Terasen Gas Inc. & Terasen Gas Vancouver Island (TGVI) 2006 Resource Plans

Terasen Gas Inc. & Terasen Gas Vancouver Island (TGVI) 2006 Resource Plans June 20 th, 2006 Stakeholder Workshop Contact Cynthia Des Brisay Cynthia.Desbrisay@terasengas.com Director, Business Development Telephone: (604) 592-7837 Ken Ross Ken.Ross@terasengas.com Resource Planning Analyst Telephone: (604) 576-7343 Terasen Gas www.terasengas.com

Introduction Tom Loski Director of Regulatory Affairs 2

Purpose of Today s Workshop is to: Explain the role of Resource Planning at Terasen Gas Provide planning background Discuss the evaluation of resource options for meeting future demand: Terasen Gas (Vancouver Island) Inc., and Terasen Gas Inc. (Mainland service area) Obtain feedback, and Outline the next steps 3

Today s Agenda & Speakers Introduction Regional Gas Supply Issues In the Pacific North West Terasen Gas Energy Outlook Demand Forecasts Tom Loski Director, of Regulatory Affairs Dan Kirschner Executive Director, Northwest Gas Association Doug Stout Vice President, Marketing and Business Development Greg Caza Energy Forecasting Manager Energy Efficiency and Optimization Sarah Smith Manager, Marketing and Energy efficiency Terasen Gas Supply Planning Resource Options to Meet Future Gas Demand Update Mt. Hayes LNG Project Tania Specogna Manager, Business Development Edmond Leung System Capacity Planning Manager & Dave Perttula Manager, Business Development Guy Wassick Manager, Business Development Conclusions, Action Plan, Next Steps Cynthia Des Brisay Director, Business Development 4

Workshop Format and Feedback Format of Today s Workshop: 1:30pm to 4:30pm Opportunities will be provided to offer comments and ask questions during the presentation We will be logging comments and questions raised during the session for consideration in the Resource Plan filing. Written comments to Ken Ross at Ken.Ross@terasengas.com by July 4 th. An electronic copy of the presentation material will be posted on the Terasen Gas web site at www.terasengas.com 5

Terasen Gas Company Overview Terasen Gas 125 communities in B.C. 900,000 customers Parent Company: Kinder Morgan Inc. Four Subsidiaries: Terasen Gas Inc. Terasen Gas (Vancouver Island) Inc. Terasen Gas (Squamish) Inc. Terasen Gas (Whistler) Inc. 6

Terasen Gas Inc. Regulatory Calendar June - December 2006 June July Aug Sept Oct Nov Dec Residential Unbundling CPCN Low Pressure System CPCN Mission Bridge CPCN IPC Decision Reconsideration TGI Annual & Mid-term Review & TGVI Settlement Update TGI & TGVI Resource Plans LEGEND Application Preparation Filing Review & Decision Process Hearing Process (Oral or Written) Decision 7

What is a Resource Plan? A long-term plan for the acquisition of resources to meet forecasted customer needs. A planning document that outlines stakeholder input and analyzes financial, environmental and social impacts. Resource Planning is intended to facilitate the selection of cost-effective resources that yield the best overall outcome of expected impacts and risks for ratepayers over the long run. - BCUC Resource Planning Guidelines, 2003 Resource Plans submitted to the BCUC for review and acceptance Approval for specific actions still subject to other regulatory review processes 8

Evaluating the Resource Options Objective Attribute Measure Ensure reliable and secure System reliability Risk of outages supply. Security of supply Gas supply diversity Provide service to Financial evaluation of Net Present Value customers at least delivered supply side and demand side Total Resource Cost (TRC) cost. resources Ratepayer Impact (RIM) Reduce rate volatility. Expected rates Risk trade-offs Balance socio-economic and environmental impacts. Social costs / benefits including: Local emissions Greenhouse gas Land use impacts Employment/local economic impacts Stakeholder consultation Air pollutants Quantity of CO 2 equivalent Area impacted Jobs created Stakeholder input 9

David Bennett, Director of Energy Management Services at Terasen Gas will now introduce: Mr. Dan Kirschner Executive Director, NORTHWEST GAS ASSOCIATION To speak on Regional Gas Supply Issues 10

NW Natural Gas Market Outlook Dan Kirschner, Executive Director Northwest Gas Association TGI Resource Plan Stakeholder Workshop June 20, 2006 11

5335 SW Meadows Rd., #220 Lake Oswego, OR 97035 (503) 624-2160 www.nwga.org NWGA Members: Avista Corporation Cascade Natural Gas Co. Intermountain Gas Co. NW Natural Puget Sound Energy Duke Energy Gas Transmission Terasen Gas TransCanada s GTN System Williams NW Pipeline

Gas a Vital Part of NW Energy Scene 1,000 NW Consumption by Energy Source (Including BC, ID, OR, WA; Source: USA-EIA, CAN-StatCan) 900 Million Dth 800 700 600 Electric Gas (including gas for generation) 500 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 13

Recent Gas Demand 1,000 900 800 Industrial Generation Commercial Residential Cumulative PNW Gas Deliveries* (source: USA-EIA, CAN-StatCan) *2005 BC estimated from preliminary StatCan data 700 Million Dth 600 500 400 300 200 100 0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 14

Proportion of Gas Demand by Sector - 2005 Composition of 2005 PNW Gas Demand Source: EIA, StatCan Industrial 33% Commercial 17% Generation 23% Residential 27% 15

Gas Demand Forecast (2006-07 through 2010-11) Low Growth Case Base (expected) Case High Growth Case Average Annual Cumulative Average Annual Cumulative Average Annual Cumulative Total 1.0% 4.1% 2.1% 8.1% 2.7% 10.2% Residential 1.9% 7.3% 3.2% 11.9% 4.2% 15.2% Commercial 1.3% 4.9% 2.5% 9.3% 3.1% 11.5% Industrial 0.0% 0.1% 0.5% 2.0% 0.6% 2.4% Generation 1.1% 4.1% 2.6% 9.7% 3.2% 11.9% 16

Demand Forecast 1,000 900 Low Projected Demand Base/Expected Demand High Projected Demand Actual Projected Regional Demand (Source: 2006 NWGA Outlook) Actual Forecast (weather normalized) Million Dth 800 700 600 500 2000 2001 2002 2003 2004 2005 06-07 07-08 08-09 09-10 10-11 17

