regulatory@fortisbc.com www.fortisbc.com F ORTIS BC 2008 A NNUAL R - - PDF document

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regulatory@fortisbc.com www.fortisbc.com F ORTIS BC 2008 A NNUAL R - - PDF document

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Dennis Swanson FortisBC Inc. Director, Regulatory Affairs Regulatory Affairs Department Suite 100, 1975 Springfield Rd. Kelowna BC V1Y 7V7 Fax: 1 866 605 9431 regulatory@fortisbc.com www.fortisbc.com F ORTIS BC 2008 A NNUAL R EVIEW AND B-8

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SLIDE 1

Dennis Swanson Director, Regulatory Affairs FortisBC Inc. Regulatory Affairs Department Suite 100, 1975 Springfield Rd. Kelowna BC V1Y 7V7 Fax: 1 866 605 9431 regulatory@fortisbc.com www.fortisbc.com

November 17, 2008

  • Ms. Erica M. Hamilton

Commission Secretary BC Utilities Commission Sixth Floor, 900 Howe Street, Box 250 Vancouver, BC V6Z 2N3 Dear Ms. Hamilton: Re: FortisBC Inc.’s 2008 Annual Review and 2009 Revenue Requirements Workshop November 13, 2008 Please find enclosed FortisBC Inc.’s presentation from the 2008 Annual Review and 2009 Revenue Requirements Workshop held at the Grand Resort and Conference Centre, Kelowna BC on November 13, 2008. If further information is required, please contact the undersigned at (250) 717 0890. Sincerely, Dennis Swanson Director, Regulatory Affairs cc Registered Intervenors

B-8 FORTISBC 2008 ANNUAL REVIEW AND 2009 REVENUE REQUIREMENTS – EXHIBIT

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SLIDE 2

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

1

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

Safety, Environment, Revenue Protection

2008 Annual Review

November 13, 2008 Kelowna, BC Michael Mulcahy VP, Customer & Corporate Services

slide-3
SLIDE 3
  • Safety
  • Environment

Overview

  • Revenue Protection

3

Safety

Safety is a never ending journey:

  • FortisBC has moved into the top half of CEA group

S f t M t S t dit d b i d d t

  • Safety Management System audited by independent

auditor

  • 2006
  • 2007
  • Continual improvement

4

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SLIDE 4

All Injury Frequency Rate

Safety

2.00 3.00 4.00 5.00 6.00 7.00 FortisBC CEA Group II (301-2300 Employees)

4

0.00 1.00 2003 2004 2005 2006 2007 2008F

Safety

Average Claim Duration 2007

5 10 15 20 25 30 35 40 45 50 FortisBC CEA WSBC Utilites WSBC Days

5

slide-5
SLIDE 5

Safety

WorkSafe Assessment Rate

$0 20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60

FBC Assessment Base

6

$- $0.20 2004 2005 2006 2007 2008 2009

Safety

600 700 800 900

Total Course Occurrences (deliveries)

100 200 300 400 500 2004 2005 2006 2007 2008 est

Total Employees Attending Training 7

1,000 2,000 3,000 4,000 5,000 6,000 7,000 2004 2005 2006 2007 2008 est.

slide-6
SLIDE 6

Financial

$15,000 $20,000 $25,000

Safety

$0 $5,000 $10,000 1 2 3 4 total Years Hours

300 350

Example – New Hire Power Line Technician - Journeyman

50 100 150 200 250 300 1 2 3 4 total Years

8

Public safety

  • FortisBC is also committed to public safety

Safety

  • Cooperative Safety Program
  • General Public Safety Awareness

9

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SLIDE 7
  • BC Energy Plan
  • Self-sufficient by 2016

Environment

  • 50% of incremental load through conservation by 2020
  • Heritage Contracts in perpetuity
  • Utilities Commission Act Amendment, Bill 15 – 2008
  • Bill 15 effectively aligned the UCA with government objectives in

the EP

  • FortisBC Initiatives

10

  • Advanced Metering Infrastructure
  • Resource Plan
  • PowerSense

Revenue Protection

2008 Revenue Protection Activities Approved Cost Forecast Cost Forecast Annual Savings NPV Saving Savings Power Diversion Inspections $235,000 $195,000 $146,439 $584,600 Third Party Contracts $25,000 $25,000 $60,700 $242,400 Total $260,000 $220,000 $207,139 $827,000

11

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SLIDE 8

Power Diversion Trends October- September

Revenue Protection

2007 2008 Diversions 29 25 High Load Paying Sites 18 26 Average Annual kWhs 93,500 123,700 Investigations 321 330

12

Primary Dip Greenwood

Revenue Protection

14

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SLIDE 9

Revenue Protection

15

Revenue Protection 2009

  • Excellent results achieved 2006-2008

Revenue Protection

  • Benefits of power diversion program
  • Safety
  • Reduced Power Purchase Costs
  • General deterrence

2009 costs are forecast at $225,000

15

2009 costs are forecast at $225,000

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SLIDE 10

Safety, Environment, Revenue Protection 2008 Annual Review

Questions/Comments Questions/Comments

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

18

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

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SLIDE 11

2008 Annual Review

Demand Side Management

Mike Mulcahy Vice President Richard Tarnoff Customer & Corporate Services DSM Advisory Committee

