diane roy director, regulatory affairs - gas b-13 fortisbc ... · areas have been adjusted over...

August 8, 2012 British Columbia Utilities Commission Sixth Floor 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: FortisBC Alternative Energy Services Inc. ("FAES")

Application for a Certificate of Public Convenience and Necessity ("CPCN") for the Approval for the PCI Marine Gateway Thermal Energy Project and Approval of Rates for Thermal Energy Service to PCI Developments Inc. (the “Application”)

Response to the British Columbia Utilities Commission (“BCUC” or the “Commission”) Information Request (“IR”) No. 2

On May 25, 2012, FAES filed the Application as referenced above. In accordance with the British Columbia Utilities Commission Order No. G-94-12 setting out the revised Regulatory Timetable for review of the Application, FAES respectfully submits the attached response to BCUC IR No. 2.

If there are any questions regarding the attached, please contact the undersigned.

Yours very truly, on behalf of FORTISBC ALTERNATIVE ENERGY SERVICES INC. Original signed by: Shawn Hill

For: Diane Roy Attachment

cc (e-mail only): Registered Parties

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-13

mailto:[email protected]

http://www.fortisbc.com/

mailto:[email protected]

ylapierr

FAES PCI Marine Gateway

FortisBC Alternative Energy Services Inc. ("FAES" or the “Company”)

Application for a Certificate of Public Convenience and Necessity (“CPCN”) for the Approval for the PCI Marine Gateway Thermal Energy Project and Approval of Rates

for Thermal Energy Service to PCI Developments Inc. (the “Application”)

Submission Date:

August 8, 2012

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

Information Request (“IR”) No. 2 Page 1

1.0 Reference: Project Description

Exhibit B-1, Application, Section 4.6.2, p. 37;

Corix 2010 CPCN UniverCity, Exhibit B-1, p. 47

In the recent UniverCity proceeding, Corix stated that: “The distribution piping system

will be installed mostly in SFU right of ways and Corix is currently working with SFU on

this arrangement.”

In Section 4.6 of the Application dealing with Contracts, along with the sections on the

Infrastructure and Service Agreements, FAES included Section 4.6.2 STATUTORY

RIGHT OF WAY:

“ • registers the Energy System on development land.”

1.1 Please confirm that this means that no separate agreement was required for

securing rights of way, as the energy system assets are confined to the specific

PCI Marine Gateway property development. If not, please clarify the meaning of

this section.

Response:

FAES confirms that all energy system assets are confined to the specific PCI Marine Gateway

property development and that no separate agreement was required for securing rights of way.




Submission Date:

August 8, 2012



2.0 Reference: GHG Emissions Savings of Closed Loop System Versus BAU

Exhibit B-4, BCUC 1.7.2

FAES provided the table below in response to BCUC 1.7.2.

2.1 In the table above, for the PCI (closed loop) option, please confirm that the

values entered for the “Building Electric Resistance” energy input should have

instead been entered for the “Building Heat Pump/Chiller Elec.” energy input. If

not, please explain why electric resistance energy input is used in the PCI Closed

Loop System.

Response:

Confirmed. The values entered for the “Building Electric Resistance” energy input should have

instead been entered for the “Building Heat Pump/Chiller Elec.” energy input for the closed loop

system.1

1 DEC’s Study #4, Appendix B: PCI Capital Cost, Maintenance Cost and Energy Estimate Summary




Submission Date:

August 8, 2012



3.0 Reference: Load Analysis and Energy Demand Forecast

Exhibit B-1, Section 3.2, p. 10; Exhibit B-4, BCUC 1.8.1

On page 10 of the Application, FAES states that “The PCI Marine Gateway Project

encompasses approximately 81,000 m² of developed floor area, as per the development

permit application of September 2011. …The total residential floor area is 30,783 m².

Commercial-Retail Units including theatres are located on the lower levels of the three

towers, covering 46,877 m².

… Details of the design are included in the schematic in Appendix I and the energy data

are included in the DEC TECH Memo #3 in Appendix H dated March 12, 2012. The

annual energy figures were based on the specific size and design of the three building

structures and type of use among the residential, office and retail structures.”

In BCUC 1.8.1, FAES provided revised floor area information as follows:

3.1 Please explain which circumstances prompted the significant changes in total

developed floor area, CRU floor area and Office floor area between the date of

the development permit application in September 2011 and the date this

Application was submitted to the BCUC in May 2012.

Response:

The table provided in the response to BCUC IR 1.8.1 excluded common area and was based on

information provided by the developer in early 2012. With common area included and

considering the adjustments made to the Office and Podium areas, the final total floor area is

approximately 81,000 m2 which is consistent with and not significantly different than the filed

information.

The table below summarizes all information available to FAES regarding the floor area of

various components of the PCI Marine Gateway development with corresponding reporting

dates. Areas have been adjusted over time as the design of Marine Gateway has progressed,

and in some cases areas have seen a slight reduction due to requests from the City of

Vancouver to improve public spaces, as well as requests from the client to improve building




Submission Date:

August 8, 2012



efficiency while maximizing leasable floor area. In general, it is FAES’ understanding that there

has been no significant change in total developed floor area, CRU floor area and Office floor

area between the date of the development permit application and the date this Application was

submitted to the BCUC.

As further clarification, the statement made in the Application and reproduced above in the

BCUC introduction to this question “The annual energy figures were based on the specific size

and design of the three building structures and type of use among the residential, office and

retail structures.” is true, but that the annual energy figures for the building have been provided

to FAES as energy figures not as energy per unit floor area. DEC Tech Memo #3 was not

based on any specific total developed building floor area. TECH Memo #3 was based on

energy demands that were provided to DEC by the building mechanical consultant (MCW).

USE Apr. 30, 2010

1 Aug. 20, 2010

2 July 19, 2011

3 Jan. 16, 2012

4 Feb. 8, 2012

5 May 24, 2012

6 July 27, 2012

7

Residential

North 20,615 29,822 30,822 30,245 27,541 30,473 18,284

South Incl. Incl. Incl. Incl. Incl. Incl. 12,189

Rental 11,353 2,415 Incl. Incl. 2,892 Incl. Incl.

Sub-total 31,968 32,237 30,822 30,245 30,433 30,473 30,473

Podium

CRU's 26,756 26,199 25,673 22,975 21,306 17,621 17,635

Theatre Incl. Incl. Incl. Incl. Incl. 5,531 5,530

Sub-total 26,756 26,199 25,673 22,975 21,306 23,151 23,165

Office 21,015 22,390 24,975 23,440 22,485 24,095 24,095

Common Area Incl. Incl. Incl. Incl. Not

Included Not

Included 3,346

Total 83,999 83,056 81,470 80,440 74,222 77,719 81,079

1 http://vancouver.ca/commsvcs/planning/rezoning/applications/8430cambie/documents/stats.pdf

2 http://vancouver.ca/commsvcs/planning/rezoning/applications/8430cambie/documents/stats3.pdf

3 http://vancouver.ca/ctyclerk/cclerk/20110628/documents/p3.pdf

Appendix H -page1 of 1

http://vancouver.ca/commsvcs/planning/rezoning/applications/8430cambie/documents/stats.pdf

http://vancouver.ca/commsvcs/planning/rezoning/applications/8430cambie/documents/stats3.pdf

http://vancouver.ca/ctyclerk/cclerk/20110628/documents/p3.pdf




Submission Date:

August 8, 2012



4 Perkins+Will email of Jan. 16,2012

5 PCI email of Feb. 8, 2012

6 Development Permit of May 24, 2012

7 Perkins+Will email of July 27, 2012

3.1.1 Please provide a similar breakdown of floor area (m2) by use for each of

the three buildings in the PCI Development.

Response:

Please refer to the response to BCUC IR 2.3.1.

3.2 Please confirm that the DEC TECH Memo #3, which was completed on March

21, 2012, is based on total developed floor area of 81,000 m2, as per the

development permit application of September 2011, that included 30,783 m2 of

residential floor and 46,877 m2 of CRU floor.

Response:

Not confirmed. DEC Tech Memo #3 was not based on any specific PCI Marine Gateway total

developed building floor area. TECH Memo #3 was based on energy demands that were

provided to DEC by the building mechanical consultant (MCW). MCW sent DEC the hourly

central plant loads on November 24, 2011.

For clarity, please also note that 46,877 m2 as mentioned above is the floor area for the

commercial component including Office Tower, theatres and CRU’s.

3.2.1 If so, and given that the annual energy figures contained in Memo #3

were based on the specific size and design of the three building

structures and type of use among residential, office and retail structures,

please revise the data contained in Table 3-1: Forecast Annual Energy

Load; Table 3-2: Forecast Peak Energy Load (Heating); Table 3-3:

Forecast Peak Energy Load (Cooling); Table 3-9: Summary of Energy




Submission Date:

August 8, 2012



Sourcing; and Table 3-10: GHG Emissions, using the revised floor area

information contained in BCUC 1.8.1.

Response:

Please refer to BCUC IR 2.3.2.

3.2.2 Alternatively, if the DEC TECH Memo #3’s energy analysis is based on

the floor area data (total and by use) as provided by FAES in BCUC

1.8.1, please indicate where this information can be verified in the

Application material or how it can be verified from the material provided in

the Application.

Response:

Please refer to BCUC IR 2.3.2.

In BCUC 1.8.2, FAES was asked to provide the Energy Use Intensity (EUI) factors by

building archetype used to forecast the annual thermal energy load for the Marine

Gateway Project. In response, FAES states that: “The table below is generated from the

output of simulation programs based on the most recent energy modelling completed by

DEC and its consultants, (which includes the modified glazing area, glazing type, etc.)

divided by the floor space as submitted for the development permit.” The table is copied

below for ease of reference.

3.3 From the table above, please confirm that the total EUI by use can be

summarized as in the table below. If not, please explain why not.




Submission Date:

August 8, 2012



Thermal

Energy

(kWh/m2)

Residential 110.3

Commercial-Retail

Units

268.8

Office 55.5

Response:

Confirmed.

3.4 Please explain the wide range of EUI by use and what causes the CRU EUI to be

significantly higher than the other two.

Response:

EUI's vary significantly between different building types therefore the wide range of EUI

presented by use in the table above is not unusual. The CRU EUI is significantly higher than the

other two archetype EUI's because the CRU space includes a grocery store, theatre and

several restaurants which all require large quantities of make-up air.

In BCUC 1.26.1, FAES states “Although FAES is confident in the demand forecast

included in the PCI cost of service analysis, the actual demand may vary from the

current forecast as the development matures.”

3.5 On what basis can FAES affirm that it is confident in the demand forecast

included in the PCI cost of service analysis?

Response:

Designing and building energy systems to meet the demands of developments is common

practice for the consultants and contractors engaged in projects like PCI Marine Gateway. The

forecast of annual energy consumption was arrived at based on simulation tools used by a




Submission Date:

August 8, 2012



subject matter expert (base building mechanical consultant) with the latest design parameters

as provided by the other Development consultants at the time of modeling.

The base building mechanical consultant retained by PCI is MCW Consultants Ltd. (“MCW”).

MCW was founded in 1964 and is an award winning national consultant with over 40 years of

Consulting Engineering experience. It is a team of Mechanical and Electrical Professional

Consulting Engineers providing services to Institutional, Educational, Industrial, Commercial and

Residential clients both nationally and internationally.

For this reason FAES is confident in the demand forecast. Please also see response to BCUC

IR 2.10.2 for a discussion on the risk of annual demand.

3.6 Does FAES agree that long-term system maintenance and operation, building

performance and occupants’ behaviour are factors that can significantly impact

the actual energy use compared to the forecast energy use? If so, by how much

could these factors impact the actual energy use? If not, why not?

Response:

FAES agrees that long-term system maintenance and operation, building performance and

occupants’ behaviour are factors that may impact actual energy use as compared to forecast

energy use. However, FAES believes that these factors will not significantly impact the actual

energy use at the PCI Marine Gateway development due to the following:

The building has been designed by an experienced, reputable firm, Perkins + Will,;

therefore, it is anticipated that the actual building envelop will perform to

specifications. The corresponding design of the energy system will be done by

experienced consultants and the system will be built in accordance with the design

specifications.

Heating/cooling system operation is within the scope and control of FAES and it is

FAES’ experience that through ensuring design-compliant installation and

commissioning, and through ongoing monitoring and maintenance programs, FAES

can ensure the system will perform to specifications.

Occupants’ behavior may include modifying summer/winter setpoints; however the

impact of this behavior is minimal since the largest energy usage is associated with

the make-up air quantity, which is outside the control of occupants.




Submission Date:

August 8, 2012



3.7 Did FAES perform a sensitivity analysis of a higher/lower annual energy use due

to these multiple energy use uncertainties on the size of the system, the total

costs (capital and O&M costs), the energy rate and the GHG emission savings?

If so, please provide the results of such analysis.

Response:

Yes, FAES performed various sensitivity analyses. In the original Monte Carlo analysis included

in the Application, both capital and load sensitivity analyses were performed. The full report was

filed in the Application as Appendix U and the below assumptions can be found on pg 39 of the

report and are reproduced here for ease of reference.

The chart below shows the distribution, mean and standard deviations regarding the Capital and

Load sensitivity that FAES has used in the Monte Carlo analysis.

O&M sensitivity was not conducted as part of the original Monte Carlo analysis in the

Application. Therefore, FAES updated the Monte Carlo analysis during preparation of this

response to include O&M sensitivity while keeping the Capital and Load sensitivity assumptions

the same as in the Application. FAES has run the updated Monte Carlo analysis using the




Submission Date:

August 8, 2012



revised Cost of Service model as per Commission’s request to update capitalized overhead as

well as debt rate in BCUC IR1.39.2. The O&M sensitivity assumption is as follows:

Assumption: O&M Sensitivity

Normal distribution with parameters:

Mean 1.00

Std. Dev. 0.05

The updated results are as follow:

Percentiles

Thermal Energy Rate

($/kWh)

0% 0.135$

10% 0.146$

20% 0.148$

30% 0.149$

40% 0.151$

50% 0.152$

60% 0.153$

70% 0.154$

80% 0.155$

90% 0.157$

100% 0.170$

Please refer to Attachment 3.7 for the full updated Monte Carlo report.

