Diane Roy Director, Regulatory Affairs - Gas 16705 Fraser ... · 2.1 Given that the fuel pump has been unavailable to customers since September 30, 2010, please explain why FEI did

August 18, 2011 British Columbia Utilities Commission Sixth Floor 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Ms. Alanna Gillis, Acting Commission Secretary Dear Ms. Gillis: Re: FortisBC Energy Inc. ("FEI")

Application for Approval of a Compression Rate for Public NGV Refueling at FEI Surrey Operations Centre (the “Application”) Response to the British Columbia Utilities Commission (“BCUC” or the “Commission”) Information Request (“IR”) No. 1

On July 8, 2011, FEI filed the Application as referenced above. In accordance with Commission Letter No. L-62-11 setting out the Regulatory Timetable for the review of the Application, FEI respectfully submits the attached response to BCUC IR No. 1.

If there are any questions regarding the attached, please contact Mark Grist, Business Development, at 604-592-7874.

Yours very truly, FORTISBC ENERGY INC. Original signed by: Shawn Hill

For: Diane Roy Attachment

Diane Roy Director, Regulatory Affairs - Gas FortisBC Energy Inc.

16705 Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) 576-7349 Cell: (604) 908-2790 Fax: (604) 576-7074 Email: [email protected] www.fortisbc.com Regulatory Affairs Correspondence Email: [email protected]

B-2

mailto:[email protected]

http://www.fortisbc.com/

mailto:[email protected]

markhuds

FEI COMPRESSION RATE FOR PUBLIC NGV REFUELING

FortisBC Energy Inc. ("FEI" or the “Company”)

Application for new Rate Schedule 6P Compression and Dispensing Rate to Provide for Public Natural Gas Vehicle (NGV) Refueling at FEI Surrey Operations Centre

Submission Date:

August 18, 2011

Response to British Columbia Utilities Commission (“BCUC” or the “Commission”)

Information Request (“IR”) No. 1 Page 1

1.0 General and Background

Reference: Application, Schedules

1.1 All schedules indicate they exclude the Natural Gas Dehydrator. Please explain

why.

Response:

The financial schedules are based on the CNG and LNG Service template cost of service

models used for evaluation and rate determination purposes for CNG and LNG services to a

specific customer. In this model, the status quo subtitle is “Excluding Natural Gas Dehydrator”.

Although accurate FEI should have removed or replaced this subtitle to avoid any confusion as

this Application does not include a Natural Gas Dehydrator.

As an existing CNG station, a Natural Gas Dehydrator (dryer) was not included in the original

station design and construction as there is no requirement for one at this time.



Submission Date:

August 18, 2011



2.0 Rate Schedule for Public Use

Reference: Application, p. 1

“The proposed Rate Schedule 6P, (provided in Appendix A in proforma form), is required

so that FEI can re-establish this service to customers who had previously used the fuel

pump up until September 30, 2010, when the ownership of the refueling station was

transferred to FEI. These customers have come to expect the refueling service from this

facility, and FEI wishes to continue to serve them.”

2.1 Given that the fuel pump has been unavailable to customers since September

30, 2010, please explain why FEI did not apply to resume service until July 8,

2011.

Response:

FEI did not apply to resume service at the refueling station until July 8, 2011, due to resource

constraints. FEI staff responsible for developing and implementing the NGV service offering to

customers were committed to working on the Application for Approval of CNG and LNG Service

filed on December 1, 2010, and the Application for Approval of a Temporary Service Agreement

for LNG Service (for Vedder Transport) filed on July 12, 2011, as these applications were seen

as being more beneficial to customers in general in the Companies‟ view. As resources

became available, we worked on and filed the Application for Approval of a Compression Rate

for Public NGV Refueling at FEI Surrey Operations Centre.

2.2 Please provide the cost of preparing the Application by year, cost centre and cost

element.

Response:

As outlined in item 14 of the FEI 2010-2011 RRA NSA and approved by Commission Order G-

141-09, it was agreed that costs associated with the NGV service offerings were to be

recovered as part of the overall O&M for FEI. There was no requirement in the NSA to track

time or allocate time specific to NGV development. As such, the costs associated with

developing this Application were not being individually tracked.



Submission Date:

August 18, 2011



2.3 Please provide the letters, emails or other communication from the customers

requesting that FEI resume CNG refuelling service to the public at the Surrey

Operations Centre.

Response:

There is no centralized listing of customers affected by the loss of public access refueling

service as the service was originally suspended by Clean Energy. Customers affected by the

closure have most likely responded to Clean Energy, not FEI. FEI has received requests from a

small number of customers inquiring about the re-opening of the refueling station (see

Attachment 2.3 for examples of some emails received with customers‟ personal information

redacted), and the security guards at the Surrey Operations Centre have reported customers

attempting to use the CNG dispenser.

As discussed in our responses to BCUC IRs 1.4.2 and 1.5.2, customers who presently own

NGVs have limited refueling options in the Lower Mainland due to a high number of fueling

station closures by Clean Energy in recent months.

2.4 Would this CNG refueling station constitute the only current „open to the public‟

refueling station owned by FEI?

Response:

Yes, subject to Commission approval of this Application, this CNG refueling station will be the

only current NGV station owned by FEI where FEI allows the general public to access CNG

refueling services. As stated in the Application, the primary purpose of the station at the Surrey

Operations Centre is for FEI‟s own fleet.

2.5 What rate was used by Clean Energy for compression and dispensing prior to the

transfer of ownership in September 2010?

Response:

As FEI understands it, the rate that Clean Energy previously charged was a bundled rate that

did not separate the compression and dispensing price from the fuel price. The rate was also



Submission Date:

August 18, 2011



unregulated, which enabled Clean Energy to change the rate as required to allow for changing

commodity prices.

FEI states the above for contextual purposes. The rate that was in place at the time when FEI

purchased the station was $0.975/kg. This equates to $0.653 per gasoline litre equivalent

(multiply by 0.67 to convert $/kg to $/GLE). FEI does not believe that a meaningful comparison

can be drawn between the proposed rate and Clean Energy‟s former rate in or about September

2010 as commodity prices have since changed and Clean Energy‟s rate was both bundled and

unregulated.



Submission Date:

August 18, 2011



3.0 Rate Schedule for Public Use

Reference: Rate Schedule 6P, p. 1

3.1 The Application and calculations are specific to the Surrey Operations Centre yet

the Rate Schedule states that the Schedule is applicable in “The Lower Mainland

Service Area, including, but not limited to” the Surrey location. Please clarify and

update documentation as necessary that the rate schedule is exclusively for use

at the Surrey Operations Centre.

Response:

Currently, the only CNG dispenser accessible by the public is the one located at the Surrey

Operations Centre in Surrey, BC. Thus, the service could only be offered in the Lower Mainland

service area at this time. As explained in the Application, the proposed C&D rate in Rate

Schedule 6P is calculated using the forecast cost of service and total annual forecast volume of

CNG for both FEI‟s own fleet and the public at the Surrey Operations Centre pump.

In the event that FEI installs similar stations at other FEI facilities to serve its fleet and there is

an opportunity for the general public to access and use the dispenser, the clause in question

would make the regulatory process for opening those stations to the public somewhat more

efficient. For example, if the refueling facilities at our Burnaby location were ever relocated

within the property in such a manner that public access became an option, FEI believes the

inclusion of the text “but not limited to” would make for a more efficient regulatory process to

allow that public access as the Rate Schedule for a similar service would already be approved.

The change would be more administrative in nature, e.g., a new location would be added to the

Rate Schedule, and a new rate with supporting calculations would be filed.



Submission Date:

August 18, 2011



4.0 Company Use and Volume Forecast

Reference: Application, pp. 1-2

“The primary purpose of this station was, and continues to be, to provide CNG for use by

FEI to fuel its own fleet of natural gas vehicles operating from the Surrey Operations

Centre. FEI‟s fleet of CNG vehicles uses this station in sufficient volume to offset the

incremental cost of service incurred through fuel savings1, and for many of FEI‟s own

vehicles this is the sole refueling station that they can access.”

4.1 For 2006-2010, please provide the FEI annual CNG consumption for the Surrey

Operations Centre and FEI‟s Burnaby facility by year and location.

Response:

Please see the table below for the total CNG consumption in gigajoules at Surrey Operations

Centre (FEI fleet vehicles and third party accounts combined) and Burnaby (only FEI fleet

vehicles) facilities.

In reference to the table above, FEI believes that the total increase in consumption at the Surrey

Operations Centre during 2010 (prior to September 30th) is attributed to the closure of public

access fueling stations throughout the Lower Mainland. FEI also believes that the decline in

consumption in Burnaby since 2006 is due to the age of FEI‟s fleet vehicles, which have

gradually been phased out of service. But FEI‟s recent conversion of fleet vehicles will create

additional load at both FEI stations in coming years.

4.2 Does FEI have CNG refueling abilities at other locations in the Lower Mainland?

If yes, please list the locations.

Year

Surrey Ops Burnaby

2006 1,092 2,298

2007 897 2,030

2008 899 1,613

2009 810 1,287

2010 1,624 765

Consumption (GJ)



Submission Date:

August 18, 2011



Response:

At this time, FEI‟s fleet may access the CNG stations listed in the table below; however, FEI

vehicles do not routinely fuel at locations other than FEI‟s Burnaby and FEI‟s Surrey Operations

Centres.

FEI also has small scale Fuelmaker® time filling appliances located in a number of remote FEI

muster stations to provide CNG for FEI‟s own NGVs and mobile service units (“MSU”). Please

see our response to BCUC IR 1.4.3 for additional discussion on MSU applications.

FEI estimates there were 52 private and public fueling stations in the BC market from 1997 to

2003. This number has declined in recent years to approximately 6 public access stations in

FEI‟s service territory. Based on this trend, FEI does not believe that it can rely on the

remaining public access fueling stations to provide CNG fueling service to FEI fleet vehicles.

Therefore, the Surrey Operations Centre and Burnaby facilities were purchased by FEI with the

primary purpose of serving FEI‟s own fleet. Furthermore, fueling at locations other than FEI‟s

own vehicle muster stations is impractical due to issues, such as access, additional travel time,

incremental fuel usage, and additional vehicle wear and tear. Additionally, the Burnaby location

includes a time fill service ensuring that each vehicle is full each time when it leaves the service

yard.

4.3 How many CNG service vehicles does FEI have in its fleet using the Surrey and

Burnaby stations?

Operator Location Type

Chevron Burnaby public access

Chevron Cloverdale public access

Chevron Vancouver public access

Christie Adams Burnaby public access

Petro Canada Coquitlam public access

Petro Canada North Vancouver public access

FortisBC Burnaby Burnaby private - commercial fleet

FortisBC Surrey Operations Centre Surrey commercial fleet with proposed public access



Submission Date:

August 18, 2011



Response:

Presently FEI has thirty CNG vehicles operating out of the Surrey location, of which five of these

are mono-fuel CNG vehicles (operate on CNG only). Eighteen CNG vehicles operate out of the

Burnaby operations location, of which two of these are mono-fuel systems.

