially face pancaking of distribution system 11

costs as well as pancaking of system losses. Creative Energy’s proposed cost allocation 12

methodologies for fuel cost recovery and for distribution system costs strike an appropriate 13

balance, avoiding subjecting NEFC hot water customers to pancaking while ensuring they fairly 14

contribute towards core steam costs. 15

Secondly, certain components of the Steam Cost Allocation to NES are allocated based on the 16

Massachusetts formula, a common methodology used amongst companies, both non-utility and 17

utility based. The Massachusetts formula works for a simple corporate structure and until 18

Creative Energy reviews its cost allocation methodology or a significant change occurs, the 19

Massachusetts formula is an acceptable approach.20 20


18 NEFC Decision, p. 64-65

19 In the NEFC proceeding, this was referred to as the NES Meter Cost Allocation, and has been relabeled in

this Application, as directed by the NEFC Decision

20 The Massachusetts formula has been widely used by many of the states in the United States (Weiner, Joann

Martens (March 2005), Formulary Apportionment and Group Taxation in the European Union: Insights from the United States and

Canada.)

http://ec.europa.eu/taxation_customs/resources/documents/taxation/gen_info/economic_analysis/tax_papers/2004_2073_EN_web_final_version.pdf

http://ec.europa.eu/taxation_customs/resources/documents/taxation/gen_info/economic_analysis/tax_papers/2004_2073_EN_web_final_version.pdf

Page | 55

Steam Cost Allocation to NES 1

In this section, the Company will first calculate the NEFC hot water revenue requirement 2

following the cost allocation approach noted above. Then, following a Commission direction 3

regarding fixed and variable components of rates for hot water service, the Company will 4

calculate the NEFC rates. 5

The Steam Costs Allocation to NES can be calculated based on the following components: 6

a. Steam Production – costs included here are steam plant depreciation and earned 7

return, plant maintenance, non-fuel consumables such as water, power and plant 8

operating staff. 9

b. Steam Distribution – includes pipe network depreciation and earned return, 10

distribution network maintenance and distribution network staff. 11

c. Corporate overheads – previously, Management Salaries was a separate allocation, 12

but upon further review, have decided to include management salaries as part of 13

Corporate Overheads. 14

Steam Production and Steam Distribution costs are allocated on a unit-cost basis, with some 15

adjustments. The cost allocation in each year will be set based on a forecast of NEFC’s steam 16

consumption. The Corporate Overheads component is allocated using the Massachusetts 17

Formula. 18

For regulated utilities allocating costs to different classes of customers, the common approach 19

is to go through an extensive functionalization and classification exercise in cost causation with 20

numerous and typically pricey studies that support and validate various utility assumptions. 21

The outcome of this long, exhaustive and costly process is setting up cost pools that capture 22

costs by driver. Typical cost driver pools are demand, customer, and energy related costs. 23

These cost pools can then be allocated to different rate classes based on the cost driver 24

characteristics of each rate class. 25

Given that Creative Energy only has two rate classes (Steam and NEFC Hot Water Service), and 26

a relatively simple rate design, Creative Energy believes that the incremental cost of the full 27

blown functionalization/classification approach will far outweigh any potential benefits. 28

Creative Energy believes that a simplified approach is warranted and is in all customers’ best 29

interests. This simplified approach, first described in the NEFC CPCN Application, is consistent 30

Page | 56

with the paramount principle of cost causation as it very reasonably depicts the cost of serving 1

each of the two proposed rate classes. 2

For this simplified approach, steam service costs were categorized as follows: 3

Steam Production (excluding fuel), 4

Steam Distribution, and 5

Corporate Overheads. 6

In the NEFC CPCN Application, Creative Energy used a fourth cost pool, Management Salaries, 7

with a separate allocation methodology. To simplify the overall cost allocation, Creative Energy 8

has included Management Salaries within the Corporate Overheads pool. 9

For each of those pools an appropriate allocator was determined and applied to arrive at the 10

allocated cost for each of the proposed rate classes. 11

Steam Production Pool 12

The Steam Production Pool captures all of the expenses incurred in production of steam at the 13

Company’s 720 Beatty Street plant, excluding natural gas and fuel oil costs as these are 14

allocated separately. The Steam Production Pool includes the following items: 15

Steam Production Supervision & Labour, 16

Other steam input costs (water, chemicals etc.), 17

Steam Production Maintenance, 18

Steam Production Plant Depreciation21, and 19

Steam Production Plant Proposed Return on Rate Base22. 20

For the Steam Production, the appropriate cost allocation driver is steam consumed by NEFC. 21

Because steam network losses are a function of steam system length, the addition of the NEFC 22

hot water network does not add incremental losses to the steam system. Our methodology 23

allocates costs to NEFC based on NEFC’s share of steam production at the Beatty Street plant 24

21 Included in here is a component that relates to general plant allocated to steam production.


Page | 57

gate (i.e. upstream of distribution system losses) so as to avoid allocating any steam distribution 1

system losses to NEFC Hot Water customers (though all NEFC hot water network distribution 2

losses are allocated 100% to NEFC hot water customers). As the addition of NEFC does not 3

increase steam system loads, and NEFC customers are wholly responsible for the cost of losses 4

within their network, allocating upstream losses in the steam distribution system to NEFC 5

customers is an unfair approach that masks the gain in efficiency from expanding into NEFC via 6

a hot water network. 7

8

[NTD do we need a table showing production allocation?] 9

10

Steam Distribution Pool 11

The Steam Distribution Pool captures all the expenses related to the delivery of steam and it 12

includes the following items: 13

Distribution Expenses-Operation (Including Supervision & Labour), 14

Distribution Expenses – Maintenance (Including Supervision & Labour), 15

Distribution Plant Depreciation23, and 16

Distribution Plant Proposed Return on Rate Base24. 17

18

For the Steam Distribution Pool an appropriate cost driver is energy delivered. It is based on a 19

similar rationale as the Steam Production pool, but with additional adjustments to ensure NEFC 20

customers are charged fairly for their usage of the existing distribution system, but not charged 21

the full cost of the existing distribution system plus the full cost of the new NEFC Hot Water 22

distribution system. Creative Energy has adjusted the distribution cost allocation so it is based 23

on NEFC’s usage of only part of the steam distribution system (the steam lines providing service 24

23 Included in here is a component that relates to general plant allocated to steam production as well as

CIAC and to NRO Depreciation credits.


Page | 58

to the NEFC area). In Creative Energy’s view, allocating NEFC customers the full unit cost of 1

steam distribution service, plus 100% of the cost of the new hot water network infrastructure 2

in NEFC, would constitute pancaking and would not be a fair allocation of costs. Creative 3

Energy’s allocation methodology instead was as follows: 4

Determine share of distribution system which is used to serve NEFC Hot Water network 5

(distance of relevant lines / distance of total lines) 6

Determine share of steam consumption within those lines which pertains to NEFC. 7

Set NEFC’s cost allocation as [total distribution system costs] x [% of system relied on 8

by NEFC] x [NEFC steam flow through relevant lines / total steam flow in relevant lines] 9

The allocation of distribution costs is as follows: 10

Table 22: Allocation Basis 11

12

Corporate Overheads Pool 13

The Corporate Overheads Pool can be thought of as a “catch all bucket” that captures all other 14

revenue requirement items (excluding direct NEFC costs). It includes the following: 15

Sales Promotion Expenses - Operation 16

Administrative & General – Operation (excluding Admin and General Salaries). 17

Municipal Taxes, 18

Property Taxes, 19

Income Tax Expense, 20

Admin and General Salaries25, 21

Amortization of Rate Base Deferred Expenses, and 22

25 Admin & General Salaries were referred to as “Management Salaries” in the NEFC Application, where

they were treated as a separate cost pool.

Allocation Basis Total NEFC Steam M&K NEFC Steam M&K

Pounds of Steam Consumed 1,073,629 5,629 1,068,000 N/A 0.52% 99.48% N/A

Grossed Up to M# produced @ Plant Gate 90% 1,192,922 5,629 0.47% 99.53% N/A

Page | 59

Amortization of Non - Rate Base Deferred Expenses. 1

2

The Massachusetts Formula has three drivers for allocating costs between utilities: 3

Relative Size of Utility Plant in Service – the size of the Utility in Service would generate the 4

need for back office support, overall shared service expenses to oversee and ensure the 5

operation of the Utility meets corporate targets. 6

Relative Size of Revenues – the use of Revenue drivers is a logical driver to use as a basis for 7

the allocation of Corporate Overhead Costs as this provides an estimate of the effort and 8

support required to support the business unit. 9

Relative Size of Direct Labour Distribution – the use of labour distribution as a basis also 10

provides a logical basis for cost allocation. 11

Table 23: Massachusetts Formula 12

13

Applying the above methodology result in the following allocation to NEFC: 14

Steam Production $13,000 in 2016 and $71,400 in 2017 15

Steam Distribution $2,600 in 2016 and $14,200 in 2017 16

Corporate Overheads $63,600 in 2016 and $177,500 in 2017 17

NES Fuel Recovery Cost Allocation 18

In keeping with the cost allocation methodology used for Steam Production and Steam 19

Distribution costs, the NES Fuel Recovery Cost Allocation is intended to fairly allocate 20

incremental fuel costs to NEFC hot water customers, and avoid unfairly requiring NEFC 21

customers to pay for embedded losses within the existing steam network plus losses within their 22

own network. This was the same approach used in the NEFC CPCN Application. 23

The allocation is based on using a formula to calculate the incremental amount of fuel 24

consumed at the Beatty Street plant to serve NEFC. For any period, this formula calculates a 25

Allocation Basis Total NEFC Steam M&K NEFC Steam M&K

Massachusetts Formula Allocation

UPIS 47,307,107 1,958,425 44,998,682 350,000 4.14% 95.12% 0.74%

Revenues 9,076,547 146,200 8,808,196 122,151 1.61% 97.04% 1.35%

Direct Labour 2,186,388 17,300 2,165,136 3,952 0.79% 99.03% 0.18%

Average 2.18% 97.06% 0.76%

Page | 60

volume of fuel in GJ. This fuel volume is multiplied by the total unit cost of fuel at Beatty 1

Street, including all carbon taxes, delivery charges, etc and before the allocation of a share of 2

fuel costs to the Steam Rates (as has been historically done). This formula-based approach will 3

ensure that NEFC hot water customers pay the cost of incremental fuel consumption at the 4

Beatty Street plant. As described in the NEFC CPCN proceeding, the formula will initially be set 5

to capture payments to the Clear Sky joint venture, and will be adjusted starting January 1, 6

2020 to account for the full transfer of the Clear Sky economizer unit to Creative Energy. 7

8

The amount of GJ anticipated to be allocated to NEFC NES is: 9

8,500 GJ for 2016 and 45,100 GJ for 2017 10

Direct Assignment Costs 11

Direct assignment costs to NEFC include depreciation and earned return (for converter stations, 12

hot water distributions and energy transfer stations), and NEFC Direct O&M such as maintenance 13

of NEFC-specific assets, direct administration costs, Municipal Access Fees for NEFC, and 14

related items. 15

NEFC Capital Additions and Associated Costs 16

The NEFC hot water network will be built in stages, in parallel with the development it is meant 17

to serve. The capital additions (including AFUDC) for the phases completed during this test 18

period and their inclusion in gross plant in service are $3.9 million for 2016 and further $2.4 19

million for 2017. 20

Included in the depreciation expense above is $0 for 2016 and $177,500 for 2017 on account of 21

incremental depreciation from NEFC. The incremental depreciation is estimated as zero for 22

2016 as it reflects the 2016 capital addition to plant pertaining to NEFC and subsequent 23

depreciation commencing 2017. 24

Included in the Rate Base Return is $123,400 for 2016 and $317,800 for 2017 on account of 25

incremental rate base financing for NEFC. 26

Page | 61

The NEFC Revenue Requirement also includes income tax costs of $0 in 2016 and $27,300 in 1

2017 based on the earned return shown above. 2

NEFC Direct O&M 3

NEFC Direct O&M is estimated as follows: 4

O&M Expense of $92,000 for 2016, and $188,300 for 2017. 5

Municipal Taxes of $1,800 for 2016, and $10,300 for 2017. 6

Summary of NEFC Revenue Requirement 7

Table 24 summarizes the NEFC Revenue Requirement. 8

Table 24: NEFC Revenue Requirement 9

10

11

1 NEFC HOT WATER SERVICE REVENUE REQUIREMENT 2016 2017

2 NEFC NEFC

3 NEFC Direct Assigned Costs

4 O&M 92,000 188,300

5 Municipal Access Fees (MAF) 1,800 10,300

6 Total Operating and Maintenance (incl. MAF) 4+5 93,800 198,600

7 Income Taxes - 27,300

8 Depreciation - 177,800

9 Amortization of RDDA Costs 8,000 8,000

10 Proposed Cost of Debt 44,100 113,500

11 Proposed Return on Equity 79,300 204,300

12 Total DHW Direct Assigned Costs Sum(6-11) 225,200 729,500

13

14 Steam Costs Allocated to NEFC NES

15 Steam Production 13,000 71,400

16 Steam Distribution 2,600 14,200

17 Total Steam Prod'n & Dist'n Cost Allocated to DHW 15+16 15,600 85,600

18 Corporate Overhead Allocated to DHW 63,600 177,500

19 17+18 79,200 263,100

20 Fuel 51,200 333,500

21

22 Net Fuel 20-21 51,200 333,500

23 Total Steam Costs Allocated to DHW 19+22 130,400 596,600

24 Revenue Requirement including Allocation from Steam System 355,600$ 1,326,100$

25

Page | 62

Variances from NEFC CPCN Proceeding 1

The 2016-2017 NEFC Hot Water revenue requirement is slightly different from the revenue 2

requirement filed as part of the NEFC CPCN proceeding. The Carbon Reduction Rider has been 3

excluded from the project and from the revenue requirement. Creative Energy has also made 4

some adjustments to how depreciation and taxes are recorded, and to the Steam Cost 5

Allocation. There has been no change to the weighted average connected floor area or to total 6

energy sales in the NEFC load forecast. The below table summarizes the revenue requirement 7

variances for 2016 and 2017. 8

9

10

The variance in depreciation in 2016 is due to a change in accounting treatment of depreciation. 11

Hard capital costs are unchanged, but development costs have increased slightly. The variance 12