Demand Forecast by Sector Projected Regional Demand By Sector - Base Case 280 260 240 Million Dth 220 200 180 160 Residential Commercial Generation Industrial 140 120 100 2006-07 2007-08 2008-09 2009-10 2010-11 18

Proportion of Projected Gas Demand by Sector: 2010-2011 Composition of PNW Demand - Base Case Change from 2005: Generation 23% Industrial 29% Residential 30% Commercial 18% Residential 3% Commercial 1% Industrial 4% Generation 19

Station 2 Western Canadian Sedimentary Basin Sumas Stanfield Kingsgate AECO Northwest Gas Supply Malin Opal Rockies Basins 20

WCSB Production 18 WCSB Production Forecasts Actual Forecast Bcf/Day 17 16 15 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Canadian Energy Research Inst. NEB (04 Techno Vert) NEB (04 Supply Push) Consensus Forecast Wood Mackenzie TransCanada Duke Energy Actual 21

Rockies Production 11 10 Bcf/d 9 8 7 6 2005 2006 2007 2008 2009 2010 2011 EEA EIA Wood Mackenzie Other Consultants Avg Consensus Forecast 22

Supplies Flow to Demand Pipeline Flow (MMcfd) 2005 6203 1205 747 238 107 1598 94 99 401 2165 180 1213 1082 840 1721 2396 2564 426 3381 2122 203 453 124 1983 1598 1186 811 921 2336 1392 474 461 Everett 3308 740 565 223 622 1884 3865 2570 912 51 899 28 224 1889 1768 2576 208 332 433 117 529 512 1312 1637 5007 5083 81 1379 391 6324 4333 2730 1650 4298 54 2507 375 570 Elba Island Cove Point 4794 1063 1510 EEA0406 669 793 1885 2013 Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease 294 Lake Charles 23

Growing Demand, Slowing Supply Projected US Supply/Demand Balance (EIA Annual Energy Outlook 2006) 30 LNG imports are the marginal resource 25 20 Frontier gas (Mackenzie, Alaska) 15 10 5 0 Other Supplies Canadian Supply Domestic Supply US Demand 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year 24 Quadrillion Btu

Northwest LNG Proposals PortWestward LNG Skipanon LNG Jordan Cove LNG Northern Star LNG Tansy Point Kitimat LNG WestPac Terminal Why LNG? Vast reserves no local market pipelines not viable decreasing costs Challenges include: Local acceptance Regulatory/Permitting Commercial considerations: economics/financing takeaway infrastructure worldwide competition supplier commitment 25

Northwest Gas Infrastructure Capacity at Major Interconnects & Storage Facilities (MDth/day) Station 2 1995 60 440 120 154 884 Malin 2119 Sumas 1306 305 100 Kingsgate 2796 Starr Road 165 Stanfield 638 62 North Flow 493 South Flow 160 Kemmerer 653 Pipelines DEGT BC Pipeline Williams NW P TransCanada - GTN Terasen S. Crossing Storage Facilities Jackson Prairie Mist LNG Facilities Plymouth Newport Portland Tilbury Nampa 26

Capacity to Serve NW Demand: Average Winter Day 6 Pipeline & Storage Capacity vs. Avg. Winter Day Demand Low Base High Pipeline Capacity Pipeline + Storage Million Dth/day 5 4 3 2 1 Includes Mist and potential JP expansions 0 2006-07 2007-08 2008-09 2009-10 2010-11 Winter Year (Dec-Feb) 27

Capacity to Serve Demand: 7 Region-wide Peak Day NW Total Firm Peak Day Demand/Capacity Balance (ID, OR, WA, BC) Low Base High Pipeline Underground Storage Peak LNG 6 Million Dth/day 5 4 3 2 1 0 2006-07 2007-08 2008-09 2009-10 2010-11 Year (Nov-Oct) 28

Capacity to Serve Demand: I-5 Peak Day I-5 Total Firm Peak Day Supply/Demand Balance 5 Low Base High Pipeline Underground Storage Peak LNG 4 Million Dth/day 3 2 1 0 2006-07 2007-08 2008-09 2009-10 2010-11 Year (Nov-Oct) 29

Jan-06 Recent Gas Prices U.S. Natural Gas Wellhead Price $12 $10 $8 $6 $4 $2 $0 30 Jul-05 Oct-05 Apr-05 $/Mcf (nominal) Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Source: EIA

Productive Capacity Source: Energy and Environmental Analysis, Inc. 55 50 Bcfd 45 Bubble Tight Market 40 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Gas Production Productive Capacity

The Good News (but for how long?) Daily Prices $16 Wyoming AECO-C Henry Hub Sumas Station 2 $14 12/1/05 12/7/05 12/13/05 12/19/05 12/25/05 12/31/05 1/6/06 1/12/06 1/18/06 1/24/06 1/30/06 2/5/06 2/11/06 2/17/06 2/23/06 3/1/06 3/7/06 3/13/06 3/19/06 3/25/06 3/31/06 4/6/06 4/12/06 4/18/06 4/24/06 4/30/06 5/6/06 5/12/06 5/18/06 5/24/06 5/30/06 $12 $10 US$/MMBtu $8 $6 $4 Source: Platts Gas Daily and EIA Natural Gas Weekly Update 32

Price Drivers: Storage (Supply) 3500 3000 2500 Bcf 2000 1500 1000 5yr high-low 5 year Minimum 5yr average 2005 2006 500 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 Source: EIA, 06/15/2006 Week 33 33

Price Drivers: Production U.S. Gas Rigs In Operation Rig Count 1,600 1,400 1,200 1,000 800 600 400 200 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 Week Source: Baker Hughes, 06/09/2006 5yr high-low 5 year minimum 5yr average 2005 2006 34

$12 Crude Oil:Natural Gas Price Correlation = 0.875 $10 $8 $6 $4 $2 $0 $80 $70 $60 $50 $40 $30 $20 $10 $0 35 Jan-2002 Apr-2002 Jul-2002 Oct-2002 Jan-2003 Apr-2003 Jul-2003 Oct-2003 Jan-2004 Apr-2004 Jul-2004 Oct-2004 Jan-2005 Apr-2005 Jul-2005 Oct-2005 Jan-2006 Apr-2006 $/Mcf $/Bbl The Price of Oil Has an Impact US Natural Gas US Crude Oil (WTI) Source: EIA