In 2010, FEI established a fleet conversion program to convert all eligible fleet vehicles1 that

muster out of the Burnaby and the Surrey Operations Centres to operate on CNG only. So far,

over thirty vehicles have been converted. At the end of the conversion program, which is

expected to be complete by the end of 2012, FEI is expected to add forty additional CNG

vehicles. Half of the forty vehicles are new vehicles, and the rest are from the conversion of

existing vehicles already in service. Twenty-five of the forty vehicles are scheduled to operate

out of the Surrey Operations Centre and the remainder out of the Burnaby center. Eight older

CNG vehicles (out of the total CNG fleet of 48) that have reached the end of their life cycle are

to be phased out before the end of 2012. These retired vehicles will be replaced with new CNG

vehicles from the group of forty additional CNG vehicles.

The primary benefits from the fleet conversion program are lower fleet operating costs through

fuel savings (approximately 50%) and GHG emission reductions (approximately 20%). A

secondary benefit is that FEI fleet vehicles have increased service capabilities. Over half of the

vehicles converted to operate on CNG are outfitted with additional MSU instrumentation. These

vehicles (typically service vans) have the ability to provide natural gas service to customers who

have been disconnected for line or service repairs through their onboard CNG tanks. The result

is more efficient service responses and less outages for gas customers.

4.3.1 What is the average age of this fleet?

Response:

The total FEI fleet size is approximately 570 vehicles ranging in age from 2001 models to 2011

models. The average age of the fleet is 3.5 years. Of this total fleet, approximately 48 are

NGVs. The average age of CNG applications is 3 years with an expected life expectancy of

over 6 years.

1 Conversion eligibility is based on the age and model of the vehicles. Some fleet vehicles are too old to

warrant conversion. For some vehicle models, suitable conversion equipment packages are not

available.



Submission Date:

August 18, 2011



4.4 For 2006-2010, please provide the annual third party CNG consumption for the

Surrey Operations Centre by year.

Response:

Since the change of ownership in September 2010, the refueling station at the Surrey

Operations Center has been closed to the general public. The table in the response to BCUC

IR 1.4.1 shows the total CNG consumption (FEI fleet and third party combined) for Surrey

Operations Centre from 2006-2010. As stated on Page of 2 of the Application, in the last six

months of operation (April 1, 2010 through September 30, 2010) before FEI took over

ownership, approximately 738 GJ of fuel was dispensed to third-party accounts (other than

FEI‟s fleet). The remaining records are not presently known by FEI.

FEI notes the fuel consumption volume (approximately 738 GJ) for the six-month period of April

2010 to September 30, 2010 may be higher than previous periods due to the number of public

access station closures throughout the Lower Mainland.

4.5 How many FEI employee vehicles primarily use(d) the Surrey facility for?

Response:

When the CNG dispenser was owned by Clean Energy, FEI is of the understanding that some

FEI employees were using the CNG dispenser to fuel their privately owned and operated NGVs.

FEI employees would be treated as any other third-party account and would be subject to the

proposed Rate Schedule 6P C&D charge should they wish to continue fueling their NGVs at the

station once it reopens.

4.5.1 What percentage of the reported 738 GJ of fuel dispensed to third-parties

(Apr – Sept 2010) can be attributed to FEI employee re-fueling volumes?



Submission Date:

August 18, 2011



Response:

FEI does not know the volume or percentage attributed to FEI employees‟ use of the fueling

station for the identified period as any historic records of credit card transactions before

September 30, 2010, are held by Clean Energy and are not accessible by FEI.



Submission Date:

August 18, 2011



5.0 Alternatives Considered


“Prior to the expiry of the service agreement, FEI considered four options with regard to

the fueling services at both the Surrey and Burnaby sites:

1. Extending the existing service agreement;

2. Having Clean Energy remove the existing assets and constructing the

Company‟s own refueling stations;

3. Using the nearest publicly accessible NGV refueling stations, approximately

seven kilometres from the Surrey Operations Centre; and

4. Purchasing the existing refueling stations from Clean Energy.”

5.1 Please provide the financial analysis summary of each of the four options listed

above.

Response:

The financial analysis summary was outlined on Pages 2 and 3 of the Application and outlined

again below:

1. Extending the existing service agreement would have an estimated cost of $84,000 per

year in lease costs. Purchasing the equipment was less than a three-year payback on

this lease cost.

2. Replacing the assets with new equipment was estimated at $250,000 per site.

3. Using the nearest public access is not a long-term viable option due to uncertainty

regarding the ongoing operation of that facility. Other factors include additional cost in

travel time, incremental fuel usage, vehicle wear and tear, and labour hours.

4. The purchase price for the refueling stations at both Burnaby and Surrey sites was

$213,603. Purchasing the stations was the most cost-effective option and provided less

than a three-year payback in comparison to option 1 of extending the lease.



Submission Date:

August 18, 2011



5.2 Is the nearest publicly accessible NGV refuelling station owned by a regulated or

non-regulated entity? Provide the name of the entity.

Response:

The nearest public access NGV refueling station is owned by Clean Energy and operated by

Chevron at 17780 56th Ave. Cloverdale, BC. FEI does not believe that Clean Energy is

regulated by the British Columbia Utilities Commission.

FEI is of the understanding that Clean Energy may close that station in the near term.

5.2.1 What is the current rate offered by the nearest publicly accessible NGV

refuelling station in comparable units ($/GJ)?

Response:

The current posted rate at Clean Energy‟s Cloverdale refueling station is $1.12/kg, or $0.75 per

gasoline litre equivalent (“GLE”). This is higher than the September 30, 2010, rate at the Surrey

Operations Centre of $0.65/GLE and the proposed rate in this Application of $0.58/GLE.



Submission Date:

August 18, 2011



6.0 Rate Setting and Review


“FEI proposes that, on an ongoing basis, Rate Schedule 6P be reviewed and, if required,

amended as part of the Company‟s revenue requirements review process.” (p. 5)

6.1 Please explain how FEI plans to have Rate Schedule 6P reviewed as part of the

future revenue requirements review processes.

Response:

FEI has determined Rate Schedule 6P based on the cost of service of the fueling station at

Surrey Operations Centre. As FEI‟s costs of service change over time, FEI proposes that Rate

Schedule 6P be reviewed through future revenue requirements application processes and is

updated in accordance with our revenue requirements and as approved by the BCUC.

6.2 Please explain why the request for approval of Rate Schedule 6P was not

included in the FortisBC Energy Utilities 2012-2013 Revenue Requirements &

Natural Gas Rates Application (FEU 2012-2013 RRA).

Response:

FEI was of the belief that this Application was best done as a “one-off” process because the

Application relates to the use of FEI‟s assets without significant impact on FEI‟s revenue

requirements for 2012 and 2013. Additionally, the public has been asking about the continuing

use of this dispenser, and as previously explained in the response to BCUC IR 1.2.1, the

Application could not have been filed earlier due to resources restraints. FEI believes and

hopes that this Application could be approved and implemented before the completion of the

regulatory process and review of the FEU 2012-2013 RRA.

6.3 Does FEI intend to include Schedule 6P as part of its upcoming rate design

application (Fall 2011)? If no, please explain why not. If yes, please explain how

it will impact the rate calculation being requested in this application.



Submission Date:

August 18, 2011



Response:

No, Rate Schedule 6P will not be reviewed as part of the Company‟s Amalgamation and Rate

Design Phase „A‟ application that will be filed this fall.

The Company intends to deal with the Rate Design of the Amalgamated entity in two phases,

Phase „A‟ and Phase „B‟. The Phase „A‟ application is intended to deal with the amalgamation

of FEI, FEVI and FEW, and postage stamp rates for the amalgamated entity for 2013. If

amalgamation and postage stamp rates are approved, then in 2012 the Company intends to file

its Phase „B‟ Rate Design application, in which the Company will address the full rate design of

its rates including all rate schedules which would include Rate Schedule 6P.



Submission Date:

August 18, 2011



7.0 O&M Costs

Reference: Application, Schedule 2

7.1 How is the O&M cost (Line 9) identified as Contractor Costs determined?

Response:

This response also addresses BCUC IRs 1.7.1.1 and 1.7.1.2.

FEI has submitted its O&M cost (identified as “Contractor Costs” in Line 9) as a forecast cost. In

June of 2010, as part of FEI‟s due diligence prior to acquiring the station assets from Clean

Energy, FEI had a private contractor perform an evaluation of the fueling station at Surrey

Operations Centre to determine annual forecast O&M requirements. The $8,500 in contractor

costs included in the forecast O&M in Schedule 2 for 2011 is reflective of this cost estimate.

The annual O&M cost estimate for years 2011 to 2020 includes all routine and preventative

maintenance, parts and service as recommended by the manufacturer and the contractor who

completed the performance evaluation in 2010.

7.1.1 Is this an actual contract cost?

Response:

Please see the response to BCUC IR 1.7.1.

7.1.2 Does it include all parts and service for 10 years of maintenance?

Response:

Please see the response to BCUC IR 1.7.1.



Submission Date:

August 18, 2011



8.0 Levelized Tariff Analysis – setting the rate

Reference: Application, Appendix B, Schedule 10

8.1 Please explain why FEI considers a ten year levelized tariff to be the most

appropriate calculation in determining the Compression & Dispensing (C&D) rate

to be charged?

Response:

FEI considers a ten-year levelized tariff to be an appropriate calculation of the Compression &

Dispensing (C&D) rate for the Surrey Operations refueling facility for several reasons:

1. Firstly, a levelized rate provides a stable and predictable rate. One of the objectives in

setting a rate is to accomplish stable and predictable rates and revenues, while yielding

sufficient recoveries to allow the utility to recover prudently incurred costs and to earn a

fair rate of return on investment.

2. Secondly, a ten-year levelized tariff balances the desire for a cost of service based rate

with the materiality of the costs and revenues. Annual third-party compression and

dispensing revenues for the service to the general public is expected to be

approximately $7 to $8 thousand (738 GJ for 6 months x 2 x $5.239 = $7.7 thousand).

That is, the benefit of the preciseness achieved from updating the rate on an annual

basis for costs and revenues of this magnitude over a ten-year term may not outweigh

the administrative costs associated with the update.

3. Thirdly, a levelized rate provides a simple approach for applying future delivery rate

changes as determined in revenue requirements proceedings, contributing to

administrative and regulatory efficiency.

4. Lastly, FEI does not consider the refueling service at FEI Surrey Operations Centre as a

primary service to customers. The primary purpose of the station is for the refueling of

FEI‟s fleet vehicles. The service to the general public is an ancillary service which

provides ancillary recoveries and therefore, an offset to costs borne by existing

customers. Therefore, FEI believes that a ten-year levelized rate provides a reasonable

reflection of the annual cost of service and consequently, reasonable recoveries (or

offset to costs) for public use of this asset.