NEFC CPCN Application

2016 2017

NES Fuel Cost Allocation 53$ 302$

Carbon Rider 7$ 42$

Steam Cost Allocation 76$ 234$

Other O&M 65$ 108$

Depreciation 141$ 220$

Interest 48$ 127$

ROE 85$ 223$

Income Taxes -$ -$

475$ 1,255$

Current Application

2016 2017

NES Fuel Cost Allocation 51$ 334$

Carbon Rider -$ -$

Steam Cost Allocation to NES 77$ 266$

Direct O&M 92$ 198$

Depreciation -$ 178$

Interest 44$ 114$

ROE 79$ 204$

Amortization of RDDA Costs 8$ 8$

Income Taxes -$ 27$

352$ 1,329$

Variance 123-$ 74$

Page | 63

in income taxes is based only on a different accounting treatment of taxes, not on any changes 1

to CCA schedules or the overall tax liability. The variance in Steam Cost Allocation to NES is 2

due to a change in methodology. Over the 15 years required to recover the deferral account, 3

this change in methodology has increased the total Steam Cost Allocation to NES by ~10% on a 4

present value basis. 5

6

Rates for Hot Water Service 7

In the NEFC CPCN proceeding, Creative Energy proposed a rate structure that included both a 8

fixed and a variable charge. The NEFC Decision specified that Creative Energy adopt a 37% fixed 9

/ 63% variable rate structure. Creative Energy notes that the NEFC Decision is internally 10

inconsistent, as it references two different ratios between fixed and variable revenues: the 11

Executive Summary references a 67% fixed / 33% variable rate structure, while the Directive on 12

page 68 references a 37% fixed / 63% variable rate structure. We also note that the decision, 13

by eliminating the Carbon Reduction Rider, actually changed the split between fixed and 14

variable costs incurred by the system. 15

There was also some confusion on the record in the NEFC proceeding, based on Creative Energy 16

mischaracterizing some costs. The Steam Production and Steam Distribution cost allocations 17

are volume-based allocations, and in providing information on fixed and variable costs during 18

NEFC CPCN proceeding, Creative Energy characterized these as variable costs from the 19

standpoint of NEFC customers. However, ultimately they are fixed costs regardless of the 20

allocation methodology, and Creative Energy submits in this application to allocate these costs 21

based on projected energy volumes, rendering them fixed from the perspective of NEFC. 22

This change in how to characterize fixed and variable costs produces an approximate 23

fixed/variable cost split of 60% fixed / 40% variable. 24

Given the above, Creative Energy proposes to adopt, for simplicity, a rate structure that 25

recovers 50% of revenue through a fixed charge, and 50% of revenue through a variable charge. 26

This is reasonably close to the underlying cost structure and is simple to communicate to 27

customers. 28

The NEFC hot water rates were developed in part by using an updated version of the financial 29

model relied on by Creative Energy during the NEFC CPCN proceeding. This updated model is 30

attached as part of this submission. Creative Energy is aware of some minor outstanding 31

Page | 64

discrepancies between this updated NEFC model, and the methodologies and schedules shown 1

in this Application. Creative Energy intends to file an updated NEFC rate model by April 30, 2

2016 as part of its proposed Application Update to incorporate other information expected to 3

be available. These refinements are not considered material and do not affect the requested 4

NEFC hot water rates for 2016 and 2017. They may affect the forecast balance of the RDDA at 5

the end of 2017, and the escalation in rates for years 2018 and beyond. 6

Creative Energy proposes the following NEFC Hot Water Rates: 7

Description Abbreviation Effective Rate Fixed Charge Variable Charge

NEFC Hot Water Rates

NEFC HW 2016: $85 per MWh

2017: $87 per MWh

2016: $0.33/m2/mth

2017: $0.34/m2/mth

2016: $43 per MWh

2017: $43.89 per MWh

8

As shown in the NEFC model, the rates will not recover the full revenue requirement in Test 9

Period 2016 and Test Period 2017. That is, the revenue requirement will exceed revenues. It 10

is for this reason that Creative Energy sought approval for the Revenue Deficiency Deferral 11

Account (RDDA). The Commission approved the establishment of the RDDA as follows; 12

The Panel approves the establishment of the RDDA and approves the accrual of 13

carrying charges on the RDDA based on Creative Energy’s after-tax weighted average 14

cost of capital.26 15

The Commission then deferred any determinations with regard to the recording of variances 16

between forecast and actual amounts in the RDDA.27 Creative Energy now proposes that the 17

difference between forecast revenue requirements, adjusted for actual fuel expenses, and 18

actual revenues be recorded in the RDDA. Details of the debits and credits recorded in the 19

RDDA are included in the NEFC model. 20

Creative Energy also proposes that the RDDA be recovered in fifteen years as advocated during 21

the NEFC proceeding, and as commented in the NEFC Decision. 28 22


27 Ibid.

28 Ibid.

Page | 65

1

2

3

4

5

Page | 66

6 APPENDIX 1 REVENUE REQUIREMENTS SCHEDULES 1

2

CREATIVE ENERGY VANCOUVER PLATFORMS INC.

2016-2017 REVENUE REQUIREMENT APPLICATION

TABLE OF CONTENTS

Schedule Name Schedule # Tab Hyperlink

REVENUE REQUIREMENT Schedule 1 RRA

RATE BASE Schedule 2 Rate_Base

PLANT CONTINUITY Schedule 3 Plant_Cnt

PLANT IN SERVICE Schedule 4 PIS

ACCUMULATED DEPRECIATION Schedule 5 AccD

CONTRIBUTIONS IN AID OF CONSTRUCTION Schedule 6 CIAC

WORK-IN-PROGRESS Schedule 7 WIP

NON-REGULATORY PLANT Schedule 8 NR_Plant

WORKING CAPITAL (OTHER ITEMS) Schedule 9 WC_Items

CASH WORKING CAPITAL Schedule 10 Cash_WC

RATE BASE SCHEDULE Schedule 11 RB

DEFERRED EXPENSES - NON RATE BASE Schedule 12 NRB_Deferrals

CAPITAL STRUCTURE AND COST OF CAPITAL Schedule 13 CS_COC

FUEL COST - BASE CHARGE Schedule 14 Fuel_BC

OPERATING & MAINTENANCE EXPENSES Schedule 15 O&M

PROPERTY TAXES Schedule 16 Prop_Tax

MUNICIPAL TAXES Schedule 17 Mun_Tax

LONG TERM DEBT CONTINUITY SCHEDULE Schedule 18 LTD

INCOME TAXES Schedule 19 TAX

CAPITAL COST ALLOWANCE & CUMULATIVE ELIGIBLE CAPITAL Schedule 20 CCA_CEC

REVENUES Schedule 21 Rev

Schedule Index



REVENUE REQUIREMENT Schedule 1

2011 2012 2013 2014 2015 2015 2016 2017

Line # Item Actual Actual Actual Actual Approved Unaudited Forecast Forecast Reference

1 Fuel Expense - Base Cost 776,987 747,104 713,966 679,578 708,850 516,156 698,700 716,000 Schedule 14

2 Operation & Maintenance Expense 3,325,093 3,725,998 3,800,717 4,028,927 4,296,955 4,219,149 4,541,000 4,642,800 Schedule 15

3 Municipal Taxes 208,873 205,226 203,043 219,893 226,316 234,217 264,200 281,000 Schedule 17

4 Other 0 0 0 0 0

5 Total Operating and Maintenance Expense 4,310,953 4,678,328 4,717,726 4,928,399 5,232,121 4,969,521 5,503,900 5,639,800

6 Property Taxes 208,945 293,237 279,508 302,798 318,375 306,658 340,700 357,800 Schedule 16

7 Income Tax Expense 206,827 42,943 0 0 237,496 73,845 240,400 266,000 Schedule 19

8 Depreciation Expense 855,980 869,146 875,141 888,873 946,757 916,215 944,900 1,137,200 Schedule 5

9 Depreciation Expense Allocated to Non Reg (706) (706) (706) (706) (700) (700) Schedule 8

10 Amortization of CIAC (18,513) (18,050) (17,598) (17,158) (24,629) (23,100) (23,100) (25,600) Schedule 6

11 Amortization of Rate Base Deferred Exp. 0 0 166,500 166,500 Schedule 11

12 Amortization of Non - Rate Base Deferred Exp. 110,500 110,500 Schedule 13

13 Actual/Proposed Return on Rate Base 1,842,990 1,274,293 1,087,128 1,147,214 1,638,914 1,114,997 1,763,000 1,989,000 Schedule 13

14 Cost of Services 7,407,183 7,139,897 6,941,198 7,249,419 8,348,329 7,357,430 9,046,100 9,640,500

15

16 Total Revenue Requirement 7,407,183 7,139,897 6,941,198 7,249,419 8,348,329 7,357,430 9,046,100 9,640,500

17

18 Fuel Cost Stabilization Account Interest Costs 36,032 per BCUC G-98-15

19 Other Income 9,376 33,804 9,730 7,700 12,400 4,800 5,000 5,000 Schedule 21

20 Steam Sales Revenues 7,397,807 7,106,093 6,931,468 7,241,719 8,299,898 7,352,630 9,041,100 9,635,500 Schedule 21

21 Total Revenues 7,407,183 7,139,897 6,941,198 7,249,419 8,348,329 7,357,430 9,046,100 9,640,500

22

23 Revenue (Surplus)/Deficiency 0 (0) 0 (0) (0) 0 0 0



RATE BASE Schedule 2

2011 2012 2013 2014 2015 2015 2016 2017

Line # Item Formulae Actual Actual Actual Actual Approved Unaudited Forecast Forecast Reference

1 GROSS PLANT IN SERVICES

2 Opening Balance 37,585,131 38,639,629 39,409,006 40,702,244 41,903,971 41,295,177 42,252,277 47,745,087 Schedule 3

3 Closing Balance 38,639,629 39,409,006 40,702,244 41,295,176 42,757,489 42,252,277 47,745,087 51,379,568 Schedule 3

4 Add/Subtract: 13 Month Avereage Adjustment

5 Average Balance (Mid-Year) (2+3)/2+4 38,112,380 39,024,318 40,055,625 40,998,710 42,330,730 41,773,727 44,998,682 49,562,327

6

7 ACCUMULATED DEPRECIATION

8 Opening Balance (13,386,367) (14,184,531) (15,053,677) (15,928,818) (16,792,216) (16,733,386) (17,649,601) (18,594,525) Schedule 3

9 Closing Balance (14,184,531) (15,053,677) (15,928,818) (16,733,386) (17,738,973) (17,649,601) (18,594,525) (19,731,695) Schedule 3

10 Average Balance (Mid-Year) (8+9)/2 (13,785,449) (14,619,104) (15,491,248) (16,331,102) (17,265,595) (17,191,493) (18,122,063) (19,163,110)

11

12 NET MID-YEAR PLANT IN SERVICE (5+10) 24,326,931 24,405,214 24,564,377 24,667,608 25,065,136 24,582,234 26,876,619 30,399,217

13

14 NET MID-YEAR CIAC* (731,243) (712,962) (695,138) (677,759) (638,649) (657,630) (684,530) (710,180) Schedule 6

15

16 MID-YEAR NET PLANT ALLOCATED TO NON-REG (37,637) (30,573) (29,866) (29,160) (28,404) (28,404) (27,698) (26,992) Schedule 8

17

18 MID-YEAR DEFERRED ACCOUNTS 747,024 747,024 663,774 497,268 Schedule 11

19

20 MID-YEAR WORKING CAPITAL** 642,819 650,983 617,173 964,861 716,767 1,266,096 1,421,846 1,450,864

21

22 MID YEAR RATE BASE 24,200,871 24,312,663 24,456,546 24,925,550 25,861,873 25,909,320 28,250,011 31,610,178(12+14+16

+18+20)



PLANT CONTINUITY Schedule 3

2010 2011 2012 2013 2014 2015 2015 2016 2017

Line # Item Actual Actual Actual Actual Actual Approved Unaudited Forecast Forecast Reference

1 Opening Gross Plant 36,749,884 37,585,131 38,639,629 39,409,006 40,702,244 41,903,971 41,295,177 42,252,277 47,745,087 Schedule 4

2 Closing Gross Plant 37,585,131 38,639,629 39,409,006 40,702,244 41,295,176 42,757,489 42,252,277 47,745,087 51,379,568 Schedule 4

3

4 Opening Accumulated Depreciation (12,548,644) (13,386,367) (14,184,531) (15,053,677) (15,928,818) (16,792,216) (16,733,386) (17,649,601) (18,594,525) Schedule 5

5 Closing Accumulated Depreciation (13,386,367) (14,184,531) (15,053,677) (15,928,818) (16,733,386) (17,738,973) (17,649,601) (18,594,525) (19,731,695) Schedule 5



PLANT IN SERVICE Schedule 4

Line # Acct. # Account Name

Opening

Balance Additions Retiremt. Adj. Transfers

Closing

Balance

1 Intangible Plant

2 301 Organization Expense 20,055 20,055

3 302 Franchises & Consents 57,932 57,932

4 303 Other Intangible Plant 8,070 8,070

5 Total Intangible Plant 86,057 0 0 0 0 86,057

6

7 Steam Production Plant

8 310 Land 565,525 565,525

9 310.1 Land Rights 0

10 311 Structures & Improvements 1,889,122 163,571 2,052,693

11 312.1 Boiler Plant Equipment 6,790,118 120,595 7,928,508

12 312.2 Boiler Tanks Equipment 130,845 0

13 312.3 Boiler Auxiliary Equipment 886,950 0

14 315 Accessory Electric Equipment 450,188 450,188

15 316 Other Steam Production Equipment 6,896 6,896

16 Total Steam Production Plant 10,719,644 284,166 0 0 0 11,003,810

17

18 Distribution Plant

19 374 Land 0


21 375 Structures & Improvements 0

22 376 Mains 13,266,866 16,116 13,282,982

23 378 Manhole Structures 1,678,129 383,385 2,061,514

24 380 Services 1,994,672 1,994,672

25 381 Meters 81,479 81,479

26 382 House Regulators & Meter Installations 8,240,297 147,755 8,388,052

27 387 Other Distribution Equipment 38,925 38,925

28 Total Distribution Plant 25,300,368 547,256 0 0 0 25,847,624

29

30 General Plant

31 389 Land 0


33 390 Structures & Improvements 295,135 295,135

34 391 Office Furniture & Equipment 64,957 3,825 68,782

35 391.1 Office Electronics 92,436 92,436

36 392 Transportation Equipment 112,527 112,527

37 393 Stores Equipment 3,068 3,068

38 394 Tools & Work Equipment 62,420 62,420

39 395 Laboratory Equipment 0

40 396 Heavy Work Equipment 0

41 397 Communication Structures & Equipment 0

42 398 Other General Equipment 13,272 13,272

43 Total General Plant 643,815 3,825 0 0 0 647,640

44

45 Undistributed Plant

46 306 Unclassified Plant 0

47 307 Allowance for Funds used during Construction 0

48 308 Overhead charged to Construction 0

49 Total Undistributed Plant 0 0 0 0 0 0

50

51 TOTAL UTILITY PLANT IN SERVICE 36,749,884 835,246 0 0 0 37,585,131

2010





Opening


Closing

Balance

1 Intangible Plant





6


8 310 Land 565,525 565,525

9 310.1 Land Rights 0 0

10 311 Structures & Improvements 2,052,693 2,052,693







17


19 374 Land 0 0


21 375 Structures & Improvements 0 0

22 376 Mains 13,282,982 13,282,982

23 378 Manhole Structures 2,061,514 67 2,061,581

24 380 Services 1,994,672 521,611 (38,868) 2,477,415

25 381 Meters 81,479 6,050 87,529

26 382 House Regulators & Meter Installations 8,388,052 554,938 (67,865) 8,875,125


