David Bennett FortisBC Inc. Regulatory Affairs Department ... · OSO1 Meadowlark Dr and 74th Ave(single structure) PIN3 356th Ave OLI1 White Lake Rd 396Ave OSO1 87th St Osoyoos(replace

September 28, 2006 Via Email Original via mail Mr. R. J. Pellatt Commission Secretary British Columbia Utilities Commission Box 250, Sixth Floor, 900 Howe Street Vancouver BC V6Z 2N3 Dear Mr. Pellatt: Re: FortisBC Inc.’s 2007-2008 Capital Expenditure Plan and 2007 System Development Plan Update Please find enclosed for filing 20 copies of FortisBC Inc.’s response to BC Utilities Commission Information Request No. 2 and Information Request No. 1 from the BCOAPO and Mr. Alan Wait regarding the above noted application.

Also enclosed is a two page document that summarizes changes to the 2007-2008 Capital Expenditure Plan filed July 26, 2006.

Should you require further information in this matter, please contact the undersigned at 250 717 0853. Sincerely, David Bennett General Counsel and Corporate Secretary cc: Registered Intervenors

FortisBC Inc. Regulatory Affairs Department 1290 Esplanade, Box 130 Trail, BC V1R 4L4 [email protected] www.fortisbc.com

David Bennett General Counsel and Corporate Secretary

B-4

mailto:[email protected]

http://www.fortisbc.com/

cnsmith

2007 CEP&SDP

2007-2008 Capital Expenditure Plan

(“2007/08 Capital Plan”) Changes to the July 26, 2006 Application

The following tables summarize changes to the 2007/08 Capital Plan since filing.

Project 2007 2008 Total

($000s)

Reference 2007/08

Capital Plan Reference

West Osoyoos Transformer Rehabilitation (Note 1) - - -150 Page 34

Table 3.1 BCUC IR1

Q18

Distribution Feeder Egress Cables – project cancelled (Note 1) (244) - (244) Page 68

Table 4.2 BCUC IR1

Q58.1

AM/FM System (Note 2) (386) - (386) Page104 Table 7.8

CPCN Application

filed August 18,

2006

DSM Tax Rate Change (Note 3) 84 91 175 Page 94 Table 6.1

Change to 2007/08 Capital Plan (546) 91 (455)

2007/08 Capital Plan Changes to the July 26, 2006 Application

Page 2

Reconciliation of 2007/08 Capital Plan as filed and at September 28, 2006

2007 2008 Total ($000s) 2007/08 Capital Plan July 26, 2006 128,621 111,607 240,228

Changes to 2007/08 Capital Plan (546) 91 (455)

2007/08 Capital Plan Revised September 28, 2006 128,075 111,698 239,773

Correction to 2006 Expenditure as stated in the 2007/08 Capital Plan

Project 2006 2007 2008

($000s)

Reference 2007/08

Capital Plan Reference

West Osoyoos Transformer Rehabilitation (Note 4)

- 150 - - Page 34 Table 3.1

BCUC IR1 Q18

Notes:

1. The ampacity rating that the Company used for evaluating the capacity of the existing feeder egress cables was incorrect. When the correct ampacity was used, it became apparent that the existing cables are adequate and the project is no longer required.

2. The forecast expenditure listed in Table 7.8 of the 2007/08 Capital Plan was inadvertently subjected to duplicate overheads of $386,000 for 2007. The CPCN that was filed on August 18, 2006, has the corrected expenditure forecast.

3. While developing the deferred charge schedule for the 2007 Revenue Requirement Application, the Company determined that it had used an incorrect tax rate in its calculations for the 2007/08 Capital Plan. The Company had used the statutory tax rate of 34.12% versus 33.0% which is the tax rate net of federal surtax as applicable for deferred charges.

4. The prior years forecast expenditures (up to December 31, 2006) were inadvertently noted as $1,723,000 in Table 3.1 of the 2007/08 Capital Plan. The actual forecast expenditures should have read $1,573,000 for a difference of $150,000.

FortisBC 2007/08 Capital Expenditure Plan and 2007 System Development Plan Update

BCUC Information Request No. 2 Request Date: September 15, 2006 Response Date: September 28, 2006

Page 1

63.0 Reference: BCUC IRs 1.3.1, 1.3.2 1

The lists of proposed rebuilds that resulted from each region were reviewed by the 2

planning and engineering groups to provide a consistent assessment of the plant that 3

was classified as deteriorated by the different regions. 4

Q63.1 Please state the criteria by which plant was classified as “deteriorated,” and 5

describe the review process. 6

A63.1 The following is the criteria by which plant is classified as deteriorated and the review 7

process used to identify and prioritize projects. 8

Criteria by which plant is classified as deteriorated: 9

The distribution structures are systematically assessed based on structure categories and 10

guidelines. Outlined below is a summary extracted from the FortisBC Overhead System 11

Line Patrol Program. If any action is required it is categorized by one of the following 12

priority codes 13

• High emergency corrective action required 14

• Medium corrective action required within 2 to 6 months 15

• Low corrective action required in 6 to 12 months (normal 16

planned rehabilitation or rebuild). 17

• Monitor condition to be checked on next patrol to see if condition 18

has deteriorated or changed. 19

Poles 20

• Surface rot, 21

o circumference greater than 1200mm and surface rot greater than 50mm for 22

30% of the circumference 23

o circumference between 775mm and 1200mm and surface rot greater than 24

25mm for more than 30% of the circumference. 25

• Degree of split top, woodpecker damage, fire damage, vehicle contact damage. 26

Crossarms 27

• Assess degree of lightning damage (if present) and splitting. 28



Page 2

• No action normally for minor surface rot or minor internal rot around through 1

bolts and insulator pins. 2

Insulation 3

• Broken chipped insulators. 4

• Presence of Ohio Brass insulators 5

• Under insulated for voltage level (substandard) 6

Conductor Ties 7

• Presence of rust on an insulator an indicator of a broken or worn tie and possible 8

damage to conductor and/or insulator. 9

• Broken tie may be an indicator of improper sag (too tight). 10

Guying 11

• Broken or missing guy 12

• Un-insulated guy wire above energized primary (substandard) 13

• Guy strain insulator added if the anchor head is buried and digging out the anchor 14

still leaves a situation where the water cannot drain away. 15

• Guy strain insulator should be added to structures with double pins.(substandard) 16

• Missing guy guard 17

• Faded and wood guy guards in high traffic areas. 18

Hardware 19

• Assess risk of porcelain lightning arrestors in installed location. 20

• Arrestors installed at high fault level locations (standard) 21

Conductor 22

• Re-ties, re-sags recommended 23

• Insufficient ground clearances (substandard) 24

• Insufficient inter-circuit clearance (substandard) 25

• Navigable waters clearance, marking (substandard) 26

Apparatus 27

• Transformer dripping oil. 28

• CSP transformers on a wye-wye bank. 29



Page 3

• CSP transformers for overloading. 1

• Switches with cracked or broken insulation 2

• Switch on riser pole in looped feed (substandard) 3

• three-phase ganged switches to be inspected for operation 4

5

Review Process used to identify and prioritize projects: 6

The assessment of the system facilities as outlined above are performed by a qualified 7

power line technician (“PLT”) through line patrols. Along with the competency gained 8

from years of experience working on the very structures they are assessing, the PLT is 9

also trained in line patrol procedure in order to bring consistency to the assessment 10

process. Typically, action items are interspersed throughout the feeder, however 11

occasionally the line patrol identifies an “area” of concern where the number of 12

deficiencies makes it impractical to address the structure or component individually. In 13

such cases a line rebuild project is put forth by the program. The rebuild section is 14

identified by a “redline” and electronically transmitted to the AM/FM data group so that 15

all structures within the “redline” boundary can be updated with an “action required” 16

note. An electronic map and description of the area is transmitted to the Regional 17

Engineer to initiate the engineering and planning reviews of the identified line rebuild. 18

The Regional Engineer will document the rebuild then schedule a review of the line 19

section by Engineering for a “consistency” check from region to region. Planning will 20

also review the individual sites to apply a second consistency check within the region. 21

22

In assigning the projects to specific years, the Regional Engineers consider the safety 23

implications and risk as well as customer service and reliability. They also schedule the 24

work within the realities that there are limited human and financial resources available to 25

complete the work. 26

27

As an example, the following is a list of identified rebuilds in the South Okanagan 28

Region. The list forms a “Planning Concept Document” used to catalog all locations and 29



Page 4

to track Operations, Engineering and Planning field assessments. Those items listed for 1

2007 and 2008 are considered to have a higher degree of safety concern than the 2

remainder. Of the 42 line rebuilds identified in this list, seven items are planned to be 3

addressed in the 2007-2008 timeframe. The rebuilds “Planning Concept Document” is 4

continuously revised to ensure the inclusion of any newly identified areas of concern, 5

delete items addressed, and to form a basic document from which to manage the highest 6

areas of concern in the distribution system. 7

8



Page 5

Feeder Location ScheduleKER2 KER 9th to 12th Section 4 2007HED2 River crossing west of Wolf Lake 2007KER2 KER 9th to 12th Section 14 2007

OLI1

Line feeding Fairview road from White Lake road through Burnell Lake Section 1(above Burnell Lake) 2007

KER2

3-way deadend at intersection of Hwy3 and 3A(part of KER feeder cap upgrade) 2007

PIN2 87th/Miller Rd 2008PIN1 95th St. Oliver

PIN1Distribution south of airport in Oliver

OLI2Oliver 39283-Hwy 97(replace 5 structures)

KAL1 Cypress Rd Kaleden Section 1 2008

OSO1Meadowlark Dr and 74th Ave(single structure)

PIN3 356th AveOLI1 White Lake Rd 396Ave

OSO187th St Osoyoos(replace 4 structures)

KER2 Middle Bench RdWEB1 Penticton RedwingKER2 Replace switches to LoadbreakKAL1 Cypress Rd Kaleden Section 2KER2 KER2 76N25 to Danko MinePIN3 350th Ave 107th St to 123rd St

NAR2Narmata relocate old 45L from Eye Ball Rock

KER2 KER 9th to 12th Section 3KER2 KER 9th to 12th Section 8KER2 KER 9th to 12th Section 7KER2 KER 9th to 12th Section 13KER2 KER 9th to 12th Section 2KER2 KER 9th to 12th Section 9KER2 KER 9th to 12th Section 1KER2 KER 9th to 12th Section 5KER2 KER 9th to 12th Section 6KER2 KER 9th to 12th Section 10KER2 KER 9th to 12th Section 11KER2 KER 9th to 12th Section 12KER2 KER 9th to 12th Section 15OLI1 4.1km north on OLI1KAL1 Lake Hill Rd KaledenOKF3 McClean Creek RdOSO1 Meadowlark Dr and 74th AvePIN3 Fairview RdOLI1 Pineridge Rd

OLI1

Line feeding Fairview road from White Lake road through Burnell Lake Section 2(below Burnell Lake)

KER2 KER 9th to 12th Section 16 1



Page 6

Q63.2 Were the age profiles of in-service assets available at the time FortisBC acquired the 1

assets? If so, what is FortisBC’s view as to why the amount of deteriorated and 2

substandard distribution plant has exceeded its expectations? 3

A63.2 The general age profile of in-service assets was available at the time FortisBC acquired 4

the assets. 5

6

The reference to the statement “the amount of deteriorated plant has exceeded FortisBC’s 7

previous expectation” is in reference to the expectations that were used as the basis for 8

estimating purposes when the 2005-2024 SDP was developed in 2004. 9

10

Q63.3 Is FortisBC able to link the substandard plant to materially worse reliability 11

metrics? If not, what is the driver for the replacement of such plant? 12

A63.3 FortisBC does not specifically link the substandard plant to materially worse reliability 13

metrics. (please see the response to BCUC IR2 Q65.2). The primary driver for the 14

replacement of plant in the rebuild project is not that it is substandard, but that a 15

significant amount of the plant is deteriorated. In FortisBC’s engineering judgment the 16

deteriorated plant should be replaced primarily for safety reasons but also for service 17

reliability purposes. It is FortisBC’s view that if deteriorated plant is not replaced it will 18

lead to increased safety incidents and degradation of service reliability as the plant fails in 19

service. 20

21

Q63.4 Does FortisBC believe that its standards are materially higher than those of the 22

previous owner? Please explain. 23

A63.4 FortisBC does not believe its standards for construction are materially higher than the 24

previous owner. 25

26

The Company is of the view that sound utility management requires that deteriorated 27

plant be replaced on a timely basis. It believes that plant that has been inspected and 28

deemed to be deteriorated by knowledgeable, experienced staff; should not be allowed to 29