  • Overview
  • 2008 Highlights
  • 2008 Forecast

20

  • 2007 Incentive Calculation
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SLIDE 12

PowerSense Overview

Award-winning program

Overview

g p g

  • Started in 1989
  • 301 GWh total energy savings
  • $33 million investment

Cost-effective electricity resource

21

2008 Highlights

Planning

  • 2009-10 DSM (CEP) filing
  • DSM strategic document

Programs

  • Cool Shops
  • Destination Conservation
  • LiveSmart BC

DSM Advisory Committee

22

DSM Advisory Committee

  • Terms of reference
  • Participation
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SLIDE 13

October PowerSense Month

Conservation Awards Luncheons

2008 Highlights

  • 40 Conservation awards
  • 11 Leadership awards

Community engagement

  • Radio contests
  • Community venues

Community venues

  • Employees

23

2008 Forecast

2008 Approved 2008 Projected 2008 Plan 2008 Projected ($000s) GWh Sector Approved Plan Projected Cost 2008 Plan Savings Projected Savings Residential 1,023 1,261 8.4 11.5 General Service 754 866 9.1 14.0 Industrial 200 110 2.0 1.4 Plan/Evaluate/Educate 378 373

  • Total

2,355 2,610 19.5 26.9

24

Total (Net of Tax) 1,613 1,801

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SLIDE 14

2007 Incentive Calculation

Eligible Amount Incentive Rate Incentive Amount Sector ($000s) ($000s) Industrial 87% 259

  • 1%

(2.6) $ General Service 98% 2,255 0%

  • $

Residential 211% 2,035 6% 122.1 $ Total 119.5 $ % of Base Benefits

25

DSM Advisory Committee

DSM Incentive Endorsement

8

Richard Tarnoff, DSM Advisory Committee member, Similkameen representative, Hedley Improvement District operator

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SLIDE 15

Demand Response Pilot Project Hedley Improvement District

  • Load shifting controls
  • Cost savings on TOU rate

27

Demand Reduction Demonstration Hedley Improvement District

  • Reservoir capacity 378,000 litres
  • 2 pumps (60 hp and 30 hp)
  • Pump controls installed Oct 2006
  • Off-peak pumping maintains satisfactory reservoir levels

28

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SLIDE 16

Demand Reduction Demonstration Results

45 000 On Peak 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

kW h

Off Peak On Peak

29

2005 Sep to 2006 Aug 2006 Sep to 2007 Aug 2007 Sep to 2008 Aug Off Peak

Demand Reduction Demonstration Bill Comparison

Consumption: 55 MWh/yr Gen Svc Rate 21

  • $ 4,677

Gen Svc TOU Rate 22A

  • $ 3,613

30

Savings $1,064/yr, or 23%

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SLIDE 17

Demand Side Management 2008 Annual Review

Questions/Comments Questions/Comments

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

32

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

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SLIDE 18

2008 Annual Review

2008/09 Capital Expenditure Plan Update

November 13, 2008 Kelowna, BC Doyle Sam Vice President Engineering and Operations

History

Overview

Market Update Challenges / Successes 2008 Progress Update 2009/2010 C it l Pl

34

2009/2010 Capital Plan

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SLIDE 19

Two year plan was submitted on July 26, 2006 and approved by BCUC on November 24, 2006

Intended Benefits Reg lator certaint

2008 Plan History

  • Regulatory certainty
  • Supply and delivery of equipment
  • Attraction & retention of labour resources

To date

  • National material agreements
  • Lead time allowed for early 2008 construction

35

Volatility continues with world market commodities and competing labour resources and material

Commodity Indices

36

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SLIDE 20

Distribution 2007 material pricing: ↑ 60% - 80% 2008: ↑ 3% from 2007 Deliveries remain consistent with 2007

Changes from 2006

Deliveries remain consistent with 2007 Station 2007 - Power transformers pricing: ↑ 80% 2008 - stabilized Deliveries remain consistent with 2007

37

Generation 2007 – Turbine pricing: ↑ 80% 2008 – stabilized Deliveries remain consistent with 2007 Challenges Labour market Local stakeholder concerns

Challenges / Successes

Successes Increased approval lead time Public consultation and permitting Combining material quotations on multiple jobs Tendering construction work for multiple jobs Utili ti f i t l

38

Utilization of internal resources Standardization of work allows for lower implementation costs New vendor attraction Material alliances

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SLIDE 21

2008 Plan 2008 Forecast

Financial Overview

($million) Generation 19.0 17.3 Transmission & Stations 59.3 50.8 Distribution 20.2 23.8 Telecommunication 3.1 3.1

39

General Plant 8.5 10.1 Demand Side Management 1.6 1.8 TOTAL 111.7 106.9

South Slocan Unit 3

Unit Life Extension Projects

40

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SLIDE 22

2008 Sustaining

41

CPCN EAC Variance ($million) Kettle Valley 20.2 26.7 6.5

CPCN Project Status

Nk’Mip 18.0 20.0 2.0 Big White 20.3 20.5 0.2 AM/FM 2.7 2.7 Ellison 17.2 17.2 Black Mountain 14.4 14.4 Di t ib ti S b t ti 6 5 6 5