As explained in the Application, the C&D rate would be reviewed as part of the Company‟s

revenue requirements review process.



Submission Date:

August 18, 2011



8.2 At this time, is it FEI‟s best estimate that the C&D rate of $5.239 determined on

Schedule 10 will be the rate charged up to and including 2020? Please explain.

If not, please explain why a ten year levelized tariff calculation was used.

Response:

As indicated in Schedule 10, $5.239/GJ represents the levelized volumetric delivery rate. The

levelized rate was calculated as a means to determine an average price over the period of 2011

and 2020, taking into account the discounted value of money over the expected remaining life of

the asset at this point in time.

As stated in the Application, the C&D rate will be reviewed as part of the Company‟s revenue

requirements review process. FEI would adjust the C&D component of the total charge by the

general percentage change in the Company‟s revenue requirements to be approved by the

Commission.

Please also refer to the response to BCUC IR 1.8.1.

8.3 Please reference other examples where rates were set based on a Levelized

Volumetric Delivery Rate.

Response:

FEI believes that using a levelized rate is appropriate to recover some of the cost of service

from those customers who enter FEI‟s Surrey site during regular working day hours to refuel

their own vehicles.

Some examples of how a levelized rate has been used in a regulated setting are presented

below.

In its negotiated settlement for the Maritimes and Northeast Pipeline, the tolls for the

January 1, 2004 through December 31, 2006 was a levelized toll for the three year

period. The levelized toll for each of the years was subject to adjustment “to dispose of

the previous year‟s deferral account balances with the carrying costs incurred or interest

gained on any balances deferred …” (Maritimes and Northeast Pipeline letter to the

National Energy Board dated July 31, 2003 re Tolls Settlement and Application for Final

Tolls).



Submission Date:

August 18, 2011



The Commission approved the Service Agreement for FEI‟s provision of CNG service to

Waste Management in Commission Order G-128-11 on July 19, 2011. The cost of

service model used to arrive at a rate generated a levelized 20 year rate that was then

converted to an inclining rate structure over time. The rate of increase was fixed through

negotiations with the customer and was set at a level that allowed for price escalation.

The 1989 Wheeling Agreement between FEI (then BC Gas Inc.) and FEVI (then PCEC)

was based on a levelized rate modified to take into consideration anticipated load growth

on PCEC‟s pipeline.

Levelized cost / rate calculations have been used by FEI in CPCN applications and other

applications to illustrate the time value average cost or rate impact such as was done for the Mt.

Hayes LNG Storage Facility CPCN (filed June 5, 2007, pages 72-73 & 120-121) and also for the

Commercial Commodity Unbundling regarding Implementation Costs (January 16, 2004

Application, Page 12).

8.3.1 Please explain why a similar calculation would be appropriate in this

situation.

Response:

Please see our responses to BCUC IRs 1.8.1 and 1.8.2.

8.4 Please confirm that if the levelized rate methodology had not been used, rates for

2011, 2012 and 2013, the rate would have been $5.69, $4.99, and $5.18

respectively? (Schedule 10, line 1 / line 30)

Response:

Had the levelized rate methodology not been used, the rates for 2011, 2012 and 2013 would

have been $ 5.69, $ 5.00, and $ 5.18 respectively. Detailed calculation is as follows:

2011: $26.865 annual revenue requirement / 4.725 TJs = $5.686




Submission Date:

August 18, 2011




Please see Schedule 10 below, Line 30:



Submission Date:

August 18, 2011



FortisBC Energy Inc.

CNG Cost of Service Surrey Operations

Excluding NG Dehydrator

CNG Cost of Service Surrey Operations: Present Value of Revenue Requirement & Levelized Tariff Analysis

Appendix - Schedule 10

($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1

2 Annual Revenue Requirement (Excluding Cost of Energy)($000s) Schedule 1, Line 13 26.865 23.645 24.457 24.792 24.926 24.899 24.745 24.489 24.153 23.754

3

4 Annual Discount Rate

5 Equity Component

6 ROE % 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500%

7 Equity Portion 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000%

8 Debt Component

9 Long Term Debt Rate 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945%

10 Long Term Debt Portion 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370%

11 Short Term Debt Rate 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500%

12 Short Term Debt Portion 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630%

13

14 Tax Rate 26.500% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000%

15 Pre- Tax Weighted Average Cost of Capital (WACC)1 9.297% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194%

16 After- Tax Weighted Average Cost of Capital (WACC)2 6.833% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895%

17

18 Present Value of Revenue Requirement

19 PV of Annual Revenue Requirement Line 2 / (1 + Line 16)^Yr 25.147 20.693 20.023 18.988 17.859 16.689 15.516 14.365 13.254 12.194

20 Total PV of Revenue Requirement Sum of Line 19 174.727

21 Total PV of Revenue Requirement, $000s/Yr Line 20 / Yrs 17.473

22 Total PV of Revenue Requirement over contract term 174.727

23

24 PV of Annual Customers Line 3 / (1 + Line 16)^Yr 0.900 0.875 0.819 0.766 0.716 0.670 0.627 0.587 0.549 0.513

25 Total PV of Customers Sum of Line 23 7.022

26

27 Tariff Analysis

28 Annual Volume (TJ) 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725

29

30 Annual Volumetric Cost of Service ($/GJ) Line 2 / Line 28 5.686 5.004 5.176 5.247 5.275 5.270 5.237 5.183 5.112 5.027

31

32 Levelized Tariff Analysis

33 PV of Annual Volume (TJ) Line 28 / (1 + Line 16)^Yr 4.423 4.135 3.868 3.619 3.385 3.167 2.963 2.772 2.593 2.426

34 Total PV of Volume (TJ) Sum of Line 33 33.350

35

36 Levelized Volumetric Delivery Rate ($/GJ) Line 20 / Line 34 5.239 5 5 5 5 5 5 5 5 5

37

38 1- ( Line 6 x Line 7) / 1- Line 14 + ( Line 9 x Line 10 + Line 11 x Line 12)

39 2- Line 7 x Line 8 + [( Line 10 x Line 11 + Line 12 x Line 13) x 1- Line 15]



Submission Date:

August 18, 2011



8.4.1 If not, please calculate the rates for 2011, 2012, and 2013 without using

the levelized costs methodology (i.e. no discounting or cumulating).

Response:

Please refer to BCUC IR 1.8.4.

8.4.1.1 Please explain why this calculation was not considered a more

appropriate methodology?

Response:

FEI believes that a ten-year levelized rate is appropriate in this circumstance for the reasons as

discussed in the response to BCUC IR 1.8.1.

Primarily, as the C&D revenue from this ancillary service is expected to be modest, under $8

thousand per year, FEI believes that a simple approach with minimal administrative

requirements is most appropriate (see response to BCUC IR 1.8.1).

8.5 Please explain why the 2011 present value calculation was forecast to occur at

time 1 rather than time 0 (i.e. why is discounting required in 2011)?

Response:

FEI has assumed that all recoveries are received by the end of the year (i.e. “Time 1”) while the

initial capital outlay incurred at the start of the year (“Time 0”) to reflect the lag between the

capital outlay, associated costs and the forecast recoveries. This time frame for discounting is

the same as for Schedule 12 (Discounted Cash Flow Analysis) where revenues (Line 2),

expenses (Line 3), Income Tax (Line 7), Overhead Capitalized Tax Shield (Line 8) and CCA Tax

Shield (Line 9) are discounted to time 1 (beginning of 2011).



Submission Date:

August 18, 2011



9.0 Gross Plant in Service Additions


“The refueling assets at the Burnaby facility are not configured for public access at this

time, and as such no public service is currently being sought at the Burnaby facility.” (p.

3)

9.1 How are the operating and capital costs for the Surrey and Burnaby facility

currently being treated?

Response:

The capital costs have been charged to FEI‟s Gas Plant in Service, Account 476-00

Compressor Equipment. Although the pooled whole life depreciation rate for all assets in

Account 476 is 26.54%, as applied for in FEU‟s 2012-2013 Revenue Requirements Application,

the estimated remaining life for these two particular assets, Surrey and Burnaby CNG

equipment, is 10 years (see also the response to BCUC IR 1.13.2). Depreciation rates for the

Company‟s Gas Plant in Service are reviewed periodically, approximately every 3 to 5 years,

and for Account 476 the depreciation rate will be adjusted in the future to reflect the remaining

whole life at that time.

The operating and maintenance costs for the Burnaby and Surrey CNG equipment are

managed as any other asset in the FEI system as the primary use of these assets is to provide

service to FEI fleet of NGVs that operate out of Surrey and Burnaby centres. In the near term,

FEI anticipates using contractors for servicing and maintaining the equipment under the

direction of asset management.

9.2 How does FEI plan to treat the operating and capital costs for the Burnaby site in

the future?

Response:

Please see the response to BCUC IR 1.9.1. FEI does not expect to treat the operating and

capital costs for the Burnaby site differently in the future than the treatment as described in the

response to BCUC IR 1.9.1.



Submission Date:

August 18, 2011



9.2.1 Have the cost of service for the Burnaby site been included in the FEU

2012-2013 RRA?

Response:

This response also addresses BCUC IR 1.9.2.2.

As at the time of filing the 2012-2013 RRA, the costs associated with both the Burnaby and

Surrey Operation sites were included in the work in progress account, but the transition of the

costs from work in progress to plant additions in 2011 was inadvertently excluded from the 2011

projected net plant in service. As a result, the capital cost for the fueling facilities has not been

included in the forecast Rate Base. Furthermore, the related cost of service, other than O&M,

has also been excluded from the FEU 2012 – 2013 RRA.

The asset costs were closed from Work in Process to Gas Plant in Service in May, 2011.

Therefore, the costs will be included in the actual net plant in service for FEI in 2011 and

consequently, the opening balance for net plant in service will reflect these fueling facilities in

the Company‟s 2014 revenue requirements.

9.2.2 Have the cost of service for the Surrey site been included in the FEU

2012-2013 RRA?

Response:

Please refer to the response to BCUC IR 1.9.2.1.

“FEI and Clean Energy reached an agreement for the sale and purchase of the assets,

with ownership transferring to FEI at the end of September, 2010.” (p. 3)

9.3 Were the assets of $212,606 a Gross Plant in Service addition in any of the

FortisBC Energy Utilities in 2010 or 2011?

Response:

Yes, the assets were a Gross Plant in Service addition in FEI in May 2011 as explained in the

response to BCUC IR 1.9.2.1.



Submission Date:

August 18, 2011



9.3.1 If yes, was any depreciation recovered in 2010 and/or 2011 rates?

Response:

No, depreciation was not recovered in 2010 or 2011 rates since this purchase was not included

in the 2010-2011 Revenue Requirement Application. The asset was closed from Work in

Process to Gas Plant in Service in May 2011.

9.3.1.1 If yes, how much?

Response:


9.3.2 If no, please explain how these costs are accounted for.

Response:

From September 2010 to May 2011, the assets were held in work in progress. The assets were

put into service in May 2011 with 7 months of depreciation expense for 2011. As this expense

was not included in the 2010 or 2011 delivery rates, it has not been, recovered from customers.