Page 7

fail in service, when such failure has a risk of creating safety incidents and degradation of 1

service reliability. 2

3

In its transition plan that was filed with its 2005 Revenue Requirements Application, the 4

Company among other things stated in Section 10.3, page 4 line 14-18 5

6

“In addition to the intentions stated in the Application, multiple stakeholder and public 7

consultations were conducted regarding the Acquisition and transition. During these 8

consultations, the Company also stated its intention to, within a reasonable transition 9

period: 10

11

1. improve the overall quality of service to customers;” 12

13

FortisBC believes that replacing deteriorated plant before it fails in service, and 14

upgrading significantly deteriorated sections of substandard plant is in concert with the 15

commitment outlined in its transition plan. 16

17


FortisBC lists a 2005 Infrastructure Upgrade that was $150,000 over on a $225,000 19

budget due to additional server requirements. FortisBC also spent an unbudgeted 20

$359,000 on CIS+ enhancements that improved data entry efficiency and reporting. 21

Q64.1 Please elaborate on the “additional server requirements” that resulted in the over-22

run on the infrastructure upgrade. 23

A64.1 There were four items that contributed to the above normal expenditures in the 24

infrastructure upgrade project. These include: 25

26

Two new servers that were necessary to meet the Microsoft SQL requirements that were 27

higher than expected, as a number of existing and new applications experienced 28

performance and storage issues. These costs were allocated to this project, as the servers 29

were shared for several applications. 30



Page 8

1

Software costs that were higher than expected were primarily due to the Microsoft 2

licensing true-up cost that is part of this budget and to the number of new hires in 2005. 3

4

Two unanticipated tape drive failures that required immediate replacement. 5

6

Unanticipated upgrades to the satellite network infrastructure which is required to serve 7

the remote substation maintenance trailer. This was due to the increased data 8

requirement for the remote unit that the existing equipment could not deliver at a usable 9

rate. 10

11

Q64.2 Please elaborate on the improvements in data entry and reporting. How have these 12

improvements been measured? 13

A64.2 Improvements made in the quality of data entry within the CIS system include: 14

• Increased billing error edits to allow correction prior to bills reaching customers. 15

• Reducing the maximum number of consecutive estimates that a customer can 16

receive from 9 to 3. 17

• Creating an automatic transfer of balances between old and new service agreements 18

to ensure customers receive the correct collections treatment as required. 19

• Reductions in the number of final notices being sent (from an average of 12 to 3) in 20

order to save un-necessary printing costs and to reduce returned mail. 21

• Audit of the print file to ensure all bills created are sent to the printer and mailed to 22

customers. 23

24

Improvements made to reporting within the CIS system include: 25

• A residential meter consumption audit report which includes meters with 26

exceptionally low and exceptionally high consumption. 27

• A report of unexpected consumption changes over previous billing period and / or 28

the same period last year. 29



Page 9

• A report of service points that have a higher consumption levels than the service 1

was designed for. 2

• Automatic creation of a message for the collections group whenever a payment 3

arrangement is broken on a delinquent account. 4

• A report of estimated reads and skip-codes by meter. 5

6

The improvements have been measured by the Company’s ability to have reduced errors 7

in its customer accounts and its ability to make improvements in customer service. 8

9

These changes in the quality of data entry and the Company’s reporting capability have 10

been deemed necessary to allow the Company to make improvements in customer service 11

including Billing Accuracy, Meter Reading Accuracy and overall Customer Satisfaction 12

levels. 13

14


FortisBC lists the main criteria used in establishing line rebuild priorities include 16

objective measures such as age of plant, level of deterioration, and level of standard 17

violations, as well as subjective measures such as perceived level of risk and the 18

anticipated amount of recurring outages that may be eliminated or avoided with a 19

line rebuild. However, reliability statistics (specifically SAIDI and SAIFI for the 20

whole feeder) are not used in setting priorities. 21

Q65.1 Please describe in detail the objective measures for level of deterioration and level of 22

standards violation that FortisBC uses. 23

A65.1 Please see the response to BCUC IR2 Q63.1. 24



Page 10

Q65.2 Please explain why reliability statistics are not used to set rebuild priorities, but 1

subjective estimates of reductions in recurring outages are. 2

A65.2 The Company does record reliability statistics such as SAIFI and SAIDI at a feeder level 3

(see 2007/08 Capital Plan, page 125-128). Generally the number of customers associated 4

with the sections of line that are included in the rebuild program are very low when 5

compared to the total number of customers on the feeder, and as such would have an 6

insignificant affect on the feeder SAIFI and SAIDI should that section of line experience 7

an outage. Consequently the Company has not found it helpful to use the feeders 8

previous years SAIFI or SAIDI for prioritizing its rebuild projects. 9

10

The rebuild project involves sections of line that have been inspected and identified as 11

having deteriorated and substandard plant that if left unattended will result in plant failure 12

with possible safety incidents and service outages. The anticipated amount of recurring 13

outages that may be eliminated or outages that may be avoided by a line rebuild is used in 14

setting priorities since everything else being equal, the Company would select the section 15

of line that affects the greatest number of customers. 16

17

66.0 Reference: Exhibit B-1, page 7, Table 1.1 18

Q66.1 Please provide the rate impacts of the proposed capital expenditures for the years 19

2007 and 2008. 20

A66.1 Although there are some costs and benefits in the year of expenditure, for the most part, 21

the impact of capital expenditures on revenue requirements is in the form of tax timing 22

differences, the cost of equity and debt, property taxes and depreciation expense which 23

does not materialize until the year after the expenditure is added to plant in service. The 24

2007 forecast capital expenditures are expected to impact 2008 rates by approximately 25

4.4% while the 2008 expenditures are forecast to have a further impact of 3.4% in 2009. 26



Page 11

67.0 Reference: Exhibit B-2 BCUC IR 10.2 1

Q67.1 Please provide a map outlining the Kelowna City Municipal Utility Boundary. 2

A67.1 The map attached as BCUC A67.1 outlines the Kelowna City Municipal Electrical Utility 3

Boundary. 4

5

Q67.2 Please provide the Agreement with the city that defines the boundaries and the 6

relationship that FortisBC has with the City (i.e. re planning and service). 7

A67.2 The service agreement exists between FortisBC’s parent company, Fortis Pacific 8

Holdings Inc. (“FPHI”) and the City of Kelowna. FortisBC provides service to the City 9

of Kelowna pursuant to a Subcontractor Agreement between FPHI and FortisBC, which 10

has been approved by the Commission. A brief description of the relationship between 11

FortisBC and the City of Kelowna is provided here. 12

13

The boundaries of the municipal utility are defined in Appendix B of the Agreement for 14

the Supply of Electricity – Wholesale Service between FortisBC and the City of 15

Kelowna. A copy of that Agreement is attached as BCUC A67.2. 16

17

FortisBC’s Regional Engineer plans both the City’s electrical system as well as the 18

FortisBC electrical system outside the municipal utility’s boundaries. The Regional 19

Engineer is involved in an annual planning meeting to understand the growth of the City 20

and also meets with the City planning department periodically through out the year. Each 21

distribution system operates independently of each other, however services provided to 22

the City, including trouble and outage response and restoration, non payment disconnects, 23

connect and disconnects related to tenant changes in residential and commercial 24

premises, and metering services including retest and legislative compliance are required 25

to meet the same standards as FortisBC’s operations. 26

27

The planning for the entire city (both FortisBC and City service areas) is derived from 28

information from local developers; the City of Kelowna’s planning department, and 29



Page 12

consultation on the Kelowna Official Community Plan (“OCP”) which outlines the 1

development for the City from 2000 to 2020. In 2005, the City reviewed the OCP to 2

determine if it required updating. During the course of that review, it determined that the 3

community is developing within 5% of its 2000 predictions and consequently the 4

community plan did not require any change. This speaks to the confidence that FortisBC 5

has in the OCP and its own load growth forecasting, which is based on the OCP. 6

7

In 2005, the City of Kelowna contracted FortisBC to develop a 20-year System 8

Development Plan for the City’s electrical system. FortisBC’s Kelowna regional 9

engineer in conjunction with an external consultant developed the plan which was 10

accepted by the City in November 2005. 11

12

68.0 Reference: Exhibit B-3, page 45, slide 89 13

Q68.1 If the Commission did not approve the capital expenditure budgets for the 14

Distribution Line Rebuild and Rehabilitation programs, how would FortisBC select 15

and prioritize the work proposed for these programs? 16

A68.1 As outlined in response to BCUC IR2 Q63.1 , in assigning the rebuild projects to a 17

specific year, FortisBC’s Regional Engineers gave due consideration to the safety 18

implications and risk as well as customer service and reliability. They also schedule the 19

work within the realities that there are limited human and financial resources available to 20

complete the work. Where the Company has been able to reduce capital to address these 21

issues it has already done so. 22

23

The Company is of the opinion that any imposed project delays will have negative 24

consequences on safety, customer service and reliability. FortisBC believes it would 25

experience increases in public and employee safety incidents, degradation in customer 26

service and reduced reliability if the capital expenditure budgets for the Distribution Line 27

Rebuild and Rehabilitation programs are not approved. The projects listed in Tables 28

4.10(b) and 4.10(c) of the 2007/08 Capital Plan are a small portion of the sections of line 29



Page 13

that have been inspected and are currently listed as being in need of replacement within 1

the next five year. As noted deferring such work to future years will lead to increased 2

safety incidents and reduced customer service. Should the Commission deem it 3

necessary to take such action, the Company would use its engineering judgment to 4

manage the projects in an attempt to minimize the negative impacts. 5

6

As outlined in the 2007/08 Capital Plan, FortisBC’s ability to meet its obligations to 7

provide quality electrical service to its customers is largely dependant upon the quality 8

and condition of its capital plant. 9

10

The electrical distribution network assets are geographically dispersed throughout the 11

Company’s service territory and include approximately 77,000 distribution poles, 31,000 12

distribution transformers, and approximately 5,000 kilometers of distribution circuitry. 13

14

FortisBC’s annual capital plans reflect the management of these relatively large number 15

of components spread over a broad geography that make up the electrical system by 16

which the Company delivers service to its customers. 17

The capital expenditures also reflect the Company’s capital management practices. The 18

annual plans are principally aimed at the prudent refurbishment of existing in service 19

assets as well as the extension of the electricity network to meet new service. FortisBC is 20

focused on managing its capital assets in a way which results in the lowest possible cost 21

to customers consistent with reliable service. 22

23

Conceptually, the Company’s approach to capital management of existing assets attempts 24

to balance the maximization of asset lives with the proactive replacement of deteriorated 25

plant. Maximizing asset lives tends to lower overall costs. However, the longer that 26

these facilities are in the field and exposed to climatic stresses, the greater the likelihood 27

of failure which often results in customer outages and operating costs. Capital 28



Page 14

expenditures for planned replacement of deteriorated distribution plant typically accounts 1

for 15-20% of FortisBC’s annual capital expenditures in the distribution category. 2

3

Average capital expenditures for distribution asset replacement for the most recent five 4

year period were approximately $3.2 million. This represents less than 1.0% of the cost 5

of installed distribution plant at the end of 2005. 6

7

Rehabilitation: Each year, the Company performs condition assessments on a portion of 8

its total distribution lines. These assessments yield information for the Company’s 9

annual distribution line capital rehabilitation program. 10

11

The routine capital maintenance resulting from regular condition assessments tends to 12

focus on individual distribution line components on a systematic basis. All distribution 13

lines have like components such as poles, crossarms, guy wires, and conductor. The 14

rehabilitation project attempts to keep the components in reasonable condition, until such 15

time as a total rebuild of a particular section of line becomes necessary due to a capacity 16

upgrade resulting from growth (see growth projects) or the overall general condition of 17

that section of line deteriorates to the point of becoming a safety or reliability concern. 18