The rates are similar in both the original and updated Monte Carlo analysis and therefore no

major concerns are raised with changes in Capital, O&M and Loads.

With respect to GHG emission savings, the annual GHG emissions as per Table 7 and Table 8

in the DEC Tech Memo # 3 were determined by the following components:

Heating from In-building simultaneous cooling

Heating from In-building refrigeration

Heating from GSHX




Submission Date:

August 8, 2012



Heating from boilers

The annual GHG-emission sensitivity analysis performed herein is based on modifying the total

(heating and cooling) building energy consumption as per Table 7. The annual heating energy is

30,744 GJ and the annual cooling energy is 15,178 GJ, with a total of 45,299 GJ. The

corresponding GHG-emission is 507 and 81 respectively, with a total of 588 tCO2e (DEC Tech

Memo #3 shows 586 GJ in Table 9).

The following Chart No. 1 shows how GHG emission in tCO2e will vary with a reduction in

building energy consumption from the projected 588 tCO2e, while Chart No. 2 shows how the

change relates to the original 588 tCO2e.

Chart No. 1




Submission Date:

August 8, 2012



Chart No. 2

If the building energy consumption reduces to 80%, the GHG emission is expected to decrease

to 119 tCO2e (20% of the projected emission), everything else being held constant. Similarly

when the building energy consumption increases to 120%, the GHG emission is expected to

increase to 1,058 tCO2e (180% of the projected emission), everything else being held constant.

It is important to note that the results presented above assume the increase/decrease in thermal

energy consumption occurs during peak heating season, which represented the best and worst

case scenario. If the increase/decrease in thermal energy consumption occurs in off-peak

season, the increase in GHG emissions will not be as high and the reduction in GHG emissions

will not be as low. Therefore, FAES believes that on average, the 60% GHG emissions

reductions will be met as per Table 3-10 in the Application.

3.7.1 If not, please provide a sensitivity analysis of an annual thermal energy

use that would be 10 percent higher than forecasted or 10 percent lower.

Response:

Please see the response to BCUC IR 2.3.7.




Submission Date:

August 8, 2012



3.8 Please discuss the potential consequences if the total actual annual energy use

turns out to be significantly higher or lower than forecasted. What steps would

FAES take to remedy each situation?

Response:

FAES believes there are two components to answering this question:

1. On a probabilistic basis, energy use variations are not expected to be significant in terms

of rate impact over the long term.

2. In the unlikely case of extreme variations in actual energy use:

a. If demand is much higher, initially, this would translate to higher use of gas and

potentially higher use of electricity (i.e. a higher ratio of variable to fixed costs). If

sustained, and if outside of the GHG reduction benchmark, FAES would look to

adding geo-exchange capacity using retrofit technology and based on FAES

experience that geo-exchange solutions are scalable, FAES expects that rate

impacts would be neutral.

b. If demand is much lower, the geo-exchange system and other equipment would

be underutilized which would translate to higher rates. If sustained, in this

instance, FAES would look to adding offsite customers to share in the use of the

energy system. As interconnection and growth of DES is a City of Vancouver

objective and as the system is designed to allow interconnection, such a plan for

achieving greater utilization would be reasonable.

3.8.1 In particular, if the total actual energy use is significantly higher than

forecast, how would the City of Vancouver’s rezoning conditions of

meeting at least 70 percent of the thermal energy requirements with the

geo-exchange system and reducing GHG emissions by at least 50

percent still be met?

Response:

The City of Vancouver requirement is that 70% of the annual space heating & DHW energy are

to be provided by renewable energy sources. The PCI Marine Gateway energy system is an

integrated system providing heating and cooling and the geoexchange system’s ability to deliver




Submission Date:

August 8, 2012



annual heating and cooling is as much a function of the heating and cooling energy balance on

the field as it is the peak capacity of one or the other. Therefore, if the annual heating and

cooling energy use increases proportionally, the geo field will be able to meet an increased

energy requirement. If the increase is not proportional (with the heating increase being

dominant) and in the very unlikely event the result is that the 70% cannot be achieved with the

base system, FAES also has the ability to use Renewable Natural Gas in the boilers. This

provides additional renewable energy capacity while maintaining reduced GHG emissions.




Submission Date:

August 8, 2012



4.0 Reference: Refrigeration Cooling Energy


FAES states that “The difference between the tables arises because FAES does not

treat refrigeration cooling energy generated heat rejected from the refrigeration units as

billable thermal energy. This is further explained on pages 10 to 11 in 4th Study (Tech

Memo) dated March 21, 2012 (“Study #4”) attached in Appendix H of the Application.”

On page 10 of the Tech Memo dated March 21, 2012 (Appendix H of the Application), it

is noted: “It is understood that Fortis would not collect revenue on the refrigeration

cooling energy.”

4.1 Please clarify what is meant exactly by “refrigeration cooling energy generated

heat rejected from the refrigeration units” and why FAES does not treat it as

billable thermal energy.

Response:

The refrigeration process generates cooling by extracting heat from the air. In some cases, the

extracted heat is then rejected as waste heat to the atmosphere. The refrigeration units referred

to in Exhibit B-4, BCUC IR 1.14.1 are grocery store coolers, fridges and freezers that are used

to store perishable food items. Absent another use for the heat, heat rejection equipment such

as dry coolers would have to be installed and maintained by the grocery store to reject the

waste heat from these units.

At PCI Marine Gateway, FAES will be using the waste heat from the refrigeration units to

supplement energy in the main sharing loop, enabling the other heat production infrastructure to

be reduced. Using waste heat from the refrigeration process to supplement heating in the main

energy sharing loop will eliminate the need and cost of installation and maintenance of extra

heat rejection equipment by the store. Since the waste heat provides a benefit to the thermal

energy system and to the grocery store, FAES does not bill the provider of waste heat nor does

it pay for the energy to generate it.




Submission Date:

August 8, 2012



5.0 Reference: System Design and Specification

Exhibit B-6, CEC IR 1.15.1

“Heating and cooling losses are minimized through sufficient insulation around pipes and

quality of workmanship. ASHRAE Standard 90.1-1977 specifies the minimum required

insulation for the expected operating temperatures. Quality workmanship is achieved

through the selection of trained contractors in the field” (Exhibit B-6, p. 28)

5.1 Please confirm that FAES will specify the minimum required insulation thickness

for the operating temperatures. Please also provide the insulation thickness that

the ASHRAE Standard specifies for the ambient, chilled and hot water loops

based on their operating temperatures.

Response:

The energy conservation standard ASHRAE 90.1-1977 noted in response to Exhibit B-6, CEC

IR 1.15.1 should have been noted as the most recent version, ASHRAE 90.1-2007.

Piping insulation thickness within the mechanical room will be specified by FAES’ consultant

during detailed design. For details related to minimum thickness associated with each of the

operating temperatures, please refer to Attachment 5.1.




Submission Date:

August 8, 2012



6.0 Reference: Operating and Maintenance Costs


“FAES will develop a verification and testing program for thermal meters based on

consultation with meter manufacturers and practices adopted by other utilities delivering

thermal energy”

6.1 Has FAES included costs for a meter verification and testing program in its

forecast O&M schedules? If so, please indicate where and what amounts.

Response:

Explicit costs for meter verification and testing programs have not been developed, but the total

forecast O&M is intended to cover these costs. Actual O&M will be recorded when it occurs.




Submission Date:

August 8, 2012



7.0 Reference: Rate Design


In FAES’s response, point #2, FAES indicates that “For example, customers that do not

require only heating should have lower load factors than customers that require heating

and cooling. Lower load factors generally produce higher rates, however, in this

instance, the existence of the heating load, at times when other customers require

cooling, provides a benefit in terms of efficiency translating into both lower capital and

operating costs for cooling customers than would otherwise be the case.”

7.1 Did FAES mean to say “customers that require only heating should have lower

load factors than customers that require heating and cooling” instead of

“customers that do not require only heating should have lower load factors than

customers that require heating and cooling”?

Response:

Correct. Starting with the third sentence in point #2, FAES’ response to BCUC 1.19.3 should

read “For example, customers that require only heating should have lower load factors than

customers that require heating and cooling. Lower load factors generally produce higher rates,

however, in this instance, the existence of the heating load, at times when other customers

require cooling, provides a benefit in terms of efficiency translating into both lower capital and

operating costs for cooling customers than would otherwise be the case.”

7.1.1 If so, did FAES mean to explain that residential customers should have

lower load factors than office or CRU customers because they require

only heating and because of that, residential customers should face

higher rates?

Response:

Yes. All things being equal (such as capital, O&M, and fuel consumptions), residential

customers who have lower load factors than office or CRU customers, should face higher rates.

However, in the case of this Project, the existence of the heating load, at times when other

customers require cooling, provides a benefit in terms of efficiency translating into both lower

capital and operating costs for cooling customers that would otherwise be the case. FAES’

response to BCUC IR 1.19.3 explained the relationship between various users of the system

(i.e. heating only and heating/cooling) and how the system overall has improved efficiency when

it serves a combination of heating only and heating/cooling customers, and those loads coincide




Submission Date:

August 8, 2012



as they do in the case of the PCI Marine Gateway project. Since both heating and

heating/cooling customers contribute to the overall efficiency of the system and for the reasons

described previously by FAES, a single rate for all customers is reasonable and appropriate for

the PCI Marine Gateway project. For further explanation, please refer to the response to BCUC

IR 2.7.2.

7.1.2 Does it follow that having an integrated energy system results in lower

rates for heating-only customers (i.e., residential customers) because

they benefit from the renewable waste heat energy source generated by

the refrigerated coolers?

Response:

Yes, the integrated energy system results in lower rates because the system is more efficient

than a non-integrated system and because it reduces the size and cost of certain equipment.

For further explanation, please refer to the response to BCUC IR 2.7.2.

7.2 In FAES’ response, point #2, FAES provides an example of how the system

provides benefits to cooling customers. What are examples of benefits, if any,

that accrue to non-cooling customers (i.e., residential customers)?

Response:

Please refer to the correction in BCUC IR 2.7.1 in which the above sentence is changed to read

“… customers that do not require only heating should have lower load factors than customers

that require heating and cooling”.

As discussed in the response to BCUC IR 2.7.1.1, customers who have lower load factors, for

example, non-cooling residential customers, generally produce higher rates. In the case of PCI

Marine Gateway, residential customers benefit from the integrated nature of the system that

enables use of waste heat from commercial customers. This reduces both the energy cost and

the GHG impacts for the residential customer. The heating requirements of the residential in

combination with the cooling requirements of non-residential balance each other to produce a

more efficient solution overall.

Taking all the reasons above into consideration, the residential customers benefit from an

integrated system that provides both heating and cooling. Therefore, the single rate remains




Submission Date:

August 8, 2012



just and reasonable despite the absence of cooling demand and infrastructure for residential

customers.




Submission Date:

August 8, 2012



8.0 Reference: Development Costs


8.1 Please provide a further breakdown of the internal development costs of

$212,691 and the external development costs of $479,495.

Response:

A further breakdown of the forecast internal development costs of $212,691 and the external

development costs of $479,495 is provided below.

Internal Costs

Labour/Salaries 209,145$

Travel & Admin 3,546

Sub-total 212,691$

External Costs

Feasibility Study 177,624$

Pre-Design & Class 3 Estimates 260,000$

Legal Fees 41,871

Sub-total 479,495$

Total Costs 692,186$




Submission Date:

August 8, 2012



9.0 Reference: Cost of Service and Rate Design

Exhibit B-4, BCUC IR 1.26.1-2, pp. 56-57

“FAES/FEI did not consider any other rate model for the Marine Gateway Project as we

believe the annually reviewed cost of service rate is appropriate.”

9.1 Has FAES discussed any alternative rate models with the customer and/or the

developer?

Response:

FAES did not propose any alternative rate models to the developer or the customer, nor did they

request any alternative rate models.

PCI has also indicated in its support letter attached as Appendix Z that

“PCI is confident that the public utility service that FAES will provide, including cost of

service based rates subject to BCUC regulation, is the best fit for both PCI as the

developer and ultimately residents and tenants for three reasons…”

Please see Appendix Z for the discussion of these reasons.

Please see the responses to BCUC IRs 1.26.1 and 1.26.2 for further discussion of the benefits

of the rate design adopted for this service.

9.1.1 If not, why not?

Response:

Given that the rate design as proposed was accepted by the customer and we believe it creates

fair and reasonable rates for customers, no further rate design proposals were considered. As

PCI has indicated in its letter of support for the Project, attached as Appendix Z to the

Application, PCI supports “the public utility service that FAES will provide, including cost of

service based rates subject to BCUC regulation…” In general, FAES believes that moving

forward, the cost of service approach will produce efficiencies in negotiations with customers,

and over time as the business models become more transparent the approvals and

administration of the contracts with the BCUC will become more streamlined.




Submission Date:

August 8, 2012



9.2 Where else in North America is traditional “cost of service rate-based

methodology” used for thermal energy systems of this scale and type? Please

provide examples, including the installed capacity in MW of the relevant systems.

Response:

FAES has not conducted a study to assess rate design methodologies used for all thermal

energy systems throughout North America, and therefore, is unable to provide the requested

information from the perspective of thermal energy systems.

9.3 What industries or types of business have rate-base?

Response:

FAES/FEI understands the question to be, “In general, which industries or types of businesses

have a rate-base?”

FAES/FEI are aware that regulated industries/businesses such as, but not limited to, utilities,

telecommunications companies and cable companies have rate bases. In BC thermal energy

service providers who provide thermal energy through (for example) geoexchange and district

energy systems are regulated as public utility service providers.