28 Total Distribution Plant 25,847,624 1,082,666 0 (106,733) 0 26,823,557

29

30 General Plant

31 389 Land 0 0



34 391 Office Furniture & Equipment 68,782 2,955 71,737

35 391.1 Office Electronics 92,436 3,388 95,824



38 394 Tools & Work Equipment 62,420 3,965 66,385

39 395 Laboratory Equipment 0 0

40 396 Heavy Work Equipment 0 0

41 397 Communication Structures & Equipment 0 0



44


46 306 Unclassified Plant 0 0

47 307 Allowance for Funds used during Construction 0 0

48 308 Overhead charged to Construction 0 0


50

51 TOTAL UTILITY PLANT IN SERVICE 37,585,131 1,161,231 0 (106,733) 0 38,639,629

2011





Opening


Closing

Balance

1 Intangible Plant





6


8 310 Land 565,525 565,525









17


19 374 Land 0 0



22 376 Mains 13,282,982 102 13,283,084


24 380 Services 2,477,415 35,110 2,512,525

25 381 Meters 87,529 7,050 94,579




29

30 General Plant

31 389 Land 0 0


33 390 Structures & Improvements 295,135 10,567 305,702

34 391 Office Furniture & Equipment 71,737 71,737










44






50


2012





Opening


Closing

Balance

1 Intangible Plant





6


8 310 Land 565,525 565,525




12 312.2 Boiler Tanks Equipment 130,845 130,845

13 312.3 Boiler Auxiliary Equipment 889,492 889,492




17


19 374 Land 0 0



22 376 Mains 13,283,084 140,024 13,423,108


24 380 Services 2,512,525 16,910 2,529,435

25 381 Meters 94,579 94,579




29

30 General Plant

31 389 Land 0 0




35 391.1 Office Electronics 97,592 942 98,534



38 394 Tools & Work Equipment 66,385 4,187 70,572






44






50

51 TOTAL UTILITY PLANT IN SERVICE 39,409,006 1,293,238 0 0 0 40,702,244

2013





Opening


Closing

Balance

1 Intangible Plant

2 301 Organization Expense 20,055 (20,055) 0

3 302 Franchises & Consents 57,932 (57,932) 0

4 303 Other Intangible Plant 8,070 (8,070) 0

5 Total Intangible Plant 86,057 0 (86,057) 0 0 0

6


8 310 Land 565,525 565,525




12 312.2 Boiler Tanks Equipment 130,845 130,845

13 312.3 Boiler Auxiliary Equipment 889,492 889,492




17


19 374 Land 0 0



22 376 Mains 13,423,108 91,745 13,514,853


24 380 Services 2,529,435 15,736 2,545,171

25 381 Meters 94,579 94,579


27 387 Other Distribution Equipment 38,925 15,230 54,155


29

30 General Plant

31 389 Land 0 0


33 390 Structures & Improvements 305,702 95,364 401,066

34 391 Office Furniture & Equipment 71,737 (13,504) 58,233


36 392 Transportation Equipment 112,527 18,714 131,241






42 398 Other General Equipment 13,272 1,452 14,724

43 Total General Plant 675,412 205,791 (13,504) 0 0 867,699

44






50

51 TOTAL UTILITY PLANT IN SERVICE 40,702,244 692,493 (99,561) 0 0 41,295,176

2014





Opening


Closing

Balance

1 Intangible Plant

2 301 Organization Expense 0

3 302 Franchises & Consents 0

4 303 Other Intangible Plant 0

5 Total Intangible Plant 0 0 0 0 0 0

6


8 310 Land 565,525 (17,000) 548,525


10 311 Structures & Improvements 2,137,202 2,137,202


12 312.2 Boiler Tanks Equipment 0

13 312.3 Boiler Auxiliary Equipment 0



16 Total Steam Production Plant 11,648,973 139,000 (17,000) 0 0 11,770,973

17


19 374 Land 0


21 375 Structures & Improvements 0

22 376 Mains 13,509,379 10,000 13,519,379


24 380 Services 2,641,691 190,518 2,832,209

25 381 Meters 94,579 94,579

26 382 House Regulators & Meter Installations 9,984,120 9,984,120



29

30 General Plant

31 389 Land 0








39 395 Laboratory Equipment 0

40 396 Heavy Work Equipment 0

41 397 Communication Structures & Equipment 0


43 Total General Plant 1,022,622 16,000 0 0 0 1,038,622

44


46 306 Unclassified Plant 0

47 307 Allowance for Funds used during Construction 0

48 308 Overhead charged to Construction 0


50

51 TOTAL UTILITY PLANT IN SERVICE 41,903,971 870,518 (17,000) 0 0 42,757,489

2015 Approved





Opening


Closing

Balance

1 Intangible Plant

2 301 Organization Expense 0 0 0 0 0 0

3 302 Franchises & Consents 0 0 0 0 0 0

4 303 Other Intangible Plant 0 0 0 0 0 0


6


8 310 Land 565,525 0 0 0 0 565,525

9 310.1 Land Rights 0 0 0 0 0 0

10 311 Structures & Improvements 2,139,065 1,500 0 0 0 2,140,565

11 312.1 Boiler Plant Equipment 7,498,962 70,348 0 0 0 7,569,310

12 312.2 Boiler Tanks Equipment 130,845 0 0 0 0 130,845

13 312.3 Boiler Auxiliary Equipment 889,492 119,053 0 0 0 1,008,545

14 315 Accessory Electric Equipment 450,188 0 0 0 0 450,188

15 316 Other Steam Production Equipment 6,896 0 0 0 0 6,896


17


19 374 Land 0 0 0 0 0 0

20 374.1 Land Rights 0 0 0 0 0 0

21 375 Structures & Improvements 0 0 0 0 0 0

22 376 Mains 13,514,853 0 0 0 0 13,514,853

23 378 Manhole Structures 2,952,749 747 0 0 0 2,953,496

24 380 Services 2,545,171 86,996 0 0 0 2,632,167

25 381 Meters 94,579 0 0 0 0 94,579

26 382 House Regulators & Meter Installations 9,584,996 542,176 0 0 0 10,127,172

27 387 Other Distribution Equipment 54,155 0 0 0 0 54,155


29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389.1 Land Rights 0 0 0 0 0 0

33 390 Structures & Improvements 401,066 2,577 0 0 0 403,643

34 391 Office Furniture & Equipment 58,233 3,640 0 0 0 61,873

35 391.1 Office Electronics 188,795 130,065 0 0 0 318,860

36 392 Transportation Equipment 131,241 0 0 0 0 131,241

37 393 Stores Equipment 3,068 0 0 0 0 3,068

38 394 Tools & Work Equipment 70,572 0 0 0 0 70,572

39 395 Laboratory Equipment 0 0 0 0 0 0

40 396 Heavy Work Equipment 0 0 0 0 0 0

41 397 Communication Structures & Equipment 0 0 0 0 0 0

42 398 Other General Equipment 14,724 0 0 0 0 14,724

43 Total General Plant 867,699 136,281 0 0 0 1,003,980

44


46 306 Unclassified Plant 0 0 0 0 0 0

47 307 Allowance for Funds used during Construction 0 0 0 0 0 0

48 308 Overhead charged to Construction 0 0 0 0 0 0


50


2015 Unaudited





Opening


Closing

Balance

1 Intangible Plant





6


8 310 Land 565,525 0 0 0 0 565,525

9 310.1 Land Rights 0 0 0 0 0 0

10 311 Structures & Improvements 2,140,565 0 0 0 0 2,140,565

11 312.1 Boiler Plant Equipment 7,569,310 670,500 0 0 278,523 8,518,333


13 312.3 Boiler Auxiliary Equipment 1,008,545 0 0 0 0 1,008,545



16 Total Steam Production Plant 11,871,875 670,500 0 0 278,523 12,820,897

17


19 374 Land 0 0 0 0 0 0

20 374.1 Land Rights 0 0 0 0 0 0


22 376 Mains 13,514,853 1,518,767 0 0 0 15,033,620


24 380 Services 2,632,167 0 0 0 0 2,632,167

25 381 Meters 94,579 0 0 0 0 94,579


27 387 Other Distribution Equipment 54,155 2,615,020 0 0 0 2,669,175

28 Total Distribution Plant 29,376,422 4,543,787 0 0 0 33,920,209

29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389.1 Land Rights 0 0 0 0 0 0

33 390 Structures & Improvements 403,643 0 0 0 0 403,643

34 391 Office Furniture & Equipment 61,873 0 0 0 0 61,873

35 391.1 Office Electronics 318,860 0 0 0 0 318,860








43 Total General Plant 1,003,980 0 0 0 0 1,003,980

44






50

51 TOTAL UTILITY PLANT IN SERVICE 42,252,277 5,214,287 0 0 278,523 47,745,087

2016





Opening


Closing

Balance

1 Intangible Plant





6


8 310 Land 565,525 0 0 0 0 565,525

9 310.1 Land Rights 0 0 0 0 0 0

10 311 Structures & Improvements 2,140,565 0 0 0 0 2,140,565

11 312.1 Boiler Plant Equipment 8,518,333 250,000 0 0 0 8,768,333


13 312.3 Boiler Auxiliary Equipment 1,008,545 0 0 0 0 1,008,545




17


19 374 Land 0 0 0 0 0 0

20 374.1 Land Rights 0 0 0 0 0 0


22 376 Mains 15,033,620 1,983,227 0 0 0 17,016,847


24 380 Services 2,632,167 0 0 0 0 2,632,167

25 381 Meters 94,579 0 0 0 0 94,579


27 387 Other Distribution Equipment 2,669,175 1,301,254 0 0 0 3,970,429

28 Total Distribution Plant 33,920,209 3,384,481 0 0 0 37,304,690

29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389.1 Land Rights 0 0 0 0 0 0

33 390 Structures & Improvements 403,643 0 0 0 0 403,643

34 391 Office Furniture & Equipment 61,873 0 0 0 0 61,873

35 391.1 Office Electronics 318,860 0 0 0 0 318,860








43 Total General Plant 1,003,980 0 0 0 0 1,003,980

44






50

51 TOTAL UTILITY PLANT IN SERVICE 47,745,087 3,634,481 0 0 0 51,379,568

2017



ACCUMULATED DEPRECIATION Schedule 5

Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant

2 301 Organization Expense 20,055 0 20,055 1.00% (5,011) (201) (5,211)

3 302 Franchises & Consents 57,932 0 57,932 1.00% (23,788) (579) (24,367)

4 303 Other Intangible Plant 8,070 0 8,070 1.00% (3,147) (81) (3,228)

5 Total Intangible Plant 86,057 0 86,057 (31,946) (861) 0 (32,806)

6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0 0 0

10 311 Structures & Improvements 1,889,122 (1) 1,889,121 1.50% (530,599) (28,337) (558,936)

11 312 Boiler Plant Equipment 6,790,118 (1,153,167) 5,636,950 2.50% (3,697,857) (140,924) (3,838,781)

12 312 Boiler Tanks Equipment 130,845 (24,145) 106,700 2.50% (69,197) (2,668) (71,864)

13 312 Boiler Auxiliary Equipment 886,950 (103,374) 783,576 5.00% (484,335) (39,179) (523,513)

14 315 Accessory Electric Equipment 450,188 (48,783) 401,405 5.00% (181,293) (20,070) (201,363)

15 316 Other Steam Production Equipment 6,896 (6,896) 0 5.00% (6,896) 0 (6,896)

16 Total Steam Production Plant 10,719,644 (1,336,366) 9,383,278 (4,970,177) (231,177) 0 (5,201,354)

17


19 374 Land 0 0 0 0 0

20 374 Land Rights 0 0 0 0 0

21 375 Structures & Improvements 0 0 0 0 0

22 376 Mains 13,266,866 0 13,266,866 2.00% (4,135,535) (265,337) (4,400,873)

23 378 Manhole Structures 1,678,129 0 1,678,129 1.50% (479,393) (25,172) (504,565)

24 380 Services 1,994,672 (0) 1,994,672 2.00% (600,576) (39,893) (640,469)

25 381 Meters 81,479 (5,540) 75,939 3.00% (13,704) (2,278) (15,982)

26 382 House Regulators & Meter Instal. 8,240,297 (315,471) 7,924,826 3.00% (2,055,049) (237,745) (2,292,793)

27 387 Other Distribution Equipment 38,925 (17,603) 21,322 5.00% (24,283) (1,066) (25,349)

28 Total Distribution Plant 25,300,368 (338,614) 24,961,754 (7,308,540) (571,492) 0 (7,880,031)

29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389 Land Rights 0 0 0 0 0 0

33 390 Structures & Improvements 295,135 (0) 295,135 1.50% (36,528) (4,427) (40,955)

34 391 Office Furniture & Equipment 64,957 (41,212) 23,745 5.00% (85,600) (1,187) (86,787)