Please refer to the response to BCUC IR 1.9.1 for a description of the accounting treatment and

the response to BCUC IR 1.9.2.1 for a description of the impact on the FEU 2012-2013 RRA.

9.4 If the assets were a Gross Plant in Service addition in either 2010 or 2011 has

the FEU 2012-2013 RRA been adjusted for the $106,801 Surrey site costs?

Response:




Submission Date:

August 18, 2011



9.5 Have any of the costs in Appendix B, Schedule 1 been included in the FEU 2012-

2013 RRA?

Response:

The O&M expenses in Schedule 1 are embedded in the forecast gross O&M in the FEU 2012-

2013 RRA.

9.6 If approval to provide CNG fueling services to customers was not approved how

would the costs in Appendix B, Schedule 1 be treated?

Response:

The primary purpose of the CNG fueling station has been, and continues to be, to serve FEI‟s

own fleet of natural gas vehicles and as such, the costs identified in Appendix B, Schedule 1 are

incurred whether or not CNG fueling services is available to customers. Therefore, regardless

whether or not CNG fueling services to the general public as contemplated in this Application is

approved, the costs of this fueling station will be embedded in the delivery rates of FEI

customers.

FEI‟s proposal to allow the general public to use this CNG fueling station provides ancillary

revenue benefits to existing natural gas customers. If the CNG fueling services to customers

were not approved, the ancillary revenue would not occur.



Submission Date:

August 18, 2011



10.0 Rate Schedule 6P Tariff

Reference: Application, Appendix A

Order G-128-11, Appendix A Reasons for Decision (CNG/LNG

Decision), p. 18 of 34

“FEI also takes the position that once the Commission has approved a tariff offering for

CNG and LNG service, such service becomes subject to the statutory framework relating

to a utility‟s legal obligation to provide its service to the public, as set out in sections 28

to 30 of the Act.”

10.1 If Rate Schedule 6P is approved, will FEI have an obligation to provide natural

gas refueling service to the public? Please explain why or why not.

Response:

FEI believes that approval of the rate schedule as requested would enable, rather than obligate,

FEI to provide the service contemplated in this Application. There are two reasons for this.

First, the public refueling station at the Surrey Operations Center is located on FEI‟s own

premises and is mainly for the use of FEI‟s own fleet. As owner of the property, FEI would

retain the ability to exclude access from the facility.

Second, in the recent Application for Approval of a Service Agreement for Compressed Natural

Gas Service and for Approval of General Terms and Conditions for Compressed Natural Gas

(“CNG”) and Liquefied Natural Gas (“LNG”) Service (the “CNG/LNG Application”), FEI provided

the following response to a similar question regarding the services proposed in that CNG/LNG

Application (partial excerpt from Exhibit B-9, response to CEC IR 2.1.3):

“Under section 28 of the Act, public utilities are under an obligation to “supply its services

to premises that are located within 200 metres of its supply line or any lesser distance

that the commission prescribes as suitable for that purpose.” Section 29 sets out the

criteria for providing service to premises over 200 metres away. Section 30 deals with

main extensions. TGI interprets the obligation to provide “its service” as meaning the

services for which TGI has obtained the approval of the Commission for offering to the

public for compensation. Thus, once Commission approval has been obtained for a tariff

offering for CNG and LNG service, TGI is subject to the statutory framework relating to

the obligation to provide “its service” to the public. In the absence of a standard form

agreement, the Commission will still have to approve each customer contract, thus

giving the Commission the ultimate say over whether a particular customer can obtain

CNG or LNG service.”



Submission Date:

August 18, 2011



In the Commission decision on LNG/CNG Application, the Commission determined, however,

that there is no obligation to serve the NGV customers if they request because “the fuel

dispensing service has no natural monopoly characteristics and could potentially be supplied by

any number of competitors.” Based on the analysis applied by the Commission, FEI would

expect the Commission would similarly find that FEI has no such obligation to serve irrespective

of whether the NGV facilities are located on private property.



Submission Date:

August 18, 2011



11.0 Schedule 2 Calculations


CNG/LNG Decision

11.1 Please revise the Application to reflect Commission Order G-128-11 and

Reasons for Decision (overhead capitalization, marketing costs, and escalation

factor).

Response:

Commission Order No. G-128-11 was a decision on a separate and unrelated application

regarding FEI‟s plan to offer a type of service to our customers that is fundamentally different

from the service FEI is seeking to offer in this Application. The application considered by

Commission Order No. G-128-11 contemplated provision of new refueling services that were

tied to specific customers and an associated rate contracted with the customer. In other words,

the assets were installed for that customer and Order No. G-128-11 reflects that the “full cost” of

providing that service must be recovered from that customer.

The current Application contemplates allowing non-specific customers (i.e. the general public on

an entirely optional and non-contractual basis) to have access to an existing asset which has

the primary services of serving FEI‟s own fleet of vehicles. In this case, FEI‟s ownership and

operation of this existing asset is already justified through the cost savings used by the FEI fleet

and the costs of service of this asset is recovered by FEI through delivery rates. The purpose of

this Application is to allow the general public to contribute additional revenue (to the marginal

benefit of all customers) through the incremental use of this station.

Included in the Reasons for Decision pertaining to BCUC Order No. G-128-11 were the

following seven directives from the Commission, in addition to the “take or pay” commitment

from potential LNG/CNG customers, related to the determination of the cost of service that is

recovered through the contract rate for a CNG or LNG Service fueling station:

i. Actual construction costs as opposed to forecast costs;

ii. Full recovery of the capital cost of the fueling station;

iii. Actual operating and maintenance costs to be recovered as fully as possible;

iv. Operating and maintenance costs to be inflated by the regional CPI annually;

v. No amount for capitalized overhead such that all operating and maintenance costs are

recovered from the CNG/LNG customer over the term of the contract;

vi. An estimate for net negative salvage value to be included; and



Submission Date:

August 18, 2011



vii. An allowance for overhead and marketing to be recovered from the CNG/LNG customer.

As described above, FEI believes that Order No. G-128-11 and the directives listed above do

not address the determination of the rate for the service contemplated in this Application;

however, for the purpose of responding to this question, FEI has updated the calculation of Rate

Schedule 6P as discussed below.

i. The actual costs of the Surrey Operations fueling station are known and were used in

the determination of the cost of service and levelized rate; thus, no changes are required

in this regard.

ii. The actual capital costs are used as basis for the determination of the rate, and thus no

changes are required in this regard. However, the primary purpose of this fueling station

is for FEI‟s own use to meet its operational requirements. Therefore, FEI believes that it

is not reasonable to recover the full capital costs associated with this station only from

those customers who may use this station.

iii. The determination of the service charge is based on the average annual cost of service

(i.e. levelized cost of service), thereby generally recovering the cost of service and O&M

in each year; thus no changes are required in this regard. However, the primary

purpose of this fueling station is for is FEI‟s own use to meet its operational

requirements. Therefore, FEI believes that it is not reasonable to recover the full O&M

costs associated with this station only from those customers who may use this station.

iv. The forecast O&M for each year is determined by taking the previous year O&M inflated

at CPI of 2 percent per year. FEI has updated the model to reflect the most recent

forecast of BC CPI.

v. The capitalized overhead component has been removed from the cost of service model

used to determine the levelized rate.

vi. The net negative salvage is expected to be approximately $10 thousand. FEI has

adjusted the calculation to include a removal provision in the annual cost of service and

to include the negative salvage in rate base.

vii. Please see item (iii) above.

The revisions to the cost of service model pertaining to BCUC Order No. G-128-11 result in a

levelized rate of approximately $5.58/GJ, or an increase of approximately $0.34/GJ as

compared to the Application. Please refer to Attachment 11.1 for the financial schedules



Submission Date:

August 18, 2011



reflecting BCUC Order No. G-128-11, and the determination of the levelized rate under this

scenario.

11.2 Commission Order G-128-11 and Reasons for Decision determined that a no

overheads should be capitalized in regards to NGV. Specifically how would it

change line 17?

Response:

Please refer to the response to BCUC IR 1.11.1. Specifically, Line 17 would show zero,

reflecting no capitalized overhead.

11.3 As a result of Commission Order G-128-11 and Reasons for Decision are there

any other O&M costs that FEI now considers necessary to include?

Response:

No. FEI believes that the existing O&M forecast included in the determination of Rate Schedule

6P is appropriate and does not require an update to reflect BCUC Order No. G-128-11.

Please refer to BCUC IR 1.11.1 for a discussion on the impacts of BCUC Order No. G-128.11

on this Application.

11.4 Property Tax on line 28 is calculated based on the forecast revenues from

Schedule 11. Please show the calculation for each year and explain how the

amount is determined to be $0.

Response:

The reference provided on Schedule 2 is incorrect. In this case, the Property Tax on line 28 is

calculated based on the levelized rate ($/GJ) multiplied by the annual volume from Schedule 10.

Years 2011 and 2012 are zero because the calculation is based on the second preceding year



Submission Date:

August 18, 2011



and in this context, 2009 or 2010 revenues do not exist to base the calculation on. The property

tax expense for years 2013 onwards shows as zero on Schedule 2 because of rounding.

Please see Table 1 below for the calculation rounded to three decimal places rather than a

whole number as presented in Appendix B:

Table 1 Property Tax Calculation

Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Annual Volume (TJ): Schedule 10, Line 29 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725

Levelized Volumetric Delivery Rate ($/GJ) Schedule 10, Line 37 5.576 5.576 5.576 5.576 5.576 5.576 5.576 5.576 5.576 5.576

Total Property Taxes 1 Line 29 x Line 27 x 1% - - 0.263 0.263 0.263 0.263 0.263 0.263 0.263 0.263



Submission Date:

August 18, 2011





12.1 Line 16 accounts for an “adjustment to 13-month average”. FEI has included a

$49,000 adjustment in 2011. Please show the calculation and the rationale for

the adjustment.

Response:

The rationale for the adjustment is to account for the full year of service of the asset in 2011,

reflecting a full ten year period on which to set the levelized rate. The calculation of the

“adjustment to 13-month average” is as follows:

= 2011 plant in-service amount x (months in service/13) -0.5

= $97 x (13/13)-0.5

= $48.5 thousand



Submission Date:

August 18, 2011



13.0 Value and Estimated Life of Surrey Assets

Reference: Application, p. 3; Appendix B, Schedule 5 & 6

“The price to purchase the C&D assets from Clean Energy was agreed to be $213,603

for the equipment at both the Surrey and Burnaby site.” (p. 3)

13.1 Please provide support for allocating 50% of the purchase price to the Surrey site

($106,801).

Response:

FEI did not receive a valuation from Clean Energy for each individual asset, but rather a total for

both stations. Based on a performance evaluation completed by an independent contractor on

behalf of FEI, the Company concluded that these assets are similar in their operational capacity

and use (“run hours”) to date. FEI thus believes the assumption to allocate the total purchase

price evenly between the stations is reasonable given the information available.

