2008 LTAP Resource Options Update. Results Session December 4, 2007

Transcription

1 2008 LTAP Resource Options Update Results Session December 4, 2007

2 AGENDA 9:00 Welcome 9:10 Context Setting 9:30 ROU Results Biomass Natural Gas Coal 10:15 Coffee Break 10:30 ROU Results continued Geothermal Wind Large hydro 11:45 Lunch 12:15 ROU Results continued Small hydro DSM Transmission 1:00 Summary & LTAP Next Steps 2

3 Introduction Cam Matheson

4 Introduction Resource options update (ROU) work is a key input into the 2008 LTAP 2008 LTAP updates the 2006 IEP/LTAP Targeted update of resource options information for 2008 LTAP 2007 Energy Plan BCUC Decision Changes in capital/construction costs Resource options information is: High level estimates developed for planning purposes Not meant to estimate the results of calls Resource options information is used to develop portfolios to analyze different resource acquisition strategies LTAP will set out volume, timing and high level acquisition strategies for future calls 4

5 Introduction continued Today s session focuses on the results of a substantial effort Scoping session held in July Meetings held with resource proponents Aug-Nov BC Hydro has received valuable input at these sessions Results today incorporate much of that input Your input today is appreciated and will be documented Large hydro Next IEP/LTAP will include a more comprehensive resource options assessment Issues that cannot be addressed by the conclusion of the ROU will be considered for the scope of next IEP 5

6 Context Nadja Holowaty

7 REVIEW: Targeted Resource Options Update 2006 IEP Resource Options Framework Wide range of Resource Options Meets government policy Greater than 50 kw Commercial, Developing & Future RO technologies ROU Targeted update: RO significantly affected by EP RO located in BC Reflects time and resource constraints 7

8 REVIEW: Resource Types for Update Supply Options Biomass Natural gas Coal Geothermal Wind Large hydro including pumped storage & Resource Smart Small hydro Demand-Side Management (DSM) Transmission Pending Burrard Generating Station DSM 8

9 REVIEW: Outside Scope Near commercial technologies Environmental and social attributes Non-integrated areas Full rewrite/update of the 2005 Resource Options Report Definition of firm energy and dependable capacity 9

10 Finalized Scope of Updates Resource Option Potential Technology Cost Small hydro Large hydro Wind Biomass Geothermal Natural gas Coal 10

11 Assumptions & Terminology Financial Assumptions Unit Energy Cost (UEC) - $/MWh Unit Capacity Cost (UCC) - $/kw-yr Levelized/annualized values based on discounted cash flows Real pre-tax cash flows Real cost of capital based on BCUC decision & IPP assumptions Include: Generation plus interconnection costs to grid 11

12 Unit Costs UEC values are categorized by price uncertainty Low, medium, high -5 to +20, +40 & +60% Estimates are high level for planning purposes Simple UECs simple ranking do not reflect: Transmission upgrades and line losses Greenhouse gas (GHG) offsets Integration cost of intermittent resources Capacity credit 12

13 Resource Options - Transmission Regions 13

14 RODAT Sheet 14 Example Only

15 ROU Engagement Process - Feedback July 19: Scoping session General acceptance of the proposed scope of work with some minor changes suggested Validity of resource option costs is important; costs have increased Greater interest in large hydro/hydro with storage Definitions of near commercial/commercial technology & clean energy July 30: Customer intervener group session UECs should be presented in context of other costs Interest in large hydro projects August to November: Resource-specific discussions Dec 4: Results session 15

16 Agenda 9:30 ROU Results Biomass Allan Grant Natural Gas Graeme Simpson Coal Sasi Sasitharan 10:15 Coffee Break 10:30 ROU Results continued Geothermal Sasi Sasitharan Wind Sol Friedman Large Hydro & Resource Smart Alec Tsang 11:45 Lunch 12:15 ROU Results continued Small Hydro Shane Grovue DSM John Duffy Transmission Rama Vinnakota 1:00 Summary & LTAP Next Steps 16