35 391 Office Electronics 92,436 (31,201) 61,235 20.00% (20,392) (12,247) (32,639)

36 392 Transportation Equipment 112,527 (24,147) 88,380 15.00% (50,235) (13,257) (63,492)

37 393 Stores Equipment 3,068 (3,068) 0 5.00% (3,068) 0 (3,068)

38 394 Tools & Work Equipment 62,420 (13,000) 49,420 5.00% (39,118) (2,471) (41,589)



41 397 Comm. Structures & Equipment 0 0 0 0 0 0

42 398 Other General Equipment 13,272 (1,197) 12,075 5.00% (3,040) (604) (3,644)

43 Total General Plant 643,815 (113,825) 529,990 (237,982) (34,193) 0 (272,175)

44



47 307 AFUDC 0 0 0 0 0 0


49 Total Undistributed Plant 0 0 0 0 0 0 0

50

51 TOTAL UTILITY PLANT IN SERVICE 36,749,884 (1,788,805) 34,961,078 (12,548,644) (837,722) 0 (13,386,367)

0

2010




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant





6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0 0 0

10 311 Structures & Improvements 2,052,693 0 2,052,693 1.50% (558,936) (30,790) (589,727)







17


19 374 Land 0 0 0 0 0 0

20 374 Land Rights 0 0 0 0 0 0


22 376 Mains 13,282,982 0 13,282,982 2.00% (4,400,873) (265,660) (4,666,532)

23 378 Manhole Structures 2,061,514 0 2,061,514 1.50% (504,565) (30,923) 21,054 (514,434)

24 380 Services 1,994,672 0 1,994,672 2.00% (640,469) (39,893) (680,362)

25 381 Meters 81,479 (5,540) 75,939 3.00% (15,982) (2,278) (18,260)

26 382 House Regulators & Meter Instal. 8,388,052 (315,471) 8,072,581 3.00% (2,292,793) (242,177) 36,762 (2,498,209)


28 Total Distribution Plant 25,847,624 (338,614) 25,509,010 (7,880,031) (581,998) 57,816 (8,404,213)

29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389 Land Rights 0 0 0 0 0 0

33 390 Structures & Improvements 295,135 0 295,135 1.50% (40,955) (4,427) (45,382)











44



47 307 AFUDC 0 0 0 0 0 0



50

51 TOTAL UTILITY PLANT IN SERVICE 37,585,131 (1,778,662) 35,806,468 (13,386,367) (855,980) 57,816 (14,184,531)

0

2011




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant





6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0 0 0








17


19 374 Land 0 0 0 0 0 0

20 374 Land Rights 0 0 0 0 0 0


22 376 Mains 13,282,982 0 13,282,982 2.00% (4,666,532) (265,660) (4,932,192)


24 380 Services 2,477,415 0 2,477,415 2.00% (680,362) (49,548) (729,911)

25 381 Meters 87,529 (5,540) 81,989 3.00% (18,260) (2,460) (20,720)


27 387 Other Distribution Equipment 38,925 (20,548) 18,377 5.00% (26,415) (919) (27,334)


29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389 Land Rights 0 0 0 0 0 0












44



47 307 AFUDC 0 0 0 0 0 0



50


0

2012




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant





6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0 0 0








17


19 374 Land 0 0 0 0 0 0

20 374 Land Rights 0 0 0 0 0 0


22 376 Mains 13,283,084 0 13,283,084 2.00% (4,932,192) (265,662) (5,197,854)


24 380 Services 2,512,525 0 2,512,525 2.00% (729,911) (50,251) (780,161)

25 381 Meters 94,579 (5,540) 89,039 3.00% (20,720) (2,671) (23,391)




29

30 General Plant

31 389 Land 0 0 0 0 0 0

32 389 Land Rights 0 0 0 0 0 0












44



47 307 AFUDC 0 0 0 0 0 0



50


0

2013




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant

2 301 Organization Expense 20,055 0 20,055 1.00% (5,813) (201) 6,013 (0)

3 302 Franchises & Consents 57,932 0 57,932 1.00% (26,105) (579) 26,684 0

4 303 Other Intangible Plant 8,070 0 8,070 1.00% (3,470) (81) 3,551 (0)

5 Total Intangible Plant 86,057 0 86,057 (35,388) (861) 36,249 (0)

6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0 0 0






15 316 Other Steam Production Equipment 6,896 (6,896) (0) 5.00% (6,896) 0 (6,896)


17


19 374 Land 0 0 0 0 0

20 374 Land Rights 0 0 0 0 0

21 375 Structures & Improvements 0 0 0 0 0

22 376 Mains 13,423,108 0 13,423,108 2.00% (5,197,854) (268,462) (5,466,316)


24 380 Services 2,529,435 0 2,529,435 2.00% (780,161) (50,589) (830,750)

25 381 Meters 94,579 (5,540) 89,039 3.00% (23,391) (2,671) (26,062)




29

30 General Plant

31 389 Land 0 0 0 0 0

32 389 Land Rights 0 0 0 0 0


34 391 Office Furniture & Equipment 71,737 (42,697) 29,040 5.00% (91,070) (1,452) 32,239 (60,283)

35 391 Office Electronics 98,534 (92,436) 6,098 20.00% (54,975) (1,220) 15,818 (40,376)


37 393 Stores Equipment 3,068 (3,068) 0 5.00% (3,068) (0) (3,068)






43 Total General Plant 675,412 (245,738) 429,674 (357,798) (14,908) 48,057 (324,649)

44


46 306 Unclassified Plant 0 0 0 0 0

47 307 AFUDC 0 0 0 0 0

48 308 Overhead charged to Construction 0 0 0 0 0


50

51 TOTAL UTILITY PLANT IN SERVICE 40,702,244 (2,535,184) 38,167,060 (15,928,818) (888,873) 84,305 (16,733,386)

0

2014




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant

2 301 Organization Expense 0 0 0 1.00% 0

3 302 Franchises & Consents 0 0 0 1.00% 0

4 303 Other Intangible Plant 0 0 0 1.00% 0

5 Total Intangible Plant 0 0 0 0 0 0 0

6


8 310 Land 565,525 565,525 0.00% 0

9 310 Land Rights 0 0 0

10 311 Structures & Improvements 2,137,202 2,137,202 1.50% (684,114) (32,058) (716,172)





15 316 Other Steam Production Equipment 6,896 (6,896) 0 5.00% (6,896) (6,896)


17


19 374 Land 0 0 0


21 375 Structures & Improvements 0 0 0

22 376 Mains 13,509,379 13,509,379 2.00% (5,466,316) (270,188) (5,736,504)

23 378 Manhole Structures 2,948,452 2,948,452 1.50% (623,130) (44,227) (667,357)

24 380 Services 2,641,691 2,641,691 2.00% (830,750) (52,834) (883,584)

25 381 Meters 94,579 (5,540) 89,039 3.00% (26,062) (2,671) (28,733)




29

30 General Plant

31 389 Land 0 0 0


33 390 Structures & Improvements 305,702 305,702 1.50% (58,981) (4,586) (63,567)



36 392 Transportation Equipment 112,527 (112,527) 0 15.00% (109,319) 0 (109,319)



39 395 Laboratory Equipment 0 0 0 0

40 396 Heavy Work Equipment 0 0 0 0

41 397 Comm. Structures & Equipment 0 0 0 0


43 Total General Plant 1,022,622 (282,564) 740,058 (379,625) (45,367) 0 (424,992)

44



47 307 AFUDC 0 0



50


2015 Approved




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant

2 301 Organization Expense 0 0 0 1.00% (0) 0 (0)

3 302 Franchises & Consents 0 0 0 1.00% 0 0 0

4 303 Other Intangible Plant 0 0 0 1.00% (0) 0 (0)

5 Total Intangible Plant 0 0 0 (0) 0 0 (0)

6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0.00% 0 0 0








17


19 374 Land 0 0 0 0.00% 0 0 0

20 374 Land Rights 0 0 0 0.00% 0 0 0

21 375 Structures & Improvements 0 0 0 0.00% 0 0 0

22 376 Mains 13,514,853 0 13,514,853 2.00% (5,466,316) (270,297) (5,736,613)


24 380 Services 2,545,171 0 2,545,171 2.00% (830,750) (50,903) (881,653)

25 381 Meters 94,579 (5,540) 89,039 3.00% (26,062) (2,671) (28,734)




29

30 General Plant

31 389 Land 0 0 0 0.00% 0 0 0

32 389 Land Rights 0 0 0 0.00% 0 0 0


34 391 Office Furniture & Equipment 58,233 (42,697) 15,536 5.00% (60,283) (777) (61,060)



37 393 Stores Equipment 3,068 0 3,068 5.00% (3,068) (153) (3,221)


39 395 Laboratory Equipment 0 0 0 0.00% 0 0 0

40 396 Heavy Work Equipment 0 0 0 0.00% 0 0 0

41 397 Comm. Structures & Equipment 0 0 0 0.00% 0 0 0



44


46 306 Unclassified Plant 0 0 0 0.00% 0 0 0

47 307 AFUDC 0 0 0 0.00% 0 0 0

48 308 Overhead charged to Construction 0 0 0 0.00% 0 0 0


50


2015 Unaudited




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant





6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0.00% 0 0 0




13 312 Boiler Auxiliary Equipment 1,008,545 (512,305) 496,240 5.00% (725,326) (24,812) (750,138)




17


19 374 Land 0 0 0 0.00% 0 0 0

20 374 Land Rights 0 0 0 0.00% 0 0 0


22 376 Mains 13,514,853 0 13,514,853 2.00% (5,736,613) (270,297) (6,006,910)


24 380 Services 2,632,167 0 2,632,167 2.00% (881,653) (52,643) (934,297)

25 381 Meters 94,579 (5,540) 89,039 3.00% (28,734) (2,671) (31,405)




29

30 General Plant

31 389 Land 0 0 0 0.00% 0 0 0

32 389 Land Rights 0 0 0 0.00% 0 0 0





37 393 Stores Equipment 3,068 0 3,068 5.00% (3,221) (153) (3,375)







44



47 307 AFUDC 0 0 0 0.00% 0 0 0



50


2016




Line

#

Acct.

# Account Name

Gross

Depreciable

Plant

Fully

Depreciated

Net

Depreciable

Plant

Dep.

Rate

Opening

Accm. Dep.

Dep.

Expense Adj.

Closing Accm.

Dep.

1 Intangible Plant





6


8 310 Land 565,525 0 565,525 0.00% 0 0 0

9 310 Land Rights 0 0 0 0.00% 0 0 0




13 312 Boiler Auxiliary Equipment 1,008,545 (543,874) 464,671 5.00% (750,138) (23,234) (773,371)




17


19 374 Land 0 0 0 0.00% 0 0 0

20 374 Land Rights 0 0 0 0.00% 0 0 0


22 376 Mains 15,033,620 0 15,033,620 2.00% (6,006,910) (300,672) (6,307,582)


24 380 Services 2,632,167 0 2,632,167 2.00% (934,297) (52,643) (986,940)

25 381 Meters 94,579 (5,540) 89,039 3.00% (31,405) (2,671) (34,076)


27 387 Other Distribution Equipment 2,669,175 (20,548) 2,648,627 5.00% (32,532) (132,431) (164,964)


29

30 General Plant

31 389 Land 0 0 0 0.00% 0 0 0

32 389 Land Rights 0 0 0 0.00% 0 0 0





37 393 Stores Equipment 3,068 (3,068) 0 5.00% (3,375) (0) (3,375)







44



47 307 AFUDC 0 0 0 0.00% 0 0 0



50

51 TOTAL UTILITY PLANT IN SERVICE 47,745,087 (3,189,451) 44,555,636 (18,594,525) (1,137,200) 0 (19,731,695)

2017

CREATIVE ENERGY VANCOUVER PLATFORMS INC. Schedule 6


CONTRIBUTIONS IN AID OF CONSTRUCTION

2011 2012 2013 2014 2015 2015 2016 2017


1 GROSS CIAC

2 Opening Balance (922,397) (922,397) (922,397) (922,397) (922,397) (922,397) (922,397) (1,022,397)

3 Repayments

4 Additions (100,000)

5 Closing Balance (922,397) (922,397) (922,397) (922,397) (922,397) (922,397) (1,022,397) (1,022,397)

6

7 CIAC ACCU. DEPRECIATION

8 Opening Balance 181,898 200,411 218,461 236,059 259,119 253,217 276,317 299,417

9 Depreciation 18,513 18,050 17,598 17,158 24,629 23,100 23,100 25,600

10 Closing Balance 200,411 218,461 236,059 253,217 283,748 276,317 299,417 325,017

11

12 NET CIAC

13 Opening Balance (740,499) (721,986) (703,937) (686,338) (663,278) (669,180) (646,080) (722,980)

14 Closing Balance (721,986) (703,937) (686,338) (669,180) (638,649) (646,080) (722,980) (697,380)

15 Net Mid-Year CIAC (731,243) (712,962) (695,138) (677,759) (650,964) (657,630) (684,530) (710,180)

CREATIVE ENERGY VANCOUVER PLATFORMS INC. #N/A


WORK-IN-PROCESS

2011 2012 2013 2014 2015 2015 2016 2017


1 Work-in-Progress Not Earning AFUDC

2 Opening 350,785 392,232 137,446 317,890 754,262 754,262 1,011,496 1,186,496

3 Closing 392,232 137,446 317,890 754,262 (46,262) 1,011,496 1,186,496 1,086,496

4 Mid-year Average 371,509 264,839 227,668 536,076 354,000 882,879 1,098,996 1,136,496



NON-REGULATORY PLANT

2011 2012 2013 2014 2015 2015 2016 2017


1 Land Book Value 60,240$ 60,240$ 60,240$ 60,240$ 60,240$ 60,240$ 60,240$ 60,240$

2 Land - Sq. Feet 51,743 51,743 51,743 51,743 51,743 51,743 51,743 51,743

3 Land Cost Per Sq. Feet 1.164$ 1.164$ 1.164$ 1.164$ 1.164$ 1.164$ 1.164$ 1.164$

4

5 Land - Sq. Feet Leased to Non Utility 12,511 12,511 12,511 12,511 12,468 12,468 12,468 12,468

6 Value of Leased Land to Non Utility 14,565 14,565 14,565 14,565 14,515 14,515 14,515 14,515

7

8

9 Building Book Value 170,000$ 170,000$ 170,000$ 170,000$ 170,000$ 170,000$ 170,000$ 170,000$

10 Building Depreciation Expense 2,550$ 2,550$ 2,550$ 2,550$ 2,550$ 2,550$ 2,550$ 2,550$

11 Building Accumulated Depreciation 109,650 112,200 114,750 117,300 119,850 119,850 122,400 124,950

12 Building Net Book Value (NBV) 60,350 57,800 55,250 52,700 50,150 50,150 47,600 45,050

13 Building - Sq. Feet 40,803 40,803 40,803 40,803 40,803 40,803 40,803 40,803

14 Building Cost per Sq. Feet 1.479$ 1.417$ 1.354$ 1.292$ 1.229$ 1.229$ 1.167$ 1.104$

15

16 Building - Sq. Feet Leased to Non Utility 11,300 11,300 11,300 11,300 11,300 11,300 11,300 11,300

17 Value of Leased Building to Non Utility (NBV) 16,713 16,007 15,301 14,595 13,889 13,889 13,182 12,476

18

19

20 Non Reg Depreciation (706) (706) (706) (706) (700) (700)

21

22 MID-YEAR NET PLANT ALLOCATED TO NON-REG (37,637) (30,573) (29,866) (29,160) (28,404) (28,404) (27,698) (26,992)



WORKING CAPITAL (OTHER ITEMS)