As Does the Weather Weather Affect on Prices Sumas (flow date) Henry Hub Spot $16 $15 $14 $13 Hurricane Katrina landfall August 29, 2005 Hurricane Rita landfall September 24, 2005 $/MMBtu $12 $11 $10 $9 $8 $7 $6 8/1/05 8/8/05 8/15/05 8/22/05 Source: Energy Information Administration 8/29/05 9/5/05 9/12/05 9/19/05 9/26/05 10/3/05 10/10/05 36

Markets Are Connected Pipeline Flow (MMcfd) 2005 6203 1205 747 238 107 1598 94 99 401 2165 180 1213 1082 840 1721 2396 2564 426 3381 2122 203 453 124 1983 1598 1186 811 921 2336 1392 474 461 Everett 3308 740 565 223 622 1884 3865 2570 912 51 899 28 224 1889 1768 2576 208 332 433 117 529 512 1312 1637 5007 5083 81 1379 391 6324 4333 2730 1650 4298 54 2507 375 570 Elba Island Cove Point 4794 1063 1510 EEA0406 669 793 1885 2013 Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease 294 Lake Charles 37

Natural Gas Demand Natural gas demand in PNW will grow moderately over next five years. normal weather, economic conditions Load shape changing: peak loads growing faster than base. 38

Natural Gas Supply There is plenty of gas, but N. American production struggling to keep up with growing demand. N. America increasingly integrated PNW consumers will benefit from incremental supplies. 39

Natural Gas Prices Natural gas prices have moderated; Prices remain volatile: tight supply/demand balance weather, production, etc. 40

Natural Gas Infrastructure Transmission/storage capacity adequate to serve region at present. Very efficient system; little redundancy; how to serve changing load shape. Permitting/regulatory processes must be nimble; facilitate necessary projects when required. Infrastructure takes time. Information sharing helps ensure supply is available when needed. 41

Energy Outlook Doug Stout, Vice President Marketing and Business Development 43

The Benefits of Natural Gas Terasen Gas offers a safe, reliable, secure, affordable and efficient energy choice to meet the growing needs of businesses and communities while enabling the pursuit of sustainability over the long run. 44

Natural Gas In BC: playing a vital role The energy industry is integral to the economy of British Columbia We are all committed to responsible and sustainable development Natural gas is vital to the prosperity of the province 11,400 jobs in 2006 $1.9 billion in Provincial Revenue 45

Natural gas & BC s energy picture Public Administration 1.2% Energy Use in British Columbia in 2004 By Sector Commercial & other institutional Commercial 15.2% and other Mining and oil & gas extraction 35.4 % - natural gasinstitutional 3.0% 32.5 % - electricity 15.2% Manufacturing 24.2% Manufacturing 44.8 % - natural gas 24.2% 44.4 % - electricity Residential Residential 15.0% 52.6 % - natural gas 15.0% 45.7 % - electricity Agricultural 1.5% Forestry 0.8% Construction 0.8% Transportation 38.3% Source: BC Ministry of Energy, Mines and Petroleum Resources 46

BC s Energy Plan Electricity deficit Marginal source / cost of electricity Natural gas role in conserving heritage resources Renewables and emerging technologies New energy cost reality New energy mix 47

Challenges in Meeting British Columbia s Energy Needs Electricity Demand / Supply Options for meeting new electricity demand and achieving self-sufficiency Alternate Energy Sources? cents/kwh Conservation & Energy Efficiency *~4.5 cents/kwh Minimize costs to British Columbians New Supply *4.5 to 15.7 cents/kwh Incremental Electricity Resources Heritage Electricity ~2.5 cents/kwh 2005 2010 2015 2020 * Resource type unit energy costs from BC Hydro 2006 IEP, Table 5-5 48

A Flexible Energy Platform Pipeline to the Future: Natural Gas is an important part of an efficient, environmentally sensitive, economic and cost effective energy platform today, and an important bridging fuel for advancements in energy system technology for tomorrow Individual metering in multiunit buildings High efficiency technology District energy technology Fleet vehicle solutions Fuel cell research Hydrogen highway Sustainable Energy Systems Community Energy Platform 2006 2010 49

Right Fuel, Right Use, Right Time! 50

Demand Forecast Greg Caza Energy Forecasting Manager 51

Demand Forecast Overview Use and Development Methodology TGVI Demand Forecast TGI Demand Forecast Update Core Market Demand Summary 52

Demand Forecasts Use & Development Terasen develops demand forecasts as key inputs to: 1) System planning 2) Annual contracting plan 3) Revenue forecasting Key activities Customer account additions Use rates Annual demand Design day and design year demand Customer Segmentation Core market demand Residential, commercial and industrial (TGI only) customers Squamish & Whistler Transportation demand Vancouver Island Gas Joint Venture (VIGJV), Generation - Island Cogeneration Plant (ICP) & Burrard Thermal 53

Forecast Methodology Core customer demand forecast Customer account additions Conducted on a community level Use rates Derived for each rate class (excluding industrial) Customer survey used for TGI industrial customers Peak day & design year demand Regression analysis of weather data to determine peak day Design year based on five coldest winters 54

TGVI Demand Forecast 55

TGVI Core Customer Additions TGVI Customer Growth 15, 0 0 0 12, 0 0 0 Cust omer addit ions CAGR 2001-05 4.12% CAGR 2006-31 B a se 2. 5 7 % High 2.94% Low 2. 17 % Total Customers High Scenario Base Case Low Scenario 200,000 180,000 160,000 Customers Additions 9,000 6,000 Actuals Forecast 140,000 120,000 100,000 80,000 60,000 Total Customers 3,000 40,000 Customer additions 20,000 0 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031-56

TGVI Use Rate Residential use rates are forecasted to remain stable over the planning period No change in normalized use rates over 2004 to 2005 period Natural gas appliances on Vancouver Island are relatively new as compared to the Lower Mainland Commercial and industrial use rates are also forecasted to remain the same Known load changes are reflected in the forecast 57

TGVI Core Customer Annual Demand Growth in residential annual demand is forecasted to outpace commercial demand growth Residential customer additions form the majority of total additions Total Core Market Annual Demand 2006 2031 Residential 39% 45% Commercial 61% 55% 58