17 Biomass Allan Grant

18 Biomass Scope Provide an update of resource potential and cost for Sawmill Woodwaste Roadside Woodwaste Standing Timber Woodwaste (Beetle Kill Timber) Municipal Solid Waste (MSW) Biogas Methodology Reviewed Resource Options Report (ROR) 2005 Woodwaste data from Ministry of Forests and Range (MOFR) 2006 Bioenergy Request for Expression of Interest (RFEOI) 2007 Environment Canada publication Communicated with interested parties Scoping Session: July 19, 2007 Targeted Engagement Meeting: September 19,

19 Biomass - Woodwaste BC Forest policy key to availability and price Sawmill Woodwaste 2007 RFEOI showed approximately 500 MW This was reduced to 100 MW based on engagement with interested parties and to account for multiple projects counting the same resource Roadside Woodwaste 2007 RFEOI showed approximately 316 MW Assuming only about 60% collection of roadside woodwaste for power generation would yield about 200 MW Standing Timber Woodwaste (Beetle Kill Timber) 2007 RFEOI showed approximately 285 MW Assuming only about 60% of standing timber woodwaste for power generation would yield about 170 MW Based on the guidelines MOFR is developing, the availability of standing timber affected by pine beetle for power generation may increase or decrease 19

20 Biomass - Woodwaste Wood Resource Average Annual Energy (GWh) Installed Capacity (MW) Unit Energy Cost ($) Sawmill Woodwaste Roadside Woodwaste Standing Timber Woodwaste (Beetle Kill Timber) All values are based on 2007 RFEOI 20

21 Biomass - MSW & Biogas Municipal Solid Waste (MSW) Bundled 3 proposed projects from the existing database 1 project in Kamloops and 2 on Vancouver Island Biogas Methane generated from garbage in landfills Price heavily dependent on whether a gas collection system in already present Entered the projects from an Environment Canada report * into the database as two bundles with and without collection * Strategic Assessment of the Additional Potential for Landfill gas Recovery and Utilization in Canada Environment Canada (June 2002). 21

22 Biomass Projects Average Annual Energy (GWh) Dependable Capacity (MW) Unit Energy 6% Unit Energy 8% MSW Bundle Biogas Bundle with no capture Biogas Bundle with capture

23 Main Drivers of Change from 2005 ROR Costs are approximately 10-20% higher than the 2005 ROR, for biomass primarily due to: Construction cost inflation Materials cost inflation Biogas looked at existing landfills Additional power may be available from agricultural waste, but very uncertain at this point Woodwaste availability and costs are uncertain Changes in Provincial forest policy to address beetle kill expected 23

24 Natural Gas Graeme Simpson

25 Natural Gas Scope Provide updates on capital and operating costs for various CCGT and SCGT projects, including small gas-fired cogeneration projects. Develop new cost estimate and technical data for a 100 MW SCGT project. Revise gas costs based on BC Hydro s April 2007 price forecast. Methodology AMEC consultants engaged to undertake cost estimate and technical data updates. Gas turbine costs updates based on current vendor information (primarily GE). 25

26 Natural Gas Methodology (continued) Factored estimates for balance of plant were escalated using representative inflation indices Bantrel study was used as baseline for determining the components for the CCGT balance-of-plant estimates. New estimate for the 100 MW SCGT was developed based on GE pricing and technical data for LMS100 gas turbine. Emission factors (local and GHG) were reviewed and updated for all SCGT and CCGT projects. Input received Updated project data sheets were circulated to natural gas stakeholder group on November 29. Responses pending. 26

27 Natural Gas Drivers of change from 2005 ROR UECs are ~7-31% higher, primarily due to: Construction, equipment and materials cost inflation Capital cost for 50 MW CCGT project increased by 26% Capital costs of other SCGT and CCGT projects did not increase as much cost estimates may have been high in 2005 ROR (but within range of planning accuracy) Capacity and heat rates have been adjusted Average degradation (2-3% on capacity, % on heat rates) LM6000 project outputs also reduced by 7 MW (SCGT and CCGT) Fixed O&M costs have come down Gas tolls have been removed from fixed O&M to avoid double-counting Updated residual fixed O&M (FOM) costs for plants are generally lower than FOM estimates in 2005 ROR. Cost of fuel Unit cost of gas (EIA forecast) is up roughly 30% 27