42

Distribution Substation Automation 6.5 6.5 Ootischenia 8.1 7.3 (0.8) TOTAL 107.4 115.1 7.7 OTR 141.4 141.4

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SLIDE 23

New substation in Boundary area Conversion of distribution to 25 kV Communications infrastructure for increased reliability

Kettle Valley

Communications infrastructure for increased reliability

43

Additional capacity to Osoyoos area 18.44 km of new transmission line Communication infrastructure to handle tripping

Nk’Mip

Communication infrastructure to handle tripping schemes to improve reliability

44

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SLIDE 24

New substation at Big White New transmission line Upgrade of distribution in area

Big White

Upgrade of distribution in area

45

Black Mountain

New substation in East Kelowna New transmission line

46

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SLIDE 25

Ellison

New substation in Kelowna Transmission and Distribution infrastructure

47

Ootischenia

New substation near Castlegar

48

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SLIDE 26

Budget Spent EAC Comments / Explanation Design and construct distribution substation with one 63/13 kV 16 MVA transformer and egress for t f d 6 586 2 662 5 941 Under Budget (000's)

Ootischenia Cost Report

two feeders 6,586 2,662 5,941 Under Budget Design and construct connections to local 13 kV distribution feeders, and transmission lines 88 163 314 Over budget due to increased distribution networking costs outside the station. The majority of these costs will be recovered in the station as the demarcation point is now the station fence as opposed to the first egress structure. Planning / Pre Engineering / Regulatory Costs 630 490 490 Under budget due to reduced community concerns. Land Acquisition and Assessments 457 366 400 Under Budget 49 SUBTOTAL 7,762 3,681 7,146 AFUDC 325 71 161 Forecast to be under budget due to less spending in 2007 and the first quarter of 2008 than originally budgeted. There will be less AFUDC because the energization date has not changed. TOTAL CAPITAL COST 8,087 3,752 7,306

  • Production on February 14, 2008
  • Completion of all phases by December 31, 2008

GIS System Upgrade

50

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SLIDE 27
  • Advanced Meter Infrastructure (AMI)

CPCNs in Progress

  • Benvoulin Substation

51

  • Positive stakeholder consultation

Conclusion

  • Positive project financial performance
  • Market still unpredictable

52

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SLIDE 28

2008 Capital Expenditure Plan Update 2008 Annual Review

Questions/Comments

53

Questions/Comments

2009 Update 2009/10 Capital Plan Summary

54

slide-29
SLIDE 29

June 27 2009/2010 Capital Plan Filing

Regulatory Timetable

Aug 7 BCUC IR1 Aug 12 Workshop Aug 28 BCUC IR2 & Intervener IR1 Sept 29 Record Closed

55

Financial Status – CPCN Projects Overview

2009 Plan 2009/10 Total ($million) Previously Approved 96.3 172.3 CPCN Submitted 24.2 64.5 CPCN t b S b itt d

56

CPCN to be Submitted Subtotal 120.5 236.9 Remainder 58.3 123.0 TOTAL 178.8 359.9

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SLIDE 30

June 27 Nov 3 ($million) Generation 21.9 22.1

2009 Planned Expenditures

Transmission & Stations 96.1 80.7 Distribution 28.2 28.8 Telecommunication 2.2 2.6 Advanced Metering Infrastructure 16.5 16.5 Information Systems 5.2 5.2

57

General Plant 6.1 6.1 Demand Side Management 2.5 2.6 TOTAL 178.8 164.5 Annual Operating Savings 0.2 0.2

  • Focused on growth, safety & aging infrastructure

Two year plan provides lead time & certainty to

Capital Plan

  • Two year plan provides lead time & certainty to

minimize market impacts

  • Ongoing policy changes
  • Long term infrastructure

58

g

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SLIDE 31

2009 Update 2009 Capital Expenditure Plan Update 2008 Annual Review

Questions/Comments

59

Questions/Comments

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

60

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

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SLIDE 32

Forecast 2008 Financial Results

2008 Annual Review

November 13, 2008 Kelowna, BC Michele Leeners VP, Finance and CFO

Revenue Requirements Overview

Approved Forecast ($000s) ($000s) ($000s) Percentage S l V l (GWh) 3 087 3 064 (23) (0 7%) Increase (Decrease) from Approved 2008 Sales Volume (GWh) 3,087 3,064 (23) (0.7%) Rate Base (mid year) 822,847 802,649 (20,198) (2.5%) Revenue 220,950 219,026 (1,924) (0.9%) Power Supply 76,396 72,492 (3,904) (5.1%) Operating 34,840 34,344 (496) (1.4%) Taxes 15,165 16,574 1,409 9.3%

62

Financing (excluding earnings) 66,145 64,415 (1,730) (2.6%) Incentive Adjustments - 2007 (1,284) (1,284)