2011 2012 2013 2014 2015 2015 2016 2017


1 Fuel Oil Inventory

2 Opening 199,653 189,189 189,189 184,077 179,444 170,556 164,556 158,556

3 Closing 189,189 189,189 184,077 179,444 170,556 164,556 158,556 152,556

4 Average 194,421 189,189 186,633 181,761 175,000 167,556 161,556 155,556

5

6 Customer Security Deposits

7 Opening (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500)

8 Closing (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500)

9 Average (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500) (3,500)



CASH WORKING CAPITAL2011 2012 2013 2014 2015 2015 2016 2017


1 AMOUNT PAID/ACCRUED

2 Natural Gas & Oil Purchases 12,518,251 10,379,618 12,802,991 14,103,356 11,756,500 9,846,230

3 Operation & Maintenance Expense 3,240,278 3,642,209 3,717,354 3,942,073 4,190,355 4,113,683 4,426,900 4,518,900 Schedule 15

4 Other 0 0 0 0 0 0 0 0

5 Municipal Taxes 208,873 205,226 203,043 219,893 226,316 234,217 264,200 281,000 Schedule 17

6 Income Tax Expense 206,827 42,943 0 0 255,645 73,845 240,400 266,000 Schedule 19

7 Insurance 84,815 83,789 83,363 86,854 106,600 105,466 114,100 123,900 Schedule 15

8 Property Taxes 208,945 293,237 241,536 302,798 318,375 306,658 340,700 357,800 Schedule 16

9

10 NET LAG/(LEAD) DAYS

11 Natural Gas & Oil Purchases 0.08 0.08 0.08 0.08 0.10 0.08 0.09 0.09

12 Operation & Maintenance Expense 19.85 19.95 20.19 21.86 21.79 20.73 20.91 21.10

13 Other 136.88 136.88 136.88 136.88 136.88 136.88 136.88 136.88

14 Municipal Taxes (247.92) (247.92) (247.92) (247.92) (247.90) (247.92) (247.91) (247.91)

15 Income Tax Expense (142.92) (142.92) (142.92) (142.92) (142.90) (142.92) (142.91) (142.91)

16 Insurance 182.50 182.50 182.50 182.50 182.50 182.50 182.50 182.50

17 Property Taxes 136.88 136.88 136.88 136.88 136.88 136.88 136.88 136.88

18

19 WORKING CAPITAL REQUIREMENTS

20 Natural Gas & Oil Purchases 2,732 2,240 2,867 3,268 3,194 2,287 0 0

21 Operation & Maintenance Expense 176,256 199,069 205,660 236,136 250,187 233,643 253,558 261,196

22 Other 0 0 0 0 0 0 0 0

23 Municipal Taxes (141,874) (139,397) (137,913) (149,356) (153,709) (159,085) (179,449) (190,859)

24 Income Tax Expense (80,986) (16,815) 0 0 (100,087) (28,914) (94,128) (104,150)

25 Insurance 42,408 41,895 41,682 43,427 53,300 52,733 57,050 61,950

26 Property Taxes 78,354 109,964 90,576 113,549 119,391 114,997 127,763 134,175

27 Total 76,890 196,955 202,872 247,025 172,275 215,661 164,794 162,312

28 Oil Inventory 194,421 189,189 186,633 181,761 175,000 167,556 161,556 155,556

29 Customer Deposits (3,500) (3,500)

30 Work in Proccess 371,509 264,839 227,668 536,076 354,000 882,879 1,098,996 1,136,496

31 TOTAL WORKING CAPITAL REQUIREMENT 642,819 650,983 617,173 964,861 701,275 1,266,096 1,421,846 1,450,864



RATE BASE SCHEDULE Schedule 11

Line 2015 Approved - Account Name

2015

Opening

Balance Opening Adj.

Adjusted

Opening Bal.

Additions/

(Deductions) Adj. Less Taxes Net Additions Amortization

Ending

Balance

Mid-Year

Balance

1 After Tax Pension Asset 414,012$ 414,012$ -$ 414,012$ 414,012$

2 GCOC Deferral Account 2013/2014 333,012$ -$ 333,012$ -$ 333,012$ 333,012$

3 -$ -$ -$ -$

4 -$ -$ -$ -$

5 Total 747,024$ -$ 747,024$ -$ -$ -$ -$ -$ 747,024$ 747,024$

Line 2015 Projected - Account Name

2015

Opening


Adjusted

Opening Bal.

Additions/

(Deductions) Adj. Less Taxes Net Additions Amortization

Ending

Balance

Mid-Year

Balance


2 GCOC Deferral Account 2013/2014 333,012$ -$ 333,012$ -$ 333,012$ 333,012$

3 -$ -$ -$ -$

4 -$ -$ -$ -$

5 Total 747,024$ -$ 747,024$ -$ -$ -$ -$ -$ 747,024$ 747,024$

Line 2016 - Account Name

2016

Opening


Adjusted

Opening Bal.

Additions/

(Deductions)

Adjustmen

ts Less Taxes Net Additions Amortization

Ending

Balance

Mid-Year

Balance


2 GCOC Deferral Account 2013/2014 333,012$ 333,012$ -$ (166,500)$ 166,512$ 249,762$

3 -$ -$ -$ -$ -$

4 -$ -$ -$ -$ -$

5 Total 747,024$ -$ 747,024$ -$ -$ -$ -$ (166,500)$ 580,524$ 663,774$

Line 2017 - Account Name

2017

Opening


Adjusted

Opening Bal.

Additions/

(Deductions)

Adjustmen

ts Less Taxes Net Additions Amortization

Ending

Balance

Mid-Year

Balance


2 GCOC Deferral Account 2013/2014 166,512$ 166,512$ -$ (166,500)$ -$ 83,256$

3 -$ -$ -$ -$ -$

4 -$ -$ -$ -$ -$

5 Total 580,524$ -$ 580,524$ -$ -$ -$ -$ (166,500)$ 414,012$ 497,268$



DEFERRED EXPENSES - NON RATE BASE Schedule 12

Line 2015 Approved - Deferred Account Name

2015

Opening

Balance

Opening

Adj.

Adjusted

Opening Bal.

Additions/

(Deductions) Adj.

Interest/

AFUDC Less Taxes

Net

Additions Amortization

Ending

Balance

1 Reg. Transitional Adjustment Deferral Account 301,177$ 301,177$ 12,047$ 12,047$ 313,224$

2 Pension Expense Deferral Account -$ -$ -$

3 -$ -$ -$ -$

4 -$ -$ -$

5 -$ -$ -$

6 -$ -$ -$

18 Total Deferred Accounts 301,177$ -$ 301,177$ -$ -$ 12,047$ -$ 12,047$ -$ 313,224$

Line 2015 Projected - Deferred Account Name

2015

Opening

Balance

Opening

Adj.

Adjusted

Opening Bal.

Additions/

(Deductions) Adj.

WACD/STD/

AFUDC Less Taxes

Net


Ending

Balance

1 Reg. Transitional Adjustment Deferral Account 301,177$ 301,177$ 12,047$ 12,047$ 313,224$

2 Pension Expense Deferral Account -$ -$ -$

3 -$ -$ -$ -$

4 -$ -$ -$

5 -$ -$ -$

6 -$ -$ -$

7 Total Deferred Accounts 301,177$ -$ 301,177$ -$ -$ 12,047$ -$ 12,047$ -$ 313,224$

Line 2016 Deferred Account Name

2016

Opening

Balance

Opening

Adj.

Adjusted

Opening Bal.

Additions/

(Deductions) Adj.

Interest/

AFUDC Less Taxes

Net


Ending

Balance

1 Reg. Transitional Adjustment Deferral Account 313,224$ 313,224$ -$ -$ (110,500)$ 202,724$

2 Pension Expense Deferral Account -$ -$ -$ -$

3 Special Services Deferral Account -$ -$ -$ -$ -$ -$

4 NEFC RDDA -$ -$ -$ -$

5 -$ -$ -$ -$

6 -$ -$ -$ -$

7 Total Deferred Accounts 313,224$ -$ 313,224$ -$ -$ -$ -$ -$ (110,500)$ 202,724$

Line 2017 Deferred Account Name

2017

Opening

Balance

Opening

Adj.

Adjusted

Opening Bal.

Additions/

(Deductions) Adj.

Interest/

AFUDC Less Taxes

Net


Ending

Balance

1 Reg. Transitional Adjustment Deferral Account 202,724$ 202,724$ 7,943$ 7,943$ (110,500)$ 100,167$

2 Pension Expense Deferral Account -$ -$ -$ -$

3 Special Services Deferral Account -$ -$ -$ -$ -$ -$

4 NEFC RDDA -$ -$ -$ -$

5 -$ -$ -$ -$

6 -$ -$ -$ -$

7 Total Deferred Accounts 202,724$ -$ 202,724$ -$ -$ 7,943$ -$ 7,943$ (110,500)$ 100,167$



CAPITAL STRUCTURE AND COST OF CAPITAL Schedule 13

2011 2012 2013 2014 2015 2015 2016 2017


1 MID-YEAR RATE BASE 24,200,871 24,312,663 24,456,546 24,925,550 25,861,873 25,909,320 28,250,011 31,610,178

2

3 CAPITAL STRUCTURE %

4 Equity 37.79% 35.89% 35.20% 34.72% 42.50% 42.50% 42.50% 42.50%

5 Long tem Debt 44.22% 43.36% 42.37% 40.84% 19.33% 19.30% 23.89% 30.05%

6 Short Term Debt 17.99% 20.75% 22.43% 24.44% 38.17% 38.20% 33.61% 27.45%

7 Total 100% 100% 100% 100% 100% 100% 100% 100%

8

9 CAPITAL STRUCTURE $

10 Equity 9,145,509 8,725,815 8,608,704 8,654,151 10,991,296 11,011,461 12,006,255 13,434,326

11 Long tem Debt 10,702,403 10,542,256 10,361,578 10,178,514 5,000,000 5,000,000 6,750,000 9,500,000

12 Short Term Debt 4,352,959 5,044,592 5,486,264 6,092,885 9,870,577 9,897,859 9,493,757 8,675,853

13 Total 24,200,871 24,312,663 24,456,546 24,925,550 25,861,873 25,909,320 28,250,011 31,610,178

14

15 COST OF CAPITAL % (Actual & Proposed)

16 Equity 13.70% 7.66% 5.58% 5.74% 9.50% 4.71% 9.50% 9.50%

17 Long tem Debt 4.07% 4.07% 4.11% 4.30% 4.52% 4.52% 4.30% 4.30%

18 Short Term Debt 3.50% 3.50% 3.30% 3.50% 3.74% 3.74% 3.50% 3.50%

19

20 COST OF CAPITAL $

21 Equity 1,253,039 668,209 480,714 496,570 1,044,173 519,159 1,141,000 1,276,000

22 Long tem Debt 435,588 429,070 425,861 437,676 226,000 226,000 290,000 409,000

23 Short Term Debt 152,354 176,561 181,047 213,251 368,818 369,838 332,000 304,000

24 Return on Rate Base 1,840,980 1,273,840 1,087,622 1,147,497 1,638,991 1,114,997 1,763,000 1,989,000

25

26

27 RATE BASE RETURN 7.61% 5.24% 4.45% 4.60% 6.34% 4.30% 6.24% 6.29%



FUEL COST - BASE CHARGE Schedule 14

2011 2012 2013 2014 2015 2015 2016 2017


1 Energy Consumed (MM BTU) 1,895,090 1,822,205 1,741,380 1,657,509 1,728,902 1,258,916 1,704,037 1,745,156

2 Base Charge per MM BTU 0.41$ 0.41$ 0.41$ 0.41$ 0.41$ 0.41$ 0.41$ 0.41$

3 Base Charge Recovered Through Tariff 776,987$ 747,104$ 713,966$ 679,578$ 708,850$ 516,156$ 698,700$ 716,000$



OPERATING & MAINTENANCE EXPENSES Schedule 15

2011 2012 2013 2014 2015 2015 2016 2017

Line # Acct. # Account Name Actual Actual Actual Actual Approved Unaudited Forecast Forecast Reference

1 Steam Production-Operation

2 500 Supervision and Labour 970,553 999,882 1,049,849 1,062,133 1,030,443 1,053,872 1,144,000 1,178,000

3 502 Steam Expenses 803,754 910,797 884,415 924,623 945,725 900,222 904,200 973,300

4 Total Steam Production-Operation 1,774,307 1,910,679 1,934,264 1,986,756 1,976,168 1,954,094 2,048,200 2,151,300

5

6 Steam Production-Maintenance

7 506 Structures and Improvements 10,644 8,262 4,552 12,473 6,300 3,576 9,200 9,400

8 512 Steam Prodution Equipment 0 0 0

9 Total Steam Production-Maintenance 10,644 8,262 4,552 12,473 6,300 3,576 9,200 9,400

10

11 Distribution Expenses-Operation

12 870 Supervision & Labour 252,184 369,484 354,299 366,071 526,622 475,908 455,000 467,500