TGVI Core Customer Annual Demand TGVI Annual Demand 2006-2031 20,000 17,500 15,000 Demand (TJ) 12,500 10,000 7,500 5,000 2,500 Residential Demand Commercial Demand 0 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 Year 59

TGVI Design Weather 32 TGVI Design Weather vs. Five Coldest Winters Heating Degree Days 28 24 20 16 12 1968 1971 1978 1984 1985 Design 8 4 0 1 20 39 58 77 96 115 134 153 172 191 210 229 248 267 286 305 324 343 362 Coldest Day to Warmest 60

TGVI Design Weather First 30 Days 32 TGVI Design Weather vs Five Coldest Years (First 30 Days) Heating Degree Days 30 28 26 24 22 1968 1971 1978 1984 1985 Design 20 18 16 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Coldest Day to Warmest 61

TGVI Core Customer Design Day TGVI Core Customer Demand vs Weather (2002-2004) Daily Core Demand (GJ per acct) 1.4 1.2 1.0 0.8 0.6 0.4 0.2 Design Day Demand (per acct) at Design Day Temperature of -10.7 degrees Celcius 0.0-15 -10-5 0 5 10 15 20 25 30 Temperature, Degrees Celcius Predicted Demand Actual Demand 62

TGVI Core Customer Design Year 200.0 TGVI Design Load Duration Curves 180.0 Daily Core Demand (TJ) 160.0 140.0 120.0 100.0 80.0 60.0 2007 2014 2031 40.0 20.0 0.0 1 20 39 58 77 96 115 134 153 172 191 210 229 248 267 286 305 324 343 362 Coldest to Warmest Day 63

TGVI Total Demand 2005 Annual Demand Peak Demand Generation 48% Core Sales 34% Generation 27% Core Sales 64% TG Squamish 1% Joint Venture 17% TG Squamish 2% Joint Venture 5% 64

TGI Demand Forecast Update 65

TGI Account Additions Significant change since the 2004 Resource Plan Dramatic increase in housing construction during the 2004-05 period as compared to the three previous years Higher growth projections from household formation 66

TGI Customer Account Additions Comparison TGI 2004 vs. 2006 Customer Additions Forecast Comparison 16,000 14,000 12,000 Actuals - 2006 Resource Plan Forecast - 2006 Resource Plan 2004 Resource Plan Customer Additions 10,000 8,000 6,000 4,000 2,000 0 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 67

TGI Total Account Forecast Total number of customers over the planning period is higher than in the 2004 Resource Plan Strong growth in customer additions during 2004-05 has moved the anchor point up Higher forecasted growth rates from the household formations report has also shifted the total number of forecasted customers upwards 68

TGI Total Account Forecast Comparison TGI Year-End Customers 1,200,000 1,100,000 1,000,000 Total Customers 900,000 800,000 700,000 600,000 High - 2006 Resource Plan Base - 2006 Resource Plan Low - 2006 Resource Plan 2004 Resource Plan 500,000 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 69

Core Market Demand Summary 70

TGI & TGVI Core Market Demand Summary TGI TGVI 2005 Customers 799,804 85,016 Annual Demand (TJ) 113,319 11,653 Peak Demand (TJ/Day) 1,256 105.9 2021 Customers 1,000,200 138,302 Annual Demand (TJ) 138,801 16,667 Peak Demand (TJ/Day) 1,507 154.3 2031 Customers 1,092,116 164,627 Annual Demand (TJ) 149,593 19,197 Peak Demand (TJ/Day) 1,600 178.3 Average Annual Demand Growth ('05-'31) 1.07% 1.94% All figures year-end Design day figures for TGI do not include Squamish Squamish 2005 Design Day = 4.0 TJ, 2021 Design Day = 7.0 TJ, 2031 Design Day = 7.8 TJ 71

Energy Efficiency & Optimization Sarah Smith Manager, Marketing and Energy Efficiency 72

Overview DSM what is it and why do we do it? DSM Tactics Conservation Potential Review Where do we go from here? 73

What is DSM? Peak Shaving Valley Filling Load Building Utility activity that modifies or influences the way in which customers utilize energy services Conservation 74

Why do DSM? Enhances customer satisfaction Allows us to use our delivery system more efficiently Improves local air quality Reduces GHGs Improves economic competitiveness Can help defer major capital investment 75

What s our approach to DSM? Tactics Technology 76

Tactics - Partners 77

Partner recognition 78

Tactics Programs - TGVI 79

Tactics Programs - TGI 80

Tactics Building on Partnerships New Home Program Launch Summer 2006 BC Hydro, MEMPR Up to $3,000 Includes $600 for gas appliances 81

Tactics Conservation Potential Review Marbek, in association with Habart and Willis Energy Services Alignment with Hydro CPR Outlook to 2015/2016 Potential results, dependent on external conditions Regional results 82

CPR Results Total Potential GJ per year By 2015/2016, GJ per year TGVI Lower Mainland Interior Total Residential EE -369,000-5,298,000-1,847,000-7,514,000 Commercial EE -385,000-1,396,000-431,000-2,212,000 Industrial EE -32,430-933,064-924,210-1,889,704 Subtotal -786,430-7,627,064-3,202,210-11,615,704 Residential Fuel Sub 1,453,000 Potential Annual Impact -10,162,704 83

CPR Results Potential Peak Day Reduction By 2015/2016, GJs TGVI Lower Mainland Interior Total Residential EE -2,646-45,933-16,641-65,220 Commercial EE -2,147-7,787-3,282-13,216 Industrial EE -175-14,031-5,716-19,922 Sub Total -4,968-67,751-25,639-98,358 Residential Fuel Sub 2,912 5,878 3,327 12,117 Potential Peak Day Impact, GJ -2,056-61,783-16,500-80,339 84

Where do we go from here? 85

TGI and TGVI Gas Supply Issues Tania Specogna Manager, Business Development 86

Overview Overview of gas supply planning at Terasen Gas Meeting Future Peak Load Growth Infrastructure projects have long lead times Regional Resource Options Available Current and Future Best Fit for TGI/TGVI Market Valuation of Resources Options 87