28 Natural Gas Project Unit Energy Costs ($/MWh) Fixed Investment FOM VOM Fuel Total Delta A ROR SCGT 47 MW CCGT 60 MW CCGT 250 MW CCGT 500 MW Small Cogeneration B ROU SCGT 40 MW % SCGT 100 MW na CCGT 50 MW % CCGT 250 MW % CCGT 500 MW % Small Cogeneration % 28

29 Natural Gas Project Name Firm Annual Energy (GWh) Installed Capacity (MW) Unit Energy 6% ($/MWh) Unit Capacity 6% ($/kw-yr) 40 MW SCGT * 100 MW SCGT * 50 MW CCGT NA 250 MW CCGT NA 500 MW CCGT NA Small Gas Cogen Projects NA * Simplified calculation 29

30 Coal Sasi Sasitharan

31 Coal 2007 Energy Plan Coal fired generation must meet a zero GHG emission standard through a combination of Clean coal fired generation technology, Carbon sequestration and Offsets for any residual GHG emissions. Scope for 2007 ROU Research the current status of coal fired generation with carbon capture and sequestration (CCS) to determine whether CCS should be included as an option for ROU. 31

32 Coal Methodology Commissioned an independent study by a consultant Reviewed literature published by National Resources Canada United States Department of Energy Alberta Geological Survey Met with representative of The Coal Association of Canada 32

33 Coal Carbon Capture and Sequestration system involves: Carbon capture CO2 is separated and captured from power plant emissions by pre combustion capture, post combustion capture or oxy-fuel capture. Carbon transportation CO2 is transported by pipeline or other gas carriers from captured facility to the storage facility. Carbon storage CO2 is injected in a suitable storage reservoir such as underground geological formations or oceans. 33

34 Coal Current Technology Development Oxy-fuel Capture Pre and Post Combustion Capture Carbon Pipeline Idea generation Invention Basic research Prototype development Field tests, demonstration & verification Niche application & supported commercial Commercial application and full integration Ocean Storage Underground Storage 34

35 Coal CO2 sequestration technology adaptation in BC Very limited information available to assess the suitability for geological storage at this time, although there are some geological sites in BC that may prove suitable for CO2 storage. Further studies would need to be performed to understand the properties and behavior of CO2 at the temperature, pressure and stress conditions found in sedimentary basins in BC. There are numerous legal/regulatory, liability, risk perception and public acceptance issues that likely need to be addressed before CO2 capture and storage technology can be considered in a commercial scale in BC. 35

36 Coal Conclusions At this time, the state of key components of CCS technology is such that it cannot be considered in commercial application. BC Hydro will continuously monitor developments in this area and include coal fired power generation with CCS as commercial option when appropriate. 36

37 Geothermal Sasi Sasitharan

38 Geothermal Scope Provide resource potential and cost update Methodology Reviewed: Green Energy Study for BC (BC Hydro 2002) Electrical Resource Potential in Northwest BC (BCTC 2007) Geothermal Resource Council Publications Input from: Western GeoPower Corp. Gaea Energy Enterprises British Columbia Transmission Corporation (BCTC) 38

39 Geothermal Potential resource in BC South Meager Geothermal Project Potential capacity MW. Resource in final stage of assessment of commercial viability. Insufficient data to determine available geothermal resources at other potential locations such as Pebble Creek, Mount Edziza, Lakelse and Mount Clay. Costly exploration and confirmation drilling is necessary at these locations to determine production potential. 39

40 Geothermal Cost Capital and O&M cost for South Meager Geothermal Project was estimated with input provided by Western GeoPower Corp. 40

41 Geothermal Project Name Average Annual Energy (GWh) Dependable Capacity (MW) Unit Energy 6% Unit Energy 8% South Meager Geothermal Project