13 874 Mains & Services 14,561 11,951 8,923 14,237 11,616 23,134 15,700 19,100

14 878 Removing & Resetting Meters 0 0 0

15 880 Other Distribution Operation 1,000 2,500 0 5,000 15,300

16 933 Transportation 15,294 17,605 17,779 10,032 15,600 14,102 24,000 24,500

17 Total Distribution Expenses-Operation 282,039 399,040 381,001 391,340 556,338 513,145 499,700 526,400

18

19 Distribution Expenses - Maintenance

20 885 Supervision & Labour 0 0 0

21 886 Structures & Improvements 0 0 0

22 887 Mains & Services 43,763 33,540 29,273 29,616 40,800 57,968 66,000 67,000

23 889 Meters & House Regulators 106,115 128,048 90,614 142,874 112,712 109,541 112,100 114,300

24 894 Other Distribution Maintenance 413 460 0 0 450 0 0 0

25 Total Distribution Expenses-Maintenance 150,291 162,048 119,887 172,490 153,962 167,509 178,100 181,300

26

27 Customer Accounts Expenses-Operation

28 901 Supervision 0 0 0

29 902 Meter Reading & Billing Delivery 0 0 0

30 903 Customer Records & Collection Exp 0 0 0

31 904 Uncollectible Acounts 0 0 0

32 Total Customer Accounts Exp-Operation 0 0 0 0 0 0 0 0

33

34 Sales Promotion Expenses-Operation

35 910 Sales Expense 25,217 14,970 34,650 38,064 56,460 58,315 67,300 70,200

36 911 Advertising 0 0 0 0 0

37 Total Sales Promotion Exp - Operation 25,217 14,970 34,650 38,064 56,460 58,315 67,300 70,200

38

39 Administrative & General - Operation

40 915 Directors Fees 22,500 26,000 30,000 30,830 42,000 60,815 48,200 49,400

41 920 Admin & General Salaries 475,326 573,924 562,683 772,641 729,719 455,906 584,600 617,900

42 921 Office Supples & Exp 161,034 88,533 63,456 95,473 78,786 107,966 97,500 105,200

43 922 Admin & General Exp 12,071 9,180 18,874 10,800 11,000

44 923 Special Services 67,581 90,487 121,161 214,159 108,000 246,121 418,200 307,300

45 924 Insurance 84,815 83,789 83,363 86,854 106,600 105,466 114,100 123,900

46 925 Injuries & Damages-WCB 8,443 8,672 8,893 10,287 12,074 12,041 14,800 14,800

47 926 Employee Benefits 236,663 344,972 433,210 190,532 450,187 508,035 461,800 465,100

48 930.1 Institutional or Goodwill Advert Exp 0 0 0

49 930.2 Other Admin. And General Exp 0 0 0

50 Total Admin & General-Operation 1,056,362 1,216,377 1,302,766 1,412,848 1,536,546 1,515,224 1,750,000 1,694,600

51

52 Administrative & General - Maintenance

53 932 Maintenance of General Plant 26,233 14,622 23,597 14,957 26,640 25,287 30,200 49,200

54 Total Admin & General-Operation 26,233 14,622 23,597 14,957 26,640 25,287 30,200 49,200

55

56 Regulatory Gross O&M Expense 3,325,093 3,725,998 3,800,717 4,028,927 4,312,414 4,237,149 4,582,700 4,682,400

57

58 O&M Expenses Allocated to Capital % 0.00% 0.00% 0.00% 0.00% 0.36% 0.43% 0.43% 0.43%

59 O&M Expenses Allocated to Capital $ 0 0 0 0 (15,459) (18,000) (19,700) (20,100)

60

61 O&M Allocated to Affiliate (22,000) (19,500)

62

63 Regulatory Net O&M Expense 3,325,093 3,725,998 3,800,717 4,028,927 4,296,955 4,219,149 4,541,000 4,642,800

64

65 O&M Capitalized 18,000 17,000 16,500 16,000 15,459 18,000 19,700 20,100



PROPERTY TAXES Schedule 16

2011 2012 2013 2014 2015 2015 2016 2017

Line # Item Actual Actual Actual Actual Approved Unaudited Forecast Forecast

1 PROPERTY TAX

2 City of Vancouver Mill Rate

3 Utility 0 55.97006 53.81857 52.26809 50.5101

4 Business and Other Utility 18.11148 17.5182 16.48542 15.91182 15.04535

5

6 Assessed Value - Taxable

7 Utility - Land 15,669,000 3,017,000 3,017,000 3,486,000 3,936,000

8 Utility - Building 32,600 10,000 10,000 10,000 10,000

9 Business and Other Utility- Land - 10,696,000 10,697,000 11,512,000 13,141,500

10 Business and Other Utility - Building - 69,000 69,000 69,000 69,000

11

12 Taxes

13 Utility - Land 283,789 168,862 162,371 181,684 190,768 198,808 220,700 231,700

14 Utility - Building 590 560 538 523 549 505 600 600

15 Business and Other Utility- Land - 187,375 176,345 183,177 192,336 197,718 219,500 230,500

16 Business and Other Utility - Building - 1,209 1,137 1,098 1,153 1,038 1,200 1,300

17 Fees 535 551 565 578 607 589 700 700

18 Total for 720 Beatty Street 284,914 358,556 340,956 367,059 385,412 398,658 442,700 464,800

19

20 Reduction for Non Reg (101,140) (85,865) (80,800) (85,258) (89,504) (92,000) (102,000) (107,000)

21

22 Add Property Tax for 701 Expo Blvd. 25,171 20,546 19,352 20,997 22,467

23

24 PROPERTY TAXES FOR UTILITY PURPOSES 208,945 293,237 279,508 302,798 318,375 306,658 340,700 357,800

25

26

27 Leasable Area - Land

28 Building Leasable Area Sq. Ft. 5,900 5,900 5,900 5,900 5,900 5,900 5,900 5,900

29 Total Land Area Sq. Ft. 51,744 51,744 51,744 51,744 51,744 51,744 51,744 51,744

30 Allocation % 11.40% 11.40% 11.40% 11.40% 11.40% 11.40% 11.40% 11.40%

31 Land Tax 283,789 240,227 226,081 238,645 250,577 256,937 285,200 299,460

32 Allocated to Non-Reg 32,356$ 27,389$ 25,776$ 27,206$ 28,569$ 29,297$ 32,517$ 34,142$

33

34 Portion of Land Tax related to BC Place Lease

35 Leasable Area Sq. Ft. 12,512 12,513 12,514 12,515 12,516 12,517 12,518 12,519

36 Total Land Area Sq. Ft. 51,744 51,744 51,744 51,744 51,744 51,744 51,744 51,744

37 Allocation % 24.18% 24.18% 24.18% 24.19% 24.19% 24.19% 24.19% 24.19%

38 Land Tax 283,789 240,227 226,081 238,645 250,577 256,937 285,200 299,460

39 Allocated to Non-Reg 68,621$ 58,092$ 54,676$ 57,704$ 60,610$ 62,153$ 68,996$ 72,451$

40

41 Leased Area of Building

42 Leased Area Sq. Ft. 5,900 5,900 5,900 5,900 5,900 5,900 5,900 5,900

43 Leased Area Sq. Ft. 5,400 5,400 5,400 5,400 5,400 5,400 5,400 5,400

44 Total Leased Area Sq. Ft. 11,300 11,300 11,300 11,300 11,300 11,300 11,300 11,300

45 Total Area of Building 40,803 40,803 40,803 40,803 40,803 40,803 40,803 40,803

46 Allocation % 27.69% 27.69% 27.69% 27.69% 27.69% 27.69% 27.69% 27.69%

47 Building Tax 590 1,384 1,302 1,257 1,257 1,189 1,189 1,248

48 Allocated to Non-Reg 164$ 383$ 361$ 348$ 348$ 329$ 329$ 346$

49

50 DEDUCTION FROM PROP TAX 101,140$ 85,865$ 80,800$ 85,258$ 89,504$ 92,000$ 102,000$ 107,000$



MUNICIPAL TAXES Schedule 17

2011 2012 2013 2014 2015 2015 2016 2017

Line # Item Actual Actual Actual Actual Approved Unaudited Forecast Forecast

1 Annual Steam Revenues 7,397,807 7,106,093 6,931,468 7,241,719 8,299,898 7,352,630 9,041,100 9,635,500

2 Tax Rate 1.25% 1.25% 1.25% 1.25% 1.25% 1.25% 1.25% 1.25%

3 Municipal Tax on Steam Revenue 92,473 88,826 86,643 90,521 103,749 91,908 113,000 120,400

4

5 Prior Year Flat Fee 116,400 116,400 116,400 129,372 122,567 129,372 142,309 151,200

6 Rate Increase 10% 6.23% 6.23%

7 Escalated Flat Fee 116,400 116,400 116,400 129,372 122,567 142,309 151,200 160,600

8

9 Total Municipal Tax 208,873 205,226 203,043 219,893 226,316 234,217 264,200 281,000



LONG TERM DEBT CONTINUITY SCHEDULE Schedule 18

2011 2012 2013 2014 2015 2015 2016 2017


1 Debt

2 Opening Balance 10,773,405 10,631,401 10,453,110 10,270,046 5,000,000 5,000,000 5,000,000 8,500,000

3 New Issues 3,500,000 2,000,000

4 Repayments (142,004) (178,291) (183,064) (183,064)

5 Closing Balance 10,631,401 10,453,110 10,270,046 10,086,982 5,000,000 5,000,000 8,500,000 10,500,000

6 Mid-Year Balance* 10,702,403 10,542,256 10,361,578 10,178,514 5,000,000 5,000,000 6,750,000 9,500,000

7 Annual Effective Interest Rate 4.07% 4.07% 4.11% 4.30% 4.52% 4.52% 4.30% 4.30%

8 Interest Expense 435,588 429,070 425,861 437,676 226,000 226,000 290,250 408,500

9

10 TOTAL MID-YEAR DEBT BALANCE 10,702,403 10,542,256 10,361,578 10,178,514 5,000,000 5,000,000 6,750,000 9,500,000

11 TOTAL INTEREST EXPENSE 435,588 429,070 425,861 437,676 226,000 226,000 290,250 408,500

12 ANNUAL EFFECTIVE INTEREST RATE 4.07% 4.07% 4.11% 4.30% 4.52% 4.52% 4.30% 4.30%

13

14 NOTES

15 *Adjusted for timing of New Issues & Repayments



INCOME TAXES Schedule 19

2011 2012 2013 2014 2015 2015 2016 2017


1 Allowed/Proposed Return on Rate Base (After Tax) 1,840,980 1,273,840 1,087,622 1,147,497 1,638,991 1,114,997 1,763,000 1,989,000 Schedule 13

2 Add: Equity Portion of AFUDC

3 Less: Financing Costs (587,941) (605,631) (606,908) (650,927) (594,818) (595,838) (622,000) (713,000) Schedule 13

4 Accounting Income After Tax 1,253,039 668,209 480,714 496,570 1,044,173 519,159 1,141,000 1,276,000

5

6 Add:

7 Depreciation Expense 837,467 851,096 856,837 871,008 921,422 892,408 921,100 1,110,900 Schedule 4

8 Amortization of Deferrals Schedule 11

9 Non Deductable/Portion of Dues & Entertainment 30,744 17,533 30,744 4,043

10 Charitable Donations 500 400 500 500 500

11 Total Additions 868,211 869,129 887,981 875,051 921,422 892,908 921,600 1,111,400

12

13 Deduct

14 Capital Cost Allowance (1,200,622) (1,190,218) (1,185,708) (1,191,888) (1,183,200) (1,183,618) (1,358,325) (1,610,055) #N/A

15 Cummulative Eligible Capital (326) (316) (294) (295) 0 (274) (255) (237)

16 Capitalized OH Deduction (Tax vs. Accounting) 0 0 0 0 (15,459) (18,000) (19,700) (20,100) Schedule 15

17 Capitalized Interest 8,667 37,626 5,378

18 Deferral Additions

19 Pension Contribution (306,400) (255,600) (190,310) (254,300)

20 Impairment of Property & Equipment Loss (and other) (48,917)

21 Total Deductions (1,547,597) (1,408,508) (1,370,934) (1,446,483) (1,198,659) (1,201,892) (1,378,280) (1,630,392)

22

23 Taxable Income/(Loss) for Tax Purposes (After Tax) 573,653 128,830 (2,239) (74,862) 766,936 210,175 684,320 757,008

24 Tax Gross Up 73.50% 75.00% 75.00% 75.00% 75.00% 74.00% 74.00% 74.00%

25 Taxable Income/(Loss) for Tax Purposes (Before Tax) 780,481 171,773 (2,986) (99,815) 1,022,581 284,021 924,757 1,022,983