  • Incentive Adjustments - 2008
  • 1,616

1,616 100% Net Earnings 29,688 30,869 1,181 4%

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SLIDE 33

Mid-Year Rate Base

Approved Forecast Increase (Decrease) from Approved 2008 Rate Base (mid year) 822,847 802,649 pp (20,198) ($000s)

63

Electricity Sales, Revenue and Power Supply

Approved Forecast Increase (Decrease) from Approved 2008 Sales Volume (GWh) 3,087 3,064 Revenue 220,950 219,026 Power Supply 76,396 72,492 (1,924) (3,904) from Approved (23) ($000s)

64

Margin 144,554 146,534 1,980

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SLIDE 34

Operating Costs

2008 Approved Forecast Increase (Decrease) from Approved O&M 45,310 44,875 (435) Capitalized Overhead (9,062) (9,062) ‐ Wheeling 3,622 3,624 2 ($000s)

65

Other Income (5,030) (5,093) 63 34,840 34,344 (496)

Taxes

Approved Forecast 2008 Increase (Decrease) from Approved Taxes Property tax 11,176 11,023 Income taxes 3,989 5,551 Total Taxes 15,165 16,574 1,562 1,409 ($000s) (153)

66

slide-35
SLIDE 35

Financing (excluding earnings)

Approved Forecast 2008 Increase (Decrease) from Approved Financing Cost of Debt 31,789 30,400 Depreciation and amortization 34,356 34,015 Total Financing 66,145 64,415 (1,389) (341) (1,730) ($000s)

67

2008 Flow Through Adjustments & ROE Incentive Adjustment

2008 Approved 2008 Forecast Variance Income Tax Shield After Tax Amount Customer Share Flow Through Adjustment 2008 Flow Through Adjustment ($000s) 2008 Flow Through Adjustment Interest Expense 31,789 30,400 (1,389) (431) (958) 100% (958) Pension Expense 2,739 2,539 (200) (62) (138) 100% (138) BC Tax Rate Reduction

  • 60

(60) 100% (60) Pope & Talbot Bad Debt

  • 565

565 175 390 100% 390 Net variance from forecast 1,291 811 480 149 331 100% 331 (Canpar / Pope / Weyerhaeuser) Flow Through Adjustment (435) 2008 ROE Incentive Adjustment 68 2008 ROE Incentive Adjustment Net Income ($000s) 29,687 32,049 2,362 0.50% (1,181)

Total Flow Through to Customers $1,616, 000

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SLIDE 36

Forecast 2008 Financial Results

Questions / Comments

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

70

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

slide-37
SLIDE 37

2008 Annual Review

Performance Standards

November 13, 2008 Kelowna, BC Doyle Sam Vice President Engineering & Operations

Performance Standards:

  • Safety Reliability Customer Service

Overview

Safety, Reliability, Customer Service

  • Set as part of the 2006 NSA
  • Provide an overall assessment of performance

Today’s Objectives:

  • Review 2008 performance (Oct ‘07 to Sept ‘08)
  • Confirm Incentive sharing

72

Confirm Incentive sharing

  • Propose targets for 2009
slide-38
SLIDE 38

2008 Performance Standards Overview

Targets were met or exceeded in 10 out of 13 categories Targets not met:

  • All Injury Frequency Rate (“AIFR”)
  • Injury Severity Rate (“ISR”)
  • System Average Interruption Duration Index (“SAIDI”)

Notable improvements:

  • Customer Residential service connection and quoting metrics

73

All Injury Frequency Rate (AIFR)

The total # of Lost Time Injuries or illness plus Medical Aid Injuries (per 100 workers). 2008 Target = 2.09 2008 Result = 2.57 Status: Target Not Met

6 7 8

74

g 2009 Target = 2.08

1 2 3 4 5 2003 2004 2005 2006 2007 2008

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SLIDE 39

Injury Severity Rate (ISR)

The total # of work days lost due to injuries or illness (per 100 workers). 2008 Target = 17.53 2008 Result = 18.52 Status: Target Not Met

75

g 2009 Target = 27.00

5 10 15 20 25 30 35 40 45 50 2003 2004 2005 2006 2007 2008

Electrical Contact

  • “Joe”
  • 30 yr practicing PLT journeyman
  • Extensive knowledge of this device
  • Detailed switching/work plan
  • Causal factors
  • Out of Scope
  • Procedure violations

76

  • Lock to Lock
  • Standard Work Procedure (SWP)
  • Personal Protective Equipment (PPE)
  • Limits of Approach
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SLIDE 40

Vehicle Incident Rate (VIR)

The # of vehicle incidents resulting in injury and/or property damage > $1,000 (per 1,000,000 kms driven).

5 6 7

2008 Target = 2.07 2008 Result = 1.12 Status: Target Met

77

1 2 3 4 2003 2004 2005 2006 2007 2008

2009 Target = 1.77 The amount of time the average customer’s power is

  • ff per year (hours).