9.4 Is FEU/FAES aware of any other thermal projects of this nature which have a

regulatory asset base, outside of BC? If so, please provide examples and

accompanying descriptions of the systems.

Response:

FAES is not aware of any other thermal projects of this nature which have a regulatory asset

base outside of BC. This is because other jurisdictions in Canada do not regulate thermal

energy services. Please refer to the response to BCUC IR 2.9.2.




Submission Date:

August 8, 2012



9.5 In the absence of tariff regulation in other North American jurisdictions, what rate-

setting mechanisms are used for developments of a similar scale and nature?

Response:

FAES has not conducted a study of non-regulated rate setting mechanisms in other North

American jurisdictions. However, FAES notes that in the absence of regulation, suppliers and

customers are free to negotiate rates in the manner they see fit.




Submission Date:

August 8, 2012




Exhibit B-4, BCUC IR 1.26.1-2, pp. 56-57; Exhibit A2-1; Paul Joskow,

Vertical Integration and Long-Term Contracts: The Case of Coal-

Burning Electric Generating Plants, Journal of Law, Economics and

Organization Vol 1 No. 1, pp. 60-64, Fall 1985;

http://classwebs.spea.indiana.edu/kenricha/Oxford/Archives/Course

s%202010/Governance%202010/Articles/Joskow%20-

%20Vertical%20Integration.pdf

Exhibit A2-2, OECD-IEA, 2004, Improving District Heating Policy in

Transition Economies, p. 122 ;

www.iea.org/textbase/nppdf/free/archives/cold.pdf

In response to IR 26.1, FAES cites the flow through of cost of service changes and

annual demand changes as the two main benefits for selecting the annually reviewed

cost of service rate over a formula-based rate which is fixed for a longer period of time.

“Both approaches have merit, however, FAES has moved toward the annual rate

review process for the following reasons:

1. Flow through of Cost of Service Changes

An annual setting of rates accounts for changes in the cost of service that may

be uncontrollable or difficult to forecast, particularly changes in commodity costs,

while a fixed rate may not have such flexibility. As fluctuations in commodity

costs are uncontrollable and can be significant, it is important to have the ability

to reset rates to reflect revised market conditions. In the case of PCI, the variable

thermal energy rate reflects the cost of delivery as well as commodity costs, and

as such FAES considered the annual rate review process to be an appropriate

mechanism to pass on cost changes in this regard. Further, changes in the

Commission approved ROE, tax rates, and accounting policies may occur from

time to time and can be included, in a timely manner, in an annual rate review

process, as compared to a fixed rate which might not flow through changes of

this nature.

2. Flow through of Annual Demand Changes

An annual rate review accounts for changes in annual demand or throughput,

while a fixed rate may not. Generally, fixed or levelized rates work well in

circumstances where there is a minimum take or pay arrangement or where the

annual demand is well established. Although FAES is confident in the demand

forecast included in the PCI cost of service analysis, the actual demand may vary

http://classwebs.spea.indiana.edu/kenricha/Oxford/Archives/Courses%202010/Governance%202010/Articles/Joskow%20-%20Vertical%20Integration.pdf



www.iea.org/textbase/nppdf/free/archives/cold.pdf




Submission Date:

August 8, 2012



from the current forecast as the development matures. As such, FAES

considered the annual rate setting process to be an appropriate mechanism to

pass on impacts to the thermal energy rate for changes in demand over time.”

While economic regulation of district energy systems was common in Eastern Europe,

there has been a shift towards simplifying “heat tariff regulation”:

“In Estonia, for instance, many companies are introducing index-based formulas

for tariff calculation that allow heat tariffs to be adjusted to fuel price fluctuations

and other changes in variable costs. …

Well-designed pricing formulas should be attractive for both district heating

companies and regulators because they are simpler to manage. An index based

tariff is negotiated and approved only once and set for a relatively long period.

The price may be adjusted under

specified conditions such as relevant external changes (to fuel costs or inflation,

for example) over agreed periods of time.” (IEA, p. 122)

A journal article by Joskow discusses some ways of structuring contracts for

“transaction-specific sunk investments”, of which the PCI-Marine-Gateway TES is a

good example:

“Establishing a pricing formula to govern compensation arrangements for

contracts lasting many years that provide incentives to both the buyer and the

seller to perform as promised without leading to serious inefficiencies itself is not

an easy task. Dealing with the kinds of ex post performance problems addressed

in the transactions cost literature and providing mechanisms for smooth

adjustments in obligations as various contingencies arise is complicated by the

uncertainty governing future costs and market conditions that are inherent in this

relationship. Input prices are likely to change over time, technological

developments may reduce the current and expected future costs of mining from

similar reserves, labor agreements may change work rules and increase or

decrease productivity, new government regulations may increase mining costs,

unanticipated mining problems may emerge, new property and severance taxes

may be applied, and so on. General changes in supply and demand are likely to

lead to changes in the value of the coal at the mine-mouth operation both from

the buyer's perspective and the seller's perspective.

The compensation arrangements should reflect two interrelated objectives. First,

they should be structured to eliminate the incentives either party has to behave

opportunistically. Second, the pricing provisions should be structured in such a




Submission Date:

August 8, 2012



way that efficient demand and supply decisions are made by both the buyer and

the seller. It would, for example, be undesirable if a pricing formula gave one or

both parties the incentive to reach their purchase and supply promises if this

would increase the social costs of supplying coal or producing electricity. Let us

examine four different methods for establishing prices over time.

….

4. Indexed contracts: The fourth and final type of contract that I consider is an

indexed contract. This is a natural alternative to a fixed price contract.

Rather than try to set a fixed price that rolls in revenues for anticipated future

changes in input prices, costs of government regulations, changes in union work

rules, and so on, we can set a base price that is adjusted over time as input

prices rise. For example, the base price can be broken down into components

(labor, materials and supplies, depreciation, profit, property taxes) and then each

component escalated according to an appropriate input price and productivity

index. This type of contract seems to deal with some of the undesirable

properties of both the fixed price and cost plus contracts.

Prices now rise over time as input prices rise and productivity opportunities

change, and we do not have to front-load cash flow. Prices rise as the supplier's

input prices rise and production opportunities change but are independent of the

actual production decisions made by the supplier. If the supplier can increase

productivity more than provided for by the index, his actual costs will rise by less

than the indexed price. If his costs rise-because of bad mining practices, for

example-his net revenues are reduced as a result.

This type of contract provides incentives for the supplier to minimize costs (given

coal quantity and quality). Furthermore, the increases in input prices,

technological change, and so forth will have similar effects on the costs of

proximate alternative suppliers as well. Although this type of pricing provision

cannot guarantee that contract prices will move in lockstep with the prices that

might be charged by competing suppliers over time, it does account for several

important causes of changing supply prices. An indexed contract therefore

appears to dominate either a fixed price or cost plus contract.” [emphasis added]

10.1 An index-based formula for tariffs appears to offer the ability to address

uncontrollable or external cost of service changes, such as changing commodity

prices which FAES mentions in IR 26.2. Has FAES/FEI considered this or other

methods as alternative ways of addressing concerns about changes in input

costs? If not, why not?




Submission Date:

August 8, 2012



Response:

This response addresses BCUC IRs 2.10.1 and 2.10.1.1.

FAES has considered and has implemented index-based formulae for rate setting as well as

fixed rates for thermal energy projects to date. Given this experience, FAES believes that for

this service, the advantages of the annual rate setting approach outweigh the disadvantages, as

compared to fixed price or indexed price contracts.

As stated in the response to BCUC IR 1.26.1, FAES believes that the annual cost of service

flow through rate setting approach is the best rate setting approach for PCI. Cost of service flow

through has advantages of simplicity, transparency, and fostering energy conservation

awareness over other fixed price approaches. FAES believes it has an incentive to control all

controllable costs through participation in the annual public review carried out by the

Commission and stakeholders in order to ensure costs and risks have been managed

appropriately. Further, the Commission and stakeholders have experience with a similar review

process used in the FEI Annual Reviews and FEVI Settlement Updates in recent years. Each

year the Commission and stakeholders are in a position to review costs and changes that

impact rate setting in order to arrive at an equitable rate for customers. Any rate volatility issues

that might arise can be dealt with during an efficient proceeding for rates set in the subsequent

period.

Furthermore FAES considers that the citations included in the preamble to this IR are more

directly applicable to other thermal energy project circumstances than to the current

circumstances PCI faces as discussed below.

The 2004 IEA report cited refers to the transition countries in Eastern Europe and gives specific

consideration to the development of the economies and regulation in those countries

transitioning from a production based to a more customer-focused management model. District

energy is much more established and long standing in Eastern Europe than it is in BC. The

amount of energy delivered through District Energy Systems according to the IEA report was at

that time over 60% of the heating and hot water needs, and about half the largest district

heating systems in the world were in transition economies.2 The challenges faced by transition

economy district energy systems included lack of customer focus, low system efficiency, and

excess capacity. FAES considers this business environment to be significantly different than for

PCI where high efficiency thermal energy is early in its development in the more highly evolved

BC energy market.

2 Exhibit A2-2, OECD-IEA, 2004, Improving District Heating Policy in Transition Economies, pp.2-3




Submission Date:

August 8, 2012



The 1985 academic paper by Joskow cited refers to the “arrangements governing coal supply

transactions between electric utilities and coal suppliers”3 which do not exist in BC, and FAES

considers not applicable to the circumstances 27 years later for thermal energy delivery at PCI.

The circumstance cited relate to large coal-fired electric generating plants where coal

commodity purchase contracts lasted many years. FAES considers that this is not the case for

the pricing structure which governs the price of electricity and natural gas used as inputs to

PCI’s thermal energy delivery service. Electricity pricing is subject to regular Commission

review, and natural gas commodity pricing is market based and price setting reviewed quarterly

by the Commission. FAES submits that the well-established Commission review process

protects customers against inefficient pricing decisions, and that the cited indexed price

contracts are not appropriate for PCI at this time.

Overall, FAES believes that indexing can simplify rate setting mechanisms where the size,

complexity and availability of information relevant to setting cost-of-service rates makes the rate

setting process inefficient or cumbersome. Given that in this case, the scale of the service is

small, and the accounting detail is readily available, there is no compelling reason to introduce

indexing as a proxy for actual costs when setting the rate. Accordingly, direct tracking and flow

through of the forecast and actual costs of the service is more appropriate than indexing for this

service.

Similarly, FAES believes that given the relatively early stages of the development of the thermal

energy services market, forecasting and fixing rates over an extended period of time such as 25

years introduces the possibility that rates may become disconnected from actual costs at some

point in the forecast period. Given this, in order to manage risks and overall rate to customers,

as well as provide transparency, the 100% variable cost of service rate is more appropriate

versus fixed price rates in the context of this service.

10.1.1 Please compare the advantages and disadvantages of these two

methods, (and any others if necessary) of reducing input price risk in

long-term contracts, including a discussion of the incentives created for

the operator to improve productivity and minimize costs.

Response:


3 Paul Joskow, Vertical Integration and Long-Term Contracts: The Case of Coal-Burning Electric Generating Plants,

Journal of Law, Economics and Organization Vol 1 No. 1, p. 34, Fall 1985




Submission Date:

August 8, 2012



10.2 A two part tariff consisting of both a fixed and a variable component would

provide an alternative mechanism of mitigating the risk of annual demand

changes, and yet FAES has opted for a 100 percent variable tariff. Please

compare the advantages and disadvantages of these two methods of dealing

with the risk of annual demand changes, namely a two-part fixed/variable tariff,

and the cost of service rate. Include a discussion of the incentives created for

both operator and customer.

Response:

While a fully variable rate is not the only solution possible, it is an appropriate solution in this

instance. The risk of annual demand changes for thermal energy is primarily dependent upon

the outside temperature. Accordingly, FAES believes that the variability in outside temperature

is a good proxy for the total annual demand risk of this service.

As shown in the graph above, between 1992 and 2011, the rolling annual heating degree days

at Vancouver International Airport displayed a standard deviation of 5.4%. Using this as a basis

to evaluate demand risk, the variation in annual demand can be expected to be approximately

plus or minus 5% in any given year. Or put another way, one out of every six years should be

5% or more below the expected value. However, the chance of two consecutive years in a row

being 5% below the expected value is one out of every forty years ((15.9% x 15.9%) or (15.9%)2

=2.5%)4. The risks go dramatically down from there and over the full 20 years, there is a small

((15.9%)20 =close to 0%) chance that the total temperature will be 5% below the expected value.

4 15.9% was calculated = 3 divided by 19 years (1993 to 2011) based on a standard deviation of 5.4%.




Submission Date:

August 8, 2012



The issue of demand risk is a temporal issue occurring from year to year relating to when, not if,

the total demand will match the expected value and how different it will be at any time.

With respect to rate design and how a fully variable rate deals with the demand risks discussed

above compared to a fixed/variable rate structure, including the incentives for customers and

the company, the risk is that in any given year, the rates will produce more or less than the

expected revenues. The fully variable rate will have more revenue variance from year to year

than a rate with some proportion of fixed charges. However, if the annual demand is lower by

5%, then all other things being equal, the revenues in that year will be lower by 5% than

forecast using the fully variable rate whereas, the fixed/variable rate will generate revenues

closer to the original forecast in proportion to the amount of fixed charges in the rates. For

example, if 25% of the rate is fixed, then the revenues will be 3.75% lower than forecast instead

of 5%. In practice then, the difference in annual revenue will be very minimal between the fully

variable and the fixed/variable structures.

It is important to note that the use of the PCI Marine Gateway Deferral Account to collect

variances and amortize the balance to smooth rates tempers the impact on customers of

revenue variability due to the risk of annual demand for both fully variable and the fixed/variable

rate structures. Notably, annual demand is not the only variable that may cause differences

between revenues and costs for inclusion in the PCI Marine Gateway Deferral Account. In other

words, a rate with a fixed component provides no material benefit over the fully variable rate

from a rate stability and predictability perspective, or from a revenue stabilization perspective in

this instance.