26

27 Effective Income Tax Rate 26.50% 25.00% 25.00% 25.00% 25.00% 26.00% 26.00% 26.00%

28 Current Income Tax Expense 206,827 42,943 0 0 255,645 73,845 240,400 266,000



CAPITAL COST ALLOWANCE & CUMMULATIVE ELIGIBLE CAPITAL #N/A

2010 2011 2012 2013 2014 2015 2015 2016 2017

Line # Actual Actual Actual Actual Actual Approved Unaudited Forecast Forecast

1 CCA 1,218,346 1,200,622 1,190,218 1,185,708 1,191,888 1,183,200 1,183,618 1,358,325 1,610,055

2 CEC 351 326 316 294 295 274 255 237

3 -7% -3% -7% 0%

4

5

6 Class No.

UCC Beg of

Period UCC Additions UCC

1/2 of

Additions Reduced UCC Rate %

Capital Cost

Allowance

UCC

End of Year

7

8 1 7,018,437 163,572 7,182,009 81,786 7,100,223 4.00% 284,009 6,898,000

9 2 1,211,383 - 1,211,383 - 1,211,383 6.00% 72,683 1,138,700

10 8 41,548 3,825 45,373 1,913 43,461 20.00% 8,692 36,681

11 10 48,504 - 48,504 - 48,504 30.00% 14,551 33,953

12 17 10,053,274 667,850 10,721,124 333,925 10,387,199 8.00% 830,976 9,890,148

13 50 2,335 - 2,335 - 2,335 55.00% 1,284 1,051

14 52 6,151 - 6,151 - 6,151 100.00% 6,151 -

15

16 Total CCA for the Period 1,218,346

17

18

19

20 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

21

22 1 6,898,000 6,898,000 - 6,898,000 4.00% 275,920 6,622,080

23 2 1,138,700 1,138,700 - 1,138,700 6.00% 68,322 1,070,378

24 8 36,681 10,308 46,989 5,154 41,835 20.00% 8,367 38,622

25 10 33,953 33,953 - 33,953 30.00% 10,186 23,767

26 17 9,890,148 1,150,923 11,041,071 575,462 10,465,610 8.00% 837,249 10,203,822

27 50 1,051 - 1,051 - 1,051 55.00% 578 473

28 52 - - - - - 100.00% - -

29


31

32

33

34 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

35

36 1 6,622,080 59,468 6,681,548 29,734 6,651,814 4.00% 266,073 6,415,476

37 2 1,070,378 1,070,378 - 1,070,378 6.00% 64,223 1,006,155

38 8 38,622 1,768 40,390 884 39,506 20.00% 7,901 32,489

39 10 23,767 23,767 - 23,767 30.00% 7,130 16,637

40 17 10,203,822 708,140 10,911,962 354,070 10,557,892 8.00% 844,631 10,067,331

41 50 473 473 - 473 55.00% 260 213

42 52 - - - - - 100.00% - -

43


45

46

47

48 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

49

50 1 6,415,476 15,514 6,430,990 7,757 6,423,233 4.00% 256,929 6,174,060

51 2 1,006,155 1,006,155 - 1,006,155 6.00% 60,369 945,786

52 8 32,489 5,129 37,618 2,565 35,053 20.00% 7,011 30,607

53 10 16,637 16,637 - 16,637 30.00% 4,991 11,646

54 17 10,067,331 1,272,595 11,339,926 636,298 10,703,628 8.00% 856,290 10,483,636

55 50 213 213 - 213 55.00% 117 96

56 52 - - - - - 100.00% - -

57


59

60

2010

2011

2012

2013



CAPITAL COST ALLOWANCE & CUMMULATIVE ELIGIBLE CAPITAL #N/A

61

62 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

63

64 1 6,174,060 11,390 6,185,450 5,695 6,179,755 4.00% 247,190 5,938,260

65 2 945,786 945,786 - 945,786 6.00% 56,747 889,039

66 8 30,607 205,791 236,398 102,896 133,503 20.00% 26,701 209,698

67 10 11,646 11,646 - 11,646 30.00% 3,494 8,152

68 17 10,483,636 475,312 10,958,948 237,656 10,721,292 8.00% 857,703 10,101,244

69 50 96 96 - 96 55.00% 53 43

70 52 - - - - 100.00% - -

71


73

74

75

76 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

77

78 1 5,938,260 11,390 5,949,650 5,695 5,943,955 4.00% 237,758 5,711,892

79 2 889,039 889,039 - 889,039 6.00% 53,342 835,697

80 8 209,698 205,791 415,489 102,896 312,593 20.00% 62,519 352,970

81 10 8,152 8,152 - 8,152 30.00% 2,446 5,706

82 17 10,101,244 475,312 10,576,556 237,656 10,338,900 8.00% 827,112 9,749,444

83 50 43 43 - 43 55.00% 24 19

84 52 - - - - 100.00% - -

85


87

88

89

90 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

91

92 1 5,711,892 4,077 5,715,968 2,038 5,713,930 4.00% 228,557 5,487,411

93 2 835,697 - 835,697 - 835,697 6.00% 50,142 785,555

94 8 352,970 3,640 356,610 1,820 354,790 20.00% 70,958 285,652

95 10 5,706 130,065 135,771 65,032 70,739 30.00% 21,222 114,549

96 17 9,749,444 819,319 10,568,763 409,660 10,159,104 8.00% 812,728 9,756,035

97 50 19 - 19 - 19 55.00% 11 9

98 52 - - - - - 100.00% - -

99

100 Total CCA for the Period 957,100 17,612,829 478,550 17,134,279 2 1,183,618 16,429,211

101

102

103

104 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

105

106 1 5,487,411 - 5,487,411 - 5,487,411 4.00% 219,496 5,267,915

107 2 785,555 - 785,555 - 785,555 6.00% 47,133 738,421

108 8 285,652 - 285,652 - 285,652 20.00% 57,130 228,522

109 10 114,549 - 114,549 - 114,549 30.00% 34,365 80,185

110 17 9,756,035 5,492,809 15,248,844 2,746,405 12,502,440 8.00% 1,000,195 14,248,649

111 50 9 - 9 - 9 55.00% 5 4

112 52 - - - - - 100.00% - -

113


115

116

117

118 Class No.

UCC Beg of


1/2 of


Capital Cost

Allowance

UCC

End of Year

119

120 1 5,267,915 - 5,267,915 - 5,267,915 4.00% 210,717 5,057,198

121 2 738,421 - 738,421 - 738,421 6.00% 44,305 694,116

122 8 228,522 - 228,522 - 228,522 20.00% 45,704 182,817

123 10 80,185 - 80,185 - 80,185 30.00% 24,055 56,129

124 17 14,248,649 3,634,481 17,883,131 1,817,241 16,065,890 8.00% 1,285,271 16,597,859

125 50 4 - 4 - 4 55.00% 2 2

126 52 - - - - - 100.00% - -

127


2015 Approved

2015 Projected

2016 Forecast

2017 Forecast

2014



REVENUES

2010 2011 2012 2013 2014 2015 2015 2016 2017

Line # Acct. # Account Name Actual Actual Actual Actual Actual Approved Projected Proposed Proposed Reference

1 Sales of Steam

2 440 Residential Sales

3 442 Commercial Sales 6,658,438 7,397,807 7,106,093 6,931,468 7,241,719 8,299,898 7,352,630 9,041,100 9,635,500

4 442.1 Industrial Sales

5 445 Other Sales

6 Total Sales of Steam 6,658,438 7,397,807 7,106,093 6,931,468 7,241,719 8,299,898 7,352,630 9,041,100 9,635,500

7

8 Other Operating Revenue

9 450 Other Income 38,560 9,376 33,804 9,730 7,700 12,400 4,800 5,000 5,000

10 451 Revenue from Service Work

11 456 Other Operating Revenue

12 Total Other Operating Revenue 38,560 9,376 33,804 9,730 7,700 12,400 4,800 5,000 5,000

13

14 TOTAL STEAM OPERATING REVENUES 6,696,998 7,407,183 7,139,897 6,941,198 7,249,419 8,312,298 7,357,430 9,046,100 9,640,500

Page | 106

7 APPENDIX 2 FUEL COST STABILIZATION ACCOUNT 1

2

11 February 2016 VIA E-MAIL B.C. Utilities Commission, Sixth Floor, 900 Howe Street, Box 250, Vancouver, B.C. V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: RE: Commission 2015-17 RRA Decision - Notice of Change to Fuel Cost Adjustment Charge Per the Commission 2015-17 RRA Decision of June 9, 2015, please see attached schedules for the Fuel Cost Adjustment Charge and the Fuel Cost Stabilization Account. Changes to the Fuel Cost Adjustment Charge was made for the January 1, 2016 billing (sent out in the first week of February 2016) and, as such, Creative Energy is filing with the Commission, for information purposes, the schedules for the Fuel Cost Adjustment Charge and the Fuel Cost Stabilization Account. Should you require any further information, please do not hesitate to contact Paul Tai at 604-692-2111. Yours truly, CREATIVE ENERGY VANCOUVER PLATFORMS INC.

Stacey Bernier President & CEO


1 of 2

FUEL CLAUSE ADJUSTMENT RELATED TO SCHEDULE 22

Gas New Total Total Cost Per 12 Mos. 12 Mos Ave 12 [email protected] Actual

Month Therms Cost Gallons Therms Cost MM/BTU Cost MM/BTU MM/BTU Cost Mos $ Spt 1/94 Adj.

----------- -------------------- -------------------- -------------------- ---------------- -------------------- ------------------ ---------------------- -------------- -------------------- ------------------------ ------------------ ---------------- --------------

Jan/14 2,196,754 1,841,707$ 219,675 1,841,707$ 8.38$ 1,708,518 12,953,644$ 7.58$ 11.21$ 12.50$

Feb. 2,226,964 2,659,074$ 222,696 2,659,074$ 11.94$ 1,733,217 14,302,782$ 8.25$ 12.25$ 13.75$

Mar. 1,876,609 1,696,096$ 187,661 1,696,096$ 9.04$ 1,740,768 14,694,330$ 8.44$ 12.55$ 12.75$

Apr. 1,404,579 1,157,661$ 140,458 1,157,661$ 8.24$ 1,739,528 14,809,777$ 8.51$ 12.66$ 12.25$

May. 971,426 795,150$ 97,143 795,150$ 8.19$ 1,735,019 14,860,116$ 8.56$ 12.74$ 12.25$

Jun. 797,542 653,241$ 79,754 653,241$ 8.19$ 1,734,478 14,938,856$ 8.61$ 12.82$ 12.25$

Jul. 702,294 534,630$ 70,229 579,792$ 8.26$ 1,735,480 15,043,556$ 8.67$ 12.90$ 12.25$

Aug. 672,312 498,772$ 67,231 498,772$ 7.42$ 1,734,440 15,096,336$ 8.70$ 12.96$ 12.25$

Sep. 736,231 551,343$ 73,623 551,343$ 7.49$ 1,728,076 15,117,399$ 8.75$ 13.03$ 12.25$

Oct. 1,061,705 739,142$ 106,170 739,142$ 6.96$ 1,694,512 14,855,815$ 8.77$ 13.06$ 12.25$

Nov. 1,819,858 1,431,043$ 181,986 1,431,043$ 7.86$ 1,697,227 14,961,672$ 8.82$ 13.13$ 12.25$

Dec. 2,106,579 1,540,865$ 1,378 2,301 $4,633 210,888 1,545,498$ 7.33$ 1,657,514 14,148,519$ 8.54$ 12.70$ 12.25$

Jan/15 2,059,548 1,427,511$ 205,954 1,427,511$ 6.93$ 1,643,793 13,734,323$ 8.36$ 12.41$ 10.75$

Feb. 1,619,510 1,089,391$ 161,951 1,089,391$ 6.73$ 1,583,048 12,164,640$ 7.68$ 11.37$ 10.50$

Mar. 1,629,571 1,104,376$ 162,957 1,104,376$ 6.78$ 1,558,344 11,572,920$ 7.43$ 10.96$ 10.25$

Apr. 1,389,550 802,184$ 138,955 802,184$ 5.77$ 1,556,841 11,217,443$ 7.21$ 10.62$ 9.50$

May. 901,116 548,289$ 90,112 548,289$ 6.08$ 1,549,810 10,970,582$ 7.08$ 10.42$ 9.50$

Jun. 691,399 411,122$ 69,140 411,122$ 5.95$ 1,539,196 10,728,463$ 6.97$ 10.25$ 9.50$

Jul. 633,795 385,273$ 63,380 385,273$ 6.08$ 1,532,346 10,533,944$ 6.87$ 10.10$ 9.50$

Aug. 633,008 403,704$ 63,301 403,704$ 6.38$ 1,528,416 10,438,876$ 6.83$ 10.03$ 9.50$

Sep. 864,107 554,778$ 86,411 554,778$ 6.42$ 1,541,204 10,442,310$ 6.78$ 9.95$ 9.50$

Oct. 1,082,310 646,791$ 108,231 646,791$ 5.98$ 1,543,265 10,349,960$ 6.71$ 9.84$ 9.50$

Nov. 1,899,082 1,150,497$ 189,908 1,150,497$ 6.06$ 1,551,187 10,069,413$ 6.49$ 9.50$ 9.50$

Dec. 2,154,085 1,338,452$ 215,408 1,338,452$ 6.21$ 1,555,707 9,862,367$ 6.34$ 9.26$ 9.50$

Jan/16 2,125,600 1,365,168$ 212,560 1,365,168$ 6.42$ 1,562,313 9,800,024$ 6.27$ 9.16$ $8.75


2 of 2

Fuel Clause Recovery Effective December 1, 1973

Steam Fuel Cons. .41c Loss Recovered Monthly Recovery

Year Sold M# MM/BTU Cost Cost Gain Credit Balance Balance

---------------- ------------------ ------------------ ------------------ ---------------- ------------------ ------------------ ---------------- --------------------

2014

----------------

Jan. 151,568 219,675 1,841,707 90,067 1,751,640 1,894,595 (142,955) (816,347)

Feb. 157,378 222,696 2,659,074 91,305 2,567,769 2,163,953 403,816 (412,531)

Mar. 128,489 187,661 1,696,096 76,941 1,619,155 1,638,235 (19,080) (431,611)

Apr. 91,300 140,458 1,157,661 57,588 1,100,073 1,118,425 (18,352) (449,963)

May. 56,435 97,143 795,150 39,829 755,321 691,329 63,992 (385,971)

Jun. 51,536 79,754 653,241 32,699 620,542 631,315 (10,773) (396,744)

Jul. 36,056 70,229 534,630 28,794 505,836 441,690 64,146 (332,598)

Aug. 32,530 67,231 498,772 27,565 471,207 398,496 72,711 (259,886)

Sep. 44,252 73,623 551,343 30,185 521,158 542,082 (20,924) (280,811)

Oct. 60,254 106,170 739,142 43,530 695,612 738,111 (42,499) (323,309)

Nov. 131,304 181,986 1,431,043 74,614 1,356,429 1,608,476 (252,047) (575,357)

Dec. 116,980 210,888 1,545,498 86,464 1,459,034 1,433,004 26,030 (549,327)

------------------ ------------------ ------------------ ---------------- ------------------ ------------------ ---------------- --------------------

Totals 1,058,082 1,657,514 14,103,357 679,581 13,423,776 13,299,711 124,065

========== ========== ========== ========= ========== ========== ========= ===========

2015

----------------

Jan. 140,808 205,955 1,427,511 84,442 1,343,069 1,513,686 (170,617) (719,943)

Feb. 97,096 161,951 1,089,391 66,400 1,022,991 1,019,513 3,478 (716,465)

Mar. 105,743 162,957 1,104,376 66,812 1,037,564 1,083,868 (46,304) (762,770)

Apr. 88,825 138,955 802,184 56,972 745,212 843,839 (98,627) (861,397)

May. 57,976 90,112 548,289 36,946 511,343 550,737 (39,394) (900,791)

Jun. 35,547 69,140 411,122 28,347 382,775 337,691 45,084 (855,707)

Jul. 33,855 63,380 385,273 25,986 359,287 321,628 37,659 (818,047)

Aug. 37,327 63,301 403,704 25,953 377,750 354,604 23,146 (794,901)

Sep. 52,054 86,411 554,778 35,428 519,349 494,517 24,832 (770,068)

Oct. 63,235 108,231 646,791 44,375 602,417 600,730 1,687 (768,382)

Nov. 129,098 189,908 1,150,497 77,862 1,072,634 1,226,438 (153,804) (922,186)

Dec. 131,583 215,408 1,338,452 88,317 1,250,134 1,250,037 98 (922,088)

------------------ ------------------ ------------------ ---------------- ------------------ ------------------ ---------------- --------------------

Totals 973,147 1,555,708 9,862,367 637,840 9,224,527 9,597,288 (372,761)

========== ========== ========== ========= ========== ========== ========= ===========

2016

----------------

Jan. 141,815 212,560 1,365,168 87,150 1,278,019 1,240,885 37,134 (884,954)

Page | 110

1

Page | 111

8 APPENDIX 3 NEFC MODEL 1

Please see Working Model filed separately 2

Page | 112

9 APPENDIX 4 COMMISSION DIRECTIVES 1

2

APPENDIX 4 – COMMISSIONS DIRECTIVE

Commission Directive Status of Compliance

The Panel determines that Creative Energy must file a long-term resource plan pertaining to the existing steam utility no later than two years from the date of this Decision and prior to making an investment decision regarding any low carbon fuel switch that may impact the existing steam customers. The LTRP shall include information available from the fuel switch feasibility study. (2015-17 RRA Decision, p. 15) … the Panel also finds that the LTRP filing previously directed for the utility includes NEFC. (NEFC Decision, p. 71)

The fuel switch feasibility study is complete and stakeholders are now being consulted. Creative Energy expects to begin consultations relevant to the LTRP in the fourth quarter of 2016. The LTRP will include NEFC.