System Average Interruption Duration Index (SAIDI)

2008 Target = 2.45 2008 Result = 2.55 Status: Target Not Met

78

0.5 1 1.5 2 2.5 3 3.5 2003 2004 2005 2006 2007 2008

g 2009 Target = 2.54

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SLIDE 41

System Average Interruption Frequency Index (SAIFI)

The average number of interruptions per customer served per year. 2008 Target = 3.11 2008 Result = 2.46 Status: Target Met

79

0.5 1 1.5 2 2.5 3 3.5 4 2003 2004 2005 2006 2007 2008

2009 Target = 2.80

Generator Forced Outage Rate (FOR)

The ratio of the total forced outage time to forced

  • utage time plus total operating time multiplied by 100.

2008 Target = 0.35% 2008 Result = 0.08% Status: Target Met

80

0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 2003 2004 2005 2006 2007 2008

2009 Target = 0.35%

slide-42
SLIDE 42

Emergency Response Time

The % of response time to site within 2 hours of initial

  • utage notification.

2008 Target = 85% 2008 Result = 93% Status: Target Met

81

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 85%

Residential Service Connections

The % of new customer connections completed within 6 business days. 2008 Target = 85% 2008 Result = 89% Status: Target Met

82

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 85%

slide-43
SLIDE 43

Residential Extension: Quoting

The % of customers that have received a design and quotation within 35 working days. 2008 Target = 80% 2008 Result = 94% Status: Target Met

83

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 89%

Residential Extension: Completion

The % of customer extensions completed within 30 working days after quote acceptance. 2008 Target = 77% 2008 Result = 95% Status: Target Met

84

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 85%

slide-44
SLIDE 44

Billing Accuracy

The % of bills delayed beyond the regular billing cycle. 2008 Target = 0.072% 2008 Result = 0.049% Status: Target Met

85

0.05 0.1 0.15 0.2 0.25 0.3 0.35 2003 2004 2005 2006 2007 2008

g 2009 Target = 0.072%

Commitment to Read Meters

The actual meters read as a percentage of those scheduled to be read. 2008 Target = 97% 2008 Result = 98% Status: Target Met

86

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 97%

slide-45
SLIDE 45

Contact Center Performance (TSF)

The % of incoming calls answered within 30 seconds. 2008 Target = 70% 2008 Result = 70% Status: Target Met

87

50 55 60 65 70 75 80 85 90 95 100 2003 2004 2005 2006 2007 2008

2009 Target = 70%

Customer Satisfaction (Informational Metric) 8.5 9.0 6.5 7.0 7.5 8.0

88

Average Score 2008 = 8.6

6.0 Q1 '04 Q3 '04 Q3 '05 Q4 '05 Q1 '06 Q2 '06 Q3 '06 Q4 '06 Q1 '07 Q2 '07 Q3 '07 Q4 '07 Q1 '08 Q2 '08 Q3 '08

slide-46
SLIDE 46
  • Targets were met or exceeded in 10 out of 13 categories
  • Continued focus on safety
  • Response time to outages has improved

2008 Performance Standards – Summary

  • Test for Incentive Sharing
  • Incentive was not earned at the expense of performance
  • The Company did not allow or cause performance to

deteriorate in a material way

  • The Company has met the test for incentive sharing

89

Performance Standards Performance Standards

Questions/Comments

slide-47
SLIDE 47

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

91

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

2009 Revenue Requirements

Load and Customer Forecast

November 13, 2008 Kelowna, BC Sandra Gault Resource Planning

slide-48
SLIDE 48
  • Creating a Load Forecast

Overview

  • Forecast Results

93

  • Temperature

Forecast Input Variables

  • Population
  • Customer surveys
  • System improvements

94

  • System improvements
  • Demand Side Management
slide-49
SLIDE 49

1. Observe load growth trends based on historical data 2 Incorporate information that affects f t re trends

Forecasting Electrical Load

2. Incorporate information that affects future trends

  • Population forecasts from BC Stats
  • Forecasts collected from primary customers
  • Usage per customer

3. Expected impact of system improvements

95

4. Energy savings from Demand Side Management

Gross Load Composition

96

slide-50
SLIDE 50

Energy Sales (GWh) Forecast Growth (%)

2008/09 Forecast

Approved Forecast 2008 2008 2009 1,193 1,205 1,222 686 659 678 904 900 921 240 225 224 13 14 14 Approved Forecast 2008 2008 2009 4.2% 2.3% 1.4% 7.7% 2.6% 2.9% 3.3% 3.3% 2.3%

  • 33.8%
  • 32.1%
  • 0.4%

0.0% 10.3% 0.0% Residential General Service Wholesale Industrial Lighting

97

51 48 48 3,087 3,051 3,107 3,396 3,350 3,408 9.1% 9.0% 8.9% 0.0%

  • 2.3%

0.0% 0.1%

  • 1.1%

1.8%

  • 0.2%
  • 1.5%

1.7%

  • 2.6%
  • 3.7%
  • 1.1%

Irrigation Net Load Gross Load Gross Loss % Forecast Customer Count Forecast Growth (%) Approved Forecast Approved Forecast Customer Class 2008 2008 2009 2008 2008 2009 Residential 96,022 95,504 97,255 2.7% 2.0% 1.8%

2008/09 Forecast

General Service 11,471 11,349 11,583 3.2% 3.1% 2.1% Wholesale 7 7 7 0.0% 0.0% 0.0% Industrial 36 37 37