While fully variable is not the only solution possible, it is an appropriate solution in this instance

because introducing a fixed component to the rate can weaken the incentive for customers in




Submission Date:

August 8, 2012



this Project to conserve as well as for the operator to forecast accurately. Given the general

predictability and stability of demand, and the generally inelastic nature of the service, FAES

continues to rely on the principles that support a variable rate structure. These principles are

simplicity, understandability and ease of administration. In short, FAES sees no compelling

reason or benefit to deviating from the fully variable rate that is proposed for this service.




Submission Date:

August 8, 2012




Utilities Commission Act, Section 60


Transition Economies, pp. 109, 132,

http://www.iea.org/textbase/nppdf/free/archives/cold.pdf

Section 60 (1)(b)(iii) of the Utilities Commission Act requires that in setting a rate, the

Commission must have due regard to the setting of a rate that encourages public utilities

to increase efficiency, reduce costs and enhance performance.

According to an International Energy Agency (IEA) publication on district heating

practices in OECD countries, a well-designed heat tariff should ideally have the following

characteristics

• “Cover the full current costs of the heat supply company.

• Include replacement costs and return on investment, taking into account the

need for adequate capacity.

• Allow sound operation and management of the district heating system.

• Be competitive with prices for other heat sources.

• Give the district heating company incentives to reduce costs.

• Give heat suppliers and customers incentives to save energy.

• Be transparent and easily understandable: customers should clearly see from

the tariff what they are responsible for and how they can influence the heat

bill.

• Last but not least, protect the consumer from unjustifiably high prices.”

[emphasis added]

11.1 What measures are FAES/FEI including in their proposed rate to ensure that the

correct incentives are in place to reduce the costs of providing thermal energy to

their PCI Marine-Gateway customers, and generally promote efficient

operations?

Response:






Submission Date:

August 8, 2012




Exhibit B-4, BCUC IR 1.26.1-2, pp. 56-57

Exhibit A2-3, District Heating and Cooling in the United States,

National Research Council, pp. 2, 86, www.nap.edu/catalog/263.html;


Transition Economies, p. 250,


According to a US National Research Council report written in 1985, regulation was a

significant factor inhibiting the growth and development of investor-owned district heating

utilities in the US. The paper concluded on page 86 that:

“The economic regulation of electric utilities, which follows from the concept of a

publicly granted and regulated monopoly, is inappropriately applied to district

heating and cooling systems. Urban systems require large initial investments,

particularly during a project's early stages, when revenues are small or lacking.

Where economic regulation by state utility commissions limits the return on

investment and controls the ability to roll investment costs into rates, the

incentive to urban systems is removed for the private sector.

Currently, most successful systems in the United States are operating without

these regulations or taxation because they are tax-exempt, not-for-profit,

municipal, or institutional installations. Likewise, costly and lengthy regulation

and permit procedures are disincentives to entrepreneurial systems because

they increase the uncertainty, cost, and complexity of development. Real or

perceived regulatory risks unfavorably affect cost and financing.

- Economic regulation of district heating and cooling systems by state or local

authorities should be eliminated. District heating and cooling systems should

be allowed to operate in the same open market that now exists for competing

fuels and energy systems.”

According to a more recent 2004 paper by the IEA:

“Some older district heating systems in the U.S., such as the system serving New

York City, are regulated by state public utility commissions. Tariffs are not

regulated in newer district energy systems.”

Page 132 of the same document discusses the general impact of tariff regulation on

prices:

www.nap.edu/catalog/263.html





Submission Date:

August 8, 2012



“Countries have taken two approaches to heat source competition: competition with

regulated prices and competition with unregulated prices (a third policy option, zoning,

allows localities to exclude customer-level competition, though zoning proponents argue

that there is de facto competition in the energy planning process used to define the

zones). Prices in countries that do not have tariff regulation are generally lower than in

those that do, possibly because of how tariff regulation reduces flexibility and creates an

administrative burden, both of which can add to costs.”

The IEA paper states on page 110 that:

“Poorly designed tariff regulation that does not provide incentives for cost

reduction may result in unnecessarily high tariffs for consumers. … Where

competition cannot be introduced, the role of regulation should be to mimic the

effect of a competitive market by creating effective incentives for cost reduction.

Not all approaches to tariff regulation can achieve this. …

…

Recommendation

Given the numerous disadvantages of cost-plus regulation, regulators should

consider using other approaches, for example price caps or benchmarking.

Incentive regulation should be robust and predictable to ensure that the operator

has sufficient motivation to improve efficiency and that it can keep the benefits of

its efforts for a relatively long period. Substitution-based tariffs can be effective

when the energy market is balanced.”

12.1 Please discuss how the traditional annual cost of service revenue requirements

rate setting mechanism encourages improved efficiency and cost-reduction.

Response:

The motivation for FAES to improve efficiency and reduce costs is found within the Utilities

Commission Act itself in section 60(1)(b)(iii), which provides that in setting rates, the

Commission is directed to “encourage public utilities to increase efficiency, reduce costs and

enhance performance”. Starting in year four of the Project, FAES’s forecast cost of service will

be subject to annual review and Commission scrutiny, and in this way FAES will be motivated to

ensure that its forecast cost of service results in just and reasonable rates, which includes a

consideration of whether FAES is making efforts to improve efficiency, reduce costs, and

enhance performance when feasible to do so.




Submission Date:

August 8, 2012



12.2 Should the BCUC consider the application of other rate-setting methodologies or

types of regulation, such as price caps, long-term contracts or benchmarking, to

encourage thermal operators to improve efficiency and lower costs, and to

ensure that the development of the district heat industry is not impaired? If not,

why not?

Response:

These broader issues are being considered in the AES Inquiry. FAES respectfully submits that

these kinds of broader, industry wide issues should be left for the panel in the AES Inquiry and

not decided in a discrete application such as this one in order to avoid inconsistency with the

results of the AES Inquiry.

FAES believes that cost of service rates and alternative rate designs, such as performance

based rates, can and should co-exist in the thermal energy marketplace (again, FAES reiterates

that the Commission should not decide this matter one way or the other in this proceeding).

Each approach will have a different value proposition for different customers. Some customers

will value the potential for lower rates on a cost of service approach, while others may value the

price certainty provided by other types of models (even if this certainty may come at a higher

cost than a cost of service approach). This proceeding concerns FAES’s application for a

CPCN and for rates to provide thermal energy services to PCI using a cost of service rate

design. FAES and PCI have negotiated cost of service rates and PCI has indicated that “public

utility service that FAES will provide, including cost of service based rates subjected to the

BCUC regulation”, is the best fit for PCI and its future tenants (Ex. B-1, App. Z). In these

circumstances, FAES does not believe that there is a compelling or useful reason to consider

these kinds of broader issues, or an alternative rate design for the project.

12.3 On what basis has FAES/FEI decided that cost of service regulation is the most

appropriate way of regulating thermal energy?

Response:

FAES does not believe that there is a “most appropriate” rate design for thermal energy

services. Rather, FAES believes that there are and should be different approaches in the

market so that customers can have a choice based on their own preferences and values. Some




Submission Date:

August 8, 2012



customers may prefer fixed price or performance based approaches that provide greater cost

certainty even though this may come at a higher cost than a cost of service approach. FAES

believes that the most appropriate approach to these matters is ultimately the approach

preferred and agreed to by the customer. Based on FAES’s experience to date with thermal

energy systems, FAES is developing and will continue to develop cost of service based rates as

it is confident that there are customers who desire this kind of service. Please see the response

to BCUC IR 2.12.2 regarding the extent to which these kind of broader issues are being

addressed in the AES Inquiry (and therefore should not be addressed in this particular

proceeding).




Submission Date:

August 8, 2012



13.0 Reference: 100 Percent Variable Rate


In BCUC 1.31.1, FAES provides three primary reasons to design a 100 percent variable

rate, among which are the following two: 1) a 100 percent variable rate enables

customers to easily identify their effective costs of thermal energy; 2) it provides a

conservation incentive for customers to limit their energy consumptions.

13.1 Please explain the disadvantages of choosing an energy rate that is 100 percent

variable.

Response:

As noted previously in the response to BCUC IRs 2.10.1 and 2.10.2, FAES believes that the

advantages of a 100 percent variable rate provide a strong rationale for choosing it in the case

of the PCI Marine Gateway project. Also see FAES’s response to BCUC IR 1.31.1.

A potential disadvantage of choosing an energy rate that is 100 percent variable is that the

possibility exists in any given year that FAES will not recover the full annual revenue

requirement or will recover more than the annual revenue requirement. However, in the event

that energy use fluctuates substantially, the differences between the revenue recovered vs. the

revenue requirement will be put into the deferral account. Since a 100 percent variable rate

benefits the customers by providing them with conservation incentive as well as enabling them

to easily identify their costs of thermal energy, and since FAES/FEI has experience managing

TES projects and their associated costs, the advantages outweigh the disadvantages.

Therefore, FAES believes that choosing an energy that is 100 percent variable is appropriate for

this project.

13.2 If actual energy use were to fluctuate substantially from year to year, what would

FAES do to prevent customers from facing highly volatile energy rates?

Response:

As discussed in the response to BCUC IR 2.13.1, and Sections 6.5 and 6.6 of the Application, if

actual energy use were to fluctuate substantially from year to year, FAES will record any

difference between the revenues and the cost of service (revenue requirement) in a deferral

account in each year through the term of the service contracts. The cost of service will include

an amount to recover any balance in this deferral account over the remaining years in the term

of the contract. The annual amortization amount has been set to manage the thermal energy




Submission Date:

August 8, 2012



rate based upon the forecast cost of service and thermal energy deliveries in the term and will

also include the previous year deferral amount, whether positive or negative. This deferral

account ensures that variances from forecast are recovered from or refunded to the customers

of this Project. In addition, the annual amortization amounts are managed to create a more

stable rate than would occur without the use of a deferral account over the remaining years in

the term, so customers will not be facing highly volatile energy rates.

13.3 Given that for residential and office spaces, and in the case of the smaller CRU

tenants, the customers will be: 1) the Strata Corporation, 2) the management

company that will manage the rental residential units, 3) the management

company that will manage the office complex, and 4) the management company

that will manage the smaller CRU tenants, would FAES agree that the benefits

outlined above are less obvious and direct than in the situation where the actual

owners or renters of residential, office or CRU units would be billed directly for

their respective energy consumption (e.g., in the case of residential owners, their

energy bills will amount to only a fraction of a higher condo fee)?

Response:

FAES does not agree that the benefits outlined above are less obvious and direct for strata

corporations or management companies than for actual owners or renters of residential, office

or CRU units versus the situation where the actual owners or renters are billed directly. FAES’s

experience with strata corporations and management companies indicates that they are keenly

aware of energy consumption and interested in understanding energy system performance

since energy costs will affect the monthly fees. FAES believes that the 100% variable rate will

be helpful in meeting the energy management needs of strata corporations and management

companies and that there remains a strong incentive to conserve energy overall due to the

maximum consumption limits placed in each of the Service Contracts.

Billing customers individually by providing individual metering was an option that FAES had

considered for this project. However, FAES believes that the costs associated with individual

billing and metering will create a financial burden for customers. As indicated in the response to

CEC IR 2.2.2, based on FAES’ interaction with residential thermal meter suppliers during the

course of planning various projects, an estimate of the incremental costs in the range of

approximately $7 to $15 per suite on a monthly basis would need to be added to customers’

bills for billing and administration purposes. As a result, FAES believes that grouping the

customers for billing purposes as stated in the Application, is a cost effective way and works in

the best interest for the customers.




Submission Date:

August 8, 2012



It is also important to note that in the case of the office complex, if customers want individual

metering, as per the response to BCOAPO IR 1.4.2, each office unit (or combination of units)

will have the capability to meter its own consumption of thermal energy, and this decision will fall

to the Office Tower Management Company and the individual office tenants once they have

been identified.

Considering there is already an incentive (max consumption limit) in place to encourage energy

conservation, and the cost associated with individual billing will create a financial burden for the

customer, FAES believes billing the customer groups instead of billing customers individually, is

the best arrangement for this Project.

13.4 What is the ratio of fixed versus variable costs for each year of the 20-year period

and on a net present value basis? Please provide the calculations and also

define what is included in fixed and variable costs.

Response:

FAES defines fixed versus variable costs from the Cost of Service as follow:

Particulars Fixed/Variable Costs?

Revenue Requirement

Cost of Natural Gas Variable

Cost of Electricity Variable

Operation and Maintenance 50% Fixed and 50% Variable*

Property Taxes Fixed

Depreciation Expense Fixed

Amortization Expense1 Fixed

Income Taxes Fixed

Earned Return Fixed

* assumed 50% fixed and 50% variable as the system will still require some type of maintenance whether or not the system is in use.

For each year the ratio is as follows:

Particulars 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Variable Costs Total 388 402 417 432 444 456 468 481 494 507 521

Fixed Costs Total 1,101 1,090 1,082 1,061 1,039 1,027 1,024 1,022 1,020 1,018 1,016

Ratio (Variable to Fix) 1:3 1:3 1:3 1:2 1:2 1:2 1:2 1:2 1:2 1:2 1:2




Submission Date:

August 8, 2012



2026 2027 2028 2029 2030 2031 2032 2033 2034

535 549 564 580 595 607 620 632 645

1,015 1,015 1,014 1,015 997 1,000 1,022 1,201 1,202

1:2 1:2 1:2 1:2 1:2 1:2 1:2 1:2 1:2

The Present Value is as follow:

PV

Present Value of Variable Costs 4,929

Present Value of Fixed Costs 10,664

Ratio (Variable to Fix) 1:2

Please also refer to the Live Spreadsheet included as Attachment 13.4 for reference.