19

Distribution Line Rebuilds: On a regular basis FortisBC’s Distribution Planning 20

Engineers undertake an evaluation of the distribution system in their particular area. The 21

results of the evaluation is a portfolio of projects identifying sections of line that have 22

deteriorated to the point that if left unattended , will result in increased public safety and 23

employee incidents or reduced reliability. 24

25

FortisBC believes that there is a strong correlation between planned preventive 26

maintenance, safety and reliability and that its current maintenance practices are essential 27

and will contribute to maintaining its current levels of safety and reliability. 28

BCUC A67.1

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BCOAPO Information Request No. 1 Request Date: September 15, 2006 Response Date: September 28, 2006

Page 1

1 Reference: SDP, page 3, lines 18-22 and Appendix 1, pages 3, 8, 29 & 30 1

Q1.1 Please provide a schedule that compares the following summer total load forecasts 2

for each of the four areas (i.e., North Okanagan (Kelowna), South Okanagan-3

Similkameen, Kootenay and Boundary): 4

o The Load Forecast underlying the 2005 SDP, 5

o The Load Forecast underlying the 2006 SDP Update, and 6

o The current Load Forecast underlying the 2007 SDP Update. 7

The schedule should cover the years 2001/02 through 2011/12 and report historical 8

values where appropriate 9

A1.1 The 2005 SDP and 2006 SDP Update contained a winter peak load forecast only because 10

FortisBC’s system as a whole is winter peaking by a margin of approximately 20% over 11

summer peak levels. In 2005, it was recognized that a few areas within the FortisBC 12

service area such as Osoyoos were already or were becoming summer peaking load areas. 13

At that time a summer forecast was compiled but was not included in the 2006 SDP 14

update. The practice of including a summer forecast in the SDP updates began in 2006 15

(for the 2007 SDP Update). Summer forecasts for 2006 and 2007 are shown below. 16 North Okanagan Summer

2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/122005 SDP2006 Update 237,408 246,135 255,162 263,989 272,616 280,843 2007 Update 249,711 260,331 271,785 283,443 295,505 307,984 Historical 184,112 197,361 208,959 224,280 220,241

North Okanagan Summer Demand Forecast

050000

100000150000200000250000300000350000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA

) 2005 SDP2006 SDP2007 SDPHistorical

17



Page 2

South Okanagan/Similkameen Summer2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12

2006 187,596 192,450 197,472 202,665 208,027 213,558 2007 Update 188,767 193,751 198,903 204,224 209,713 215,371 Historical 158,583 166,346 178,214 172,898 169,885

South Okanagan/Similkameen Summer Demand Forecast

-

50,000

100,000

150,000

200,000

250,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA

)

20062007 SDPHistorical

Kootenay Summer

2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/122006 153,607 154,902 156,198 157,493 158,788 160,083 2007 Update 152,353 153,629 154,905 156,182 157,458 158,734 Historical 129,649 127,636 148,918 143,790 142,177

Kootenay Summer Demand Forecast

-20,00040,00060,00080,000

100,000120,000140,000160,000180,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA

)

20062007 SDPHistorical



Page 3

Boundary Summer2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12

2005 SDP2006 Update 42,979 43,521 44,067 44,617 45,171 45,729 2007 Update 44,126 44,631 45,140 45,653 46,171 46,692 Historical 35,823 38,593 41,797 41,749 42,518

Boundary Summer Demand Forecast

0

10000

20000

30000

40000

50000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA




Page 4

Q1.2 Please provide a schedule that compares the following winter total load forecasts for each 1

of the four areas (i.e., North Okanagan, South Okanagan-Similkameen, Kootenay and 2

Boundary): 3

o The Load Forecast underlying the 2005 SDP, 4

o The Load Forecast underlying the 2006 SDP Update, and 5

o The current Load Forecast underlying the 2007 SDP Update. 6

The schedule should cover the years 2001/02 through 2011/12 and report historical 7

values where appropriate 8

A1.2 The tables below provide the requested information. 9

North Okanagan Winter2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12

2005 SDP 244,941 253,935 259,393 267,530 276,179 285,062 2006 Update 272,675 283,979 295,582 306,985 318,188 328,991 2007 Update 279,602 297,447 311,174 324,138 338,920 352,835 Historical 210,042 224,393 257,196 254,262 249,151

North Okanagan Winter Demand Forecast

-50,000

100,000150,000200,000250,000300,000350,000400,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA




Page 5

South Okanagan/Similkameen Winter2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12


South Okanagan/Similkameen Winter Demand Forecast

-50,000

100,000150,000200,000250,000300,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA


Kootenay Winter

2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/122005 SDP 188,376 189,871 190,793 193,235 195,450 197,726 2006 Update 212,897 214,697 216,497 218,296 220,096 221,896 2007 Update 213,015 214,789 216,563 218,337 220,111 221,885 Historical 182,144 184,071 210,436 200,509 197,361

Kootenay Winter Demand Forecast

-

50,000

100,000

150,000

200,000

250,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA




Page 6

Boundary Winter2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12


Boundary Winter Demand Forecast

-10,00020,00030,00040,00050,00060,00070,000

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

2011

/12

Load

(kVA


2 Reference: SDP, BCUC Information Request 1.49.1 1

Q2.1 Please confirm that the “original” values reported on Page 42 are from the 2005 2

SDP. 3

A2.1 As noted on page 3 of the 2005-2024 SDP lines 23 - 25, the values reported on page 42 4

(Appendix 2) are the original values “updated for currently approved (2006 rates) 5

overhead and Allowance for Funds used During Construction (“AFUDC”) rates.” 6



Page 7

Q2.2 Please provide a table similar to that provided in response to BCUC 1.49.1 but for 1

the period 2007 – 2008. 2

A2.2 The table below provides FortisBC’s best efforts at assigning the overall 2007-2008 cost 3

increase of $24.7 million into the various categories requested. 4

Category ($million)

Inflation 4.7 Project Scope Changes 10.6 Refined Estimates 5.8 Schedule changes -2.4 Added Projects 6.8 Cancelled Projects -0.7 Total 24.7

Q2.3 With respect to Table 49.1, provided in response to BCUC 1.49.1, please provide the 5

following: 6

o A listing of the projects with “refined estimates” accounting for the $29.2 M and 7

the change in cost for each. 8

o A listing of the projects with “scope changes” accounting for the $12.0 M and the 9

change in cost for each. 10

o A listing of the “added projects” accounting for the $12.4 M and the cost of each. 11

A2.3 Attachment BCOAPO A2.3 provides a listing of the projects with refined estimates, 12

scope changes, added projects, cancelled projects, schedule changes and inflation 13

changes. 14

15

Q2.4 With respect to those projects in Table 49.1 with “refined estimates”, please indicate 16

the major reasons for the change in the “cost estimate” for each. 17

A2.4 Attachment BCOAPO A2.4 provides the major reasons for the change in the cost 18

estimate for each project in Table 49.1 with refined estimates where the change is greater 19

than $350,000. 20



Page 8

Q2.5 With respect to Table 49.1, please explain the key factors leading to the $12 M 1

increase attributable to inflation. Is FortisBC’s forecast of general inflation higher 2

now than in the 2005 SDP or are there specific materials whose prices are now 3

forecast to be higher in the future than in the 2005 SDP? 4

A2.5 As outlined in the 2007/08 CEP, page 8, lines 8-13, the key factors leading to the $12 5

million increase attributable to inflation in its transmission, station and distribution 6

sustaining projects is the increase in material and electrical equipment cost. 7

8

“An analysis of material purchases since 2004 shows that on an overall basis material has 9

seen inflationary increases of approximately 8% during that period. Suppliers indicate 10

that material price increases will continue over the next few years with transformer and 11

circuit breaker price increases in excess of 10% in 2007 and 8% in 2008. Based on this 12

information, FortisBC has used an overall inflation rate of approximately 5% for most of 13

its transmission, station and distribution sustaining projects.” 14

15

3 Reference: SDP, page 6, line 18 to page 8, line 6 and Appendix 2, page 43 16

Q3.1 The text starting on page 6 makes reference to and then discusses four bulk 17

transmission projects. However, Appendix 2 lists five, including an additional 230 18

kV Vaseux to Bentley facility. Please reconcile and provide details on the additional 19

bulk transmission project. 20

A3.1 The 2007 SDP Update at Appendix 2 list the following five projects 21

1. Double Circuit 230 kV Vaseux to RGA 22

2. 230/161/138 Bentley Terminal 23

3. 230 kV Vaseux to Bentley 24

4. Kelowna Shunts and SVC 25

5. Vaseux Transformer 3 26

27

The 2007 SDP Update, page 6-8, makes reference to four bulk transmission projects. 28

These include the following: 29



Page 9

1. Vaseux Terminal to Anderson Terminal 230 kV Circuit: (This is same as item 1 1

above). 2

2. New Bentley Terminal Station: (The text indicates that this is the construction of a 3

new Bentley Terminal station supplied by a 230 kV line from Vaseux Terminal. 4

This is the same as item 2 and item 3 above). 5

3. Kelowna Switched Shunts and Static VAr Compensator: (This is same as item 4 6

above). 7

4. Vaseux Lake Terminal Station Transformer 3: (This is same as item 5 above) 8

9

A brief description of the overall project which is now referred to as the Okanagan 10

Transmission Reinforcement (“OTR”) project is included in the 2007/08 Capital Plan, 11

page 39-41. An application for a CPCN for this project is anticipated to be filed in the 12

first quarter of 2007. 13

14

Q3.2 The discussion on pages 6-8 states that the first project (Vaseux Lake Terminal to 15

Anderson Terminal 230 kV Circuit) and the last project (Vaseux Lake Terminal 16

Station Transformer 3) are unchanged. However, there are no similar statements 17

for the other two projects. Are there any changes to either them from what what 18

was planned in the 2005 SDP? 19

A3.2 Yes, the timing for the completion of the remaining two projects has changed from what 20

was planned in the 2005-2024 SDP. The projects were originally scheduled for the 21

2008/09 timeframe, however, a further review has scheduled the completion for 2010. 22

23

4 Reference: SDP, page 8, lines 11-15 and page 10, lines 6-9 & 13 - 14 24

Q4.1 The discussion on page 8 indicates that load growth in the Kelowna area is higher 25

than forecasted in the 2005 SDP. In light of this, please explain more fully why 26

FortisBC is able to delay the projects discussed on page 10. 27

A4.1 Load in the overall Kelowna area has grown, however, FortisBC reviews the load 28

forecast for each individual substation on an annual basis to confirm the growth at each 29

substation. The 2006 review for the Recreation Substation identified that the transformer 30



Page 10

capacity of 31.5 MVA will not be exceeded until the winter of 2010/2011 where the 1

forecast identified that the load would be 32.0 MVA. This project has been postponed 2

due to less growth in the Recreation area for 2007 to 2009 timeframe. 3

4

5 Reference: SDP, page 10, lines 15-22; page 11, lines 5-12 & 13-13 and Appendix 2, 5

page 43 6

Q5.1 Please explain more fully why a new substation (Benvoulin Substation) is preferred 7

to the originally planned Hollywood and OK Mission Capacity Upgrades. 8

A5.1 Listed are the primary reasons why a new substation (Benvoulin Substation) is preferred 9

to the originally planned Hollywood and OK Mission Capacity Upgrades. 10

11

1. There is insufficient room for the high-voltage switchgear required to serve a third 12

transformer at the Hollywood and OK Mission sites. 13

2. There is insufficient room for Reactors which would be required for reducing fault 14

levels at the site. 15

3. The high cost of the distribution system and the extent of the underground 16

distribution to get egress out of the station to the load centers. 17

4. The Benvoulin Substation will provide support for both the Hollywood Substation 18

and the 2010 proposed OK Mission transformer addition. This project eliminates 19

the OK Mission project from the plan. 20

5. The Benvoulin Substation provides back up for DG Bell Terminal station which is at 21

57% back up. This is well below FortisBC’s planning criteria of 80%. This will 22

continue to diminish as load is growing significantly in the Upper Mission area 23

which is served by the DG Bell Terminal station. 24

6. The Benvoulin Substation has the potential to defer the Braeloch Substation since it 25

will provide supply into the south Kelowna area where Braeloch Substation will 26

eventually serve load. 27

7. The distribution feeder along sections of Benvoulin Road and Swamp Road will 28

require rebuilding within the next five years if no action is taken. This project will 29