Gas Supply Planning Criteria / Managing Risks Build supply diversity into portfolio Ideally have multiple suppliers, pipelines, storage resources, supply basins. Attempt to limit exposure to problems associated with a single source. Support regional infrastructure planning- NWGA Work cooperatively with other utilities in the region. Ensure adequate supply. Infrastructure projects have long lead times. Add resources that reduce price volatility. Manage price risk Store gas in summer Use financial tools (buy at fixed prices in advance). Build a flexible plan 88

2006/07 TGI Normal and Design Load vs Supply Typical Resource Fit Create a portfolio to meet Design Peak Day Requirements Baseload/Seasonal Pipeline for average day supply Shorter-term pipeline contracts and upstream storage for winter average day Market Area storage most efficient for short term peaks Provide security of supply in event of failures Pipeline capacity sets a price cap 1,400 1,300 1,200 1,100 1,000 900 800 700 600 500 400 300 200 100 0 Design Peak Day Peaking Resources Market Area Storage/Shaped Pipeline Capacity Pipeline Capacity Design Normal TJ/d 01/11/2006 15/11/2006 29/11/2006 13/12/2006 27/12/2006 10/01/2007 24/01/2007 07/02/2007 21/02/2007 07/03/2007 21/03/2007 04/04/2007 18/04/2007 02/05/2007 16/05/2007 30/05/2007 13/06/2007 27/06/2007 11/07/2007 25/07/2007 08/08/2007 22/08/2007 05/09/2007 19/09/2007 03/10/2007 17/10/2007 31/10/2007 89

31/10/2007 13/12/2006 27/12/2006 10/01/2007 24/01/2007 07/02/2007 21/02/2007 07/03/2007 21/03/2007 04/04/2007 18/04/2007 02/05/2007 16/05/2007 30/05/2007 13/06/2007 27/06/2007 11/07/2007 25/07/2007 08/08/2007 22/08/2007 05/09/2007 19/09/2007 03/10/2007 17/10/2007 Meeting Future Demand Growth As peak day grows each year need combination of pipe/incremental shorter duration resources.. Regional Issues Growth in peak day requirements is higher than average day. All utilities in our region face need to add new resources to meet growth. Availability of Shaped Resources vs baseload Large infrastructure projects require longer lead times 1,400 1,300 1,200 1,100 1,000 900 800 700 600 500 400 300 200 100 0 Design Peak Day Peaking Resources Market Area Storage/Shaped Pipeline Capacity Pipeline Capacity Design 90 TJ/d 01/11/2006 15/11/2006 29/11/2006

Regional Resource Options Upstream Supply/Storage Pipeline Capacity On System Resources Market Area Storage 91

Westcoast Pipeline Infrastructure 700 MMcfd uncontracted capacity Market requires capacity on colder than normal days Already accounted for in today s regional design peak day Pipe expansion to meet future design peak day growth No expansion pipe capacity until TSouth recontracted MMcfd 1800 1600 1400 1200 1000 800 600 400 200 0 1-Nov-05 8-Nov-05 Nov 05- Mar 06 Westcoast T-South Flows TGI Load 600 TJ/d (half design peak day) Pipeline Capacity to Sumas T-South Firm Contracted Capacity 15-Nov-05 22-Nov-05 29-Nov-05 6-Dec-05 13-Dec-05 20-Dec-05 27-Dec-05 3-Jan-06 10-Jan-06 17-Jan-06 24-Jan-06 31-Jan-06 7-Feb-06 14-Feb-06 21-Feb-06 28-Feb-06 7-Mar-06 14-Mar-06 21-Mar-06 28-Mar-06 Winter 2004/05 Winter 2003/04 92

NorthWest Pipeline Infrastructure Replaced 26 line from service with looping, compression and capacity turn-back No incremental Capacity No additional I-5 expansions scheduled 93

Market Area Storage Infrastructure On & Off System Market Area Storage Resources Off System Storage JPS Expansion Up to 300 MMcfd LNG Storage One third contracted for avg term 32 years Redelivery More Expensive (30-50% of Firm NWP Rate) Mist Expansion Potential for Future Expansions Issue of Redelivery On System Tilbury LNG Storage Expansion New LNG Storage 94

TGI & TGVI Off System & On System Market Area Storage & Future Requirements Market area storage 30-40% of design peak day Puget and NWN 50-60% of design peak day 75% of TGI/TGVI Off System storage has renewal risk (price and/or availability) TJ/d 750 700 650 600 550 500 450 400 350 300 250 200 TGI and TGVI Market Area Storage Contracts and Future Requirements 40% 30% 30%-40% Peak Day Off System Market Area Storage 150 100 50 On System Market Area Storage 0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 95

Incremental Capacity in the Region Expansion of NWP system north of Chehalis (JPS) No scheduled expansion Expand upstream Pipe Capacity 700 MMcfd WEI uncontracted LNG Storage Add On System Resource On System LNG Storage Increases Security of Supply Must be Cost Effective 96

Market Valuation For On System Resource 25 Year PV; 6.1% Discount $400 $350 $300 Cdn$ Millions $250 $200 $150 $100 $50 $0 Long Term Low Cost Redelivery Long Term High Cost Redelivery Market Area Storage 10 day 150 MMcfd Equivalent WEI Pipe with Mitigation WEI Pipe without Mitigation WEI Pipeline 10 day 150 MMcfd Equivalent 97

Summary Need to Evaluate Resources to Meet Future Peak Growth Infrastructure projects have long lead times Pipeline Expansions No Expansion on T-South in the near term No Expansion North of JPS scheduled Storage Expansions JPS Expansion and potential Mist Expansion Firm redelivery will cost more than existing contracts On System resource better fit Security of Supply Cost of Off System Market Area Storage and Westcoast Pipe provide proxy 98

Resource Portfolio Development Edmond Leung System Capacity Planning Manager 99

Resource Planning Portfolio Analysis Overview Agenda Brief System Overview 3 Major Transmission Systems (TGVI, TGI Coastal, TGI Interior) Drivers for infrastructure resource additions Anticipated constraints and timing for reinforcement Resource options 100

Resource Planning Portfolio Analysis Overview 6% 5% % Flow of Day 4% 3% 2% 1% 0% 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour of Day ITS CTS TGVI-TS Overview of Terasen Major Transmission Systems inter-relationship and general peak day flow patterns design for peak day versus peak hour flow 101