As demonstrated above, if FAES had chosen a fixed/variable rate structure for PCI, customers

would face a high fixed cost and a lower variable rate, which in this project does not send the

appropriate energy efficiency and conservation or demand side management price signals for

the customer. For these reasons and other reasons stated in BCUC IR2.13.3; BCUCIR2.10.1

and BCUCIR2.10.2, FAES believes the 100% variable rate is appropriate for this project.

13.5 Why has FAES not considered using a rate design that would have a fixed and a

variable component aimed to respectively recover the Project’s fixed and variable

costs, as in the cases of Dockside Green, Corix UniverCity and River District?

Please also list the pros and cons of a rate design including both fixed and

variable components.

Response:

For clarity, the rate design FAES has proposed for this service does recover the fixed and

variable costs of the service and conforms to the cost of service standard of public utility rate

making.

Variable Rate Design

FAES believes the variable rate design in this project is appropriate as there is only one class of

service, and this single variable rate per kWh of energy delivered is set to recover cost of

service satisfying the cost of service standard of ratemaking. In addition, the single variable rate

produces a rate that is always above the avoidable costs of providing service, preventing any

undue price discrimination potential between customers. This is further explained in the

responses to BCUC IR 2.13.1 and BCRUCA IR 2.1.1.




Submission Date:

August 8, 2012



FAES’ response to BCUC IR 1.31.1 lists three primary “pros” related to fully variable rates: 1) A

100% variable rate enables customers to easily identify their effective costs of thermal energy;

2) It provides a conservation incentive for customers to limit their energy consumption; 3) It is an

administratively efficient, easily communicated an equitable method of allocating costs between

customers. The disadvantages of this approach are that 100% of fixed costs must be collected

in the variable rate component along with the units of energy, and the revenue from a low

consumption period may not cover fixed costs during that period.

Fixed Variable Rate Design

In the case of a fixed/variable rate design, one of the debates is over the appropriate

percentage of actual fixed costs that should be picked-up in the fixed charge component. It

could be within a range of 100% to a minimal amount. If it is less than 100%, then the

disadvantage of this approach is the same as the 100% variable rate design described above.

It is simply the degree of the disadvantage that differs. In addition this rate design is less

effective than the total variable rate design as a conservation incentive to limit energy

consumption.

Typically, the use of fixed/variable rates in a mature utility rate design has less to do with the

fixed and variable components of the allocated cost of service by rate class than it does with the

creation of manageable economic crossovers between rate classes. In other words, where

multiple rate classes exist, the rate design should create natural incentives for customers to self

select into the proper rate class.

Further, under a fixed/variable rate design, all users within a rate class, large or small, are

charged the same amount, instead of a proportional one, for fixed costs. This has the potential

to adversely affect small users if their usage characteristics are not in line with others in their

rate class or group.




Submission Date:

August 8, 2012



14.0 Reference: Transfer Pricing Policy


14.1 Has FAES/FEI received an external audit opinion on its transfer pricing policy?

Response:

Neither FAES nor FEI has ever received an external audit opinion on the transfer pricing policy.

Prior to 2010, FEI had an external audit firm provide a “review opinion” of compliance with this

policy. As requested and subsequently approved in its 2010/2011 Revenue Requirements

Application, FEI discontinued this practice starting in 2010. Currently, the internal audit group of

FEI provides an annual “review opinion” on compliance with this policy.

14.2 If yes, please file the latest audit report, whether internal or external, on FAES/

FEI’s transfer pricing policy.

Response:

As indicated in the response to BCUC IR 2.14.1, the internal audit group at FEI provides a

review opinion on compliance with the FEI transfer pricing policy annually. The latest report,

which was filed with the BCUC and is dated December 8, 2011, is provided in Attachment 14.2.

FAES has not previously filed a similar report.




Submission Date:

August 8, 2012



15.0 Reference: Negative Salvage

Exhibit B-4, BCUC 1.34.1, 1.34.2

15.1 How does FAES/FEI plan to deal with future negative salvage costs associated

with the Delta School District and Tsawwassen Springs projects?

Response:

For Tsawwassen Springs, negative salvage will be addressed as part of the compliance filing.

For the Delta School District, FAES will include a provision for negative salvage costs and the

actual removal costs in a Negative Salvage deferral account, similar to the treatment of negative

salvage in this Application, and reflect these costs in the actual and forecast cost of service on a

prospective basis.

15.2 How does FAES plan to account for and report on the collection of negative

salvage value for the PCI Marine Gateway project?

Response:

FAES plans to report the collection of negative salvage for the PCI Marine Gateway project as

part of the Cost of Service compliance filing on an annual basis to the Commission. The

amounts shown on Schedule 11 of Appendix T will be updated to reflect the actual provisions

and actual removal costs incurred.

The cost of service rates include a provision related to the forecast removal costs of the capital

equipment associated with the thermal energy system. The annual negative salvage rates for

the Project are set to recover the forecasted removal costs of the assets over their useful lives.

These annual negative salvage periods and rates, the forecast removal costs and the annual

provision, are shown in Table 6-2 of the Application and reproduced here for ease of reference.

The calculated removal cost provisions are included in Schedule 11 of Appendix T.

EC Equipment

Negative Salvage

Period in Years

Annual Negative

Salvage Rate

Forecasted Removal

Costs (thousands)

Annual Removal

Provision (thousands)

(1) (2) (3) (4) (5) = (3) x (4)

Pumps, Heat Pumps and Exchanger Equipment 22 4.63% $240.2 $11.1

Boilers high CCA 35 2.86% $15.5 $0.4

Structures - Cooling Towers 22 4.63% $21.8 $1.0

Loop Field (Ground Source Heat Exchanger) 50 2.00% $22.5 $0.5




Submission Date:

August 8, 2012



15.3 How will FAES treat the collection of negative salvage amounts at the end of the

contract term if the customer buys out his/her portion of the remaining rate base?

Response:

Please refer to the response to BCOAPO IR 1.6.1 filed confidentially with the Commission. The

negative salvage amounts are defined as part of the Rate Base Value, specifically item c)-mid-

year balance of unamortized deferral accounts, with the net amount of the negative salvage

provision less actual removal costs incurred fully recoverable from or repayable to the customer

if they choose to buy out the remaining value of the rate base.

15.4 How will FAES treat the collection of negative salvage amounts if the customer

renews the contract at the end of the contract term?

Response:

If the customer renews the contract at the end of the contract term, FAES will continue to record

an annual negative salvage provision and actual removal costs against the Negative Salvage

deferral shown in Schedule 11 of Appendix T in the Application. The ending balance of this

deferral in Year 20, as well as the other rate base balances, would serve as the opening rate

base balance for the term of the renewal agreement.




Submission Date:

August 8, 2012



16.0 Reference: Project Deferral Account

Exhibit B-4, BCUC 1.35.4.1

“The Project Deferral Account will be a stand-alone deferral account within FAES

pending the outcome of the AES inquiry.”

16.1 Why has FAES chosen to name this deferral account the “Project” Deferral

Account instead of the “PCI Marine Gateway Deferral Account”?

Response:

As defined in Section 1.1, “Project” actually refers to PCI, the “mixed-use commercial and

residential development at Cambie Street and Marine Drive in Vancouver (the “Development”,

“PCI Marine Gateway” or the “Project”)”.

As this account serves the same purpose as the “SD37 Deferral Account” from the Delta School

District Application, FAES agrees that an appropriate name for this deferral is the “PCI Marine

Gateway Deferral Account”.

16.2 Does FAES’ choice to use the generic term “project” deferral account suggest

that FAES is intending to allocate costs from other/future TES projects to this

deferral account?

Response:

No, this deferral account will specifically capture amounts related to the PCI Marine Gateway

project only. Please refer to the response to BCUC IR 2.16.1.

16.2.1 If so, how will FAES be able to distinguish between the costs associated

with each customer/project within this deferral account should this be

required in the future?

Response:





Submission Date:

August 8, 2012



16.3 How would FAES treat variances accrued due to the rate smoothing mechanism

if the Commission were to order FAES to file separate rates for each customer

type?

Response:

If the Commission were to order FAES to file separate rates for each customer type, FAES

would still record any variances in the PCI Marine Gateway Deferral Account. That is, FAES

has the ability to track actual revenues received by rate class and as such, any variance

between actual revenues received for a specific rate class and those forecasted in rates would

be captured in the PCI Marine Gateway Deferral Account. If detailed cost of service allocation

information was available, FAES would likely refund or recover the variance accumulated in the

account by customer type; however, in the absence of detailed cost of service allocation

information, FAES would likely propose to refund or recover this variance equally amongst all

customers.

However, as per BCUC IR 1.19.3, FAES believes that having separate rates for each customer

type in the PCI Marine Gateway Development is not appropriate and strongly believes that a

single rate for thermal energy is an efficient and equitable rate design for this service as:

a) no customer should ever receive service at rates below their avoidable cost of service;

b) this is an integrated system that provides both heating and cooling by balancing load

characteristics;

c) the administrative cost and complexity of performing a detailed cost of service allocation

study is not warranted in this case;

d) actual consumption data at this stage is not available to determine whether any

customer segmentation is possible.

Therefore, FAES continues to propose a single rate for all customer types for the PCI Marine

Gateway Development with variances recorded in the PCI Marine Gateway Deferral Account.

16.3.1 How would FAES distinguish between variances accrued from each

customer type?

Response:





Submission Date:

August 8, 2012



17.0 Reference: Overhead Recovery


“Accordingly, for this Project FAES has forecast the overhead recovery at a higher level

than the Delta School District Project, and arrived at 33 percent of total O&M as a

reasonable estimation for this amount.” [Emphasis added]

17.1 Please explain in more specific detail how the 33 percent for overhead recovery

was calculated.

Response:

The overhead recovery was an estimate calculated by FAES assuming that the recovery will be

approximately 50% of the direct O&M of $102 thousand (for the first contract year), which

translates to 33% of total O&M of $153 thousand for the first contract year ($102 thousands of

direct O&M + $51 thousands of overhead recovery). These overheads are then escalated at

inflation each year similar to the Direct O&M costs in the Application.

As per Section 6.3.3 of the Application and further discussed in the response to BCUC IR

1.35.5, in addition to a ratio of total O&M, FAES also considered a reasonable estimate of the

various components of overheads in arriving at the forecast amount. These overheads consist

of ongoing overhead costs attributable to managing the FAES business including contract

administration, billing, customer support, shared services and recovery of a reasonable share of

the TESDA balance. The breakdown is as per Table 6-3 of the Application and reproduced

below:

Table 6-3: Ongoing Overheads and TESDA

Contract Administration 6,240$

Billing 1,230$

Customer Service 3,120$

Insurance 4,545$

Corporate Overheads/TESDA/MISC 35,865$

51,000$

FEI will track and charge to FAES all such overhead costs, and variances between the forecast

amount and actual costs will be recorded in the PCI Marine Gateway deferral account. These

variances will either be recovered from or credited to the tenants in subsequent years.

Further, FAES or FEI, as the case may be, intend to provide a submission to the Commission

separately respecting the allocation of the TES Deferral Account to projects and this allocation

will be adjusted subject to BCUC approval from time to time, with any changes accordingly

reflected in the PCI cost of service




Submission Date:

August 8, 2012



18.0 Reference: TESDA


18.1 Please confirm that the total overhead estimation of $51,000 for PCI is a “place-

holder” in the PCI cost of service to account for the recovery of the TESDA.

Response:

Confirmed. This amount will be adjusted subject to BCUC approval from time to time.




Submission Date:

August 8, 2012



19.0 Reference: Exhibit B-4, BCUC 1.39.2, Attachment 39.2

19.1 Please provide the live excel workbook version of Attachment 39.2, which

includes all of the most recent updates/amendments.

Response:

Attachment 19.1 is being filed confidentially as it contains commercially sensitive information.

The financial model in Attachment 19.1 is the result of significant development effort on behalf

of FAES and therefore the formulaes and configuration of the model are commercially sensitive.

This is particularly important because to the best of FAES’ knowledge, the business model

FAES has employed for this application is unique in the industry and as such is commercially

sensitive.




Submission Date:

August 8, 2012



20.0 Reference: Capital Structure and Return on Equity


20.1 Given the content and nature of the TESDA and the fact that FEI can defer the

development costs of abandoned projects, does FAES/FEI agree that its

TES/AES business risk is reduced?

Response:

No, as stated in the response to BCUC IR 1.41.1 business risk is not reduced as, ultimately,

there remains a risk that the costs recorded to the TESDA will not eventually be recovered in

rates. In fact, it is just the opposite, by deferring the recovery of costs, the risk of their eventual

non- recovery in rates increases.

20.1.1 If not, why not?

Response:





Submission Date:

August 8, 2012



21.0 Reference: Capital Structure and Return on Equity


21.1 Please provide FAES’ assessment of the risk level for risk factor #3 in the table

(Customer Base) and provide FAES’ rationale for this risk level assessment.

Response:

In the referenced table, FAES described customer base as “Greenfield Utility; four types of

customers” and in the subsequent table in the response to BCUC IR 1.41.4 described the

customer base risk as “low-confirmed customers but limited diversity”. The “Customer Base” is

confirmed and has limited diversity as it has four customer types and building construction is

underway. While the residential component has reasonable certainty of long term continuous

occupancy, the commercial component is less so. For this reason, the risk around customer

base is higher than Delta Schools, which is one established customer and was described as

“lower” in the table in the response to BCUC IR 1.41.4 but lower than Dockside Green, which

was described as “higher” and “uncertainty related to timing of full build-out” in the tables and

has yet to develop subsequent buildings which the system was built to serve. .

21.1.1 Please explain why FAES does not believe that the risk level is “low”

given that the residential units are already sold out and that there are

already “significant commitments from major tenants such as Cineplex

and Loblaws, which represent over 50 percent of the available

commercial square footage” (BCUC 1.21.1).

Response:





Submission Date:

August 8, 2012



22.0 Reference: Electricity Benchmark


The table provided by FAES in response to BCUC 1.43.4 is copied below for ease of

reference.