  • 10.0%
  • 2.6%

0.0% Other 3,227 3,031 3,031 0.0% 0.3% 0.0% Total 110,763 109,928 111,913 2.6% 2.0% 1.8% Account Growth 2,858 2,203 1,985

98

slide-51
SLIDE 51

Load and Customer Forecast 2008 Annual Review

Questions/Comments

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

100

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

slide-52
SLIDE 52

2009 Revenue Requirements

Power Purchase Expense

November 13, 2008 Kelowna, BC

Wheeling Expense & Water Fees

Dan Egolf Manager, Resource Planning

Power Purchase Cost forecast to increase from $64.6 ($68.5 approved) to $71.5 million

Comparison with 2008

approved) to $71.5 million

  • Load forecast to increase from 3,369 to 3,433 GWh
  • Reduced summer surplus from 48 to 30 GWh
  • Increase in Brilliant Power Purchase Agreement rates
  • Increase in BC Hydro costs due to April 1, 2008 rate

increase

102

increase

  • Business as usual
slide-53
SLIDE 53

January Peak Load/Resource Balance (after outages)

CAPACITY (701 MW) ENERGY (3,433 GWh)

Spot Market 8 GWh

Spot Market 7 MW

Brilliant 857 GWh BC Hydro PPA 914 GWh

Brilliant Upgrade 65 GWh

DSM / IPP 38 GWh

BC Hydro PPA 190 MW

Spot Market 7 MW

Brilliant Upgrade/Tailrace 24 MW

DSM / IPP 5 MW

TeckCominco Capacity 150 MW

103

FortisBC 1,581 GWh FortisBC 202 MW Brilliant 123 MW

FortisBC Plants

CPA Entitlement Adjustments (before outages/reserves):

Review Resources - 2009

Canal Plant Agreement Annual Energy Entitlement down 2.6 GWh at 1,591 GWh (Before all Upgrades 1,541 GWh) December Capacity Entitlement flat at 223 MW No Further Adjustments to Annual Entitlement Planned

104

No Further Adjustments to Annual Entitlement Planned

slide-54
SLIDE 54

Brilliant Power Purchases

  • Rate increase

B l t 2 7% i f $33 13/MWh t $34 03/MWh

Review Resources - 2009

  • Base plant 2.7% increase from $33.13/MWh to $34.03/MWh
  • Upgrade 4.1% increase from $24.89/MWh to $25.9/MWh
  • 25 MW December Capacity Block at $7,800 per MW
  • Brilliant Expansion Tailrace Capacity Agreement
  • Between 1 and 6 MW depending on month

105

  • About 75% of the BC Hydro Capacity Rate, or $3,796 per MW

month

BC Hydro 200 MW Power Purchase Agreement Review Resources - 2009

  • Volume taken expected to increase from 830 to 914 GWh
  • No BC Hydro rate increase assumed but April 1, 2008 interim rate

applies for full year rather than only 9 months of 2008

  • BC Hydro rates for 2008 and 2009 are still uncertain and will be

trued up as required

106

slide-55
SLIDE 55

Independent Power Producers

  • Volume expected to drop (due to Zellstoff Celgar) to 13.0 GWh in

Review Resources - 2009

p p ( g ) 2009

  • Rate paid to Independent Power Producers is tied to the BC Hydro

Power Purchase Agreement rate of $29.67/MWh

  • 2008 Rate was lower than BC Hydro rate at times due to freshet

conditions

107

Capacity Purchases from Teck

  • Purchased 150 MW for January and 75 MW for February

Market Purchases - 2009

estimated at $6,673 and $6,746 per MW

  • Assumed 75 MW for November and 125 MW December at

estimated $5,643 per MW

  • Average rate increases from $5,048 per MW in 2008 to $6,201

per MW mainly due to exchange rate changes

108

p y g g

slide-56
SLIDE 56

Spot Purchases & Summer Surplus

  • Spot purchase energy forecast is 8 GWh

Market Purchases - 2009

Spot purchase energy forecast is 8 GWh

  • Rate forecast to decrease from $91 per MWh to $76 per MWh
  • Summer surplus to decline to 30 GWh from 48 GWh
  • Rate forecast to decrease from $45.7 per MWh to $31.5 per MWh

109

  • To serve FortisBC loads in the Okanagan and Creston

Wheeling Expense

  • General Wheeling Agreement with BC Hydro
  • BCTC Wholesale Transmission Tariff
  • Teck Cominco Charges
  • Estimated to increase from $3.6 million in 2008 to $4.0 million due

to a 3.3% BCTC rate increase and an increase in our GWA

110

nomination by 15 MW to 175 MW in the OK and 2 MW to 35 MW at Creston.

slide-57
SLIDE 57
  • Water Fees are paid to the Province based on the total amount

f

Water Fees

  • f generation in the previous year and the peak MW capability
  • FortisBC water fees estimated to increase from $7.9 million in

2008 to $8.7 million due to an 82 GWh increase in 2008 entitlement usage compared to 2007