13.2 Please provide support for the estimated life of the assets at 10 years.

Response:

The assets have been in service for approximately 10 years, and the estimated useful life of the

assets are 20 years without major capital upgrades. As this is a commercially designed

package, major capital upgrades can extend the life of the base asset.

13.3 What are the current age and original design life of the two stations?

Response:

Please refer to the response to BCUC IR 1.13.2.



Submission Date:

August 18, 2011





14.1 Please confirm that line 30, Annual Volume (TJ) is 4.725 rounded up to be 5. If

yes, please refile the schedule using three decimal points for all calculations.

Response:

Confirmed, Line 30 annual volumes in TJs is 4.725 rounded up to 5. Please see amended

Schedule 10 below:



Submission Date:

August 18, 2011






CNG Cost of Service Surrey Operations: Present Value of Revenue Requirement & Levelized Tariff Analysis




1

2 Annual Revenue Requirement (Excluding Cost of Energy)($000s) Schedule 1, Line 13 26.865 23.645 24.457 24.792 24.926 24.899 24.745 24.489 24.153 23.754

3

4 Annual Discount Rate

5 Equity Component

6 ROE % 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500% 9.500%

7 Equity Portion 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000% 40.000%

8 Debt Component

9 Long Term Debt Rate 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945% 6.945%

10 Long Term Debt Portion 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370% 58.370%

11 Short Term Debt Rate 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500% 4.500%

12 Short Term Debt Portion 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630% 1.630%

13

14 Tax Rate 26.500% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000% 25.000%

15 Pre- Tax Weighted Average Cost of Capital (WACC)1 9.297% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194% 9.194%

16 After- Tax Weighted Average Cost of Capital (WACC)2 6.833% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895% 6.895%

17

18 Present Value of Revenue Requirement

19 PV of Annual Revenue Requirement Line 2 / (1 + Line 16)^Yr 25.147 20.693 20.023 18.988 17.859 16.689 15.516 14.365 13.254 12.194

20 Total PV of Revenue Requirement Sum of Line 19 174.727

21 Total PV of Revenue Requirement, $000s/Yr Line 20 / Yrs 17.473

22 Total PV of Revenue Requirement over contract term 174.727

23

24 PV of Annual Customers Line 3 / (1 + Line 16)^Yr 0.900 0.875 0.819 0.766 0.716 0.670 0.627 0.587 0.549 0.513

25 Total PV of Customers Sum of Line 23 7.022

26

27 Tariff Analysis

28 Annual Volume (TJ) 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725

29

30 Annual Volumetric Cost of Service ($/GJ) Line 2 / Line 28 5.686 5.004 5.176 5.247 5.275 5.270 5.237 5.183 5.112 5.027

31

32 Levelized Tariff Analysis

33 PV of Annual Volume (TJ) Line 28 / (1 + Line 16)^Yr 4.423 4.135 3.868 3.619 3.385 3.167 2.963 2.772 2.593 2.426

34 Total PV of Volume (TJ) Sum of Line 33 33.350

35

36 Levelized Volumetric Delivery Rate ($/GJ) Line 20 / Line 34 5.239 5 5 5 5 5 5 5 5 5

37

38 1- ( Line 6 x Line 7) / 1- Line 14 + ( Line 9 x Line 10 + Line 11 x Line 12)

39 2- Line 7 x Line 8 + [( Line 10 x Line 11 + Line 12 x Line 13) x 1- Line 15]



Submission Date:

August 18, 2011



14.2 Because the same discount rate was used for both the numerator and the

denominator please confirm that the calculation for Levelized Volumetric Delivery

Rate on line 42 would be the same whether or not the calculation was

discounted.

Response:

Not confirmed, because mathematically the result is not the same. As demonstrated in the table

below, ignoring the discounting of the cost of service and volumes and calculating a simple 10

year arithmetic average, results in a rate of $5.222/GJ. This is approximately $0.017/GJ lower

than the levelized rate of $5.239/GJ.

14.3 Does FEI anticipate a future situation where it would use a different discount rate

for the present value of the revenue requirement and the present value of the

volume?

Response:

No, FEI does not anticipate a future situation where it may use a different discount rate for the

revenue requirements and the volume.

Furthermore, FEI does not anticipate that it would re-evaluate the levelized rate in the future by

using a revised discount rate for the remaining years. As discussed in the Application, FEI

proposes to amend the Compression and Dispensing rate in the future as part of the general

rate change from the Company‟s revenue requirements review process.

Particulars Reference Total 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Annual Revenue Requirement

(Excluding Cost of Energy)($000s) Schedule 1, Line 13 246.725$ 26.865$ 23.645$ 24.457$ 24.792$ 24.926$ 24.899$ 24.745$ 24.489$ 24.153$ 23.754$

Annual Volume (TJ) 47.250 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725

Average Cost of Service Rate 5.222$ 5.686$ 5.004$ 5.176$ 5.247$ 5.275$ 5.270$ 5.237$ 5.183$ 5.112$ 5.027$



Submission Date:

August 18, 2011



14.4 Please confirm that if the right amount of decimal points were used a straight

average of line 2 divided by line 30 would give you $5.239.

Response:

Not confirmed. Line 2 divided by Line 30 would not yield $5.239. For 2011, Line 2 divided by

Line 30 equals $5.686 / GJ (Line 34). Please see the response to BCUC IR 1.8.4 for the annual

Cost of Service rate.

The levelized rate of $5.239 is derived by dividing $174.7 thousand (Line 22 – PV of Annual

Revenue Requirement) by 33.350 TJ (Line 38 – Total PV of Volume (TJ).

14.4.1 If not, please explain.

Response:

Please refer to the responses to BCUC IRs 1.14.2 and 1.14.4.

14.4.2 If yes, please explain why discounting has been used when it does not

affect the results on line 42.

Response:

Discounting does affect the result, although the difference in this case is not significant

compared to an arithmetic average for 10 years. Please refer to the response to BCUC IR

1.14.2.

14.5 Would it have been possible to smooth out the rates by using some sort of

deferral account treatment in determining the Annual Revenue Requirement (line

1) instead of averaging out the forecast 10 year rate?



Submission Date:

August 18, 2011



Response:

While it would have been possible “to smooth out the rates by some sort of a deferral account”

as suggested, doing so would introduce additional administrative accounting activity when what

is being contemplated is a small incremental activity yielding ancillary compression and

dispensing revenue of less than $8 thousand per year. As FEI explained in responses to BCUC

IRs 1.8.1 and 1.8.2, under such circumstances, it is appropriate and desirable to have an

approach that sets the initial rate and to adjust the rate thereafter in the future if required. Using

a deferral account was not considered and would not be desirable given the requirements for

additional accounting activity to perform the tracking and report of the deferral account.

14.5.1 If yes, was this treatment considered?

Response:


14.5.2 If not, please explain why it is not the preferred treatment.

Response:




Submission Date:

August 18, 2011





15.1 Footnote 1 states “…each year of the contract”, what contract is being referred

to?

Response:


This footnote was inadvertently included, and is not applicable to the Application.

15.2 Please confirm that line 7 are the forecast revenues from public refueling of

NGV‟s at the Surrey site.

Response:


Not confirmed, Line 7 does not reflect the forecast revenues from public refueling of NGVs at

the Surrey site.

15.2.1 If not, please explain what line 7 refers to.

Response:

Please refer to the response to BCUC 1.15.3.

15.2.2 If not, why was it used in the calculation for Property Tax on Schedule 2,

line 28?



Submission Date:

August 18, 2011



Response:


15.2.3 If yes, what support does FEI have that the forecast revenues on line 7

are reasonable?

Response:


15.3 What is the purpose of Schedule 11 (other than to support the Property Tax

calculation) and how does it support the Application?

Response:

This response also addresses BCUC IRs 1.15.1, 1.15.2, 1.15.2.1 and 1.15.2.2 and 1.15.2.3.

Schedule 11, “Contract Rate Design” schedule, does not support this Application and should

have been excluded from the set of financial schedules filed with the Appendix. This Rate

Design schedule is a part of the template cost of service model used to evaluate CNG and LNG

Service contracts for permanent fueling stations which use an escalated rate to recover the cost

of service over the term of the contract.

Property tax is calculated from Schedule 10, levelized rate ($/GJ) multiplied by annual volume

(TJ) (Line 30 x Line 42 x 1%).



Submission Date:

August 18, 2011





16.1 Footnote 4 states the evaluation period reflects the useful life of the asset,

therefore it is assumed that the terminal value is zero; however, on line 11, year

2020, a terminal value of $90.5 has been included. Please explain.

Response:

Footnote 4 should not have been included in the schedule for this Application as it is appropriate

in this case to assume the service would continue indefinitely and that at the end of year 10,

there would be some value from continuing to provide C&D service from the Surrey Operations

Center. The schedule is reproduced below without footnote 4.



Submission Date:

August 18, 2011






CNG Cost of Service Surrey Operations: Discounted Cash Flow Analysis




1 Cash Flow

2 Add: Revenue Schedule 11, Line 7 22.9 23.3 23.8 24.3 24.7 25.2 25.7 26.3 26.8 27.3

3 Less: O&M, Property Tax Expense Schedule 10, - (Line 3 + Line 4 + Line 6) (8.5) (8.7) (9.1) (9.3) (9.4) (9.6) (9.8) (10.0) (10.2) (10.4)

4 EBITDA1 Line 2 + Line 3 14.4 14.6 14.7 15.0 15.3 15.6 15.9 16.2 16.6 16.9

5 Capital Expenditures2Schedule 6, Line 39 (106.8) - - - - - - - - -

6 Pre-Tax Cash Flow Line 4 + Line 5 (92.4) 14.6 14.7 15.0 15.3 15.6 15.9 16.2 16.6 16.9

7 Income Tax Expense Line 4 x (- Schedule 3, Line 12) (3.8) (3.7) (3.7) (3.8) (3.8) (3.9) (4.0) (4.1) (4.1) (4.2)

8 Overhead Capitalized Tax Shield Schedule 3, -Line 8 x Line 12 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.2

9 CCA Tax Shield Schedule 3, -Line 9 x Line 12 2.8 4.8 3.9 3.1 2.5 2.0 1.6 1.3 1.1 0.9

10 Terminal Value of CCA Tax Shield 4 - - - - - - - - - 3.1

11 Terminal Value - - - - - - - - - 90.5

12

13 Free Cash Flow Line 6 + Line 7 (93.3) 15.9 15.0 14.5 14.1 13.9 13.7 13.7 13.7 107.3

14

15 After Tax WACC % Schedule 10, Line 17 6.83% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90%

16 Present Value of Free Cash Flow 3 Line 13 / (1 + Line 15)^Yr (94.1) 13.9 12.3 11.1 10.1 9.3 8.6 8.0 7.5 55.1

17 Total Present Value of Free Cash Flow Sum of Line 16 41.8

18

19 1- Earnings Before Interest, Taxes, Depreciation & Amortization (EBITDA)

20 2- Net of CIAC and removal costs (if applicable) and excludes capitalized overhead

21 3- 2011 present value calculates capital expenditure to occur at time zero

22 4- Evaluation period reflects the useful l ife of the assets, therefore it is assumed that the terminal value is zero



Submission Date:

August 18, 2011



16.2 What would the present value of cash flows on line 17 be if the terminal value

was $0?