In BCUC 1.43.3, FAES confirmed that the Year 2012 in Table 6-7 in the Application

referred to rates as of April 1, 2012, which corresponds with BC Hydro’s fiscal year 2013

(F2013).

22.1 Since Year 2012 in Table 6-7 of the Application refers to BC Hydro rates in

F2013, does it follow that Years 2013 to 2017 in Table 6-7 of the Application refer

respectively to BC Hydro rates in F2014 to F2018?

Response:

FAES has updated the table based on Commission’s revised table and guidance in BCUCIR

2.22.5. Please refer to the response to BCUC IR 2.22.5.1 for the revised table.

22.1.1 If so, please explain why the last column of the above table has not been

filled out, as it would correspond to the Year 2017 in Table 6-7 of the

Application, i.e., the third year of the smoothing mechanism.




Submission Date:

August 8, 2012



Response:

FAES agrees that the last column in the above table should have been populated. FAES has

updated the table based on the Commission’s revised table and guidance in BCUC IR 2.22.5.

Please refer to BCUC IR 2.22.5.1 for the revised table.

22.2 In the table above, for the years F2015 and beyond, when FAES assumes an

overall rate increase of six percent for the combination of rate and DARR, please

indicate separately what is FAES’s implied assumption regarding the rate

increase.

Response:

FAES has updated the table based on the Commission’s revised table and guidance in BCUC

IR 2.22.5. Please refer to BCUC IR 2.22.5.1 for the revised table.

22.3 From the table above and calculations therein, it appears that FAES has applied

annual rate increases to the previous year’s tariff, including the DARR. Please

confirm whether this is the case.

Response:

FAES has updated the table based on Commission’s revised table and guidance in BCUC IR

2.22.5. Please refer to the response to BCUC IR 2.22.5.1 for the revised table.




Submission Date:

August 8, 2012



The following is an excerpt of BC Hydro’s Electric Tariff Schedule 1901 regarding the

Deferral Account Rate Rider.

22.4 Given that the rate rider does not form part of the residential electric tariff but is

added on top of the other residential bill components, does FAES agree that

annual rate increases should in fact only be applied to the tariff components,

excluding the DARR, and then add the five percent rate rider in order to calculate

a benchmark electricity rate for the purposes of this Application?

Response:

Yes. FAES has separated the calculation for the DARR and updated the table based on

Commission’s revised table and guidance in BCUC IR 2.22.5. Please refer to the response to

BCUC IR 2.22.5.1 for the revised table.

22.5 The methodology described in the previous question has been used to derive the

bolded figures in the table below from information provided by FAES in the table

in BCUC 1.43.4. Please indicate whether FAES agrees with it or not. If not,

please provide a corrected version and explain the changes.




Submission Date:

August 8, 2012



Response:

FAES has updated the table based on the Commission’s revised table and guidance. Please

refer to the response to BCUC IR 2. 22.5.1 for the updated table.

22.5.1 In particular, please confirm whether it was FAES’s intention to assume

BC Hydro’s residential electric tariff would go up by forecasted annual

rate increases of 6.31 percent, 6.75 percent and 6.03 percent for F2015,

F2016 and F2017 respectively. If so, please provide FAES’s rationale for

using these assumptions. If not, please correct the table below using

revised forecast rate increase. In either case, please provide a complete

table including the year F2018.




Submission Date:

August 8, 2012



BCH Fiscal

Year

F2013

($/kWh)

F2014

($/kWh)

F2015

($/kWh)

F2016

($/kWh

)

F2017

($/kWh

)

F2018

(S/kWh

)

a BCH Electric

Tariff Forecast

(50% Step 1

and 50% Step

2)

(line a * BCH

Rate Escalation

line b)

$0.085 $0.086 $0.091 $0.097 $0.103 Missin

g

b BCH Rate

Escalation

Based on Order

G-77-12 until

F2014

-

1.44% 6.31% 6.75% 6.03% Missin

g

c Rate Rider @

5% for all years

$0.04 $0.04 $0.05 $0.005 $0.005 Missin

g

d Rate forecast

including DARR

(line a + line c)

$0.089 $0.090 $0.096 $0.102 $0.108 Missing

e 10% premium

(line d * 0.10)

$0.009 $0.009 $0.010 $0.010 $0.011 Missing

f Energy Rate for

Marine Gateway

(line d + line e)

$0.098 $0.099 $0.106 $0.112 $0.119 Missing

g Table 6-7 in

Application

$0.093 $0.099 $0.104 $0.109 $0.115 $0.120

h Variances -5.1% 0.0% -1.9% -2.7% -3.4% Missing

Response:

FAES has revised the table based on the above format and italicized revisions made by FAES.

The new results are also italicized for ease of reference.




Submission Date:

August 8, 2012



FAES notes that the DARR calculations in the above table appear to have missed one decimal

place. As a result, FAES has also updated the calculations.

For the actual formula that FAES used to derive the calculations, please refer to the excel

spreadsheet attached in this IR.

BCH Fiscal Year F2013 ($/kWh) F2014 ($/kWh) F2015 ($/kWh) F2016 ($/kWh) F2017 ($/kWh) F2018 (S/kWh) FAES Comments

BCH Fiscal YearApril 1 2012 to

March 31, 2013

April 1 2013 to

March 31, 2014

April 1 2014 to

March 31, 2015

April 1 2015 to

March 31, 2016

April 1 2016 to

March 31, 2017

April 1 2012 to

March 31, 2013FAES added for clarifications

PCI Service Agreement RatesUsed as First Year

Rate

Used as Second

Year Rate

Used as Third Year

RateFAES added for clarifications

BCH Electric Tariff Forecast

(50% Step 1 and 50% Step 2)

(line a * BCH Rate Escalation line b)

-

c Rate Rider @ 5% for all years $0.004 $0.004 $0.005 $0.005 $0.005 $0.005 FAES corrected

calculations for DARR

d Rate forecast including DARR (line a + line c) $0.089 $0.091 $0.095 $0.100 $0.105 $0.110 formula

e 10% premium (line d * 0.10) $0.009 $0.009 $0.010 $0.010 $0.010 $0.011 formula

f Energy Rate for Marine Gateway (line d + line e) $0.098 $0.100 $0.105 $0.110 $0.115 $0.121

formula

g Table 6-7 in Application $0.093 $0.099 $0.104 $0.109 $0.115 $0.120 same as Application

h Variances -5.56% -0.59% -0.55% -0.73% -0.25% -0.88% formula

FAES corrected percentage

based on new format

FAES updated $0.105

bBCH Rate Escalation Based on Order G-77-12

until F20141.44% 5.00% 5.00% 5.00% 5.00%

a $0.085 $0.086 $0.091 $0.095 $0.100

22.6 In the above table, line g has been properly copied from Table 6-7 in the

Application and the variances recalculated. Does FAES agree with the

corrections? If not, please explain why not.




Submission Date:

August 8, 2012



Response:

FAES has updated the table based on the Commission’s revised table and guidance in the

response to BCUC IR 2.22.5. Please refer to BCUC IR 2.22.5.1 for the revised table.

FAES states in BCUC 1.43.4 that “It is important to note that FAES has set the rate for

the first three years in order to provide rate predictability and stability as the service

begins. Accordingly, while the rates generally follow the calculations below, this does not

mean that electricity is the comparable BAU for this service, or that the rates should

adjust precisely with electricity rates in those years. These calculations provide a

reasonable level of rates for the first three years that will provide the rate stability and




Submission Date:

August 8, 2012



predictability that is desired, at rates that a reasonably comparable to other thermal

energy rates recently approved such as the River District.” [Emphasis added]

22.7 Please update Table 6-8: Thermal Energy Rates of the Application (and the

corresponding Rate Design Schedule 12 in Appendix T, as well as any other

affected Schedules).

Response:

FAES assumes the Commission is asking FAES to update Table 6-8 in the Application based

on the results in the responses to BCUC IRs 2.22.5 and 2.22.6. However, as the variances in

the first to third year contract rates are all less than 1% (from -0.88% to -0.25%) based on

today’s assumptions, FAES believes the rates for the first three years of $0.109/kWh,

$0.115/kWh and $0.120/kWh respectively, remain reasonable. These are negotiated rates with

PCI that provide a reasonable level of rates for the first three years, allow for rate stability and

predictability, and are comparable to other recent thermal energy rates. Thus, based on the

results in BCUC IR 2.22.5 and BCUC IR 2.22.6, Table 6-8 of the Application does not require an

update.

FAES notes that the Commission asked FAES to update the calculation of capitalized overhead

in BCUC IR 1.39.2. In the response to the IR, FAES updated the calculation based on a change

to capitalized overhead as well as an update to the debt rate of 5.37 percent to align with the

DSD revisions made per Commission Order G-71-12. These two updates change Table 6-8

slightly from the original Application. The thermal energy rates as shown in Schedule 12 of

BCUC IR 1.39.2 and the original Application are shown below for comparison purposes. Please

note that Schedules affected by these two changes were filed as Attachment 39.2 in the

response to BCUC IR 1.39.2.

Updated Thermal Energy Rates from BCUC IR 1.39.2:

Line Particulars PV 2015 2016 2017 2018 2019 2030 2031 2032 2033 2034

1 Annual Volume for Billing (MWh) 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328

2 Present Value 107,552 9,632 8,984 8,378 7,814 7,288 3,384 3,156 2,944 2,746 2,561

26 Total Annual Revenue 1,127 1,183 1,242 1,298 1,357 1,859 1,896 1,934 1,973 1,989

27 Present Value 15,641 1,051 1,029 1,008 982 957 609 580 551 524 493

28 Cost of Service (after smoothing ) Rate $/kWh 0.145 0.109 0.115 0.120 0.126 0.131 0.180 0.184 0.187 0.191 0.193

Original Table 6-8 from Application:




Submission Date:

August 8, 2012



FortisBC Alternative Energy Services Inc.

Thermal Energy Solutions

PCI Only Closed GEOx

Thermal Energy Solutions: Rate Design

($000's), unless otherwise stated

Schedule 12

Line Particulars PV 2015 2016 2017 2018 2019 2030 2031 2032 2033 2034

1 Annual Volume for Billing (MWh) 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328 10,328

2 Present Value 104,921 9,603 8,930 8,303 7,720 7,179 3,225 2,999 2,788 2,593 2,411

26 Total Annual Revenue 1,127 1,183 1,242 1,298 1,357 1,923 1,962 2,001 2,041 2,039

27 Present Value 15,494 1,048 1,023 999 970 943 600 570 540 512 476

28 Cost of Service (after smoothing ) Rate $/kWh 0.148 0.109 0.115 0.120 0.126 0.131 0.186 0.190 0.194 0.198 0.197

22.7.1 In particular, please indicate clearly what FAES’s updated proposals are

for: 1) the first three years under the Rate Smoothing Mechanism; 2) all

remaining years; and 3) the 20-year levelized thermal energy rate.

Response:


Rates are not affected by the results of BCUC IR 2.22.5 and BCUC IR 2.22.6; thus updated

proposals for the first three years, the subsequent 17 years, and the 20-year levelized thermal

energy rate are not required.

With respect to the response to BCUC IR 1.39.2, which was an update to the cost of service

and financial schedules for capitalized overhead and the debt rate consistent with Order No. G-

71-12, Schedule 12 of Attachment 39.2 contains the rates for the first three years under rate

smoothing (at $0.109/kWh, $0.115/kWh and $0.120/kWh respectively), the rates for the

subsequent 17 years, as well as the 20-year levelized thermal energy rate. A summary of

Schedule 12, updated for these changes, is included in the response to BCUC IR 2.22.7.

22.7.2 How do FAES’s updated rate proposals compare with those contained in

the Application (e.g., higher, lower, the same)?

Response:

FAES is making two comparisons to the rates contained in the Application and has summarized

each below.




Submission Date:

August 8, 2012



1. As per the response to BCUC IR 2.22.7 and BCUC IR 2.22.7.1, rates are not affected by

the results of updating the BCH rates in BCUC IR 2.22.5 and BCUC IR 2.22.6 and, as

such, rates are the same as those contained in the Application; and,

2. As also shown in the response to BCUC IR 2.22.7, updated rates determined in

reference to BCUC IR 1.39.2 (i.e. cost of service updates based on BCUC Order No. G-

71-12 for changes in capitalized overhead and an update to the debt rate of 5.37

percent) are lower than the rates contained in the Application.




Submission Date:

August 8, 2012



23.0 Reference: Energy Rate

Exhibit B-1, Appendix H, Project Requirements, p. 2

On page 2 of Appendix H of the Application (TECH Memo #3), it is noted that “FEI has

identified several project requirements that must be met. The first requirement is that the

energy rate charged by FEI to the DESS clients is equal to the tier 2 BC Hydro electricity

rate. To achieve this goal the estimated capital costs of the DESS project must align with

the predicted delivered energy (revenue) while meeting internal FEI returns.” [Emphasis

added]

23.1 Please elaborate on this FAES/FEI requirement that the energy rate charged by

FAES/FEI to customers is equal to the tier two BC Hydro electricity rate. What is

the rationale for this requirement and is this requirement still in place?

Response:

This requirement is no longer in place. At the time TECH Memo #3 was prepared, FAES was in

the process of determining the appropriate benchmark for the Project. As the Project evolved

(see discussion in Section 6.5 of the Application), mutually agreed rates for the first three years

were developed based on recent guidance from the Commission in Order G-2-12 in which the

Commission Panel approved using a benchmark based on BC Hydro residential electricity rates

at 50 percent Tier 1 and 50 percent Tier 2 plus a 5% to 10% premium. In the fourth year, rates

will be set according to the forecast cost of service in that year, including an amortization

amount to start to recover the balance in the deferral account.

23.2 Regarding the annual energy rates proposed in the Application, was this

requirement met? Please provide the supporting material.

Response:


23.3 If this requirement is still valid, please demonstrate that the revised energy rates

now proposed for the Marine Gateway Project meet it.