42 Geothermal Main drivers of change from 2005 ROR Costs are ~ 20% higher primarily due to: Construction cost inflation Materials cost inflation 42

43 Wind Sol Friedman

44 Wind Resource Scope To determine the estimated resource potential and unit energy cost of the wind resource in different regions in BC. Study Undertaken Internationally respected wind energy specialists, Garrad Hassan (GH) were retained to do the study. They did a similar study in 2005 for BC Hydro. They used all sites with investigative use permits (IUPs) (either applied for or granted) to identify and define the area boundaries, and wind farm turbine densities (MW / km 2 ) to determine theoretical potential of each area. Used available monitoring data and wind speed map to estimate range of capacity factors by region. Used cost estimate for a generic project in each region which had an assumed size and distance from transmission. Assumed that about 10% of the theoretical potential would be realized due to terrain issues, environmental issues, available electrical transmission and energy need. Notes: 1) This is a very high level study, and potential is expected to be verified in coming years 2) The financial model used to calculate the unit energy costs uses BC Hydro s assumptions, and different financial models could yield very different results 44

45 Consultation with Interested Parties Presentation at Power Acquisitions stakeholder engagement session on System Needs in June 2007 Discussion session at the Resource Option Update session in July 2007 Questionnaire to Wind IPPs requesting information in September / October 2007 Presentation at IPPBC Annual Conference in November 2007 Nov. 30, Issued draft of the Garrad Hassan Report to IPPBC for distribution to Wind IPPs for review and comments 45

46 The Four Wind Regions of BC 46

47 IUP Sites for the Vancouver Island Region 47

48 IUP Sites for the North Coast region 48

49 IUP sites for the northern Peace Region 49

50 IUP sites for the mid Peace Region 50

51 IUP sites for the southern Peace Region 51

52 IUP sites for the Southern & Eastern Interior 52

53 Results from GH Study North Coast Onshore North Coast Offshore Peace Region Vancouver Island Southern & Eastern Interior Wind Speed (m/s) Potential (MW) 500 1,400 1, ,000 Generic Project Size (MW) Capacity Factor (%) Avg. Annual Energy (GWh/yr) 1,510 4,610 6,610 1,665 2,380 Estimated Transmission (km) Unit Energy Cost Range ($/MWh) Avg. UEC for cheapest bundle Note that these results are from the first draft of the Garrad Hassan report. There may be some changes before the report is finalized. 53

54 Main Drivers of Change from 2005 ROR UECs in some regions are 50% higher than the 2005 ROR, primarily due to: Construction cost increases Material cost increases Potential energy assessment is higher due to: A fourth geographic region being included (Southern & Eastern Interior) The number of IUP sites has increased from just over 100 in early 2005 to over 250 in September 2007 Many more meteorological towers and site data available 54

55 Wind Integration What are the transmission system requirements to integrate wind resources? (Study being undertaken by BCTC) What capability does the power system have to integrate intermittent wind resources from a system operations perspective, and how does increasing amounts of wind energy impact the system s flexibility? What are the benefits of diverse wind resource locations and correlation between wind power and peak demand in terms of minimizing integration costs and impacts? What are the associated costs of integrating wind energy, and what forecasting standards and equipment and wind farm design methods can be used to reduce the integration impacts / costs? What are the potential impacts of other jurisdictions acquiring BC wind resources? 55

56 Large Hydro & Resource Smart Alec Tsang

57 Large Hydro Scope-Resource Potential Cost Methodology Collected new project data and updated existing projects Met with internal project teams and external project proponents Calculated UEC & UCC from newly collected project data Preliminary results review with large hydro interest group (Nov 28) 57

58 Large Hydro Resource Options Mica Units 5 & 6 Revelstoke Unit 6 Resource Smart bundle Jordan River Pumped Storage Other pumped storage options Waneta Expansion Site C 58

59 Upper Columbia Mica Unit 5 & 6 and Revelstoke Unit 6: Resource Smart projects Additional units at existing facilities Capacity projects UCC calculations exclude bulk transmission reinforcement 59