Response:

Please refer to the responses to BCUC IRs 1.16.2.1 and 1.16.3.

If the terminal value were set to zero, the present value on Line 17 would be negative $4.7

thousand as shown below:

The present value is derived from discounting the terminal value by 10 years.

16.2.1 How would this impact FEI‟s analysis and conclusions?

Response:

Aside from deriving a negative present value over the estimated 10 year life of the asset, setting

terminal value to zero would not change the rate proposed.

16.3 What is the purpose of Schedule 12 and how does it support the Application?

Response:

Schedule 12 provides Discounted Cash Flow Analysis. It is the Company‟s practice to perform

such analysis for projects for which CPCNs are required and for new service offerings such as

Total Present Value of Free Cash Flow 41.775$

Less: Terminal Value (90.492)$

After Tax Weighted Average Cost of Capital 6.90%

Present Value (46.454)$

(4.679)$

Total Present Value of Free Cash Flow excl.

Present Value of the Terminal Value



Submission Date:

August 18, 2011



the one contemplated in this Application. The purpose of such analysis is to ensure that future

revenues less ongoing costs will be sufficient to cover all costs incurred at “Time 0”.

FEI has chosen to include Schedule 12 here as a matter of trying to be consistent with such

applications for CPCNs and new service offerings. The CNG equipment is required for fueling

the Company‟s own fleet of natural gas vehicles and the ancillary revenue helps to offset the

operating costs while providing service to the general public who would like to be able refuel

their vehicles at the Surrey Operations Center. In this instance, the schedule may not be as

applicable to this Application as it is to CPCNs.

Attachment 2.3

From: Sent: October 6, 2010 6:46 AM To: vito.triggiano'terasen.com Subject: CNG

Dear Sir

Yesterday the pump of CNG at Terasen was closed to the people outside de Company

When I bought my Ford E 250 CNG car I did it because the government wanted to have a clean environment, but since

then, every day the gas station with natural gas has been closed leaving to us not to many options.

My name is -- anadian citizen and I live in - - close to the Terasen offices, and I would

like to know when, if this is going to happened, the gas station will be open as before.

Yours truly

From: Sent: ’ceibØf2T Z.Tw I 4ö 1 -IVI To: Triggiano, Vito Subject: NGV FUELING

Customer is concerned about the closer of the Natural Gas station in Surrey, advised the customer of Gas Station in Cloverdale. Cx would like to be informed asap when the gas station re-opens to the public.

This message is for the designated recipient only and may contain privileged, proprietary, or otherwise private information. If you have received it in error, please notify the sender immediately and delete the original. Any other use of the email by you is prohibited.

Bevacgua, Ilva

From: Sent: March 11,201112:47 PM To: Triggiano, Vito Subject: FW: NGV Fueling Information

Jennifer Findlay

Fortis BC-Natural Gas Central Desk Team Lead Presto Customer Service

3401 Schmon PKWY Thorold

TEL - 1-888-244-2760 FAX -1-866-321-4159

Original Message-----

From: Customer Service [mailto:[email protected]] Sent: Friday, March 11, 20119:25 AM

To: CentralDesk.ESC

Subject: NGV Fueling Information

Hi,

Please see the email below regarding the NGV station in surrey.

If you know when it will be available, please email me directly at - - dnd I will respond to the customer via email.

Thanks,

From:

Sent: March 9, 201112:08 AM

To: Customer Service

Subject CNG FILL-UP ATTERASEN OFFICE IN SURREY--168ST /FRASER HWY.

Dear Sir, Please advise when CNG will be available to the public. Thanks and best regards.

This e-mail is the property of Fortis BC Inc. and/or its affiliates and may contain confidential material for the sole use of

the intended recipient(s). Any review, use, distribution or disclosure by others is strictly prohibited. Fortis BC Inc. and its

affiliates do not accept liability for any errors or omissions which arise as a result of e-mail transmission. If you are not

the intended recipient, please contact the sender immediately and delete all copies of the message including removal

from your hard drive. Thank you.

This message is for the designated recipient only and may contain privileged, proprietary, or otherwise private

information. If you have received it in error, please notify the sender immediately and delete the original. Any other

use of the email by you is prohibited.

Attachment 11.1

Financial Schedules CNG Cost of Service Surrey Operations BCUC IR 1.11.1 Schedule Cost of Service 1

O&M, Other Revenue & Property Tax 2

Income Tax Expense 3

Capital Cost Allowance 4

Rate Base 5

Capital Spending 6

Gross Plant In Service and Contributions in Aid of Construction 7

Accumulated Depreciation and Amortization 8 Deferred Charges 9

Present Value and Levelized Tariff Analysis 10 Rate Design 11 Cash Flow Analysis 12

FortisBC Energy Inc.CNG Cost of Service Surrey Operations, BCUC IR 1.11.1Updated for BCUC Order No. G-128-11

CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Revenue RequirementAppendix B - Schedule 1($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Revenue Requirement2 Cost of Energy Sold - - - - - - - - - - 3 Operation and Maintenance Schedule 2, Line 19 8.5 8.7 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 4 Property Taxes Schedule 2, Line 29 - - 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 5 Depreciation Expense Schedule 8, Line 17 + Line 38 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 6 Removal Cost Provision Schedule 8, Line 48 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 7 Amortization Expense Schedule 9, Line 19 - - - - - - - - - - 8 Other Revenue Schedule 2, Line 24 - - - - - - - - - - 9 Income Taxes Schedule 3, Line 20 1.7 (1.4) (0.3) 0.6 1.3 1.8 2.2 2.5 2.6 (0.5) 10 Earned Return Schedule 5, Line 27 7.6 7.1 6.1 5.2 4.3 3.4 2.4 1.5 0.6 0.0 1112 Annual Revenue Requirement Sum of Lines 2 through 10 29.4 26.0 26.7 26.8 26.7 26.5 26.1 25.7 25.1 21.7

Cost of Service 1 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: O&M, Other Revenue and Property TaxAppendix B - Schedule 2($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Gross O&M2 Labour Costs - - - - - - - - - - 34 Vehicle Costs - - - - - - - - - - 5 Employee Expenses - - - - - - - - - - 6 Materials & Supplies - - - - - - - - - - 7 Computer Costs - - - - - - - - - - 8 Fees & Administrations Costs - - - - - - - - - - 9 Contractor Costs 8.5 8.7 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10 Facilities - - - - - - - - - - 11 Recoveries & Revenue - - - - - - - - - - 1213 Non-Labour Costs 8.5 8.7 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 1415 Total Gross O&M Expenses 8.5 8.7 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 1617 (Less): Capitalized Overhead - - - - - - - - - - 18 Add (Less): Adjustment - - - - - - - - - - 19 Net O&M 8.5 8.7 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 2021 Other Revenue22 Environmental Credits - - - - - - - - - - 23 Miscellaneous - - - - - - - - - - 24 Total Other Revenue - - - - - - - - - - 2526 Property Taxes27 General, School and Other - - - - - - - - - - 28 1% in Lieu of General Municipal Tax1

Schedule 10, Line 29 x Line 37 x 1% - - 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 29 Total Property Taxes - - 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 3031 1- Calculation is based on the second preceeding year; ex., 2012 is based on 2010 revenue

O&M and Property Tax 2 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Income Tax ExpenseAppendix B - Schedule 3($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Income Tax Expense23 Earned Return Schedule 5, Line 27 7.6 7.1 6.1 5.2 4.3 3.4 2.4 1.5 0.6 0.0 4 Deduct: Interest on debt Schedule 5, Line 26 (3.9) (3.7) (3.2) (2.7) (2.2) (1.7) (1.3) (0.8) (0.3) (0.0) 5 Add (Deduct): Amortization Expense Schedule 9, Line 19 - - - - - - - - - - 6 Add: Depreciation Expense Schedule 8, Line 17 + Line 38 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 7 Add: Removal Provision Schedule 8, Line 48 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 8 Deduct: Overhead Capitalized Expensed for Tax Purposes - - - - - - - - - - 9 Deduct Removal Costs Schedule 8, Line 53 - - - - - - - - - (10.0) 10 Deduct: Capital Cost Allowance Schedule 4, Line 34 (10.7) (19.2) (15.4) (12.3) (9.8) (7.9) (6.3) (5.0) (4.0) (3.2) 11 Taxable Income After Tax Sum of Lines 3 through 10 4.6 (4.2) (0.8) 1.9 3.9 5.4 6.5 7.4 7.9 (1.5) 1213 Income Tax Rate 26.50% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00%14 1 - Current Income Tax Rate 1 - Line 13 73.50% 75.00% 75.00% 75.00% 75.00% 75.00% 75.00% 75.00% 75.00% 75.00%1516 Taxable Income Line 11 / Line 14 6.3 (5.5) (1.0) 2.5 5.2 7.2 8.7 9.8 10.6 (2.0) 1718 Total Income Tax Expense Line 16 x Line 13 1.7 (1.4) (0.3) 0.6 1.3 1.8 2.2 2.5 2.6 (0.5) 19 Adjustments - - - - - - - - - - 20 Net Tax Expense Line 18 + Line 19 1.7 (1.4) (0.3) 0.6 1.3 1.8 2.2 2.5 2.6 (0.5)