The Commission directs Creative Energy, in its next revenue requirements application, to propose a permanent treatment of this Fuel Cost Stabilization Account. As a minimum, the proposal must address: 1) whether this account should be established as a non-rate base or a rate base deferral account, or by way of another method; and 2) the appropriate means to compensate customers for the interest to be accrued on the balance or excess of billings to customers in respect to fuel costs over actual costs incurred. (2015-17 RRA Decision, p. 19)

In this Application, Creative Energy is seeking approval that the Fuel Cost Stabilization Account (FCSA) be established as a non-rate base deferral account with carrying costs at the weighted average cost of debt calculated on monthly deferral account balances.

… the Panel directs Creative Energy to apply its weighted average cost of debt to the most current balance of this Fuel Cost Stabilization Account… The resulting interest cost (customer credit) shall be treated as a revenue-offset to the 2015 revenue requirements. (2015-17 RRA Decision, p. 19)

Compliance complete.

The Panel directs Creative Energy to file a Phase I rate design application within one year from the date of this Decision specifically in regard to the recovery of fuel costs. (2015-17 RRA Decision, p. 25)

Creative Energy expects to file the Phase I rate design application as requested by the Commission.

The Panel directs Creative Energy to include an annual reconciliation of the Fuel Cost Stabilization Account with its Annual Report to the Commission and also with it Annual Gas Contracting Plan required according to the Commission’s Rules for Natural Gas Supply Contracts. (2015-17 RRA Decision, p. 26)


The Panel also directs Creative Energy to file with the Commission, for information purposes, a

Since the Decision, Creative Energy has changed the Fuel Cost Adjustment Charge once with an


copy of the notice of a change to the Fuel Cost Adjustment Charge and the details showing the amount of the change, the new Fuel Cost Adjustment Charge, effective date, and updated versions of the schedules that are Table 6.1.7.C and Table 6.1.7.D in Tab 6 of the Application within 10 business days of the effective date of each change. (2015-17 RRA Decision, p. 26)

effective date of January 1, 2016, and a copy of the notice of change was filed on February 11, 2016.

As part of its compliance filing for this Decision, Creative Energy must file an amended version of the Fuel Cost Adjustment clause in the tariff to reflect the reporting changes directed above. Creative Energy is to include in the compliance filing schedules in the format of Table 6.1.7.C and Table 6.1.7.D for the 12 month period up to the date of this Decision, showing the closing balance of the Fuel Cost Stabilization Account as of the date of this Decision, the current Fuel Cost Adjustment charge as at the date of the compliance filing and a history of the charges to the Fuel Cost Adjustment charge in 2015 to the date of the compliance filing. (2015-17 RRA Decision, p. 27)

Compliance complete

… Creative Energy must clarify in the confidential component of its compliance filing the amount by which the O&M is reduced due to this disallowance [25% instead of 50% of VP BD salary] and how the transfers will be tracked. (2015-17 RRA Decision, p. 34)


Creative Energy is also directed to file a cost allocation methodology with the Commission within 24 months of this Decision, to address resource sharing, cost allocation policies and the Panel’s concerns on cross subsidization expressed in this Decision. (2015-17 RRA Decision)

Creative Energy believes the cost allocation methodology proposed in the NEFC Application and in this Application satisfy this directive.

For these reasons, , the Panel directs Creative Energy to file a capitalized overhead study in its next RRA outlining the utility’s policies on allocating costs from O&M to capital. (2015-17 RRA Decision, p. 35)

Creative Energy obtained an estimate for a capitalized overhead study and does not propose to file a capitalized overhead study, unless directed to by the Commission following this proceeding.

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. (2015-`17 RRA Decision, p. 40)

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.


… the Panel directs that when determining the mid-year After-tax Regulatory Pension Asset in future test periods the opening balance will equal the previous year’s December 31 Pension Asset (after-tax) reported on the audited financial statements. The test periods ending balance will be calculated in accordance with Table 8.9 of this Decision. (2015-17 RRA Decision, p. 55)

In this Application, Creative Energy has calculated the ending balance in accordance as directed by the Commission.

Creative Energy is directed to make this correction [GCOC impact calculation] in its subsequent compliance filing. The allowance rate base financing shall be calculated on the mid-year unamortized balance. (2015-17 RRA Decision, p. 56)


Future RRAs, the Panel directs that Creative Energy must take into account the following minimum requirements… (2015-16 RRA Decision, p. 57)

Creative Energy has reviewed the minimum requirements identified by the Commission and believes that the Application is substantially in accordance with the minimum requirements and more.

The Panel approves in principle the capitalization of project development costs incurred by Creative Energy for direct recovery from NEFC ratepayers. The Panel makes no determination at this time on the appropriate recovery period or on the amount of project development costs to be recovered from NEFC ratepayers as these costs are not yet known with a sufficient degree of certainty. Creative Energy must file for final approval of project development costs as part of a future rate application. (NEFC Decision, p. 35)

In this Application, Creative Energy is not seeking final approval of project development costs because such costs continue to be incurred. However, project development costs that have been incurred are included in the direct assignment costs in this Application.

The Panel approves the establishment of the RDDA and approves the accrual of carrying charges on the RDDA based on Creative Energy’s after-tax weighted average cost of capital. (NEFC Decision, p. 60)

The RDDA forecast balances together with the after-tax weighted average cost of capital are provided in the NEFC model filed with the Application. And in this Application, Creative Energy seeks approval of amounts to be recorded in the RDDA.

In the upcoming RDA and RRA application, Creative Energy is directed to:

1) include a discussion on whether the rates for both the core and NEFC should be considered as a separate class of service under section 60(1)(c) of the UCA.

2) Provide a clearer labeling of the proposed cost allocations.

3) Provide more clarity on the cost causation of the parameters of the Massachusetts formula, including a

In this Application, Creative Energy proposes a separate class of service for steam service and for hot water service, has provided a clearer labeling of proposed cost allocations, and more clarity on cost causation of the parameters of the Massachusetts formula.


confirmation of whether the proposed methodology has been reviewed by the auditors. (NEFC Decision, p. 65)

Page | 117

10 APPENDIX 5 DRAFT ORDER – INTERIM RATES 1

2

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

Creative Energy Vancouver Platforms Inc.

2016-2017 Revenue Requirements Application

BEFORE:

O R D E R

WHEREAS:

A. On April 1, 2016, Creative Energy Platforms Inc. (Creative Energy) filed its 2016-2017 Revenue

Requirements Application (Application) with the British Columbia Utilities Commission (Commission) seeking among other things, approval to increase existing Steam Rates (net of the fuel cost adjustment charge, which is not expected to change) by 6.23% in 2016 and 6.23% in 2017 and approval of new hot water rates for Northeast False Creek, consistent with the Commission

Decision granting a CPCN for NEFC issued December 8, 2015; B. The Commission established a written process for review of the Application in Order xx-xxx-xx; C. The Commission has considered the Application and determined that approval is warranted.

NOW THEREFORE the Commission orders as follows:

1. Pursuant to sections 59 to 60 of the Utilities Commission Act (the UCA), the Commission grants

interim approval of the following: a) An increase to Steam Rates of 6.23 percent effective May 1, 2016; and b) NEFC Hot Water Rates effective August 1, 2016.

2. Pursuant to section 61 of the UCA, the Commission will accept for filing the revised rate schedules reflecting an interim Steam Rate increase effective May 1, 2016, and the NEFC Hot Water Rates effective August 1, 2016.

3. The rates approved by the Order will remain interim and subject to refund with interest at Creative Energy’s weighted average cost of debt until further Order of the Commission.

4. The Commission hereby establishes the following Regulatory Timetable attached as Appendix A for the review of the Application.

5. Interveners who wish to participate in the regulatory proceeding are to register with the Commission by completing a Request to Intervene Form, available on the Commission’s website at http://www.bcuc.com/Registration-intervener-1.aspx by the date established in the Regulatory Timetable attached as Appendix A to this order and in accordance with the Commission’s Rules of Practice and Procedure

6. Creative Energy is to provide a copy of this Commission order to all parties who participated in the 2015-2017 RRA Application, and is to send a letter to all customers as soon as practicable providing notice of the increase in rates and this Order.

DATED at the City of Vancouver, in the Province of British Columbia, this XX day of X, 2016.

BY ORDER

Original Signed By:

Panel

Chair/Commissioner

Attachment

Appendix A

Regulatory Timetable

Action Dates (all 2016)

Information Requests (First) April 18

Response to Information Requests April 29

Information Requests (Second, if any) May 18

Response to Information Requests (Second) June 1

Intervener Submissions, if any June 7

Creative Energy response to Intervener Submissions June 15

Page | 121

11 APPENDIX 6 DRAFT ORDER – FINAL RATES 1

2

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

Creative Energy Vancouver Platforms Inc.

2016-2017 Revenue Requirements Application

BEFORE:

O R D E R

WHEREAS:

A. On April 1, 2016, Creative Energy Platforms Inc. (Creative Energy) filed its 2016-2017 Revenue Requirements Application (Application) with the British Columbia Utilities Commission (Commission) seeking among other things, approval to increase existing Steam Rates (net of the fuel cost adjustment charge, which is not expected to change) by 6.23% in 2016 and 6.23% in 2017 and approval of new hot water rates for Northeast False Creek, consistent with the Commission

Decision granting a CPCN for NEFC issued December 8, 2015; B. The Commission established a written process for review of the Application in Order xx-xxx-xx; C. Creative Energy filed an Evidentiary Update on April xx, 2016, which included a summary of corrections and adjustment impacting the rates sought. D. On May XX, 2016, Creative Energy filed its Final Submission to the Commission. E. The Commission has reviewed and considered all the evidence filed in this proceeding and finds that the following approvals are warranted.

NOW THEREFORE the Commission orders as follows:

1. Pursuant to sections 59 to 60 of the Utilities Commission Act (the UCA), the Commission grants

approval of the following for Creative Energy:

a) The final Steam Rates for all retail steam customers effective May 1, 2016 are approved subject to the filing of the adjustments to the 2016-17 revenue requirements as outlined in the attached Decision;

b) The interim Steam Rates for all steam customers effective January 1, 2017 are approved subject to the filing of the adjustments to the 2017 revenue requirements and an updated load forecast as outlined in the attached Decision;

c) The final NEFC Hot Water Rates for all NEFC customers effective August 1, 2016 are approved subject to the filing of the adjustments to the 2016-17 revenue requirements as outlined in the attached Decision;

d) The interim NEFC Hot Water Rates for all NEFC customers effective January 1, 2017 are approved subject to the filing of the adjustments to the 2017 revenue requirements as outlined in the attached Decision;

e) The difference between the interim Steam Rates and final Steam Rates is to be [collected from or refunded] to customers by way of an adjustment to the Steam Rates effective January 1, 2017. Alternative, Creative Energy is to propose different options for the recovery of the difference between interim rates and the final rates in its Compliance Filing.

2. The establishment of the Special Services Deferral Account non-rate base deferral account, as described in subsection 3.4.3.4 and in subsection 4.6.1 of the Application is approved, with carrying costs based on the cost of short-term debt calculated on monthly deferral account balances.

3. The establishment of the Fuel Cost Stabilization Account non-rate base deferral account, as described in section 3.2 of the Application is approved, with carrying costs at the weighted average cost of debt calculated on monthly deferral account balances.

4. Pursuant to section 44.2(3) of the UCA, the Commission approves the capital expenditures and projects for 2016 and 2017 as described in section 4 of the Application.

5. Creative Energy is directed to comply with all other directives identified in this Decision. 6. Creative Energy shall submit a compliance filing to the Commission, within 30 business days

from the date of this Decision, which will include updated and corrected financial schedules reflecting the various directives contained in this Decision.

7. Pursuant to section 61 of the UCA, the Commission will accept for filing the revised Steam Rate schedules reflecting a general rate increase effective May 1, 2016, and the NEFC Hot Water Rate schedules effective August 1, 2016.

DATED at the City of Vancouver, in the Province of British Columbia, this XX day of XXXX, 2016.

BY ORDER

Original Signed By:

Panel Chair/Commissioner

Attachment

Page | 124

12 APPENDIX 7 HAYGROUP REPORT (SECTIONS: 1

“BACKGROUND” & “METHODOLOGY” 2

Please see Confidential Filing 3

decision dated december 8, 2015. this application includes ... … · with directives found in the...

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