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

Transcription

1 Terasen Gas Inc. & Terasen Gas Vancouver Island (TGVI) 2006 Resource Plans June 20 th, 2006 Stakeholder Workshop Contact Cynthia Des Brisay Director, Business Development Telephone: (604) Ken Ross Resource Planning Analyst Telephone: (604) Terasen Gas

2 Introduction Tom Loski Director of Regulatory Affairs 2

3 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

4 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

5 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 5

6 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

7 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

8 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

9 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

10 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

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

12 5335 SW Meadows Rd., #220 Lake Oswego, OR (503) 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

13 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 Electric Gas (including gas for generation)

14 Recent Gas Demand 1, Industrial Generation Commercial Residential Cumulative PNW Gas Deliveries* (source: USA-EIA, CAN-StatCan) *2005 BC estimated from preliminary StatCan data 700 Million Dth

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

16 Gas Demand Forecast ( through ) 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

17 Demand Forecast 1, Low Projected Demand Base/Expected Demand High Projected Demand Actual Projected Regional Demand (Source: 2006 NWGA Outlook) Actual Forecast (weather normalized) Million Dth

18 Demand Forecast by Sector Projected Regional Demand By Sector - Base Case Million Dth Residential Commercial Generation Industrial

19 Proportion of Projected Gas Demand by Sector: 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

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

21 WCSB Production 18 WCSB Production Forecasts Actual Forecast Bcf/Day Canadian Energy Research Inst. NEB (04 Techno Vert) NEB (04 Supply Push) Consensus Forecast Wood Mackenzie TransCanada Duke Energy Actual 21

22 Rockies Production Bcf/d EEA EIA Wood Mackenzie Other Consultants Avg Consensus Forecast 22

23 Supplies Flow to Demand Pipeline Flow (MMcfd) Everett Elba Island Cove Point EEA Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease 294 Lake Charles 23

24 Growing Demand, Slowing Supply Projected US Supply/Demand Balance (EIA Annual Energy Outlook 2006) 30 LNG imports are the marginal resource Frontier gas (Mackenzie, Alaska) Other Supplies Canadian Supply Domestic Supply US Demand Year 24 Quadrillion Btu

25 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

26 Northwest Gas Infrastructure Capacity at Major Interconnects & Storage Facilities (MDth/day) Station Malin 2119 Sumas Kingsgate 2796 Starr Road 165 Stanfield 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

27 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 Includes Mist and potential JP expansions Winter Year (Dec-Feb) 27

28 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 Year (Nov-Oct) 28

29 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 Year (Nov-Oct) 29

30 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

31 Productive Capacity Source: Energy and Environmental Analysis, Inc 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

32 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

33 Price Drivers: Storage (Supply) Bcf yr high-low 5 year Minimum 5yr average Source: EIA, 06/15/2006 Week 33 33

34 Price Drivers: Production U.S. Gas Rigs In Operation Rig Count 1,600 1,400 1,200 1, Week Source: Baker Hughes, 06/09/2006 5yr high-low 5 year minimum 5yr average

35 $12 Crude Oil:Natural Gas Price Correlation = $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

36 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

37 Markets Are Connected Pipeline Flow (MMcfd) Everett Elba Island Cove Point EEA Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease 294 Lake Charles 37

38 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

39 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

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

41 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

42 5335 SW Meadows Rd., #220 Lake Oswego, OR (503) 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

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

44 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

45 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

46 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

47 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

48 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 * Resource type unit energy costs from BC Hydro 2006 IEP, Table

49 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

50 Right Fuel, Right Use, Right Time! 50

51 Demand Forecast Greg Caza Energy Forecasting Manager 51

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

53 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

54 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

55 TGVI Demand Forecast 55

56 TGVI Core Customer Additions TGVI Customer Growth 15, , Cust omer addit ions CAGR % CAGR B a se % High 2.94% Low % Total Customers High Scenario Base Case Low Scenario 200, , ,000 Customers Additions 9,000 6,000 Actuals Forecast 140, , ,000 80,000 60,000 Total Customers 3,000 40,000 Customer additions 20,