Income Tax 3 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Capital Cost AllowanceAppendix B - Schedule 4($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 CNG Dispensing Equipment- Class 8 @ 20%2 Opening Balance Preceeding Year, Line 5 - 96.1 76.9 61.5 49.2 39.4 31.5 25.2 20.2 16.1 3 Additions Schedule 7 , Line 12 - AFUDC 106.8 - - - - - - - - - 4 CCA [Line 2 + ( Line 3 x 1/2)] x CCA Rate (10.7) (19.2) (15.4) (12.3) (9.8) (7.9) (6.3) (5.0) (4.0) (3.2) 5 Closing Balance Sum of Lines 2 through 4 96.1 76.9 61.5 49.2 39.4 31.5 25.2 20.2 16.1 12.9 67 Foundation- Class 1.3 @ 6%8 Opening Balance Preceeding Year, Line 11 - - - - - - - - - - 9 Additions Schedule 7 , Line 13 - AFUDC - - - - - - - - - - 10 CCA [Line 8 + ( Line 9 x 1/2)] x CCA Rate - - - - - - - - - - 11 Closing Balance Sum of Lines 8 through 10 - - - - - - - - - - 1213 Pumps- Class 8 @ 20%14 Opening Balance Preceeding Year, Line 17 - - - - - - - - - - 15 Additions Schedule 7 , Line 14 - AFUDC - - - - - - - - - - 16 CCA [Line 14 + ( Line 15 x 1/2)] x CCA Rate - - - - - - - - - - 17 Closing Balance Sum of Lines 14 through 16 - - - - - - - - - - 1819 NG Dehydrator- Class 8 @ 20%20 Opening Balance Preceeding Year, Line 23 - - - - - - - - - - 21 Additions Schedule 7 , Line 15 - AFUDC - - - - - - - - - - 22 CCA [Line 20 + ( Line 21 x 1/2)] x CCA Rate - - - - - - - - - - 23 Closing Balance Sum of Lines 20 through 22 - - - - - - - - - - 2425 Capitalized Overhead- Class 0 @ 0%26 Opening Balance Preceeding Year, Line 29 - - - - - - - - - - 27 Additions Schedule 2 , Line 17 x 0 / 0 - - - - - - - - - - 28 CCA [Line 26 + ( Line 27 x 1/2)] x CCA Rate - - - - - - - - - - 29 Closing Balance Sum of Lines 26 through 28 - - - - - - - - - - 3031 Total CCA32 Opening Balance Preceeding Year, Line 35 - 96.1 76.9 61.5 49.2 39.4 31.5 25.2 20.2 16.1 33 Additions 1 106.8 - - - - - - - - - 34 CCA (10.7) (19.2) (15.4) (12.3) (9.8) (7.9) (6.3) (5.0) (4.0) (3.2) 35 Closing Balance Sum of Lines 32 through 34 96.1 76.9 61.5 49.2 39.4 31.5 25.2 20.2 16.1 12.9 36 1- Schedule 7 , Line 17 - Line 16, + Line 27 above - AFUDC

CCA 4 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Rate BaseAppendix B - Schedule 5($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Rate Base2 Gross Plant In Service- Beginning Schedule 7, Line 9 - 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 3 Gross Plant In Service- Ending Schedule 7, Line 33 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 45 Accumulated Depreciation- Beginning Schedule 8, Line 9 - (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) 6 Accumulated Depreciation- Ending Schedule 8, Line 33 (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) (106.8) 78 Contributions in Aid of Construction- Beginning Schedule 7, Line 37 - - - - - - - - - - 9 Contributions in Aid of Construction- Ending Schedule 7, Line 40 - - - - - - - - - - 1011 Negative Salvage - Beginning Schedule 8, Line 51 - (1.0) (2.0) (3.0) (4.0) (5.0) (6.0) (7.0) (8.0) (9.0) 12 Negative Salvage - Ending Schedule 8, Line 54 (1.0) (2.0) (3.0) (4.0) (5.0) (6.0) (7.0) (8.0) (9.0) - 1314 Accumulated Amortization- Beginning Schedule 8, Line 37 - - - - - - - - - - 15 Accumulated Amortization- Ending Schedule 8, Line 40 - - - - - - - - - - 1617 Net Plant in Service, Mid-Year Sum (Lines 2 through 15 )/2 47.6 89.3 77.6 65.9 54.2 42.6 30.9 19.2 7.5 0.8 1819 Adjustment to 13-month average 1 48.1 - - - - - - - - - 20 Unamortized Deferred Charges, Mid-Year Schedule 9, Line 22 - - - - - - - - - - 21 Cash Working Capital 2 (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) 22 Total Rate Base Sum of Lines 17 - 21 95.4 89.1 77.4 65.7 54.0 42.3 30.7 19.0 7.3 0.6 2324 Return on Rate Base25 Equity Return Line 22 x ROE x Equity % 3.6 3.4 2.9 2.5 2.1 1.6 1.2 0.7 0.3 0.0 26 Debt Component 3 3.9 3.7 3.2 2.7 2.2 1.7 1.3 0.8 0.3 0.0 27 Total Earned Return Line 25 + Line 26 7.6 7.1 6.1 5.2 4.3 3.4 2.4 1.5 0.6 0.0 28 Return on Rate Base % Line 27 / Line 22 7.93% 7.93% 7.93% 7.93% 7.93% 7.93% 7.93% 7.93% 7.93% 7.93%2930 1- [Schedule 7, (Line 17 + Line 38) + Schedule 8, (Line 17+ Line 38)] x (Days In-service/365-1/2)31 2- Schedule 7, Line 33 x TGI CWC/Closing GPIS %32 3- Line 22 x (LTD Rate x LTD% + STD Rate x STD %)

Rate Base 5 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Capital SpendingAppendix B - Schedule 6

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Capital Spending Prior to 20112 CNG Dispensing Equipment - 3 Foundation - 4 Pumps - 5 NG Dehydrator - 67 Total Capital Spending Prior to 2011 Sum of Lines 2 through 6 - 89 AFUDC Prior to 201110 CNG Dispensing Equipment - 11 Foundation - 12 Pumps - 13 NG Dehydrator - 1415 Total AFUDC Prior to 2011 Sum of Lines 10 through 14 - 1617 Capital Spending 2011 Onwards18 CNG Dispensing Equipment 106.8 - - - - - - - - - 19 Foundation - - - - - - - - - - 20 Pumps - - - - - - - - - - 21 NG Dehydrator - - - - - - - - - - 2223 Total Capital Spending 2011 Onwards Sum of Lines 18 through 22 106.8 - - - - - - - - - 2425 AFUDC 2011 Onwards26 CNG Dispensing Equipment - - - - - - - - - - 27 Foundation - - - - - - - - - - 28 Pumps - - - - - - - - - - 29 NG Dehydrator - - - - - - - - - - 3031 Total AFUDC 2011 Onwards Sum of Lines 26 through 30 - - - - - - - - - - 3233 Total Capital Spending1 Line 23 106.8 - - - - - - - - - 34 Total AFUDC Line 31 - - - - - - - - - - 35 Total Annual Capital Spending and AFUDC Line 33 + Line 34 106.8 - - - - - - - - - 3637 Contributions in Aid of Construction - - - - - - - - - - 38 Removal Costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 39 Net Annual Project Costs- Capital Line 35 + 37 + 38 106.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4041 Total Project Costs- Capital Spending and AFUDC Sum of Line 35 106.8 42 Total Net Project Costs- including CIAC & Removal Costs Sum of Line 39 106.9 4344 1- Excluding capitalized overhead; First year of analysis includes all prior year spending

Capital Spending 6 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Gross Plant in Service & Contributions in Aid of ConstructionAppendix B - Schedule 7($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Gross Plant in Service23 Gross Plant in Service, Beginning4 CNG Dispensing Equipment Preceeding Year, Line 28 - 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 5 Foundation Preceeding Year, Line 29 - - - - - - - - - - 6 Pumps Preceeding Year, Line 30 - - - - - - - - - - 7 NG Dehydrator Preceeding Year, Line 31 - - - - - - - - - - 8 Capitalized Overhead Preceeding Year, Line 32 - - - - - - - - - - 9 Total Gross Plant in Service, Beginning Sum of Lines 4 through 8 - 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 1011 Gross Plant in Service, Additions12 CNG Dispensing Equipment Schedule 6, Lines 2 + 10 + 18 + 26 106.8 - - - - - - - - - 13 Foundation Schedule 6, Lines 3 + 11 + 19 + 27 - - - - - - - - - - 14 Pumps Schedule 6, Lines 4 + 12 + 20 + 28 - - - - - - - - - - 15 NG Dehydrator Schedule 6, Lines 5 + 13 + 21 + 29 - - - - - - - - - - 16 Capitalized Overhead Schedule 2, Line 17 - - - - - - - - - - 17 Total Gross Plant in Service, Additions Sum of Lines 12 through 16 106.8 - - - - - - - - - 1819 Gross Plant in Service, Retirements20 CNG Dispensing Equipment - - - - - - - - - - 21 Foundation - - - - - - - - - - 22 Pumps - - - - - - - - - - 23 NG Dehydrator - - - - - - - - - - 24 Capitalized Overhead - - - - - - - - - - 25 Total Gross Plant in Service, Retirements Sum of Lines 20 through 24 - - - - - - - - - - 2627 Gross Plant in Service, Ending28 CNG Dispensing Equipment Line 4 + Line 12 + Line 20 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 29 Foundation Line 5 + Line 13 + Line 21 - - - - - - - - - - 30 Pumps Line 6 + Line 14 + Line 22 - - - - - - - - - - 31 NG Dehydrator Line 7 + Line 15 + Line 23 - - - - - - - - - - 32 Capitalized Overhead Line 8 + Line 16 + Line 24 - - - - - - - - - - 33 Total Gross Plant in Service, Ending Sum of Lines 28 through 32 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 106.8 343536 Contributions in Aid of Construction (CIAC)37 CIAC, Beginning - - - - - - - - - - 38 Additions - - - - - - - - - - 39 Retirements - - - - - - - - - - 40 CIAC, Ending Sum of Lines 37 through 39 - - - - - - - - - -

Gross Plant in Service 7 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Accumulated Depreciation & AmortizationAppendix B - Schedule 8($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Accumulated Depreciation23 Accumulated Depreciation, Beginning4 CNG Dispensing Equipment Preceeding Year, Line 28 - (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) 5 Foundation Preceeding Year, Line 29 - - - - - - - - - - 6 Pumps Preceeding Year, Line 30 - - - - - - - - - - 7 NG Dehydrator Preceeding Year, Line 31 - - - - - - - - - - 8 Capitalized Overhead Preceeding Year, Line 32 - - - - - - - - - - 9 Total Accumulated Depreciation, Beginning Sum of Lines 4 through 8 - (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) 1011 Accumulated Depreciation, Depreciation Expense1