Page 11

rebuild those lines to support growth which will remove the necessity to rebuild the 1

lines in the future. 2

3

Q5.2 Is the spending reported for the Hollywood Upgrade (Appendix 2, page 43) actually 4

the planned spending for the Benvoulin Substation? If not, please explain the 5

spending reported for the cancelled upgrade. 6

A5.2 Yes, the spending reported for the Hollywood Upgrade (Appendix 2, page 43) is the 7

planned spending for the Benvoulin Substation. 8

9

6 Reference: SDP, page 11, lines 2-4 and Appendix 2, page 43 10

Q6.1 Please explain the large increase in spending on the Braeloch Distribution Sources 11

($6.3 to $9.2 M – per Appendix 2) when, as stated on page 11 the project is 12

“unchanged”. 13

A6.1 The original forecast for this project did not include the cost of transmission and the cost 14

of distribution. Also please see the response to BCOAPO IR1 Q2.4. 15

16


Q7.1 How does the current projected cost of the New East Osoyoos Substation compare 18

with the estimated cost of the project when approved by the Commission? 19

A7.1 The Commission approved the New East Osoyoos Substation Option 2 (as modified) in 20

Order G-114-06. The estimated cost for the project was provided in FortisBC’s 21

Undertaking No. 14 (March 30, 2006) as: 22

2006 2007 Future Total

($million) 2.77 12.43 0.20 15.40

The current forecast included in the 2007/08 Capital Plan, estimated the cost of the New 23

East Osoyoos Substation project to be $15.41 million. The details are given below: 24

2006 2007 Future Total

($million) 2.70 12.49 0.22 15.41



Page 12


Q8.1 Please confirm that the Castlegar Capacity Upgrade was not included in the 2005 2

SDP. 3

A8.1 The Castlegar Capacity Upgrade was included in the 2005-2024 SDP. It was scheduled 4

for completion in 2006 but was deferred as a result of load transfers to the Blueberry 5

Substation. The project was outlined on page 36 of the 2005-2024 SDP and was listed on 6

page 2 of Appendix C of the same document. As outlined in the 2007/08 Capital Plan , 7

Appendix 6 page 2, and the 2007 SDP Update, Appendix 1, page 39, the current forecast 8

indicates that the load will reach 18.6 MVA or 124% of nameplate rating by 2010. 9

10

Q8.2 Please indicate the change in load growth (from the 2005 SDP) that gives rise to the 11

need for the Castlegar Capacity Upgrade/New Substation. 12

A8.2 Please see the response to BCOAPO IR1 Q8.1 above. 13

14

Q8.3 For how long can construction of a new substation be delayed through load 15

transfers? What are the limiting factors? 16

A8.3 The construction of the substation has been delayed from 2006 to 2008 through load 17

transfers. Further delays are limited by the thermal capacity and voltage levels of the 18

Blueberry Substation feeders. 19

20


Q9.1 Please compare the current forecast cost of $1.7 M for the Crawford Bay Capacity 22

Increase and Grounding Bank with the original 2006 cost estimate. Please provide 23

reasons for any cost changes if more than 5%. 24

A9.1 The current forecast cost of $1.7 million for the Crawford Bay Capacity Increase and 25

Grounding Bank is $200,000 more than the original 2006 cost estimate. The primary 26

reason for the difference is that the current forecast also includes funds to upgrade the 27

distribution switchgear. As outlined in the 2007/08 Capital Plan, pages 47-48, the 28

existing switchgear has a number of problems that need to be addressed. 29



Page 13


Q10.1 Please compare the current forecast cost of $2.8 M for the New Transformer at 2

Lambet Terminal with the planned cost when approved by the Commission in 3

Order G-8-06. Please provide reasons for any cost changes if more than 5%. 4

A10.1 The estimate that was approved by the Commission in Order G-8-06 was $2.0 million for 5

2006 and $2.29 million for 2007 for a total of $4.29 million. 6

7

The current forecast is $1.501 million for 2006 and $2.797 million for 2007 for a total of 8

$4.298 million. 9

10


Q11.1 Please compare the current forecast cost of $6.8 M for the Kettle Valley 12

Distribution Source with the planned cost as submitted in the 2005 CPCN. Please 13

provide reasons for any cost changes if more than 2%. 14

A11.1 The current forecast for the Kettle Valley Distribution Source and voltage conversion 15

project contained in the 2007/08 Capital Plan, Table 3.1, line 8 is $17.45 million. The 16

Kettle Valley Distribution Source substation project, which is a subset of this project, is 17

forecasted at $8.913 million. The expenditure by year is given below: 18

Pre 2006 2006 2007 2008 Total

($million) 0.486 1.618 5.811 0.998 8.913

This compares favorably with the planned expenditures of $8.74 million as submitted in 19

the 2005 CPCN dated October 11, 2005 (Exhibit B1, Pg 35). 20

21

The total estimated expenditures for all components of the Kettle Valley project is $17.45 22

million as outlined in the 2007/08 Capital Plan, Table 3.1. This also compares favorably 23

with the $17.20 million submitted in the CPCN. 24

25

Please note that the $6.8 million referenced in the above query is for the 2007/2008 26

forecast expenditure only and does not include the pre 2006 and 2006 expenditures. 27



Page 14

1

12 Reference: SDP, page 17 and Appendix 2, pages 44 & 45 2

Q12.1 Please compare the current forecast cost for the Coffee Creek and Kaslo Capacitors 3

with the cost per the 2005 SDP. Please provide reasons for any cost changes if more 4

than 5%. 5

A12.1 The 2005 SDP forecast, updated with approved overhead and AFUDC was: $0.97 6

million for Kaslo and $0.97 million for Coffee Creek. ($1.94 million total) 7

8

The 2007 SDP Update is: $0.078 million for Kaslo and $0.245 million for Coffee Creek. 9

($0.323 million total) 10

11

When the proposed conversion of 30 Line between South Slocan and Crawford Bay to 63 12

kV operation is complete, the supply to the area (Coffee Creek, Kaslo and Crawford Bay) 13

during off peak operation can be backed up by 32 Line in case of the outage of 30 Line 14

between South Slocan and Coffee Creek. This proposed change in operation has changed 15

the reactive compensation requirements from those outlined in the 2005-2024 SDP. 16

Adequate system voltage can now be maintained with less reactive compensation. 17

18

Q12.2 Please confirm that the cost savings from the Coffee Creek and Crawford Bay 19

transformer replacement projects are $1.9 M for each (page 45). 20

A12.2 Yes, the cost savings from the Coffee Creek and Crawford Bay transformer replacement 21

projects are $1.9 million for each project. These savings will be somewhat offset by the 22

new project known as the 30 Line conversion. With the proposed conversion of 30 Line 23

between South Slocan and Crawford Bay to 63 kV operations, the designated costs for 24

the transformer replacements ($1.9 million each) will not be required. 25



Page 15


Q13.1 What is the final cost for the 2006 Ymir Transformer Replacement? How does this 2

compare with the estimated cost when it was approved by the Commission (G-8-3

06)? 4

A13.1 The forecast cost of the Ymir Transformer Replacement is $2.823 million compared to 5

$2.531 million approved by Commission Order G-8-06. 6

7

Q13.2 Please compare the current forecast cost of $1.8 M for the Breaker at Waneta with 8

the original cost estimate for 2006 installation. 9

A13.2 The original cost in the 2005-2024 SDP for the 2006 installation (updated for currently 10

approved overhead and AFUDC) was $1.21 million compared to the 2006 SDP Update 11

cost of $1.8 million (loaded) and the current forecast of $1.8 million. The estimate has 12

been provided by Teck Cominco, the owners of the facilities. 13

14

14 Reference: SDP, Appendix 2, page 44 and BCUC 1.2.1 15

Q14.1 Please provide the annual spending on Urgent Repairs for the period 2001 to 2006 16

A14.1 The following table, Table 3.3 from page 49 of the 2007/08 Capital Plan provides the 17

expenditures on Urgent Repairs for the period 2003 to 2006F. The expenditures for 2001 18

and 2002 are not available. 19

Table 3.3 Transmission Line Urgent Repairs

Year 2003 2004 2005 2006F 2007 2008

Cost ($000s) 550 128 268 358 257 308

Q14.2 Why was there no spending on Transmission Condition Assessments included in the 20

2005 SDP? 21

A14.2 In the 2005-2024 SDP the expenditures for Transmission Condition Assessments were 22

included in the line item “Future Year Rehabilitation and Condition Assessments” for the 23

years 2006 to 2010. 24



Page 16

15 Reference: SDP, page 5, lines 14-16; page 22, lines 6-10 and Appendix 2, page 46 1

Q15.1 Please provide a schedule setting out the forecast number of annual new 2

connections underlying the 2005 SDP and the current 2007 SDP Update. 3

A15.1 The forecast expenditures for new connections are based on prior years total cost for new 4

connections. The number of new connections has not been specifically used in 5

forecasting the expenditures. 6

7

Q15.2 The current forecast of cost for New Connects (page 46) does not include a forecast 8

of associated CIAC (similar to that provide for the 2005 SDP). Please indicate the 9

anticipated CIAC associated with the current new connects forecast. 10

A15.2 The updated line item for new connects is the net expenditure. The anticipated CIAC is 11

50% of the Gross expenditures. For ease of explanation, the Gross expenditures for new 12

connects for the period 2007 to 2011 is forecast at $86.10 million, offset by forecast 13

CIAC of $43.05 million for a forecast net new connection expenditure of $43.05 million. 14

15

16 Reference: SDP, page 24, lines 16-23; page 9, lines 1-8 and Appendix 2, pages 43 16

& 46 17

Q16.1 What was the projected cost of the Ellison Substation – New Feeder included in the 18

2005 SDP? Is this project still reported separately in Appendix 2 and, if so, where? 19

A16.1 The projected cost of the Ellison Substation - New Feeder in the 2005-2024 SDP was 20

$0.5 million. 21

22

This Project is reported separately in Appendix C, Page 4 of the 2005-2024 SDP, under 23

“Distribution Growth - Kelowna area” and is designated as - RETERMINATE LEE 24

FEEDERS AT N. KELOWNA SUBSTATION. 25

26

Please also note that this Project is no longer reported in the 2007 SDP Update as a 27

separate project, instead, the project description and cost has been included in the 28

proposed Ellison Project (please refer to 2007 SDP Update, Page 24, Lines 21 to 23). 29



Page 17

Q16.2 The cost of the Ellison Substation has increased significantly ($7.9 M to $13.3 M). 1

How much of this increase is due to the inclusion of the “New Feeder” in the project 2

scope (per page 24)? If this change in scope doesn’t account for the entire increase 3

please provide an explanation for the cost increase. 4

A16.2 The Ellison Project was initially listed in the 2005 Capital Plan (Tab 9, page 21, Table 5

9.3.1 of the 2005 Revenue Requirements Application) at an estimated cost of $8.25 6

million excluding loading and AFUDC. With loading and AFUDC this increased to 7

$9.24 million. 8

9

In the 2006 Capital Plan that was filed in August 2005, the forecast was revised to a 10

loaded figure of $11.7 million (please refer to the 2006 Capital Plan, page 25). The 11

increase was necessary to accommodate the transmission line and the distribution 12

infrastructure upgrade/addition with station egress which was inadvertently not 13

considered in the 2005 Capital Plan. 14

15

In the 2007/08 Capital Plan the Ellison Project is estimated at $15.159 million. The 16

difference of $3.459 million between the 2006 Capital Plan and the 2007/08 Capital Plan 17

is primarily associated with the large amount of distribution networking that is required 18

to match the recent rapid growth in the Duck Lake-Ellison-Sexsmith area which is 19

greater than was originally anticipated at the time of submitting the 2006 Capital Plan. 20

21

An application for a CPCN for this project is planned to be filed in the fourth quarter of 22

2006. 23

24

Q16.3 Please provide an explanation for the increase in forecast costs of Distribution Line 25

Rebuilds. 26




Page 18


Q17.1 Please provide an explanation for the increase in the forecast cost of Forced 2