111

Questions/Comments

Power Purchase Expense Wheeling Expense & Water Fees

Questions/Comments

slide-58
SLIDE 58

2008 Annual Review and 2009 Revenue Requirements Workshop

Morning Time Afternoon Time Time 9:00 Welcome and Introductions David Bennett/BCUC Staff 9:15 Opening Remarks John Walker 2008 Annual Review 9:30 Key Issues Michael Mulcahy 10:00 DSM Committee Report Michael Mulcahy/Richard Tarnoff 10:30 Capital Projects Doyle Sam Time 1:15 Performance Standards 2008 Results and 2009 Targets Doyle Sam 2009 Revenue Requirements 2:00 Load Forecast Sandra Gault 2:30 Power Purchase Expense Wheeling & Water Fees Dan Egolf 3:00 Break 3 30 2009 R R i t

113

Doyle Sam 11:15 Break 11:30 2008 Financial Results Variance & Incentive Review Michele Leeners 12:15 LUNCH (provided) 3:30 2009 Revenue Requirement Overview Michele Leeners 4:00 Summary & Closing - David Bennett

Summary

2009 Revenue Requirements

November 13, 2008 Kelowna, BC Michele Leeners VP, Finance & CFO

slide-59
SLIDE 59

Updated November 3, 2008 Application

  • Rate increase of 5.6%

Summary Final Calculation - Outstanding

  • Final ROE – November consensus
  • Any NSA Adjustments

115

2009 Revenue Requirements Overview

2008 2009 Increase Rate Approved Forecast (Decrease) Impact Sales Volume (GWh) 3,087 3,107 20 Rate Base (mid year) 822,847 909,553 86,706 Power Supply Power Purchases 68,538 71,476 2,938 1.14% Water Fees 7 858 8 700 842 0 33% ($000s) Water Fees 7,858 8,700 842 0.33% 76,396 80,176 3,780 1.47% Operating O&M Expense 45,310 46,997 1,687 0.66% Capitalized Overhead (9,062) (9,399) (337)

  • 0.13%

Wheeling 3,622 4,010 388 0.15% Other Income (5,030) (4,915) 115 0.04% 34,840 36,693 1,853 0.72% Taxes Property Taxes 11,176 11,561 385 0.15% Income Taxes 3,989 3,671 (318)

  • 0.12%

15,165 15,232 67 0.03% Financing Cost of Debt 31,762 34,850 3,088 1.20% Cost of Eq it 29 688 32 416 2 728 1 06%

116

Cost of Equity 29,688 32,416 2,728 1.06% Depreciation and Amortization 34,356 37,492 3,136 1.22% 95,806 104,758 8,952 3.48% Incentives Prior Year Incentive True-up 22 173 151 0.06% Flow-Through Adjustments (42) (435) (393)

  • 0.15%

AFUDC / CWIP Shortfall 895

  • (895)
  • 0.35%

ROE Sharing Mechanism Adjustments (2,159) (1,181) 978 0.38% (1,284) (1,443) (159)

  • 0.06%

Interest on Non Rate Base Deferral Account 27

  • (27)

Total Revenue Requirement 220,950 235,416 14,466 Rate Increase 5.6%

slide-60
SLIDE 60

Rate Base

Forecast Forecast 2008 2009 ($000s) Opening depreciated rate base 772,893 845,590 Increase in year 72,697 107,396 Closing depreciated rate base 845,590 952,986 Mean depreciated rate base 809,241 899,288 Allowance for working capital and capital additions (6 592) 10 265 ($000s)

117

Allowance for working capital and capital additions (6,592) 10,265 Mid-year rate base 802,649 909,553 % change over prior year 13%

Deferred Charges

Demand Side Management Regulatory Deferred

  • Flow Through & ROE Sharing Mechanisms

R R i t di

  • Revenue Requirement proceedings
  • Cost of Service Study and Rate Design

Preliminary & Investigative Other Deferred

  • Pension & Post Retirement Benefit Costs
  • Revenue Protection

I t ti l Fi i l R ti St d d (IFRS)

118

  • International Financial Reporting Standards (IFRS)
  • Right of Way Encroachment Litigation
  • 2011 Long Term CEP & SDP
  • DSM Study

Deferred Issue Costs

  • Debt Issue Costs
slide-61
SLIDE 61

Operating Costs

2008 2009 Increase Approved Forecast (Decrease) ($000s) ($000s) ($000s) O&M expense 45,310 46,997 1,687 Capitalized Overhead (9,062) (9,399) (337) Wheeling 3,622 4,010 388 Other Income (5,030) (4,915) 115 Total Operating 34,840 36,693 1,853

119

  • Total O&M expense includes base O&M, Pension and

Post-Retirement Benefits and Trail Office Lease costs Operating - O&M Expense

  • 2009 Base O&M determined by formula:

Base O&M = 2008 adjusted base O&M / customer x [1 + (forecast 2009 BC CPI – PIF)] x average # of customers Base O&M = $382.48 x [1 + 2.1% - 2.0%] x 110,920