Resource Planning Portfolio Analysis Overview - Interior Transmission System KAMLOOPS ITS Core Demand [mmscfd] Total with Industrial/ transports [mmscfd] Savona 12 Current Demand 202 277 Annual growth 3 WEI VERNON Capacity 303 Kingsvale KELOWNA Reinforcement Required 2013+ 12 12 4 PENTICTON 6 NELSON Hedley 10 16 OLIVER Y 10 Midway 10 8 Trail 12 Kit-A YAHK TCPL Kit-B LEGEND COMPRESSOR UNIT 24 102

Resource Planning Portfolio Analysis Overview - Interior Transmission System Pipeline loop KAMLOOPS LNG Savona WEI VERNON 12 Kingsvale KELOWNA Pipeline loop 12 PENTICTON NELSON Hedley 10 16 OLIVER Y Midway 10 Trail 12 Kit-A YAHK TCPL Kit-B LEGEND COMPRESSOR UNIT 24 Compressor Addition 103

Resource Planning Portfolio Analysis Overview - Coastal Transmission System Burrard Thermal Plant BURRARD THERMAL PLANT TGVI Custody Transfer Point (Eagle Mountain) 20 EAGLE MOUNTAIN 24 24 20 COQUITLAM AREA Pipeline with compressed gas Pipeline with uncompressed gas METRO- VANCOUVER AREA FRASER COQUITLAM COQUITLAM 20 36 PORT MANN CROSSING 12 FRASER VALLEY AREA HANEY 20 24 36 PATTULLO 18 24 24 NICHOL 30 12 FORT LANGLEY 12 6 TILBURY LNG PLANT TILBURY 12 BENSON BURNS BOG ROEBUCK 24 18 42 BALFOUR 12 30 Langley Comp Stn 30 42 HUNTINGDON 104

Resource Planning Portfolio Analysis Overview - TGVI Transmission System Proposed Reinforcement V3b V2 Loop d/s of Watershed and & V5 V1 U4 V6 105

TGVI current System Capacity vs Demand Projection 250 TGVI Design Day Forecast 200 Terajoules per Day 150 100 50 TGVI Core Whistler BC Hydro Squamish VIGJV 2005 Capacity 0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year beginning November 106

Pipe & Compression Portfolio Long Term Demand Scenario TGVI, TGS and TGW Core Market Demand 2008 V4 minor Upgrades 2021 V3b V2 2013 Joint Venture Mills V5 2013 V1 U4 2017 2027 V6 107

Pipe & Compression Portfolio Peak Day System Capacity Versus Demand TGVI with P&C w/ core + JV (Case 6) 108 24 17 13 9 5 1 12 8 5 1 8 6 3 1 26 24 21 19 17 15 12 9 6 3 1 2030 2031 2028 2029 2027 250.0 Avail PD Capacity for IT JV Whistler Squamish Core Add V2 & V5 V1-U4 V3b V6 200.0 150.0 100.0 Peakday System Capacity Peakday Demand [TJ/d] 50.0 0.0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Winter

LNG Storage Portfolio Long Term Demand Scenario TGVI, TGS and TGW Core Market Demand Joint Venture Mills V5 2008 V4 minor Upgrades 2029 Mt. Hayes LNG 2010 109

LNG Storage Portfolio Peak Day System Capacity Versus Demand 250.0 Avail PD Capacity for IT JV Whistler Squamish Core Peakday System Capacity LNG TGVI with Mt. Hayes LNG w/ core + JV (Case 5) V5 200.0 110 0 24 17 13 0 0 7 0 45 45 45 45 45 42 38 35 19 0 0 0 0 0 0 0 0 0 150.0 100.0 Peakday Demand [TJ/d] 50.0 0.0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Winter

Resource Planning Portfolio Analysis Overview - Portfolio Summary Resource Portfolios: LNG Storage versus Pipe & Compression Pipe and Compression Portfolio Squamish V2 Dunsmuir V5 Coquitlam V1-U4 Sechelt V3b Crofton V6 Watershe d 25.3 km Loop Total Expediture millions 2006$ direct $22.7 $21.6 $15.6 $21.6 $21.6 $27.7 Core Markets (TGVI, TGS, TGW) 2016 2016 2021 2025 2030 $103.1 Core Markets + JV 2013 2013 2017 2021 2027 $103.1 Core Markets + JV + ICP 2010 2013 2012 2013 2027 2029 $130.8 LNG Storage Portfolio Squamish V2 Dunsmuir V5 Coquitlam V1-U4 Sechelt V3b Crofton V6 Watershe d 25.3 km Loop Total Expediture millions 2006$ direct $22.7 $21.6 $15.6 $21.6 $21.6 $27.7 Core Markets (TGVI, TGS, TGW) Core Markets + JV 2029 $21.6 Core Markets + JV + ICP 2019 2029 2028 $59.9 111

Resource Portfolio Evaluation David Perttula Terasen Gas Business Development 112

TGVI Portfolio Analysis TGVI Portfolio Analysis Process 1. TGVI System Costs - incremental facilities cost of service, system fuel and wheeling a) Most likely demand forecast & Industrial load variations b) Core Market demand variations 2. Gas Supply Issues LNG vs. Market Storage 3. Combined Evaluation of TGVI System Costs and Net Cost of On-System LNG Storage 4. Balanced Portfolio Considerations 5. Conclusions / Recommendations 113

1. TGVI System Costs (LNG vs. Pipe & Compression Portfolios) Most Likely Demand Forecast Scenario and Industrial Load Variations TGVI System Costs ($ Millions) 15 - Year PV COS 25 - Year PV COS Discount Rate 6.2% LNG Storage P&C LNG Storage P&C Difference Portfolio Portfolio Portfolio Portfolio Difference Core Markets (TGVI, TGS, TGW) $46 $78 ($31) $66 $148 ($82) Core Markets + JV (Base Case) $51 $107 ($56) $81 $185 ($104) Core Markets + JV + ICP $103 $176 ($73) $172 $279 ($108) 15 - Year PV COS 25 - Year PV COS Discount Rate 10% LNG Storage P&C LNG Storage P&C Difference Portfolio Portfolio Portfolio Portfolio Difference Core Markets (TGVI, TGS, TGW) $36 $57 ($21) $46 $91 ($45) Core Markets + JV (Base Case) $39 $78 ($39) $54 $117 ($63) Core Markets + JV + ICP $79 $133 ($54) $112 $183 ($71) 114