60 Resource Smart Bundle 6 projects: 5 conceptual and 1 pre-feasibility Mix of energy and capacity Purely Resource Smart driven projects Projects selected based on economic viability 60

61 Jordan River Pumped Storage BCUC Directive No.21 Pumped storage between existing reservoirs High level study conducted by BC Hydro Engineering low viability: Low storage capacity in existing reservoirs High penstock length/head ratio for existing reservoirs Small capacity: <20MW Cost estimate pending 61

62 Other Pumped Storage Options Capacity Options Vancouver Island resources: Shawnigan Lake 200 MW Comox Lake 200 MW Strathcona 100 MW 62

63 Waneta Expansion BCUC directive No.21 Columbia Power Corporation Energy and capacity 63

64 Large Hydro Site C Potential 3rd facility on the Peace River Provides 900 MW of dependable capacity Provides 4600 GWh per year of energy Project is in Stage 2 Project Definition Consultation Interim project cost estimates to be released at end of each stage of project review Cost estimates are preliminary, significant uncertainty remains 64

65 Large Hydro Summary Table Project Name Installed Capacity Average Annual Energy 4% 6% 8% 4% 6% [MW] [GWh] [$/MWh] [$/MWh] [$/MWh] [$/kw-yr] [$/kw-yr] Mica New Unit Mica New Unit Revelstoke New Unit Resource Smart Bundle Other Pumped Storage Options * 169** Waneta Expansion TBD TBD - TBD TBD - - Peace River Site C Note: UEC & UCC represented in real cost of debt rates *6% **8% 65

66 Small Hydro Shane Grovue

67 Small Hydro Scope Update the small hydro resource potential and cost Run-of-river < 100MW, with no storage Methodology Reviewed data used for 2005 ROR Sigma Engineering Knight-Piesold Consulting Contracted with Knight-Piesold to update their data Contracted with Kerr Wood Leidal 67

68 Small Hydro Engagement: Met with Small Hydro group three times Reviewed: Scope of update Methodology and assumptions Results General acceptance of scope, methodology and assumptions Suggested improvements for future studies Incorporated comments from interested parties Reviewed consultants results Knight-Piesold high level, general cost ranges Kerr Wood Leidal high level, individual site estimates 68

69 Small Hydro Kerr Wood Leidal results used as input into ROU Used GIS Tool to investigate potential & cost across BC 500 kw to 100 MW installed capacity 0.1 to 200 m3/sec design flow, 30 to 1000m head Individual site characteristics were identified Installed Capacity Dependable Capacity Average Annual Energy Firm Energy Unit Energy Cost Costs based on actual projects: Includes interconnection to closest transmission or distribution Includes access roads 69

70 Small Hydro Improved firm energy & dependable capacity resolution Averaged across entire province in 2005 Now have better resolution separately estimated for each bundle GIS Tool and Water Survey Canada gauge information GIS Tool provided additional information Land area affected proxy for environmental impact Construction and permanent jobs Arranged projects into price bundles $10/MWh price increments in each of the 8 transmission regions RODAT sheets summarize bundled site characteristics 70

71 Small Hydro Assumptions: Firm Energy Minimum annual energy during period of record Dependable Capacity Power that could be generated 85% of the time in December and January Unit Energy Costs based on 6% cost of capital (real, pre-tax) Sensitivity performed at 8% Each site treated as if built individually Entire cost for transmission/distribution & access roads 71

72 Small Hydro Summary of Small Hydro Potential Price Bundle Number Installed Dependable Annual Firm Weighted Ave 6%) of Capacity Capacity Energy Energy UEC ($/MWh) ($/MWh) Projects (MW) (MW) (GWh/a) 8% ,283 1, ,499 2, ,705 1, ,303 1, TOTAL 197 1, ,416 6,791 Majority of potential in higher cost bundles Some lower-cost potential is available Dependable capacity is low 72