Upgrades and Line Moves (over the 2005 SDP) as shown on page 47. In particular, 3

how much of this is due to line moves and why has the requirement for line moves 4

increased? 5

A17.1 The updated forecast for Forced Upgrades and Line Moves is based on the average actual 6

expenditures for the past three years (2006 included) adjusted for inflation. The 2005-7

2024 SDP forecast used a fixed amount (based on past experience) with no adjustment 8

for inflation. This account does not track cost by specific categories. 9

10

Q17.2 Are the forecast costs for Line Moves net of anticipated recoveries from 3rd parties 11

(per page 29)? If not, please provide the net amounts for the 2005 SDP and the 2007 12

SDP Update. 13

A17.2 Yes, the forecast costs are net of anticipated recoveries. 14

15

Q17.3 Please provide an explanation for the increase in forecast costs of Distribution Line 16

Rebuilds. 17


19

18 Reference: CEP, page 12, Table 1.4 20

Q18.1 Please provide a schedule setting out a list of the projects (along with their costs) 21

that fall into the following categories: 22

• Approval has been provided in previous Commission Orders 23

• A CPCN has been filed, and 24

• A CPCN will be filed. 25

26

A18.1 Table 18.1 (a) and Table 18.1(b) below provide the requested information. 27



Page 19

Table 18.1 (a)

Projects which have been approved by previous Commission Orders

Previously Approved

Prior Year Exp. up to Dec

31/06

2007 Total

2008 Total

Future (1)

Total

($000s)

Lower Bonnington Unit 3 ULE 7,842 7,377 15,219

South Slocan Unit 1 ULE 1,438 8,747 3,149 13,334

Lower Bonnington Unit 3 Headgate Rebuild 595

68

663

South Slocan Pole Yard Remediation 577 325 902

Corra Linn Forebay Boom & Anchor Upgrades 155 155

Fault Level Reduction 1,112 3,371 4,483 Naramata Substation (Arawana) 2,584 1,959 4,543 Nk’Mip (East Osoyoos) Source 2,700 12,489 218 15,407 Lambert Substation -

Transformer Installation 1,501 2,797 4,298

Kettle Valley Distribution Source and voltage conversion

Approved since CEP

filed

5,354 9,491 2,605 17,450

Big White Supply

Approved since CEP

filed

2,092 9,969 8,244 20,305

Computerized Maintenance Management System 1,101 246 1,347

West Osoyoos Transformer Rehabilitation 1,723 343 2,066

PCB Program 852 868 3,480 5,200

Benvoulin Property Expansion 150 3,948 4,098



Page 20

Table 18.1 (b) Projects for which

A CPCN has been or will be filed

CPCN to be filed

Prior Year Exp. up to Dec

31/06

2007 Total

2008 Total

Future (1)

Total

($000s) Ellison Distribution Source 1,840 13,319 15,159 Black Mountain Source 524 497 8,727 9,748 Okanagan Transmission

Reinforcement 2,996 20,497 51,580 75,073

Distribution Substation Automation, Metering and Communications

800 1,999 2,000 1,000 5,799

AM/FM Upgrade

CPCN

filed since CEP filed

727 1,679 338 2,744


Q19.1 For those previously approved Generation Projects, please compare the current 2

forecasted cost of project with the cost estimate when the project was approved by 3

the Commission. If the variance is greater than +/- 2% please explain the reason for 4

the change. 5

A19.1 The table below identifies the previously approved projects from 2007/08 Capital Plan 6

Table 2.1, and compares the current forecasted cost of project with the cost estimate 7

when the project was approved by the Commission. 8



Page 21

Generation (Previously Approved only)

Approved Amount

2006 Capital Plan

($000)

Forecast 2007 Capital

Plan ($000)

Variance(%) Reason for Variance

Lower Bonnington Unit 3 ULE 16,153 15,219 -5.8

Changes in the Company’s capitalized O/H loading and AFUDC rates as applied to Generation Projects.

South Slocan Unit 1 ULE 15,598 13,334 -14.5


Lower Bonnington Unit 3 Headgate Rebuild

741 663 -10.5


South Slocan Pole Yard Remediation 1,356 902 -33.4

Sample testing of the whole site is ongoing and the total extent of remediation has not been determined, however testing of the yard has been completed and it has been determined that the amount of contaminated soil in the pole yard that will require treatment is less than anticipated.

Corra Linn Forebay Boom and Anchor Upgrades

93 155 66.7

Scope change from pre manufactured “tuffboom” to log boom. This was based on new information which indicates that a log boom has a much longer life.



Page 22


Q20.1 For those previously approved Transmission and Stations Projects, please compare 2

the current forecasted cost of project with the cost estimate when the project was 3

approved by the Commission. If the variance is greater than +/- 2% please explain 4

the reason for the change. 5

A20.1 The table below identifies the previously approved projects from Table 3.1, and 6

compares the current forecast cost of project with the cost estimate when the project was 7

approved by the Commission. 8

Transmission and Stations Projects

(Previously Approved only)

Approved Amount

2006 Capital Plan

($000s)

Forecast 2007/08 Capital

Plan ($000s)

Percent Variance

% Reason for Variance

Fault Level Reduction 4,292 4,483 + 4.4 Schedule change, Inflation

Naramata Substation (Arawana) 3,700 4,543 + 22.8

Escalated equipment costs, land acquisition costs and refined estimates

Nk’Mip (East Osoyoos) Source 15,407 15,407 0

Lambert Substation - Transformer Installation 4,290 4,298 0

Computerized Maintenance Management System 888 1,347 + 51.6

Scope of the project changed to include Generation division. Unanticipated hardware cost. Software and Implementation costs are higher than anticipated.

West Osoyoos Transformer Rehabilitation

2,041 2,066 + 1.2



Page 23

21 Reference: CEP, page 36, lines 4-7; page 37, lines 15-20; page 43, lines 11-28; 1

Order G-8-06, Appendix A, page 1 and 2

BCUC 1.4.1, 1.45.2 & 1.46.1 3

Q21.1 Please explain why CPCNs are planned for the Ellison Project and the Black 4

Mountain Source Project, when both are below the $20 M threshold. 5

A21.1 Applications for CPCNs will be submitted for the Ellison and Black Mountain projects as 6

requested by Commission Order G-8-06 (Appendix A, Ref 3.2.1 and 3.2.2). Although 7

they did not fall within the scope of FortisBC’s criteria, the Commission requested that 8

specific issues be tested and clarified through the CPCN application process. 9

10

Q21.2 Please explain why a CPCN is not considered necessary for the Benvoulin Station 11

project when it also involves the construction of a distribution substation with a cost 12

of roughly the same order of magnitude as Ellison and Black Mountain. 13

A21.2 FortisBC confirms that the forecast cost for the Benvoulin Substation project is 14

approximately the same order of magnitude as those estimated for the Ellison and Black 15

Mountain projects. However, with respect to the latter projects, the Commission 16

requested that individual CPCN applications be submitted based on specific questions. 17

18

The primary driver for the Ellison CPCN was the cost escalation from the 2005 Capital 19

Plan ($8.25 million) to the 2006 Capital Plan ($11.7 million). The Commission saw 20

benefit in having that difference explained by way of a CPCN application. In the case of 21

the Black Mountain Distribution Source, the project is proposed to interconnect with 22

other facilities in an area of rapid growth. To help the Commission clearly understand 23

the need and related power system implications, they requested that a CPCN application 24

be submitted. 25

26

With respect to the Benvoulin Substation project, the site is proposed at a location 27

immediately adjacent to the 138 kV transmission source, thereby requiring very little 28

transmission line work. There are three neighboring properties. One, a local heritage 29

site, is immediately north. The other two are across a busy street and are commercial in 30



Page 24

nature. The proposed site currently houses multiple AM radio transmission towers which 1

are significantly higher than the proposed substation structures. The end result is that the 2

future use of the site will not be dramatically different than that of today. 3

4

Notwithstanding the above, as outlined in the 2006/08 Capital Plan, page 14, and further 5

articulated during the 2007/08 Capital Plan workshop on September 6, 2006, FortisBC 6

recognizes the value of stakeholder consultation and is in the process of undertaking such 7

consultation even though a CPCN application is not proposed. 8

9

For the reasons cited above, based on the accepted submission criteria and as explained 10

further in the response to BCOAPO IR1 Q21.3, FortisBC does not have reason to believe 11

that the Benvoulin Substation project requires a CPCN application. 12

13

Q21.3 How has FortisBC been able to determine for the Benvoulin Station project that 14

neither of the following CPCN criteria apply when it has not specifically discussed 15

theproject with stakeholders: 16

a) the project is likely to generate significant public concerns or 17

b) a credible majority of stakeholders desire a CPCN application? 18

19

A21.3 FortisBC is currently commencing the public consultation phase of the Benvoulin 20

Substation project. At this point in time, no obvious reasons for concern have been 21

identified. 22

23

In general terms, certain features of a project are likely to cause community interest in a 24

project, whereas other features are considered more publicly benign. Examples of issues 25

that might raise public concern are situating a facility in a densely populated residential 26

environment, noise/light pollution, extensive new transmission and /or distribution lines, 27

potential environmental impacts or First Nations conflicts. The Benvoulin Substation 28

project has been planned to minimize or eliminate these concerns. As noted in the 29

response to BCOAPO IR1 Q21.2 the proposed use of the site will not be dramatically 30



Page 25

different than what it is today. Based on this first stage evaluation, FortisBC does not 1

have reason to believe that the Benvoulin Substation project requires a CPCN 2

application. 3

4

Q21.4 Could future stakeholdering for this project lead to FortisBC determining a CPCN 5

is necessary? 6

A21.4 Yes, as the public consultation process unfolds and more specific community information 7

is gathered, it is possible that the level of interest in the project and its impacts will cause 8

FortisBC to recognize a need for a CPCN application. However, at this time, there are no 9

specific reasons or expressed concerns that warrant a CPCN application. The Company 10

will work diligently with its stakeholders through the public consultation process to 11

balance the needs of the individual stakeholders and the community. FortisBC 12

appreciates Commission input into its processes but wishes to build its relations with 13

stakeholders by addressing their needs without being ordered to do so by the 14

Commission. 15

16

22 Reference: CEP, page 46, line 10 to page 47, line 1; 17

Order G-8-06, Appendix A, page 1 18

BCUC 1.4.1 & 1.47.3 19

Q22.1 Please explain why a CPCN is not considered necessary for the Castlegar Area 20

Capacity Increase when it also involves the construction of a distribution substation. 21

A22.1 FortisBC is of the opinion that proposing the installation of a new distribution substation 22

does not by itself create the need for a CPCN. FortisBC has developed specific criteria 23

for the submission of such an application, and the Commission has agreed that these 24

criteria are acceptable. Of the recent CPCN applications that were either requested by 25

the Commission or initiated by FortisBC, none were submitted based solely on the 26

inclusion of a substation in the project. Depending on the outcome of the planning and 27

consultation phases, a capital project involving a new substation may or may not generate 28

a CPCN application process. The costs and delays associated with a application CPCN 29

for every substation would not be in the best interest of the Company's customers. The 30



Page 26

Company believes that subject to its CPCN criteria it is able to balance the needs of its 1

stakeholders and the community in determining the configuration of a substation. 2

3

Q22.2 Has FortisBC undertaken any stakeholdering with respect to the Castlegar project 4

to determine if a) the project is likely to generate significant public concerns or b) a 5

credible majority of stakeholders desire a CPCN application? 6

A22.2 FortisBC has had initial discussions regarding a new substation site with the mayor of 7

Castlegar and an engineering firm representing property developers in the area. More 8

recently the Company has started the first phase of the public consultation process for the 9

Castlegar project. This involves identifying and meeting with elected and appointed 10

representatives of the various regulating and permitting authorities, including the City of 11

Castlegar and the Regional District of Central Kootenay and with First Nations. 12

13

These meetings allow detailed information about area development plans, land zoning, 14

agricultural and environmental concerns, etc. to be obtained. Additionally and inherent 15

in these initial meetings are discussions about local land user groups, visual screening 16

options, possible concerned neighbours and general impact minimization. While specific 17

concerns by specific citizens have not been completely identified, the initial stakeholder 18

feedback is that station siting can likely be accomplished without undue community 19

impact. 20

21

Q22.3 With respect to part (2), if yes, please indicate the stakeholdering initiatives 22

undertaken and their outcome. If no, is any stakeholdering planned and could this 23

lead to FortisBC determining a CPCN is necessary? 24

A22.3 For specific stakeholder consultations to date, please refer to the response to BCOAPO 25