57 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

58 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 Residential 39% 45% Commercial 61% 55% 58

59 TGVI Core Customer Annual Demand TGVI Annual Demand ,000 17,500 15,000 Demand (TJ) 12,500 10,000 7,500 5,000 2,500 Residential Demand Commercial Demand Year 59

60 TGVI Design Weather 32 TGVI Design Weather vs. Five Coldest Winters Heating Degree Days Design Coldest Day to Warmest 60

61 TGVI Design Weather First 30 Days 32 TGVI Design Weather vs Five Coldest Years (First 30 Days) Heating Degree Days Design Coldest Day to Warmest 61

62 TGVI Core Customer Design Day TGVI Core Customer Demand vs Weather ( ) Daily Core Demand (GJ per acct) Design Day Demand (per acct) at Design Day Temperature of degrees Celcius Temperature, Degrees Celcius Predicted Demand Actual Demand 62

63 TGVI Core Customer Design Year TGVI Design Load Duration Curves Daily Core Demand (TJ) Coldest to Warmest Day 63

64 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

65 TGI Demand Forecast Update 65

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

67 TGI Customer Account Additions Comparison TGI 2004 vs Customer Additions Forecast Comparison 16,000 14,000 12,000 Actuals Resource Plan Forecast Resource Plan 2004 Resource Plan Customer Additions 10,000 8,000 6,000 4,000 2,

68 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 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

69 TGI Total Account Forecast Comparison TGI Year-End Customers 1,200,000 1,100,000 1,000,000 Total Customers 900, , , ,000 High Resource Plan Base Resource Plan Low Resource Plan 2004 Resource Plan 500,

70 Core Market Demand Summary 70

71 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, Customers 1,000, ,302 Annual Demand (TJ) 138,801 16,667 Peak Demand (TJ/Day) 1, Customers 1,092, ,627 Annual Demand (TJ) 149,593 19,197 Peak Demand (TJ/Day) 1, 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

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

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

74 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

75 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

76 What s our approach to DSM? Tactics Technology 76

77 Tactics - Partners 77

78 Partner recognition 78

79 Tactics Programs - TGVI 79

80 Tactics Programs - TGI 80

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

82 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

83 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, ,000-2,212,000 Industrial EE -32, , ,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

84 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 ,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

85 Where do we go from here? 85

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

87 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

88 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

89 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, Design Peak Day Peaking Resources Market Area Storage/Shaped Pipeline Capacity Pipeline Capacity Design Normal TJ/d 01/11/ /11/ /11/ /12/ /12/ /01/ /01/ /02/ /02/ /03/ /03/ /04/ /04/ /05/ /05/ /05/ /06/ /06/ /07/ /07/ /08/ /08/ /09/ /09/ /10/ /10/ /10/

90 31/10/ /12/ /12/ /01/ /01/ /02/ /02/ /03/ /03/ /04/ /04/ /05/ /05/ /05/ /06/ /06/ /07/ /07/ /08/ /08/ /09/ /09/ /10/ /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, Design Peak Day Peaking Resources Market Area Storage/Shaped Pipeline Capacity Pipeline Capacity Design 90 TJ/d 01/11/ /11/ /11/2006

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

92 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 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 Nov Nov-05 6-Dec Dec Dec Dec-05 3-Jan Jan Jan Jan Jan-06 7-Feb Feb Feb Feb-06 7-Mar Mar Mar Mar-06 Winter 2004/05 Winter 2003/04 92

93 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

94 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

95 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 TGI and TGVI Market Area Storage Contracts and Future Requirements 40% 30% 30%-40% Peak Day Off System Market Area Storage On System Market Area Storage

96 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

97 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

98 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

99 Resource Portfolio Development Edmond Leung System Capacity Planning Manager 99

100 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

101 Resource Planning Portfolio Analysis Overview 6% 5% % Flow of Day 4% 3% 2% 1% 0% 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