73 Small Hydro Small Hydro Potential By Transmission Region Transmission Region Number of Installed Capacity Annual Energy Dependable Capacity Firm Energy Projects (MW) (GWh/a) (MW) (GWh/a) CENTRAL INTERIOR EAST KOOTENAY KELLY/NICOLA , LOWER MAINLAND , ,988 NORTH COAST , ,041 PEACE RIVER SOUTH INTERIOR VANCOUVER ISLAND TOTAL 197 1,982 8, ,791 Majority of potential in Lower Mainland (Transmission Region) Capital costs are lower due to lower road, transmission, and labour costs Favourable hydrologic region with high annual run-off 73

74 Small Hydro Costs: Greatly influenced by the remoteness of the site Availability of labour and material Power line and road access substantial Access roads and power lines ~ 50% of cost in remote sites ~ 25% of cost closer to major centres Major drivers of change from 2005 ROR: Costs are approximately 25-50% higher, primarily due to: Construction cost inflation Materials cost inflation Resource availability primarily in higher cost bundles 74

75 Demand-Side Management John Duffy

76 Demand-Side Management Context 2006 LTAP called for definition phase work on Energy Efficiency 3, 4 and 5 BC Energy Plan 2007 BC Hydro to acquire 50% of incremental resource needs through conservation by

77 Demand-Side Management Inputs Conservation Potential Review Long Term Rate Strategy Research on codes and standards Development work on new programs and initiatives 77

78 Demand-Side Management Engagement CPR External Review Panel Rates Working Group Electricity Conservation and Efficiency Advisory Committee 78

79 Demand-Side Management - New elements Codes and standards Building code, equipment regulations, tax measures, etc Conservation rate structures Inclined block and time of use rates Power Smart programs Residential: appliances, low income, voltage optimization, behavioural, distributed generation Commercial: water, renewable district energy, building operation Industrial: thermo-mechanical pulping, operational Supporting initiatives 79

80 Demand-Side Management Assembling the DSM Plan 1. Codes and Standards 1a) Moderate 1b) Aggressive 2. Rate Structures 2a) Moderate 2b) Aggressive 3. Programs 3a) Moderate 3b) Aggressive Combined Scenarios 4a) Moderate = moderate codes and standards, rate structures & programs + program adjustments 4b) Aggressive = aggressive codes and standards, rate structures & programs + program adjustments 4c) Mixed = other combinations Supporting Initiatives Public Awareness and Communication Community Engagement Codes and Standards Support Technology Innovation 80

81 Demand-Side Management Comparison to 2005 ROR and 2006 LTAP 2005 ROR EE 3, 4 and 5 = 7,300 GWh by 2024 UEC up to $54/MWh 2006 LTAP Balance of DSM 2 + EE 3, 4 and 5 = 9,600 GWh by LTAP ROU 3 DSM scenarios centred around 10,000 GWh by 2020, as per the Energy Plan UECs of scenarios to be determined 81

82 Demand-Side Management Timeline December Release Conservation Potential Review Early January Provide DSM plan scenarios for LTAP portfolio analysis Spring File DSM plan as part of 2008 LTAP 82

83 Transmission Resource Options Update Rama Vinnakota Resource Options Update December 4, 2007

84 Transmission Resource Options Overview Cut-planes Transmission options Conclusions

85 System Requirements System Parameter Perspective Thermal Voltage Frequency

86 Transmission options North interior GMS to Kelly 5L8 and 5L14 Series capacitor on 5L61

87 Transmission options GMS Slide with 5L5 and 5L14 animation to be prepared Williston GMS - Williston - Kelly Reinforcement and 5L61 Series capacitor Kelly

88 Transmission options South Interior Selkirk to Nicola 5L97 and 5L99 Series capacitor upgrades

89 Generation addition west of Selkirk Selkirk-Vaseux-Nicola Reinforcement 5L97 5L96 Vaseux lake S/S 5L99

90 Mica transmission reinforcement Series compensation on 5L71 & 5L72

91 Transmission options Series compensation on 5L76, 5L79, 5L91 & 5L96 5L96 VASEUX

92 South Interior transmission reinforcement Nicola Substation 500 kv Reconfiguration June 2, 2005

93 Transmission options Continued Interior to Lower Mainland Nicola to Meridian 5L83 Kelly to Cheekye 5L46 Lower Mainland to Vancouver Island Arnott to VIT second circuit