IR1 Q22.2. 26

27

It is possible, depending on the outcome of the second phase of the public consultation 28

process (which includes individual residents and landowners) that a CPCN application 29

will be deemed appropriate. While FortisBC views the CPCN application as a useful tool 30



Page 27

for certain projects, all attempts are made to gather and provide the information 1

necessary for the Commission to make a well informed project decision for all projects, 2

whether or not the process includes a CPCN. As noted in the response to BCOAPO IR1 3

Q21.2, public consultation, including discussions with local government, industry, 4

community groups and private citizens is pursued irrespective of the decision to submit a 5

CPCN application. 6

7

Q22.4 More generally, how does FortisBC determine where a project meets the following 8

criteria for a CPCN: 9

• The project is likely to generate significant public concerns. 10

• After presentation of a capital plan to FortisBC stakeholders, a credible 11

majority of those stakeholders express a desire for a CPCN application. 12

In particular, with respect to the second criterion, does FortisBC make 13

presentations to local stakeholders for all of its capital projects? 14

A22.4 Certain project attributes are more likely to generate community interest than others. 15

Projects that include installing extensive new transmission lines through urban areas, 16

construction in community sensitive areas such as parks and school zones, and changing 17

the land use of recreational sites are examples where public interest is likely to be high. 18

Knowledge of this in advance may trigger FortisBC to see the CPCN submission criteria 19

as being met, thereby initiating the need for a CPCN application. 20

21

Similarly, FortisBC may choose to submit a CPCN application once the public 22

consultation phase is underway. As information is gathered, previously unknown 23

concerns may be deemed significant enough to create the need for an application. 24

25

The concept of “significant public concern” is important. Conventional wisdom and 26

recent experience both demonstrate that most new infrastructure, regardless of size or 27

location often results in concerns by those who may be impacted. A single new 28

distribution pole on a property line may cause the local homeowner to express concern 29

but would not warrant the time and expense of a CPCN process. If controversy arises in 30



Page 28

the process after approval of a project, both the Commission and the Company are free to 1

seek a CPCN process if the Company is not able to address the needs of the stakeholders 2

in a balanced and fair approach. While FortisBC will make efforts to satisfy those 3

concerns, is it unrealistic to expect that all concerns can be addressed to everyone’s 4

satisfaction in all cases. Even a larger group of organized citizens may not be considered 5

to generate “significant public concern”, if they are only concerned with their own 6

specific interests. The definition is subjective and relies on other inputs, such as the 7

overall benefit to the community, the efforts made to reduce impacts, the positive 8

feedback from other parts of the community, etc. Each decision must be made on the 9

circumstances associated with that project. 10

11

With respect to the second noted criterion, FortisBC makes efforts to contact and 12

communicate with all local stakeholders that are likely to be impacted or that have 13

meaningful input to the decision making process. For obvious reasons, the scale and 14

impact of the project will be a major consideration in determining who will be consulted 15

and in what form. This may or may not be in the form of a “presentation”. 16

17

Typically, attempts are made to contact all residents and businesses along a proposed line 18

route and, within a 0.5 kilometer radius of a distribution substation. Oversights do 19

occasionally occur and there are specific challenges communicating with absentee 20

landowners, but efforts are made to contact, inform and solicit advice from those that 21

may be impacted. 22

23

23 Reference: CEP, page 54, Table 3.8 and SDP, Appendix 2, page 44 24

Q23.1 The forecast expenditures for Switch Additions reported in Table 3.8 differ from 25

those in the SDP by a factor of 10. Please reconcile. 26

A23.1 The original table contained an error and is corrected as follows. 27



Page 29

Table 3.8 Switch Additions

2007 2008 Total

Cost ($000s) 362.0 190.0 552.0

24 Reference: CEP, page 65, Table 4.1 and page 66, lines 5-10 1

Q24.1 Are the forecast capital expenditures on new connects shown in Table 4.1 net of 2

CIAC (i.e., has CIAC been deducted and the net cost to FortisBC reported)? If not, 3

please indicate the net forecast of cost of new connects. 4

A24.1 Yes, the forecast capital expenditures for new connects shown in Table 4.1 are net of 5

CIAC. 6



Page 30

25 Reference: CEP, page 68, Table 4.2 and page 8, Table 1.2 1

Q25.1 Distribution expenditures for the 2007-2008 period are up almost 50% relative to 2

the spending in the 2005 SDP for the same period. For the distribution growth 3

projects shown in Table 4.2 please indicate what the cost included in the 2005 SDP 4

for each project was for the same period and explain any differences. 5

A25.1 The following table shows the cost (updated for approved loading and AFUDC) included 6

in the 2005-2024 SDP for the projects shown in Table 4.2 and an explanation of the cost 7

changes. 8

Distribution Growth Capacity Projects Project 2007 2008 SDP Reason

($000s)

1 Glenmore Substation - New Feeder 1,371 1,230

The original estimate was based on preliminary concepts. The revised estimate is based on more detailed engineering design.

2 Keremeos Feeder 1 Capacity Upgrade 353 0 New Project

3 Princeton Feeder 4 Capacity Upgrade 881 0 New Project

4 OK Falls Feeder 3 Capacity Upgrade 294 300 0 New Project

5 Crawford Bay Feeder 2 Capacity Upgrade 372 0 New Project

6 Feeder Egress Cables 244 0 New Project

7 McKinley Landing Capacity Upgrade 359 545 Same as Item 1

8 Valhalla Feeder 1 Capacity Upgrade 897 0 New Project

9 Hollywood Feeder 1 - OK Mission Feeder 1 Tie 349 554 Same as Item 1

10 FA Lee Feeder 2 - Hollywood Feeder 5 Tie 419 246 Same as Item 1

Q25.2 Were there any distribution growth projects included in the 2005 SDP for 2007-9

2008 that are not included in the current CEP? If so, please identify the projects 10

and their 2007 and 2008 costs per the 2005 SDP. 11

A25.2 The following table shows the distribution growth projects included in the 2005-2024 12

SDP for 2007-2008 that are not included in the current 2007/08 Capital Plan. As outlined 13



Page 31

on page 118, lines 25-26 of the 2007/08 Capital Plan, these projects have been deferred 1

to mitigate capital expenditures. 2

Distribution Growth Projects

Project Original Update 2005 SDP Cost ($000s)

1 Hollywood Feeder 1 - DG Bell Feeder 3 Tie 2007 2009 726

2 McKinley Landing - Clifton Road Tie 2008 2010 240

26 Reference: CEP, page 88, Table 5.1 and SDP, Appendix 2, page 48 3

Q26.1 Please explain the reasons for the reduction in 2007-2008 expenditures on sustaining 4

projects for telecommunications, SCADA and Protection & Control relative to the 5

planned 2005 SDP spending for the same period. In particular, how much is due to 6

scheduling changes as opposed to projects being dropped/added. 7

A26.1 The reason for the reduction in 2007-2008 expenditures on sustaining projects for 8

telecommunications, SCADA and Protection & Control relative to the planned 2005 SDP 9

spending for the same period is refined estimates. The expenditure estimates in the 2005-10

2024 SDP, for 2007 and 2008, that were compiled in 2004, were based on FortisBC’s 11

best assessment of the requirements that would materialize in 2007 and 2008. The 12

expenditure estimates in the 2007/08 Capital Plan are based on a more current assessment 13

of these requirements. None of the decrease is due to scheduling changes or specific 14

projects being dropped / added. While there has been a decrease, the 2007/08 15

expenditures are still in line with the original estimates. 16

17

Q26.2 Were there any distribution growth projects included in the 2005 SDP for 2007-18

2008 that are not included in the current CEP? If so, please identify the projects 19

and their 2007 and 2008 costs per the 2005 SDP. 20

A26.2 Please see the response to BCOAPO IR1 Q25.2. 21



Page 32

27 Reference: CEP, pages 94 and 95 1

Q27.1 Are any of FortisBC’s DSM programs reliant on funding or support from the 2

Canadian Federal Government? If so, please identify the programs along with their 3

costs and FortisBC’s current understanding as to whether there will be continuing 4

Federal support. 5

A27.1 The Federal government is providing supplementary funding for a number of programs. 6

These include the Air Source Heat Pump, Energy Star window and EnerGuide 80 new 7

home programs as follows: 8

9

• $150,000 in Heat Pump Technology Support to provide more advertising, seminars, 10

general information and advanced contractor training up to March 31, 2007; 11

• $260,000 for the Energy Star Window rebate program under which both electric heat 12

and non-electric heat customers will receive $1.50 per square foot of qualified 13

windows installed up to March 31, 2007; 14

• $275,000 in “EnerGuide 80 for New Houses” to help build 500 qualified homes 15

throughout the utility’s service area up to March 31, 2007; 16

17

In 2007, FortisBC will continue DSM programs for heat pumps ($513,000), energy star 18

windows for electrically heated customers ($15,000) and the new home program 19

($424,000). 20

21

The federal government will be announcing its plans for support of energy efficiency 22

initiatives later this year and until that time we do not know what level of financial 23

support it will offer in the future. 24



Page 33

28 Reference: CEP, page 104, Table 7.8 and BCUC Order G-58-06 1

Q28.1 Is the SAP Upgrade project (as presented in the 2006 CEP and the 2006 RRA) to be 2

fully completed in 2006 or is there any spending carry over to 2007-2008? If the 3

latter, please indicate how much and where it is reported in the 2007-2008 CEP. 4

A28.1 The SAP Upgrade project as presented in the 2006 Capital Plan and the 2006 Revenue 5

Requirements Application is anticipated to be completed by December 31, 2006. 6

7

Q28.2 What is the current final cost estimate of the SAP Upgrade project and how does 8

this compare with the cost estimate presented in FortisBC’s 2006 RRA? 9

A28.2 The current cost estimate for the SAP Upgrade project is $1.85 million which will be 10

approximately 21% over the cost estimate of $1.532 million presented in FortisBC’s 11

2006 Revenue Requirements Application. One of the major activities required for the 12

SAP upgrade was the removal of the billing component from the SAP software system. 13

During the course of the project it was determined that there had been more custom 14

program changes made specifically for the billing component than had been previously 15

recognized. FortisBC confirmed that it did not require the billing component, and 16

determined that its removal would result in a much simpler upgrade path and would 17

reduced the overall size of the database by over 60%. This required more time and effort 18

to address, leading to increased cost for the upgrade project, but the elimination of the 19

billing component will have a positive effect on infrastructure and support costs on a go 20

forward basis. 21

22


Q29.1 Please reconcile the spending on the Benvoulin Property Expansion reported in 24

Table 7.9 with that shown on page 115. 25

A29.1 The items listed in Table 7.9 are scheduled for the existing property/building at 2850 26

Benvoulin Road and are separate from the Benvoulin Property Expansion project. The 27

items in Table 7.9 include the following: 28



Page 34

Item 7 - 2007: install a roof over the walkway between the warehouse and west door 1

(safety issue) and increase west fence height (security issue); 2

2008: upgrade the existing buildings at the rear of the property to facilitate additional 3

crew usage and to provide covered environmental storage. 4

5

Item 8 - 2007: construct additional office space in the mezzanine area; install circulation 6

fans in the warehouse and fleet area; and provide plotter room exhaust improvements. 7

8

Q29.2 Similarly, please reconcile the 2006/2007 timing for the project suggested in the text 9

(page 115, lines 6-7) with the 2007/2008 timing of the project suggested in Table on 10

page 115 (lines 8-10). 11

A29.2 The Table on page 115 (lines 8-10) incorrectly showed 2006 costs. The correct table is 12

shown below. 13

Benvoulin Property Expansion

2007 2008 Cost ($million) 3.95 -

Q29.3 Please provide an update as to the status of removing the land associated with the 14

Benvoulin Property Expansion from the Agricultural Land Reserve. 15

A29.3 The application to the Agricultural Land Commission (“ALC”) was submitted (as 16

required) through the City of Kelowna on August 24, 2006. The City Planning 17

Committee undertook its review of the application during the week of September 11, 18