120

Base O&M = $42,467,000

slide-62
SLIDE 62

Operating - O&M Expense and Capitalized Overhead

2008 2009 Increase Approved Forecast (Decrease) Percentage Base O&M 41,818 42,467 649 1.5% ($000s) ($000s) ($000s) Other O&M costs outside of formula: Trail Office Lease 753 1,212 459 Pension and other post retirement benefits 2,739 3,318 579 Sub Total 3,492 4,530 1,038 Total O&M Expense 45,310 46,997 1,687 Capitalized Overhead (20%) (9,062) (9,399) (337) Net O&M Expense 36,248 37,598 1,350

121

Taxes

2008 2009 Increase Approved Forecast (Decrease) Property Taxes 11,176 11,561 385 Income Taxes 3,989 3,671 (318) 15,165 15,232 67 ($000s) ($000s) ($000s)

122

slide-63
SLIDE 63

2008 2009 Increase Approved Forecast (Decrease) ($000s) ($000s) ($000s)

Financing Costs

Cost of Debt 31,762 34,850 3,088 Cost of Equity 29,688 32,416 2,728 Depreciation and Amortization 34,356 37,492 3,136 95,806 104,758 8,952

123

  • 2008 incentives returned to customers in 2009

2008 Incentives

($000s) 2007 Incentive True-up: 173 Flow Through Adjustments: Interest Expense (958) Pension Expense (138) BC Tax Rate Reduction (60) Pope & Talbot Bad Debt 390 Net Variance from Forecast (Canpar / Pope / Weyerhaeuser) 331 124 2008 ROE Incentive Adjustment: (1,181) Total Reduction to the Revenue Requirements (1,443) Rate Impact (including tax effect) (.9%)

slide-64
SLIDE 64

Accounting Changes Deferred Income Taxes

  • Effective January 1, 2009. Recognize liability with offsetting

regulatory asset

  • No effect on 2009 Revenue Requirements

International Financial Reporting Standards

  • Effective January 1, 2011
  • Uncertainty around treatment of regulatory assets & liabilities

125

2009 Revenue Requirements Overview

Questions / Comments

slide-65
SLIDE 65

FortisBC Presentation of Customer Incentive Sharing

November 13, 2008

No customer Customer

  • Nov. 3

incentive incentive Filing w/ incentive Forecast Forecast Forecast 2009 2009 2009 REVENUE DEFICIENCY POWER SUPPLY Revenue Requirements Overview POWER SUPPLY Power Purchases 71,476

  • 71,476

Water Fees 8,700

  • 8,700

80,176

  • 80,176

OPERATING O&M Expense 46,997

  • 46,997

Capitalized Overhead (9,399)

  • (9,399)

Wheeling 4,010

  • 4,010

Other Income (4,915)

  • (4,915)

36,692

  • 36,693

TAXES Property Taxes 11,561

  • 11,561

Income Taxes 4,302 (631) 3,671 15,863 (631) 15,232 2 15,863 (631) 15,232 FINANCING Cost of Debt 34,873 (23) 34,850 Cost of Equity 32,444 (28) 32,416 Depreciation and Amortization 37,492

  • 37,492

104,809 (51) 104,758 Prior Year Incentive True Up

  • 173

173 Flow Through Adjustments

  • (435)

(435) AFUDC / CWIP shortfall

  • ROE Sharing Incentives
  • (1,181)

(1,181)

  • (1,443)

(1,443) TOTAL REVENUE REQUIREMENT 237,541 (2,125) 235,416 RATE INCREASE 6.59%

  • 0.95%

5.64%

slide-66
SLIDE 66

No customer Customer

  • Nov. 3

incentive incentive Filing w/ incentive Forecast Forecast Forecast 2009 2009 2009 UTILITY INCOME BEFORE TAX 71 619 (682) 70 937 SCHEDULE 3 INCOME TAX EXPENSE UTILITY INCOME BEFORE TAX 71,619 (682) 70,937 Deduct: Interest on Non Rate Base Deferral Account

  • Interest Expense

34,873 (23) 34,850 ACCOUNTING INCOME 36,746 (659) 36,087 Adjustments to Accounting Income to arrive at Taxable Income Deductions Capital Cost Allowance 49,846

  • 49,846

Capitalized Overhead 9,399

  • 9,399

Incentive & Revenue Deferrals

  • 1,443

1,443 Financing Fees 1,034

  • 1,034

All Other (net effect) 501 501 3 All Other (net effect) 501

  • 501

60,780 (1,443) 62,223 Additions Amortization of Deferred Charges 2,558

  • 2,558

Depreciation 34,934

  • 34,934

37,492

  • 37,492

TAXABLE INCOME 13,457 (2,101) 11,356 Tax Rate 30.0%

  • 30.0%

Taxes Payable 4,037 (630) 3,407 Prior Years' Overprovisions/(Underprovisions)

  • Deferred Charges Tax Effect

265

  • 265

REGULATORY TAX PROVISION 4,302 (630) 3,672

Amount Refunded back to Customers in 2009 Customer Incentive Sharing (presented as after tax) $1 443 Customer Incentive Sharing (presented as after tax) $1,443 Reduction in Income Tax Expense 631 Reduction in Financing Costs 51 Total reduction in 2009 Customer Revenue $2,125

4