Submission Date:

August 8, 2012



Response:





Submission Date:

August 8, 2012



24.0 Reference: BC Energy Objectives


BCUC 1.49.2 asked FAES to describe the extent to which the Marine Gateway Project

also supports BC Energy Objective (j), among others, which reads as “to reduce waste

by encouraging the use of waste heat, biogas and biomass”.

In response, FAES stated: “The proposed closed-loop geo-exchange system for this

Project utilizes clean and renewable resources because it both extracts or injects energy

in the form of heat from or into the earth as a source of heating and cooling. This is not

biogas or biomass, nor is it waste heat recovery in the conventional sense, however the

principle implicit in energy objective (i) of making efficient use of available energy

sources is present in the energy solution for the Marine Gateway Project.” (Emphasis

added)

In BCSEA 1.2.3, FAES states “… with the availability of heat recovery energy (from

cooling load)” and in BCSEA 1.2.6, FAES states “The Marine Gateway is designed

based upon a large amount of heat recaptured from waste heat from refrigerated cases

in a food store as well as from an in-building cooling system”.

24.1 Please explain why the use of waste heat from refrigeration energy and from the

in-building cooling system is not “waste heat recovery in the conventional sense.”

Response:

In this case, geo-exchange is not waste heat recovery in the conventional sense since waste

heat can be rejected into the ground and recovered at a later date. Further, the conventional

waste heat recovery is generally at a high temperature from an industrial process as an

example. The Marine Gateway is designed based on recovery of rejected heat from building

cooling and is unconventional because it happens at a lower temperature, is not constant or

consistent and is not typically done on a District scale.

24.1.1 In particular, why would the use of waste heat from refrigeration energy

and from the in-building cooling system not help FAES in meeting BC

Energy Objective (j) in regards to the use of waste heat?




Submission Date:

August 8, 2012



Response:

FAES agrees with the Commission’s observation that waste heat from refrigeration energy and

from the in-building cooling system helps to meet BC Energy Objective (j). As described in

Table 3-9 on page 25 of the Application, waste heat from these two sources provides 28% of

total consumption.




Submission Date:

August 8, 2012



25.0 Reference: Monte Carlo Analysis


In BCUC 1.50.3, FAES explains that a Thermal Energy Rate of $0.153/kWh means it is

the 20-year levelized outcome in the 60 percentile, meaning that 60 percent of all the

scenarios produced a 20-year levelized rate below $0.153/kWh.

25.1 Is it equivalent to saying that there is a 60 percent chance that the rate will be

equal to or below $0.153/kWh?

Response:

Yes.

In the Application on page 61, FAES states that “The Monte Carlo results indicate that

rates are competitive in all scenarios when compared to other thermal energy systems

recently approved by the BCUC.” [Emphasis added]

25.2 How does FAES define the term “competitive”?

Response:

When talking about rates specifically, as in the preamble to this question, by “competitive” FAES

means that the rates for the PCI Marine Gateway service will be the same as or close to the

rates (on a levelized basis) charged by other providers of similar services. Please see FAES’s

response to BCUC IR 2.25.3 for actual comparisons that establish that the rates charged for the

service that is the subject of this proceeding are “competitive” with the rates charged for similar

services by other utilities.

However, FAES also uses the term “competitive” in a broader sense (in other contexts) to

connote other attributes of FAES’s service that go beyond dollar-to-dollar rate comparisons, but

that also make FAES’s service “competitive” with other service providers.

In addition, our thermal energy system helps reduce greenhouse gas emissions and supports

BC’s energy objectives as described in Section 8 of the Application. FAES’ energy solution

also offers the potential to provide and/or exchange energy to future developments on adjacent




Submission Date:

August 8, 2012



sites, aligning with the City of Vancouver’s EcoDensity Charter and its goal to be the “greenest

city in the world by 2020”. 5

25.3 Does it mean to say that even the 100 percentile rate of $0.174/kWh (which

means that all scenarios produced a 20-year levelized rate below $0.174/kWh) is

competitive with: 1) Corix’s 20-year levelized rate of $152/MWh; 2) River

District’s 20-year levelized rate of $148/MWh; and 3) Delta School District 37’s

20-year levelized rate of $116/MWh? If not, please clarify what FAES meant by

that.

Response:

A comparison of FAES PCI’s rate of $0.174/kWh at the 100 percentile of the Monte Carlo

sensitivity analysis to the base case scenarios of other levelized rates is not a valid indicator of

competitiveness. Instead, FAES has prepared the table below which compares levelized rates

without sensitivity and levelized rates with sensitivity from among various energy systems to

demonstrate that the PCI Marine Gateway thermal rates are competitive (this is the same table

as was provided in the response to BCUC IR 1.50.5).

Thermal Energy System Order & Date

20 year levelized rate without

sensitvity analysis 20 year levelized rate with sensitvity analysis

Corix 2010 CPCN UniverCity Commission Order C-7-11 $155.84/MWh

From $138/MWh to $ 170/MWh Base Year = 2012

(Table 20 of Neighbourhood Utility Service at

UniverCity, Burnaby CPCN Order G-193-10)

River District Energy 2011

CPCN

Commission Order C-14-11

Decebmer 19, 2011

Order G2-12-2012

$150/MWH

$148/MWH

From $140/MWh to $163/MWh Base Year =

2012(Table 26 District Energy Utility (“DEU”) at the

River District CPCN Order G-141-11)

FortisBC/FAES 2011 Delta SD Commission Order G-88-12 $116/MWh (with $1.36M CIAC)

From $116/MWh to $122/MWh Base Year = 2012

(Table 7 Delta School District Number 37 Order G-

205-11)

FAES PCI Marine Gateway

Application May 2012

Updated Model based on

BCUC IR142.1

$148/MWh

$145/MWh

From $135/MWh to $174/MWh Base Year = 2015

(Table 6-11 of Application)

As shown in the table above, FAES’ base case levelized rates, as well as the 20 year levelized

rates with sensitivity analysis, are equal or similar to the other systems. This demonstrates that

variables in the sensitivity analysis (such as increase in fuel costs, CPI, exchange rates, loads

and capital) affecting FAES’ levelized rate will also affect rates for others. In addition, it is

important to note that PCI’s base case starts at 2015; whereas other systems’ base cases start

5 http://vancouver.ca/greencapital/index.htm

http://vancouver.ca/greencapital/index.htm




Submission Date:

August 8, 2012



at different years such as 2012. The discount factor therefore, will also affect the results of the

levelized rates.

On that basis, FAES continues to believe that rates are competitive in all scenarios when

compared to other thermal energy systems recently approved by the BCUC.




Submission Date:

August 8, 2012



26.0 Reference: Maximum Consumption Limits

Exhibit B-5, BCOAPO 1.4.2

In BCOAPO 1.4.2, FAES states “However, there remains a strong incentive to conserve

energy overall due to the maximum consumption limits placed on the office tower.”

26.1 Please indicate the maximum consumption limits placed on the office tower and

why such limits have been imposed. Please provide the reference material in the

Application.

Response:

The statement made in the response to BCOAPO 1.4.2 is correct, but for clarity it should read

“However, there remains a strong incentive to conserve energy overall due to the maximum

consumption limits in the Service Agreements (filed confidentially with the Commission as

Appendix V due to commercial sensitivity) that were based on peak energy modeling for the

office tower and other customers. Per the Service Agreements, these limits are subject to

change based on review by FAES as necessary.”

The maximum consumption limit will be further revised, if necessary, once actual consumption

data is available to evaluate load characteristics. The consumption limits will ensure that all

types of customers, not only the office tower, will be encouraged to conserve energy.

26.2 Are those limits strictly limited to the office units? If so, why? If not, please

indicate what maximum consumption limits are placed upon the residential

customers (Strata and Rental) and the CRU units, and why.

Response:

No, maximum consumption limits are not strictly limited to the office units. Please refer to the

response to BCUC IR 2.26.1.

Attachment 3.7

BCUC IR3.7 Monte Carlo Updated report.xlsx

Crystal Ball Report - Assumptions

Simulation started on 7/31/2012 at 2:01 PM

Simulation stopped on 7/31/2012 at 2:08 PM

Run preferences:

Number of trials run 25,000

Monte Carlo

Random seed

Precision control on

Confidence level 95.00%

Run statistics:

Total running time (sec) 380.28

Trials/second (average) 66

Random numbers per sec 10,058

Crystal Ball data:

Assumptions 153

Correlations 0

Correlated groups 0

Decision variables 0

Forecasts 4

Page 1


Assumptions

Worksheet: [Copy of BCUC IR 1 39 2 Revised Financial Model_updated Jul 31 with updated O&M sensitivity.xlsm]Inputs

Assumption: 2015 CPI Rate Cell: C77

Logistic distribution with parameters:

Mean 1.97%

Scale 0.65%

Assumption: 2015 LTD Rate Cell: C58


Mean 6.95%

Std. Dev. 0.11%

Assumption: 2015 ROE Cell: C56

Student's t distribution with parameters:

Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5

Selected range is from 6.50% to 13.50%

Assumption: 2015 US$/CAN$ Cell: C74


Mean 1.000

Std. Dev. 0.060

Page 2


Assumption: 2016 CPI Rate Cell: D77


Mean 1.97%

Scale 0.65%

Assumption: 2016 LTD Rate Cell: D58


Mean 6.95%

Std. Dev. 0.11%

Assumption: 2016 Real Gas Price Cell: D131

Uniform distribution with parameters:

Minimum 2.643

Maximum 8.753

Selected range is from 1.000 to 20.000

Assumption: 2016 ROE Cell: D56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Page 3


Assumption: 2016 Station 2 Price Spread Cell: D137

Lognormal distribution with parameters:

Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Assumption: 2016 US$/CAN$ Cell: D74


Mean 1.000

Std. Dev. 0.060

Assumption: 2017 CPI Rate Cell: E77


Mean 1.97%

Scale 0.65%

Assumption: 2017 LTD Rate Cell: E58


Mean 6.95%

Std. Dev. 0.11%

Page 4


Assumption: 2017 Real Gas Price Cell: E131


Minimum 2.643

Maximum 8.753


Assumption: 2017 ROE Cell: E56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2017 Station 2 Price Spread Cell: E137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Assumption: 2017 US$/CAN$ Cell: E74


Mean 1.000

Std. Dev. 0.060

Page 5


Assumption: 2018 CPI Rate Cell: F77


Mean 1.97%

Scale 0.65%

Assumption: 2018 LTD Rate Cell: F58


Mean 6.95%

Std. Dev. 0.11%

Assumption: 2018 Real Electricity Price Change Cell: F110


Location -24.58%

Mean 0.98%

Std. Dev. 2.87%

Assumption: 2018 Real Gas Price Cell: F131


Minimum 2.643

Maximum 8.753


Page 6


Assumption: 2018 ROE Cell: F56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2018 Station 2 Price Spread Cell: F137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Assumption: 2018 US$/CAN$ Cell: F74


Mean 1.000

Std. Dev. 0.060

Assumption: 2019 CPI Rate Cell: G77


Mean 1.97%

Scale 0.65%

Page 7


Assumption: 2019 LTD Rate Cell: G58


Mean 6.95%

Std. Dev. 0.11%

Assumption: 2019 Real Electricity Price Change Cell: G110


Location -24.58%

Mean 0.98%

Std. Dev. 2.87%

Assumption: 2019 Real Gas Price Cell: G131


Minimum 2.643

Maximum 8.753


Assumption: 2019 ROE Cell: G56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Page 8


Assumption: 2019 Station 2 Price Spread Cell: G137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Assumption: 2019 US$/CAN$ Cell: G74


Mean 1.000

Std. Dev. 0.060

Assumption: 2020 CPI Rate Cell: H77


Mean 1.97%

Scale 0.65%

Assumption: 2020 LTD Rate Cell: H58


Mean 6.95%

Std. Dev. 0.11%

Page 9


Assumption: 2020 Real Electricity Price Change Cell: H110


Location -24.58%

Mean 0.98%

Std. Dev. 2.87%

Assumption: 2020 Real Gas Price Cell: H131


Minimum 2.643

Maximum 8.753


Assumption: 2020 ROE Cell: H56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2020 Station 2 Price Spread Cell: H137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 10


Assumption: 2020 Tax Rate Cell: H65

Maximum Extreme distribution with parameters:

Likeliest 25.00%

Scale 3.50%

Assumption: 2020 US$/CAN$ Cell: H74


Mean 1.000

Std. Dev. 0.130

Assumption: 2021 CPI Rate Cell: I77


Mean 1.97%

Scale 0.65%

Assumption: 2021 LTD Rate Cell: I58


Mean 6.95%

Std. Dev. 0.11%

Page 11


Assumption: 2021 Real Electricity Price Change Cell: I110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2021 Real Gas Price Cell: I131


Minimum 2.643

Maximum 8.753


Assumption: 2021 ROE Cell: I56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2021 Station 2 Price Spread Cell: I137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 12


Assumption: 2021 Tax Rate Cell: I65


Likeliest 25.00%

Scale 3.50%

Assumption: 2021 US$/CAN$ Cell: I74


Mean 1.000

Std. Dev. 0.130

Assumption: 2022 CPI Rate Cell: J77


Mean 1.97%

Scale 0.65%

Assumption: 2022 LTD Rate Cell: J58


Mean 6.95%

Std. Dev. 0.11%

Page 13


Assumption: 2022 Real Electricity Price Change Cell: J110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2022 Real Gas Price Cell: J131


Minimum 2.643

Maximum 8.753


Assumption: 2022 ROE Cell: J56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2022 Station 2 Price Spread Cell: J137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 14


Assumption: 2022 Tax Rate Cell: J65


Likeliest 25.00%

Scale 3.50%

Assumption: 2022 US$/CAN$ Cell: J74


Mean 1.000

Std. Dev. 0.130

Assumption: 2023 CPI Rate Cell: K77


Mean 1.97%

Scale 0.65%

Assumption: 2023 LTD Rate Cell: K58


Mean 6.95%

Std. Dev. 0.11%

Page 15


Assumption: 2023 Real Electricity Price Change Cell: K110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2023 Real Gas Price Cell: K131