2006 19

20

It has been indicated, but not confirmed, that the proposal will be presented at the 21

Advisory Agricultural Committee meeting on September 28 and Advisory Planning 22

Committee meeting in mid-October; and with the Kelowna City Council in early 23

November. Once the application has been forwarded to the ALC there is a guaranteed 24

turn-around time of 90 days. 25



Page 35


Q30.1 What are the anticipated rate reductions in 2007 and 2008 from deferring the 2

capital projects listed in the Table on page 119? 3

A30.1 The anticipated rate reductions in 2007 and 2008 from deferring the capital projects listed 4

in the Table on page 119 is less than 0.1%. 5

6

Q30.2 Not all of the projects that were identified as “deferrable” were deferred. Please 7

explain the basis on which FortisBC made the determination as to which projects 8

would actually be deferred. 9

A30.2 FortisBC believes that all the projects are necessary to provide adequate reliability. The 10

projects that were selected for deferral was reviewed by the Regional Engineer and 11

assessed as having a lower customer impact than those selected for construction. 12

BCOAPO A2.3

07-'11 Total 07-'11 TotalInflation Project

ScopeRefined

EstimatesSchedule Change

Added Project

Cancelled Project

original update

TRANSMISSION GROWTHBULK SYSTEMDOUBLE CIRCUIT 230 kV VAS TO RGA 36,215 38,995 2,780230/161/138 BENTLEY TERMINAL 25,205 21,933 -3,272230 KV VASEUX TO BENTLEY 6,140 6,499 359KELOWNA SHUNTS & SVC 2,460 2,930 470VASEUX TRANSFORMER 3 (500/230 kV) 1,845 0 -1,845

KELOWNA AREABIG WHITE 138 kV LINE & SUBSTATION 19,360 18,213 -1,147ELLISON DISTRIBUTION SOURCE 7,865 13,319 4,704 750ELLISON TRANSMISSION LOOP 0 3,489 3,489BLACK MOUNTAIIN DISTRIBUTION SOURCE 8,610 9,224 614LINESFAULT LEVEL REDUCTION 0 3,371 3,371CLOSE 138 kV LOOPS KELOWNA 14,065 5,220 -8,845RECREATION CAPACITY INCREASE 2,460 2,749 289HOLLYWOOD CAPACITY INCREASE 2,460 11,119 8,659BRAELOCH (SW) DISTRIBUTION SOURCE 6,280 9,192 2,912OK MISSION CAPACITY INCREASE 3,900 0 -3,900DUCK LAKE REGULATOR BANK 0 294 294NORTH KELOWNA TRANSFORMER ADDITION 0 0GLENMORE SUBSTATION NEW FEEDER 0 392 392

PENTICTON/SUMMERLAND AREANARAMATA REHABILITATION 0 1,959 1,959HUTH REBUILD AS 63 kV RING BUS 6,500 6,333 -167SUMMERLAND 63 kV BACKUP 3,531 0 -3,531WESTBENCH SUBSTATION REGULATOR BANK 0 294 294

OSOYOOS/OLIVER AREANEW EAST OSOYOOS SOURCE 0 12,707 12,707EAST OSOYOOS-BENTLEY TRANSMISSION 6,650 0 -6,650CONVERT EXISTING OLIVER TO 138/63/13 kV DISTRIBUTION SOURCE STATION 4,910 4,716 -194

PRINCETON/KEREMEOS AREAPRINCETON TRANSFORMER REPLACEMENTS 0 0HEDLEY STEP UP 5 MVA TRANSFORMER 0 391 391KEREMEOS NEW FEEDER 0 263 263

BOUNDARY/GRAND FORKS AREAKETTLE VALLEY DISTRIBUTION SOURCE 0 6,809 6,809KETTLE VALLEY VOLTAGE CONVERSION 4,275 4,026 -249BOUNDARY AREA STATION CONVERSIONS 1,210 1,261 51GRAND FORKS AREA VOLTAGE CONVERSIONS 5,090 4,048 -1,042GRAND FORKS DISTRIBUTION SOURCE 12,640 10,533 -2,107

CASTLEGAR AREACASTLEGAR SUB CAPACITY INCREASE 0 6,378 3,189 3,189

0 0COFFEE CREEK - KASLO AREA 0 0CAPACITOR AT COFFEE CREEK 0 245 245CAPACITOR AT KASLO 0 78 78COFFEE CREEK T3 REPLACEMENT 1,230 2,600 1,37030 LINE CONVERT TO 63 kV 0 2,500 2,500

CRAWFORD BAY AREACRAWFORD BAY CAPACITY INC. 0 1,714 1,714

CRESTON/WYNDELL AREANEW LAMBERT 230/63 KV TRANSFORMER & 230 kV RING 0 2,797 2,797

SOUTH SLOCAN AREASLOCAN - NEW DENVER 63KV LOOP 0 0

TRAIL/SALMO AREAYMIR FEEDER CONVERSION 0 815 815NEW 18 L BREAKER AT WANETA 0 1,800 1,800

SUBTOTAL - TRANSMISSION GROWTH 182,901 219,206 903 12,652 5,008 13,056 4,686

TRANSMISSION LINE SUSTAININGTRANSMISSION LINE URGENT REPAIRS 902 1,584 167 516RIGHT OF WAY ENHANCEMENTS 1,503 1,820 182 136ROW RECLAMATIONS 0 1,807 185 1622TRANSMISSION CONDITION ASSESSMENTS 0 3,520 840 2680SWITCH ADDITIONS 1,803 552 -1,251FUTURE YEAR REHABILITATION 10,102 9,539 973 -15366A LINE REHABILITATION 59 0 -5926 LINE REHABILITATION 94 0 -9427 LINE REHABILITATION 293 0 -29328 LINE REHABILITATION 12 0 -12SUBTOTAL - TRANSMISSION LINE SUSTAINING 14,765 18,822 2,347 1,711

STATION SUSTAININGSTATION ASSESSMENT AND MINOR PROJECTS 6,010 6,201 191STATION UNFORESEEN REPAIRS 1,803 2,131 226 102CMMS 0 246 246BULK OIL BRKR REPLACEMENT 2,352 780 -1,572WARFIELD TERMINAL CONNECTOR REPLACEMENT AND DEFICIENCY CORRECTION 0 1,268 1,268GROUND GRID UPGRADES 1,503 1,543 41TRANSFORMER OIL FILTRATION/REPLACEMENT 1,503 542 -961LTC OIL FILTRATION 902 991 90WEST OSOYOOS TRANSFORMER REHAB 0 343 343KASLO SUB UPGRADE 968 1,265 297PINE STREET T1 REPLACEMENT 303 0 -303TROUT CREEK T1 REHAB 1,002 343 -659REPLACE COFFEE CREEK T2 1,933 0 -1,933REPLACE CRAWFORD BAY T1 1,933 0 -1,933TAP CHANGER LEAK REPAIR AND UPGRADESUBTOTAL - STATIONS SUSTAINING 20,209 15,653 226 -659 -1,521 -6 1,268 -3,865

TOTAL - TRANSMISSION 217,875 253,681 3,476 11,994 5,198 13,051 5,954 -3,865

TRANSMISSION PROJECT DESCRIPTION

BCOAPO A2.3

07-'11 Total 07-'11 TotalInflation Project

ScopeRefined

EstimatesSchedule Change

Added Project

Cancelled Project

original update

DISTRIBUTION GROWTHNEW CONNECTS SYSTEM-WIDE 19,285 43,050 4,300 19,465

KELOWNA AREAKELOWNA GENERAL FEEDER PROTECTION 315 0 -315MCKINLEY LANDING CAPACITY UPGRADE(#2 TO 477) FED FROM SEX3 545 359 -186NEW GLE6 FEEDER(50L U/B HIGH RD-CLIFTON) 1,230 1,371 141HOL1-DGB3/LEE2 TIE 726 1,500 774HOL1-OKM1 TIE ALONG KLO RD 554 349 -205MCKINLEY TO CLIFTON TIE 246 633 387LEE2-HOL5 TIE, ADD N.O. 246 419 173RETERMINATE LEE FEEDERS AT NEW N. KELOWNA SUBSTATION 615 0 -615FUTURE KELOWNA DISTRIBUTION UPGRADES 3,795 3,852 57Feeder Egress Cables 0 244 244GLE1/GLE2/HOL4 U/G CABLES 0 94 94HOL3-SEX4 TIE 0 250 250HOL1 HOL2 TIE 0 49 49LEE2 REGULATOR 0 157 157SEX4 REGULATOR 0 160 160

PENTICTONWEB1 VOLTAGE REGULATORPRI4 CAPACITY UPGRADE 0 2,231 2,231OKF1 CAPACITY UPGRADE 0 594 594

OSOYOOS/OLIVER25 KV TIE TO ANARCHIST/BRIDESVILLE 2,460 0 -2,460

SIMILKAMEENKEREMEOS FEEDER 0 158 158KER1 CAPACITY UPGRADE 0 553 553KER2 CAPACITY UPGRADE 0 196 196SOUTH SLOCANVAL1 CAPACITY UPGRADE 0 897 897

CRESTON AREACRA2 CAPACITY UPGRADE 0 372 372

GENERAL (PRIMARY & SECONDARY VOLTAGE PROBLEMS, RELIABILITY IMPROVEMENTS, SWITCHING IMPROVEMENTS) 3,150 3,744 594

SUBTOTAL - DISTRIBUTION GROWTH 33,166 61,232 4,894 20,607 -2,460 5,955 -930

DISTRIBUTION SUSTAININGDISTRIBUTION CONDITION ASSESSMENTS 2,705 3,581 388 489DISTRIBUTION REHABILITATION 9,015 9,411 973 -577ROW RECLAMATION 3,396 3,245 316 -467DISTRIBUTION LINE REBUILDS 4,508 9,917 1,091 4,319SMALL PLANNED CAPITAL 3,215 1,999 212 -1,428PCB PROGRAM 4,508 4,458 -50FORCED UPGRADES AND LINE MOVES 3,005 7,038 757 3,276DISTRIBUTION URGENT REPAIRS 6,010 7,483 782 691AESTHETIC & ENVIRONMENTAL UPGRADES 0 512 512SUBTOTAL - DISTRIBUTION SUSTAINING 36,361 47,132 4,519 6,253 512

TOTAL - DISTRIBUTION 69,526 108,364 9,413 26,860 -2,460 6,467 -930

DISTRIBUTION PROJECT DESCRIPTION

07-'11 Total 07-'11 Total Inflation Project Scope

Refined Estimates

Schedule Change

Added Project

Cancelled Project

original update

TELECOM, SCADA, P&C GROWTHDISTRIBUTION SUBSTATION AUTOMATION, METERING AND COMMUNICATIONS 4,388 4,999 611TRAIL-OLIVER HIGH CAPACITY COMMUNICATIONS 7,590 3,859 -2,731 -1000TELECOMMUNCIATIONS BACKBONE LOOP CLOSE 0 0TELECOMMUNICATIONS FOR BUSINESS SYSTEMS 0 0

SUBTOTAL - TELECOM, SCADA, P&C GROWTH 11,978 8,858 -2,120 -1,000

TELECOM, SCADA, P&C SUSTAININGNARROW SPECTRUM CONVERSIONHARMONIC REMEDIATION 601 537 -64PROTECTION UPGRADES 3,431 3,737 306FAULT LOCATING INACCESSIBLE LINES 902 459 -443COMMUNICATIONS UPGRADES 1,478 984 -494

SUBTOTAL - TELECOM, SCADA, P&C SUSTAINING 6,411 5,717 -694

TOTAL - TELECOM, SCADA, P&C 18,389 14,575 -2,814 -1,000

TELECOM, SCADA, P&CPROJECT DESCRIPTION

BCOAPO A2.4

Refined Estimates

Major Reason For Change

DOUBLE CIRCUIT 230 kV VAS TO RGA 2,780 Project amalgation - recognition of overlaps in specific projects - will be addressed in the CPCN230/161/138 BENTLEY TERMINAL -3,272 Same as above230 KV VASEUX TO BENTLEY 359 Same as aboveKELOWNA SHUNTS & SVC 470 Same as aboveELLISON DISTRIBUTION SOURCE 750 The orignal estimate was based on preliminary concepts. Revised estimate based on more detailed engineering design.