12 CNG Dispensing Equipment@ 10% Schedule 7, Line 4 & Line 12 (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) 13 Foundation@ 5% Schedule 7, Line 5 & Line 13 - - - - - - - - - - 14 Pumps@ 10% Schedule 7, Line 6 & Line 14 - - - - - - - - - - 15 NG Dehydrator@ 10% Schedule 7, Line 7 & Line 15 - - - - - - - - - - 16 Capitalized Overhead@ 0% Schedule 7, Line 8 & Line 16 - - - - - - - - - - 17 Total Accumulated Depreciation, Depreciation ExpSum of Lines 12 through 16 (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) (10.7) 1819 Accumulated Depreciation, Retirements20 CNG Dispensing Equipment Schedule 7, Line 20 - - - - - - - - - - 21 Foundation Schedule 7, Line 21 - - - - - - - - - - 22 Pumps Schedule 7, Line 22 - - - - - - - - - - 23 NG Dehydrator Schedule 7, Line 23 - - - - - - - - - - 24 Capitalized Overhead Schedule 7, Line 24 - - - - - - - - - - 25 Total Accumulated Depreciation, Retirements Sum of Lines 20 through 24 - - - - - - - - - - 2627 Accumulated Depreciation, Ending28 CNG Dispensing Equipment Line 4 + Line 12 + Line 20 (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) (106.8)29 Foundation Line 5 + Line 13 + Line 21 - - - - - - - - - - 30 Pumps Line 6 + Line 14 + Line 22 - - - - - - - - - - 31 NG Dehydrator Line 7 + Line 15 + Line 23 - - - - - - - - - - 32 Capitalized Overhead Line 8 + Line 16 + Line 24 - - - - - - - - - - 33 Total Accumulated Depreciation, Ending Sum of Lines 28 through 32 (10.7) (21.4) (32.0) (42.7) (53.4) (64.1) (74.8) (85.4) (96.1) (106.8)343536 Accumulated Amortization of Contributions in Aid of Construction (CIAC)37 Accumulated Amortization CIAC, Beginning - - - - - - - - - - 38 Amortization 1 - - - - - - - - - - 39 Retirements - - - - - - - - - - 40 Accumulated Amortization CIAC, Ending Sum of Lines 37 through 39 - - - - - - - - - - 4142 Removal Provision43 CNG Dispensing Equipment (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) 44 Foundation - - - - - - - - - - 45 Pumps - - - - - - - - - - 46 NG Dehydrator - - - - - - - - - - 4748 Total Removal Provision Sum of Lines 43 through 47 (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) 4950 Negative Salvage Continuity - Foundation51 Opening Balance - (1.0) (2.0) (3.0) (4.0) (5.0) (6.0) (7.0) (8.0) (9.0) 52 Provision (Cr.) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) 53 Removal Costs - - - - - - - - - 10.0 54 Ending Balance (1.0) (2.0) (3.0) (4.0) (5.0) (6.0) (7.0) (8.0) (9.0) - 55565758 1- Depreciation & Amortization Expense calculation is based on opening balance + (additions x in-service days/365 if it is the in-service year for project/; otherwise, additions x 1/2)

Accumulated Depreciation 8 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Deferred Charges & Deficiency / Surplus [Tracker]Appendix B - Schedule 9($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 202012 Deficiency / Surplus [Tracker]3 Opening Balance Previous Year, Line 11 - - - - - - - - - - 4 Gross Addition Schedule 11, Line 15 - - - - - - - - - - 5 Tax - - - - - - - - - - 6 Net Addition Line 4 + Line 5 - - - - - - - - - - 7 AFUDC8 Equity (Line 3) x (Schedule 10, Lines 7 x 8) - - - - - - - - - - 9 Debt 1 - - - - - - - - - - 10 Interest Adjustment 2 - - - - - - - - - - 11 Closing Balance Sum of Lines 6 through 10 - - - - - - - - - - 1213 Deferred Charge- Rate Base14 Opening Balance Previous Year, Line 21 - - - - - - - - - - 15 Opening Balance, Adjustment - - - - - - - - - - 16 Gross Additions - - - - - - - - - - 17 Tax - - - - - - - - - - 18 Net Additions - - - - - - - - - - 19 Amortization Expense - - - - - - - - - - 20 Closing Balance Lines 14 + 18 + 19 - - - - - - - - - - 2122 Deferred Charge, Mid-Year (Line 14+ Line 15 + Line 20) / 2 - - - - - - - - - - 2324 1- (Line 3) x [Schedule 10 , (Lines 10 x 11+ Lines 12 x 13) x (1- Tax Rate)]25 2- Adjustment to net account to zero in final year; result of varying WACC rates throughout contract

Deferred Charges 9 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Present Value of Revenue Requirement & Levelized Tariff AnalysisAppendix B - Schedule 10($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 202012 Annual Revenue Requirement (Excluding Cost of Energy)($000s) Schedule 1, Line 13 29.4 26.0 26.7 26.8 26.7 26.5 26.1 25.7 25.1 21.7 45 Annual Discount Rate6 Equity Component 7 ROE % 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50%8 Equity Portion 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00%9 Debt Component10 Long Term Debt Rate 6.95% 6.95% 6.95% 6.95% 6.95% 6.95% 6.95% 6.95% 6.95% 6.95%11 Long Term Debt Portion 58.37% 58.37% 58.37% 58.37% 58.37% 58.37% 58.37% 58.37% 58.37% 58.37%12 Short Term Debt Rate 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%13 Short Term Debt Portion 1.63% 1.63% 1.63% 1.63% 1.63% 1.63% 1.63% 1.63% 1.63% 1.63%1415 Tax Rate 26.50% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00%16 Pre- Tax Weighted Average Cost of Capital (WACC)1 9.30% 9.19% 9.19% 9.19% 9.19% 9.19% 9.19% 9.19% 9.19% 9.19%17 After- Tax Weighted Average Cost of Capital (WACC)2 6.83% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90%1819 Present Value of Revenue Requirement 20 PV of Annual Revenue Requirement Line 2 / (1 + Line 17)^Yr 27.5 22.8 21.8 20.5 19.2 17.8 16.4 15.1 13.8 11.1 21 Total PV of Revenue Requirement Sum of Line 20 186.0 22 Total PV of Revenue Requirement, $000s/Yr Line 21 / Yrs 18.6 23 Total PV of Revenue Requirement over contract term 186.0 2425 PV of Annual Customers Line 3 / (1 + Line 17)^Yr 1 1 1 1 1 1 1 1 1 1 26 Total PV of Customers Sum of Line 24 7 2728 Tariff Analysis29 Annual Volume (TJ) 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 4.725 3031 Annual Volumetric Cost of Service ($/GJ) Line 2 / Line 29 6.224 5.508 5.645 5.672 5.657 5.608 5.533 5.435 5.321 4.586 3233 Levelized Tariff Analysis34 PV of Annual Volume (TJ) Line 29 / (1 + Line 17)^Yr 4.423 4.135 3.868 3.619 3.385 3.167 2.963 2.772 2.593 2.426 35 Total PV of Volume (TJ) Sum of Line 34 33.350 3637 Levelized Volumetric Delivery Rate ($/GJ) Line 21 / Line 35 5.576 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 3839 1- ( Line 7 x Line 8) / 1- Line 15 + ( Line 10 x Line 11 + Line 12 x Line 13)

Levelized Rate Calculation 10 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Contract Rate DesignAppendix B - Schedule 11($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Required Delivery Revenue ($) (discounted) - 10 years Schedule 10, Line 21 x 1000 185,956 2 Required Delivery Revenue ($) (discounted, contract term) - 10 yrs Schedule 10, Line 23 x 1000 185,956 3 Year 1 Contract Rate, Escalated at 0% Annually 1 26,346 4 Annual Contract Rate Escalation 0.00%56 Annual Discount Rate (After- Tax WACC) 6.83% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90%7 Annual Contract Rate 2 29,411 26,023 26,670 26,801 26,731 26,500 26,142 25,683 25,143 21,667 8 PV of Annual Contract Rate Line 7 / (1 + Line 6)^Yr 27,529 22,774 21,835 20,527 19,152 17,762 16,392 15,065 13,797 11,123 9 PV of Total Revenue Collected Sum of Line 8 185,956 1011 Monthly Rate, Escalated at 0% annually and then COS based beyond Contract Term 2,451 2,169 2,223 2,233 2,228 2,208 2,178 2,140 2,095 1,806 12 Annual Volumetric Contract Rate ($/GJ) 6.224 5.508 5.645 5.672 5.657 5.608 5.533 5.435 5.321 4.586 1314 Annual Cost of Service Schedule 1, Line 13 x 1000 29,411 26,023 26,670 26,801 26,731 26,500 26,142 25,683 25,143 21,667 15 Annual Difference (Cost of Service - Contract Rate) Line 14 - Line 7 - - - - - - - - - - 1617 Early Contract Termination3

18 Excluding PV of Future Earnings19 Deferral Account Repayment Schedule 9, Line 11 - - - - - - - - - - 20 Residual Asset Value Schedule 5, (Line 3 + Line 6) x 1000 96,120 85,440 74,760 64,080 53,400 42,720 32,040 21,360 10,680 (0) 21 Approximate Early Termination Fee ($) Line 19 + Line 20 96,120 85,440 74,760 64,080 53,400 42,720 32,040 21,360 10,680 (0) 2223 1- Line 2 /sum of [(1+inflation) ^ year / (1+WACC) ^ year] for each year of the contract24 2- Previous Year x (1+ 0%); in 2021+, Line 1425 3- The forecast early termination fee has been calculated on a year end basis. The actual fee would be determined at the time of contract termination and may be different than the amount shown on Line 2126

Rate Design 11 of 12


CNG Cost of Service Surrey Operations, BCUC IR 1.11.1: Discounted Cash Flow AnalysisAppendix B - Schedule 12($000's), unless otherwise stated

Line Particulars Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 20201 Cash Flow2 Add: Revenue Schedule 11, Line 7 29.4 26.0 26.7 26.8 26.7 26.5 26.1 25.7 25.1 21.7 3 Less: O&M, Property Tax Expense Schedule 10, - (Line 3 + Line 4 + Line 6) (8.5) (8.7) (9.1) (9.3) (9.5) (9.7) (9.8) (10.0) (10.2) (10.4)

4 EBITDA1 Line 2 + Line 3 20.9 17.4 17.6 17.5 17.3 16.8 16.3 15.6 14.9 11.2 5 Capital Expenditures2

Schedule 6, Line 39 (106.8) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) 6 Pre-Tax Cash Flow Line 4 + Line 5 (85.9) 17.3 17.6 17.5 17.3 16.8 16.3 15.6 14.9 11.2 7 Income Tax Expense Line 4 x (- Schedule 3, Line 13) (5.5) (4.3) (4.4) (4.4) (4.3) (4.2) (4.1) (3.9) (3.7) (2.8) 8 Overhead Capitalized Tax Shield Schedule 3, -Line 8 x Line 13 - - - - - - - - - - 9 CCA Tax Shield Schedule 3, -Line 10 x Line 13 2.8 4.8 3.8 3.1 2.5 2.0 1.6 1.3 1.0 0.8 10 Terminal Value of CCA Tax Shield 4 - - - - - - - - - 2.4 11 Terminal Value 4 - - - - - - - - - 59.3 1213 Free Cash Flow Line 6 + Line 7 (88.6) 17.8 17.0 16.2 15.4 14.6 13.8 13.0 12.2 70.9 1415 After Tax WACC % Schedule 10, Line 17 6.83% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90% 6.90%16 Present Value of Free Cash Flow 3 Line 13 / (1 + Line 15)^Yr (89.8) 15.6 13.9 12.4 11.0 9.8 8.6 7.6 6.7 36.4 17 Total Present Value of Free Cash Flow Sum of Line 16 32.3 1819 1- Earnings Before Interest, Taxes, Depreciation & Amortization (EBITDA)20 2- Net of CIAC and removal costs (if applicable) and excludes capitalized overhead21 3- 2011 present value calculates capital expenditure to occur at time zero22 4- Evaluation period reflects the useful life of the assets, therefore it is assumed that the terminal value is zero

Discounted Cash Flow Analysis 12 of 12

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