1. TGVI System Costs (LNG vs. Pipe & Compression Portfolios) Core Market Demand Variations TGVI System Cost ($ Millions) 15 - Year PV COS 25 - Year PV COS Discount Rate 6.2% LNG Storage P&C LNG Storage P&C Difference Portfolio Portfolio Portfolio Portfolio Difference Low Core Markets + JV $52 $88 ($36) $77 $152 ($75) Core Markets + JV (Base Case) $51 $107 ($56) $81 $185 ($104) High Core Markets + JV $57 $127 ($70) $114 $219 ($105) 15 - Year PV COS 25 - Year PV COS Discount Rate 10% LNG Storage P&C LNG Storage P&C Difference Portfolio Portfolio Portfolio Portfolio Difference Low Core Markets + JV $40 $64 ($24) $52 $96 ($44) Core Markets + JV (Base Case) $39 $78 ($39) $54 $117 ($63) High Core Markets + JV $44 $94 ($50) $72 $139 ($67) 115

1. TGVI System Costs (LNG vs. Pipe & Compression Portfolios) Comments / Observations Demand forecasts with increased Industrial or Core Market Load provide a greater benefit to having On-System Storage 116

2. Gas Supply Issues LNG Storage vs. Market Storage On-System LNG Storage ($ Millions) 15-Year PV COS 25-Year PV COS 0.5 Bcf 1.0 Bcf 1.5 Bcf 0.5 Bcf 1.0 Bcf 1.5 Bcf (6.2% Discount Rate) Facility Facility Facility Facility Facility Facility On-System LNG Storage ($ Millions) $99 $143 $186 $127 $182 $237 Level Unit Cost ($/Mcf) $20.7 $14.9 $12.9 $20.3 $14.5 $12.6 (10% Discount Rate) On-System LNG Storage ($ Millions) $79 $113 $147 $92 $133 $172 Level Unit Cost ($/Mcf) $20.6 $14.8 $12.8 $20.4 $14.6 $12.6 117

2. Gas Supply Issues LNG Storage vs. Market Storage Estimated Value of Market Storage ($ Millions) Low Cost 1 High Cost 2 Low Cost 1 High Cost 2 (6.2% Discount Rate) Range Range Range Range 0.5 Bcf LNG Equivalent $55 $72 $72 $95 1.0 Bcf LNG Equivalent $110 $145 $145 $190 1.5 Bcf LNG Equivalent $165 $217 $217 $285 (10% Discount Rate) 15-Year PV Off-System Storage and Redelivery 25-Year PV Off-System Storage and Redelivery 0.5 Bcf LNG Equivalent $44 $57 $52 $69 1.0 Bcf LNG Equivalent $87 $115 $104 $137 1.5 Bcf LNG Equivalent $131 $172 $157 $206 Notes: 1 Low Cost Range for Off-System Storage based on Storage Contract Costs plus Redelivery at 30% of NWP TF-1 2 High Cost Range for Off-System Storage based on Storage Contract Costs plus Redelivery at 50% of NWP TF-1 118

2. Gas Supply Issues LNG Storage vs. Market Storage Present Value @ 6.2 %, 15 & 25 Years, $ Millions 300 250 200 150 100 50 0 Off System Market Storage High Range Off System Market Storage Low Range On System LNG Storage 99 On System LNG Storage vs Off System Market Storage (PV@6.2%) 72 55 15 Years 25 Years 217 143 145 110 186 165 0.5 Bcf 1.0 Bcf 1.5 Bcf 0.5 Bcf 1.0 Bcf 1.5 Bcf 127 95 72 182 190 145 237 285 217 Observations: There is a net cost of on-system LNG storage relative to the low end cost range of market storage. With larger LNG facilities, the high cost range of market storage, and the longer evaluation period, the net cost of LNG becomes a net benefit. 119

2. TGI & TGVI - Future Storage Requirements assuming LNG in 2010 TGI and TGVI Market Area Storage Contracts and Future Requirements TJ/d 750 700 650 600 550 500 450 400 350 300 250 200 150 100 50 0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 40% 30% 30%-40% Peak Day Off System Market Area Storage VI LNG Facility On System Market Area Storage 120

3. Combined Evaluation of TGVI System Costs and Net Cost of LNG Storage Most Likely (Base) Demand Forecast Present Value @ 6.2%, 15 & 25 Years, $ Millions 200 180 160 140 120 100 80 60 40 Combined TGVI Facilities and Low Storage Costs Base Case (PV@6.2%) Net LNG Cost - Low Range Market Storage 185 TGVI System Costs 15 Years 25 Years 132 117 107 101 93 82 71 20 0 P & C Porfolio 0.5 Bcf 1.0 Bcf 1.5 Bcf P & C Porfolio 0.5 Bcf 1.0 Bcf 1.5 Bcf LNG Storage Portfolio LNG Storage Portfolio 121

3. Combined Evaluation of TGVI System Costs and Net Cost of On-System Storage Comments / Observations Portfolios including on-system LNG storage are favoured relative to Pipe & Compression portfolios As consideration is given to: larger LNG facilities, higher cost range of market storage, and the longer evaluation period the net benefit of on-system LNG storage increases 122

4. Security of Supply, Rate Volatility and Balanced Impacts Security of Supply and Rate Volatility LNG Storage portfolio Increases Vancouver Island local gas supply diversity Provides supply protection against upstream pipeline disruptions Alleviates TGI/TGVI winter flow requirements at Huntingdon which reduces NWP downstream concerns Provides buffer against price disconnects due to regional capacity constraints Balanced Impacts Emission factor comparable between portfolios Land Use favours Pipe and Compression portfolio Employment favours LNG Storage portfolio LNG Storage Pipe and Compression CO 2 e (average tonnes per TJ delivered) 2.58 2.56 NO x (average kg per TJ delivered) 1.56 1.55 SO 2 (average kg per TJ delivered) 0.051 0.051 Land Use (acres) 92 60 Employment construction (person years) 188 101 Employment permanent 9.5 2.5 123