BRAELOCH (SW) DISTRIBUTION SOURCE 2,912The orignal estimate was based on preliminary concepts. Revised estimate based on more accurate equipment cost and recognition that transmission and Distribution facilities will be required.

COFFEE CREEK T3 REPLACEMENT 1,370 The orignal estimate was based on preliminary concepts. Revised estimate based on more accurate equipment cost.TRANSMISSION LINE URGENT REPAIRS 516 Revised estimate based on three year average

136ROW RECLAMATIONS 1622 The original plan had inadvertenly ommitted expenditures for this project

TRANSMISSION CONDITION ASSESSMENTS 2680 The original plan had inadvertenly included the funds for condition assessments in the Future year rehabalation project.

SWITCH ADDITIONS -1,251The original plan anticipated that switches would have to be replaced in each year of the plan, however further analysis indicates that no switchs are required to be replaced between 2009-2011 .

FUTURE YEAR REHABILITATION -1536 See Transmission Condition Assessment above.59

BULK OIL BRKR REPLACEMENT -1,572The original plan anticipated that Bulk oil Circuit Breakers would have to be replaced in each year of the plan, however further analysis indicates that no Bulk oil Circuit Breakers are required to be replaced between 2010-2011 .

41TRANSFORMER OIL FILTRATION/REPLACEMENT -961 analysis indicates that no transformer oil is required to be replaced between 2007-2010.

TRANSMISSION PROJECT DESCRIPTION

BCOAPO A2.4

Refined Estimates Major Reason For Change

NEW CONNECTS SYSTEM-WIDE 19,465The original plan was based on the historical cost associated with the low growth period 2001-2003. The revised estimate is based on the higher growth period starting in 2004 and 2005.

HOL1-DGB3/LEE2 TIE 774The orignal estimate was based on preliminary concepts. Revised estimate based on more detailed engineering design.

MCKINLEY TO CLIFTON TIE 387The orignal estimate was based on preliminary concepts. Revised estimate based on more detailed engineering design.

DISTRIBUTION CONDITION ASSESSMENTS 489The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

DISTRIBUTION REHABILITATION -577The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

ROW RECLAMATION -467The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

DISTRIBUTION LINE REBUILDS 4,319 See response to BCUC IR 1. 3.1

SMALL PLANNED CAPITAL -1,428The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

FORCED UPGRADES AND LINE MOVES 3,276The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

DISTRIBUTION URGENT REPAIRS 691The estimate in the original plan was based on a fixed amount , the revised estimate is based on a three year average which better reflects the current environment.

DISTRIBUTION PROJECT DESCRIPTION

Refined Estimates Major Reason For Change

DISTRIBUTION SUBSTATION AUTOMATION, METERING AND COMMUNICATIONS 611

The orignal estimate was based on preliminary concepts. The revised estimate is based on more detailed engineering design that has occurred during the past few years regarding new substatios such as Lambert and Nkmip.

TRAIL-OLIVER HIGH CAPACITY COMMUNICATIONS -2,731 The estimate for the Grand Forks to Trail section of line has been reduced based on the detiled work associated with FAULT LOCATING INACCESSIBLE LINES -443 The original plan anticipated that fault locating equipment would have to be replaced in each year of the plan, however COMMUNICATIONS UPGRADES

-494The original plan anticipated that a level amount of communication upgrades would be required in each year of the plan, however further analysis indicates that the amount can be reduced in 2010 and 2011.

TELECOM, SCADA, P&CPROJECT DESCRIPTION


Wait Information Request No. 1 Request Date: September 14, 2006 Response Date: September 28, 2006

Page 1

Q1. Reference BCUC IR #40 1

P.70, L.16 states the capacity of the Corra Linn turbines is 12,810 cfs while the 2

Water License is for only 12,600 cfs. 3

Would FortisBC be able to obtain a Water License for the additional 210 cfs at 4

Corra Linn? If so, please confirm whether it would rank before or after the Canal 5

Plant Water license. 6

A1. FortisBC could apply for a Water License for an additional 210 cfs at Corra Linn, 7

however it’s success in obtaining the Water License is not certain. Even if FortisBC was 8

successful in its application, BC Hydro’s Water License for the Kootenay Canal 9

Generating Station would hold precedence over the suggested new FortisBC Water 10

License at the Corra Linn Generating Station. 11

12

Q2. If the additional 210 cfs water license above could be obtained, could the year round 13

capacity at Corra Linn be increased for the additional 210 cfs under the Canal Plant 14

Agreement? What energy increase could be expected? 15

A2. If FortisBC was successful in its application for an additional 210 cfs Water License at 16

the Corra Linn Generating Station, there would be no change to the Canal Plant 17

Agreement entitlement capacity associated with the Corra Linn Generating Station. The 18

Canal Plant Agreement entitlement capacity assigned to the Corra Linn Generating 19

Station is based on tests conducted immediately prior to the original Canal Plant 20

Agreement in 1972. At that time, the technology did not exist to accurately discriminate 21

between 12,600 cfs and 12,810 cfs, so the output of the facility was measured at “full 22

capability”, which in all probability was 12,810 cfs rather than 12,600 cfs. During the 23

negotiations that preceded the 2005 Canal Plant Agreement, FortisBC was able to 24

preserve the concept that the entitlement capacity assigned to the Corra Linn Generating 25

Station would be based on the original measurements rather than new tests indexed to 26

12,600 cfs. Therefore, since the original tests were probably based on the higher flow, no 27

increase to entitlement capacity associated with the Corra Linn Generating Station is 28

anticipated from an additional 210 cfs Water License. Similarly, the energy output is not 29

expected to change for the same reasons. 30



Page 2

Q3. If a new turbine was installed at Corra Linn unit #1, what flow and capacity 1

increase could be obtained without other significant changes to the generator or 2

transformer for unit #1? What energy increase could be expected? 3

A3 The flow and capacity increases resulting from a new turbine installed in Corra Linn Unit 4

1 would depend on the design of the turbine. Clause 2.8 of the FortisBC Entitlement 5

Adjustment Agreement, shown below, places restrictions on the design of the new 6

turbine: 7

FortisBC would be required to design a new turbine for Expected Actual Streamflows, 8

which are currently restricted to 5,000 cfs for at least 9 months of every year. A turbine 9

optimized for Expected Actual Streamflows would likely have its peak efficiency point at 10

a lower flow, rather than a higher flow, resulting in lower output at both the 12,600 cfs 11

and 12,810 cfs flows. If the turbine was instead redesigned for maximum efficiency 12

with the same peak efficiency point and flow characteristics (which would not be 13

consistent with Clause 2.8 above), energy gains on the order of 1% could be realized 14

without significant changes to the transformer or generator. 15



Page 3

Q4. Would the capacity increase in IR #3 above be available year round under the 1

Canal Plant Agreement to better manage the Kootenay Lake storage? Would the 2

energy component for non-freshette months remain the same? 3

A4. As previously described, it is unlikely there would be any capacity increase associated 4

with a new turbine installed in Corra Linn Unit 1, and at best, a 1% increase in the energy 5

component. 6

7

Q5. Reference Appendix 3, Upper Bonnington units 1-4 8

In conjunction with replacing the Upper Bonnington units 1-4, is FortisBC 9

considering an option moving some of the Upper Bonnington capacity to Lower 10

Bonnington as well as South Slocan, and co-operating with the City of Nelson to 11

balance the hydraulic capacity of the four sites: Corra Linn, Upper Bonnington, 12

Lower Bonnington and South Slocan? 13

A5. In order to replace the capacity associated with Upper Bonnington Units 1 to 4 at either 14

the Lower Bonnington or South Slocan Generating Stations, a fourth unit would be 15

required at both of those stations, in addition to a new water license of 3,000 to 4,000 cfs. 16

The cost of each of the additional units at the Lower Bonnington and South Slocan 17

Generating Stations would be approximately $40 - $50 million. With the operating 18

conditions associated with the 2005 Canal Plant Agreement, such a solution would not 19

yield any additional benefit from Expected Actual Streamflows. Therefore, there is no 20

reason to investigate this further. 21

22

Flow coordination with the City of Nelson’s Bonnington Falls Generating Station also 23

does not provide an opportunity to re-capture the benefits associated with Upper 24

Bonnington Units 1 to 4. During periods when the Expected Actual Streamflow is 5,000 25

cfs (approximately 9 months of the year), the City of Nelson’s Bonnington Falls 26

Generating Station currently processes 1,693 cfs, and FortisBC’s Upper Bonnington 27

Generating Station processes the balance, almost always passing the 3,307 cfs through 28

either Unit 5 or Unit 6. Under these conditions, if more water was assigned to the City of 29

Nelson’s Bonnington Falls Generating Station it would simply reduce flow through the 30



Page 4

FortisBC Upper Bonnington Generating Station, with no appreciable difference in 1

generation. During freshet, when flows are in excess of 15,000 cfs, all units at both the 2

City of Nelson’s Bonnington Falls Generating Station and the FortisBC Upper 3

Bonnington Generating Station are dispatched full on, so there is no opportunity for 4

coordination. The period of time that streamflows are between 5,000 cfs and 15,000 is so 5

short, that there is no possibility for benefits from coordination to displace the generation 6

provided by Upper Bonnington Units 1 to 4. 7

8

Q6. Would an option described in IR #5 above provide additional energy during the 9

spring freshette period, if the total generating capacity of the four sites were 10

increased. 11

A6. Adding more units at the four sites would provide additional energy during the freshet 12

period, but the capital cost associated with adding the additional units exceeds the 13

expected benefit to be gained from the additional energy. 14

15

Q7. Under the Canal Plant Agreement, would FortisBC be able to capitalize on 16

additional capacity as per IR #6 above during the non-freshette portion of the year, 17

if the installed capacity at the 4 Kootenay River sites were say 13,400 cfs each? 18

A7. There would be no benefit to FortisBC for additional capacity outside the freshet period. 19

20

Q8. If FortisBC were to equalize the capacities (in co-operation with the City of Nelson) 21

of the four Kootenay River dam sites, would FortisBC be able to obtain an increase 22

of energy due solely to the previous mismatch of the existing dams under the Canal 23

Plant Agreement? 24

A8. Equalizing the capacities at the four Kootenay River dam sites would not result in any 25

increase in the Canal Plant Agreement entitlement energy received by FortisBC unless 26

there was an associated increase in actual generation from Expected Actual Streamflows. 27

Since the installed capacity at the four Kootenay River dam sites exceeds the Expected 28

Actual Streamflows of 5,000 cfs for at least nine months of every year, there is no benefit 29

to be gained during this period. 30



Page 5

1

For the freshet period, facilities could be modified or added to capture streamflows in 2

excess of current flow processing capabilities of the facilities. However, the capital costs 3

associated with such modified or additions currently exceed the value of the additional 4

energy that could be generated. 5

6

Q9. Reference Oil Filtration Page 60 7

The oil filtration units appear to cost in excess of $30,000 each. Please provide 8

information on the amount of the oil per transformer to be filtered, and some 9

specifications on the filter units themselves. Do the installations occur at the same 10

time as the transformers are being serviced under normal maintenance or are the 11

installations done completely separately? 12

A9. The filtration units are used to filter the oil in the tap changer units. The volume of oil 13

being filtered ranges from 500 liters to 5,000 liters depending on the specific tap changer. 14

(Note that this system is not used for filtering the main transformer tank oil). 15

16

Installations are coordinated with the maintenance activities where reasonably 17

practicable. 18

19

The specifications for the filter units is shown below. 20



Page 6



Page 7

Q10. Reference Slide 14, from the Workshop 1

When does FortisBC anticipate the T3 transformer will be required at the Vaseux 2

Substation? 3

A10. The current forecast and system studies indicate that Transformer 3 at Vaseux will not be 4

required until after the year 2020. 5

6

Q11. Reference Slide 85, from the Workshop 7

Do the bars on the chart represent the number of poles remaining in service that 8

were installed in each year, or the total number of poles put into service in each 9

year? 10

A11. The bars on the chart represent the number of poles remaining in service that were 11

installed in each year. 12

Documents

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