Minimum 2.643

Maximum 8.753


Assumption: 2023 ROE Cell: K56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2023 Station 2 Price Spread Cell: K137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 16


Assumption: 2023 Tax Rate Cell: K65


Likeliest 25.00%

Scale 3.50%

Assumption: 2023 US$/CAN$ Cell: K74


Mean 1.000

Std. Dev. 0.130

Assumption: 2024 CPI Rate Cell: L77


Mean 1.97%

Scale 0.65%

Assumption: 2024 LTD Rate Cell: L58


Mean 6.95%

Std. Dev. 0.11%

Page 17


Assumption: 2024 Real Electricity Price Change Cell: L110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2024 Real Gas Price Cell: L131


Minimum 2.643

Maximum 8.753


Assumption: 2024 ROE Cell: L56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2024 Station 2 Price Spread Cell: L137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 18


Assumption: 2024 Tax Rate Cell: L65


Likeliest 25.00%

Scale 3.50%

Assumption: 2024 US$/CAN$ Cell: L74


Mean 1.000

Std. Dev. 0.130

Assumption: 2025 CPI Rate Cell: M77


Mean 1.97%

Scale 0.65%

Assumption: 2025 LTD Rate Cell: M58


Mean 6.95%

Std. Dev. 0.11%

Page 19


Assumption: 2025 Real Electricity Price Change Cell: M110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2025 Real Gas Price Cell: M131


Minimum 2.643

Maximum 8.753


Assumption: 2025 ROE Cell: M56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2025 Station 2 Price Spread Cell: M137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 20


Assumption: 2025 Tax Rate Cell: M65


Likeliest 25.00%

Scale 3.50%

Assumption: 2025 US$/CAN$ Cell: M74


Mean 1.000

Std. Dev. 0.130

Assumption: 2026 CPI Rate Cell: N77


Mean 1.97%

Scale 0.65%

Assumption: 2026 LTD Rate Cell: N58


Mean 6.95%

Std. Dev. 0.11%

Page 21


Assumption: 2026 Real Electricity Price Change Cell: N110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2026 Real Gas Price Cell: N131


Minimum 2.643

Maximum 8.753


Assumption: 2026 ROE Cell: N56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2026 Station 2 Price Spread Cell: N137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 22


Assumption: 2026 Tax Rate Cell: N65


Likeliest 25.00%

Scale 3.50%

Assumption: 2026 US$/CAN$ Cell: N74


Mean 1.000

Std. Dev. 0.130

Assumption: 2027 CPI Rate Cell: O77


Mean 1.97%

Scale 0.65%

Assumption: 2027 LTD Rate Cell: O58


Mean 6.95%

Std. Dev. 0.11%

Page 23


Assumption: 2027 Real Electricity Price Change Cell: O110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2027 Real Gas Price Cell: O131


Minimum 2.643

Maximum 8.753


Assumption: 2027 ROE Cell: O56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2027 Station 2 Price Spread Cell: O137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 24


Assumption: 2027 Tax Rate Cell: O65


Likeliest 25.00%

Scale 3.50%

Assumption: 2027 US$/CAN$ Cell: O74


Mean 1.000

Std. Dev. 0.130

Assumption: 2028 CPI Rate Cell: P77


Mean 1.97%

Scale 0.65%

Assumption: 2028 LTD Rate Cell: P58


Mean 6.95%

Std. Dev. 0.11%

Page 25


Assumption: 2028 Real Electricity Price Change Cell: P110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2028 Real Gas Price Cell: P131


Minimum 2.643

Maximum 8.753


Assumption: 2028 ROE Cell: P56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2028 Station 2 Price Spread Cell: P137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 26


Assumption: 2028 Tax Rate Cell: P65


Likeliest 25.00%

Scale 3.50%

Assumption: 2028 US$/CAN$ Cell: P74


Mean 1.000

Std. Dev. 0.130

Assumption: 2029 CPI Rate Cell: Q77


Mean 1.97%

Scale 0.65%

Assumption: 2029 LTD Rate Cell: Q58


Mean 6.95%

Std. Dev. 0.11%

Page 27


Assumption: 2029 Real Electricity Price Change Cell: Q110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2029 Real Gas Price Cell: Q131


Minimum 2.643

Maximum 8.753


Assumption: 2029 ROE Cell: Q56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2029 Station 2 Price Spread Cell: Q137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 28


Assumption: 2029 Tax Rate Cell: Q65


Likeliest 25.00%

Scale 3.50%

Assumption: 2029 US$/CAN$ Cell: Q74


Mean 1.000

Std. Dev. 0.130

Assumption: 2030 CPI Rate Cell: R77


Mean 1.97%

Scale 0.65%

Assumption: 2030 LTD Rate Cell: R58


Mean 6.95%

Std. Dev. 0.11%

Page 29


Assumption: 2030 Real Electricity Price Change Cell: R110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2030 Real Gas Price Cell: R131


Minimum 2.643

Maximum 8.753


Assumption: 2030 ROE Cell: R56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2030 Station 2 Price Spread Cell: R137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 30


Assumption: 2030 Tax Rate Cell: R65


Likeliest 25.00%

Scale 3.50%

Assumption: 2030 US$/CAN$ Cell: R74


Mean 1.000

Std. Dev. 0.130

Assumption: 2031 CPI Rate Cell: S77


Mean 1.97%

Scale 0.65%

Assumption: 2031 LTD Rate Cell: S58


Mean 6.95%

Std. Dev. 0.11%

Page 31


Assumption: 2031 Real Electricity Price Change Cell: S110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2031 Real Gas Price Cell: S131


Minimum 2.643

Maximum 8.753


Assumption: 2031 ROE Cell: S56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2031 Station 2 Price Spread Cell: S137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 32


Assumption: 2031 Tax Rate Cell: S65


Likeliest 25.00%

Scale 3.50%

Assumption: 2031 US$/CAN$ Cell: S74


Mean 1.000

Std. Dev. 0.130

Assumption: 2032 CPI Rate Cell: T77


Mean 1.97%

Scale 0.65%

Assumption: 2032 LTD Rate Cell: T58


Mean 6.95%

Std. Dev. 0.11%

Page 33


Assumption: 2032 Real Electricity Price Change Cell: T110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2032 Real Gas Price Cell: T131


Minimum 2.643

Maximum 8.753


Assumption: 2032 ROE Cell: T56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2032 Station 2 Price Spread Cell: T137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 34


Assumption: 2032 Tax Rate Cell: T65


Likeliest 25.00%

Scale 3.50%

Assumption: 2032 US$/CAN$ Cell: T74


Mean 1.000

Std. Dev. 0.130

Assumption: 2033 CPI Rate Cell: U77


Mean 1.97%

Scale 0.65%

Assumption: 2033 LTD Rate Cell: U58


Mean 6.95%

Std. Dev. 0.11%

Page 35


Assumption: 2033 Real Electricity Price Change Cell: U110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2033 Real Gas Price Cell: U131


Minimum 2.643

Maximum 8.753


Assumption: 2033 ROE Cell: U56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2033 Station 2 Price Spread Cell: U137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 36


Assumption: 2033 Tax Rate Cell: U65


Likeliest 25.00%

Scale 3.50%

Assumption: 2033 US$/CAN$ Cell: U74


Mean 1.000

Std. Dev. 0.130

Assumption: 2034 CPI Rate Cell: V77


Mean 1.97%

Scale 0.65%

Assumption: 2034 LTD Rate Cell: V58


Mean 6.95%

Std. Dev. 0.11%

Page 37


Assumption: 2034 Real Electricity Price Change Cell: V110


Location -24.58%

Mean 0.97%

Std. Dev. 2.87%

Assumption: 2034 Real Gas Price Cell: V131


Minimum 2.643

Maximum 8.753


Assumption: 2034 ROE Cell: V56


Midpoint 10.00%

Scale 0.95%

Deg. Freedom 5


Assumption: 2034 Station 2 Price Spread Cell: V137


Location 86.25%

Mean 106.88%

Std. Dev. 19.99%

Page 38


Assumption: 2034 Tax Rate Cell: V65


Likeliest 25.00%

Scale 3.50%

Assumption: 2034 US$/CAN$ Cell: V74


Mean 1.000

Std. Dev. 0.130

Assumption: Capital Sensitivity Cell: B24


Mean 1.00

Std. Dev. 0.05 (=0.05)

Assumption: Load Sensitivity Cell: B229


Mean 1.00

Std. Dev. 0.10

Page 39


Assumption: O&M Sensitivity Cell: B241


Mean 1.00

Std. Dev. 0.05

End of Assumptions

Page 40

Attachment 5.1

TABLE 6.8.3 Minimum Pipe Insulation Thickness

Fluid Design Insulation Conductivity Nominal Pipe or Tube Size (mm)

Operating Temp. Conductivity Mean Rating Range (Oq (W/m'K) Temp.oC <25 25 to <40 40 to <100 100 to <200 :::::200

Heating Systems (Steam, Steam Condensate, and Hot Water)b C

>177 0.046-0.049 121 6.4 7.6 7.6 10.2 10.2

122-177 0.042-0.046 93 3.8 6.4 7.6 7.6 7.60

94-121 0.039-0.043 66 3.8 3.8 5.1 5.1 5.1

61-93 0.036-0.042 52 2.5 2.5 2.5 3.8 3.8

41-60 0.032-0.040 38 1.3 1.3 2.5 2.5 2.5

Domestic and Service Hot Water Systems

41+ 0.032-0.040 38 1.3 1.3 2.5 2.5 2.5

Cooling Systems (Chilled Water, Brine, and Refrigerant)d

4-16 0.032-0.040 38 1.3 1.3 2.5 2.5 2.5

<4 0.032-0.040 38 1.3 1.3 2.5 2.5 3.8

a For insulation outside the stated conductivity range, the minimum thickness (T) shall be determined as follows: T = r{(l + /Ir{fk ... I} where T = minimum insulation thickness (cm). r = actual outside radius of pipe (cm), I = insulation thickness listed in this table for applicable fluid temperature and pipe size, K = conductivity of alternate material at mean rating temperature indicated for the applicable fluid temperature (W 1m' K); and k= the upper value of the conductivity range listed in this table for the applicable fluid temperature.

b These thicknesses are based on energy efficiency considerations only. Additional insulation is sometimes required relative to safety issueslsurface temperature. c Piping insulation is not required between the control valve and coil on run-outs when the control valve is located within 1.2 m of the coil and the pipe size is 25 mm or less. d These thicknesses are based on energy efficiency considerations only. Issues such as water vapOt permeability or surface condensation sometimes require vapor retarders or addi

tional insulation.

ANSIIASHRAE/IESNA STANDARD 90.1-2004 55

jbekesza

Text Box

BCUC IR 2.5.1PIPE INSULATION

Attachment 13.4

REFER TO LIVE SPREADSHEET Provided in electronic format only

(accessible by opening the Attachments Tab in Adobe)

Attachment 14.2

1

FortisBC Energy Inc.

Internal Audit Report

To: John Walker, President and CEO

Cc: Scott Thomson, Executive Vice President, Finance, Regulatory & Energy Supply

David Bennett, Vice President and General Counsel

Roger Dall’Antonia, Vice President, Finance & Chief Financial Officer; Treasurer (Gas)

From: Terry McMillan, Director, Internal Audit

Date: December 8, 2011

Re: Annual Review of Compliance with the Code of Conduct and Transfer Pricing Policy

Introduction

Internal Audit has completed a review of compliance with the Code of Conduct and Transfer Pricing

Policy (COC & TPP). This review is conducted to satisfy the following requirements:

“FortisBC Energy Inc. (the Company) will ensure that it receives adequate compensation for

the resources and services provided, thereby protecting ratepayers from subsidizing unregulated

activities.”

“FortisBC Energy Inc. will monitor employee compliance with the Code of Conduct by

conducting an annual compliance review, the results of which will be summarized in a report to

be filed with the Commission (B.C. Utilities Commission) within 60 days of the completion of

this review.” 1

“The Transfer Pricing Policy will be reviewed on an annual basis as part of the Code of

Conduct compliance review.” 2

Background

The COC & TPP were issued in August 1997 to govern the relationships between the Company and Non-

Regulated Businesses (NRBs) for the provision of Utility resources. NRBs are defined as: “an affiliate of

the Utility not regulated by the Commission or a division of the Utility offering unregulated products

and/or services”.3 The Company has processes and practices that are designed to ensure compliance with

these Policies.

Objective and Approach

Objective:

Consistent with prior years, the objective of this review is to determine whether the existing processes and

controls that support compliance with the COC & TPP are adequately designed and operating effectively

during the period under review.

1 Item 7 Code of Conduct 2 Item 7 Transfer Pricing Policy 3 page 2 Definitions, both Code of Conduct and Transfer Pricing Policy

2

Approach:

Our review of business processes and controls that support compliance with the COC & TPP was made in

accordance with Canadian generally accepted standards for review engagements as set out in the

Canadian Institute of Chartered Accountants Handbook. Procedures for enquiry, analytical procedures

and discussion included the following:

Review the Code of Conduct and Transfer Pricing Policy.

Make enquires to understand the provision of Utility resources to NRBs.

Make enquiries to understand the processes and controls maintained by the Company to comply with

the COC & TPP.

Review evidence of such processes and controls and determine whether the Company is in

compliance with the COC & TPP.

Conclusion

As a result of this review, it can be concluded that FortisBC Energy Inc. is operating within the

requirements of the Code of Conduct and Transfer Pricing Policy and the internal controls in place are

effective in ensuring that the regulated customer is not subsidizing non-regulated business activities.

Attachment 19.1


FILED CONFIDENTIALLY


Attachment 22.5.1



diane roy director, regulatory affairs - gas b-13 fortisbc ... · areas have been adjusted over...

Documents