5. Resource Evaluation Matrix LNG Storage portfolio is preferred Lowest delivered cost based on avoided facilities and value of market area storage Increased regional supply diversity improves security of supply and reduces rate volatility Portfolios are comparable on Balanced Impacts of emissions, land use, and employment LNG Storage Pipe & Compression Lowest Delivered Cost Security of Supply Rate Volatility Balanced Impacts 124

5. Conclusions / Recommendations Portfolios with On-System LNG storage are preferred. There are opportunities to achieve greater benefits for the region by building a larger-sized LNG facility Action items TGVI should pursue arrangements with TGI, other utilities and regional gas market participants to realize the regional benefits associated with the larger LNG facilities. TGVI will develop and file a revised CPCN application for an onsystem LNG storage 125

Update on the Mt. Hayes LNG Project Guy Wassick Manager, Projects 126

Agenda LNG General Approvals Project Costs 127

What Is LNG? LNG (liquefied natural gas) is natural gas cooled until it condenses into a clear liquid. LNG is stored at -162 o C (-260 o F) at atmospheric pressure in a thermos like storage container. LNG takes up far less space about 1/600 th of its original volume as a gas. LNG (the liquid itself) is not flammable or explosive. 128

Types of LNG Facilities Peak Shaving: Peak days sendout Small storage capacity Onsite liquefaction and vaporization Annual fill and use Base Load - Import/Export Terminal: Base load supply Large storage capacity Daily liquefaction or send out Supplied to/by marine tanker 129

Tilbury Island (Delta, B. C.) Peak shaving LNG Plant (1970) - 0.6 bcf 130

LNG Facility Site Near Ladysmith LNG Storage Facility Storage: 0.5 to 1.5 bcf Send-out: 10 days at max. rate Liquefaction: 200 days 6km NW of Ladysmith, West of Mt. Hayes Located near load center on Southern Vancouver Island 131

LNG Project Approvals APPROVALS RECEIVED Site Re-Zoning Environmental Assessment Site Purchase Option Agreements with local First Nations Crown Land Permits Previous conditional CPCN OUTSTANDING APPROVALS BCUC CPCN OGC Construction Permit (req ts confirmed) Prov. & Local permits (req ts confirmed) 132

Site Photograph Mt. Hayes in background - view to east Tank Location 133

Artist Rendering 134

TGVI Project Capital Costs Capital Costs, 2006 $million Facility Size 0.5 BCF 1.0 BCF 1.5 BCF EPC Contract $57.3 $86.0 $111.1 Owner's Costs $18.0 $24.4 $31.7 TOTAL $75.3 $110.4 $142.8 135

Projected Timing Task Name 2006 TGVI Resource Plan BCUC - CPCN Process Project Prep Facility Construction Commission & Test Operation by TGVI Y1 Y2 Y3 Y4 136

Artist Rendering 137

Wrap-Up & Next Steps Cynthia Des Brisay Director, Business Development 138

Regional Supply and Demand Balance Demand Growth will result in infrastructure constraints by the end of the decade I-5 Total Firm Peak Day Supply/Demand Balance 5 Low Base High Pipeline Underground Storage Peak LNG 4 Million Dth/day 3 2 1 0 2006-07 2007-08 2008-09 2009-10 2010-11 Year (Nov-Oct) From NWGA 2006 Outlook 139

Terasen Gas Demand Growth TGI TGVI 2005 Customers 799,804 85,016 Annual Demand (TJ) 113,319 11,653 Peak Demand (TJ/Day) 1,256 105.9 2021 Customers 1,000,200 138,302 Annual Demand (TJ) 138,801 16,667 Peak Demand (TJ/Day) 1,507 154.3 2031 Customers 1,092,116 164,627 Annual Demand (TJ) 149,593 19,197 Peak Demand (TJ/Day) 1,600 178.3 Average Annual Demand Growth ('05-'31) 1.07% 1.94% All figures year-end Design day figures for TGI do not include Squamish Squamish 2005 Design Day = 4.0 TJ, 2021 Design Day = 7.0 TJ, 2031 Design Day = 7.8 TJ 140

Energy Efficiency Conservation Potential By 2015/2016, GJ per year TGVI Lower Mainland Interior Total Residential EE -369,000-7,417,000-1,847,000-9,633,000 Commercial EE -385,000-1,850,000-431,000-2,666,000 Industrial EE -32,430-933,064-924,210-1,889,704 Subtotal -786,430-10,200,064-3,202,210-14,188,704 Residential Fuel Sub 1,453,000 Potential Annual Impact -12,735,704 141

TGI & TGVI Gas Supply Portfolio Increasing need for Storage Resources 750 TGI and TGVI Market Area Storage Contracts and Future Requirements 700 650 600 550 500 450 40% 30% 30%-40% Peak Day TJ/d 400 350 300 250 Off System Market Area Storage 200 150 100 50 0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 On System Market Area Storage 142

System Expansion Requirements Terasen Gas Lower Mainland Requirements depend on future of Burrard Thermal and ICP No major requirements before 2010 Interior System Requirements driven by Core market growth No major requirements before 2012 Terasen Gas (Vancouver Island) System currently constrained Future requirements driven by industrial and generation (ICP) loads Expansion facilities could be required by 2010 143

TGVI Current System Capacity vs Demand Projection 250 TGVI Design Day Forecast 200 Gigajoules per Day 150 100 50 TGVI Core Whistler BC Hydro Squamish VIGJV 2005 Capacity 0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year beginning November 144

On Island Peak Shaving Facility Present Value @ 6.2%, 15 & 25 Years, $ Millions 200 180 160 140 120 100 80 60 40 Combined TGVI Facilities and Low Storage Costs Base Case (PV@6.2%) Net LNG Cost - Low Range Market Storage 185 TGVI System Costs 15 Years 25 Years 132 117 107 101 93 82 71 20 0 P & C Porfolio 0.5 Bcf 1.0 Bcf 1.5 Bcf P & C Porfolio 0.5 Bcf 1.0 Bcf 1.5 Bcf LNG Storage Portfolio LNG Storage Portfolio 145

Next Steps July TGI and TGVI Resource Plans complete June to September Storage Services Agreement between TGVI and TGI Develop Energy Efficiency strategy and programs Stakeholder Consultation September October Potential CPCN filing for MT Hayes Facility to support 2010 in-service date October November Request for approval for Energy Efficiency programs 146

Thank you, for your participation 147