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

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

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

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

106 TGVI current System Capacity vs Demand Projection 250 TGVI Design Day Forecast 200 Terajoules per Day TGVI Core Whistler BC Hydro Squamish VIGJV 2005 Capacity Year beginning November 106

107 Pipe & Compression Portfolio Long Term Demand Scenario TGVI, TGS and TGW Core Market Demand 2008 V4 minor Upgrades 2021 V3b V Joint Venture Mills V V1 U V6 107

108 Pipe & Compression Portfolio Peak Day System Capacity Versus Demand TGVI with P&C w/ core + JV (Case 6) Avail PD Capacity for IT JV Whistler Squamish Core Add V2 & V5 V1-U4 V3b V Peakday System Capacity Peakday Demand [TJ/d] Winter

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

110 LNG Storage Portfolio Peak Day System Capacity Versus Demand Avail PD Capacity for IT JV Whistler Squamish Core Peakday System Capacity LNG TGVI with Mt. Hayes LNG w/ core + JV (Case 5) V Peakday Demand [TJ/d] Winter

111 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) $103.1 Core Markets + JV $103.1 Core Markets + JV + ICP $130.8 LNG Storage Portfolio Squamish V2 Dunsmuir V5 Coquitlam V1-U4 Sechelt V3b Crofton V6 Watershe d 25.3 km Loop Total Expediture millions 2006$ 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 $

112 Resource Portfolio Evaluation David Perttula Terasen Gas Business Development 112

113 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

114 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

115 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

116 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

117 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 $

118 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 $ Bcf LNG Equivalent $110 $145 $145 $ 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 $ Bcf LNG Equivalent $87 $115 $104 $ 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

119 2. Gas Supply Issues LNG Storage vs. Market Storage Present 6.2 %, 15 & 25 Years, $ Millions 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%) Years 25 Years Bcf 1.0 Bcf 1.5 Bcf 0.5 Bcf 1.0 Bcf 1.5 Bcf 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

120 2. TGI & TGVI - Future Storage Requirements assuming LNG in 2010 TGI and TGVI Market Area Storage Contracts and Future Requirements TJ/d % 30% 30%-40% Peak Day Off System Market Area Storage VI LNG Facility On System Market Area Storage 120

121 3. Combined Evaluation of TGVI System Costs and Net Cost of LNG Storage Most Likely (Base) Demand Forecast Present 6.2%, 15 & 25 Years, $ Millions 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 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

122 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

123 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) NO x (average kg per TJ delivered) SO 2 (average kg per TJ delivered) Land Use (acres) Employment construction (person years) Employment permanent

124 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

125 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

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

127 Agenda LNG General Approvals Project Costs 127

128 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

129 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

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

131 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

132 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

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

134 Artist Rendering 134

135 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 $

136 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

137 Artist Rendering 137

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

139 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 Year (Nov-Oct) From NWGA 2006 Outlook 139

140 Terasen Gas Demand Growth TGI TGVI 2005 Customers 799,804 85,016 Annual Demand (TJ) 113,319 11,653 Peak Demand (TJ/Day) 1, Customers 1,000, ,302 Annual Demand (TJ) 138,801 16,667 Peak Demand (TJ/Day) 1, Customers 1,092, ,627 Annual Demand (TJ) 149,593 19,197 Peak Demand (TJ/Day) 1, 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

141 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, ,000-2,666,000 Industrial EE -32, , ,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,

142 TGI & TGVI Gas Supply Portfolio Increasing need for Storage Resources 750 TGI and TGVI Market Area Storage Contracts and Future Requirements % 30% 30%-40% Peak Day TJ/d Off System Market Area Storage On System Market Area Storage 142

143 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

144 TGVI Current System Capacity vs Demand Projection 250 TGVI Design Day Forecast 200 Gigajoules per Day TGVI Core Whistler BC Hydro Squamish VIGJV 2005 Capacity Year beginning November 144

145 On Island Peak Shaving Facility Present 6.2%, 15 & 25 Years, $ Millions 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 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

146 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

147 Thank you, for your participation 147