94 Interior to Lower Mainland Nicola to Meridian 500 kv line (5L83) MDN 5L83 June 2, 2005

95 Interior to Lower Mainland 5L46 Kelly Lake to Cheekye 500 kv line (5L46) June 2, 2005

96 Lower Mainland to Vancouver Island resources 230 kv Arnott VIT second circuit Arnott VIT

97 Conclusions Identify transmission congestion Generation location Update transmission options

98 Key Contact Persons Janet Fraser (604) Manager, Market Operations Jim Ko (604) Manager, Interconnections

99 Thank you Comments / Suggestions

100 Summary Tables & LTAP Next Steps Randy Reimann

101 2008 LTAP VS IEP Load Forecast Key Risks and Uncertainties Step 1 - Establish Objectives Step 2 - Load Resource Balance Step 4 Develop & Evaluate Portfolios Step 5 Portfolio Trade-Off Analysis Step 6 Long- Term Acquisition Plan Attributes Step 3 Resource Options Inventory Targeted Update 101

102 UEC Summary Table Base UEC Additional Cost Adders (e.g., CIFT, GHG) UEC Range Biomass $50 Wind 102

103 UEC by Resource Option Biomass Base UEC Additional Cost Adders (e.g., CIFT, GHG) $50 + $x +$y +$z UEC Range Wind 103

104 UEC Summary Table Base UEC Additional Cost Adders (e.g., CIFT, GHG) UEC Range Biomass $50 + $x +$y +$z $xx - $yyy Wind 104

105 Summary Table Total Adjusted UECs (see Handout) DRAFT For Illustrative Purposes Note: Resource option information was prepared for BC Hydro's electricity planning purposes only. This information should not be relied upon by others for design, financing, or development decision-making. Actual technical and financial project information may vary from that shown above and is subject to change. 105

106 Supply Curves Total Adjusted UECs LTAP ROU Supply Curves Total Adjusted UECs -Median Value- Unit Energy Cost ($/MWh) Average Annual Energy (GWh) Small Hydro Large Hydro Natural Gas (500MW CCGT) Wind Geothermal DRAFT Note: Resource option information was prepared for BC Hydro's electricity planning purposes only. This information should not be relied upon by others for design, financing, or development decision-making. Actual technical and financial project information may vary from that shown above and is subject to change. 106

107 UEC Ranges Total Adjusted UECs 2008 LTAP ROU - Total Adjusted UECs 300 Unit Energy Cost ($/MWh) Small Hydro Large Hydro Natural Gas (500MW CCGT) Min. Weighted Ave. Max. Wind Geothermal Biomass DRAFT Note: Resource option information was prepared for BC Hydro's electricity planning purposes only. This information should not be relied upon by others for design, financing, or development decision-making. Actual technical and financial project information may vary from that shown above and is subject to change. 107

108 Summary Table Dependable Capacity 2008 LTAP ROU - Resource Type Dependable Capacity Summary Resource Type Installed Capacity Dependable Capacity Dependable Capacity Factor Average Annual Energy (MW) (MW) (GWh) Capacity Factor Small Hydro 1, % 8, % Large Hydro 1,021 1, % 4, % Natural Gas 1,087 1, % 8, % Wind 5, % 16, % Geothermal % % Biomass % 4, % DRAFT Note: Resource option information was prepared for BC Hydro's electricity planning purposes only. This information should not be relied upon by others for design, financing, or development decision-making. Actual technical and financial project information may vary from that shown above and is subject to change. 108

109 Summary Table Capacity Options 2008 LTAP ROU - Unit Capacity Cost for Capacity Options Resource Option Dependable Capacity Unit Capacity Unit Capacity Unit Capacity (MW) $/kw/yr $/kw/yr $/kw/yr Mica Mica Rev Simple Cycle Gas Turbine - 40 MW Simple Cycle Gas Turbine MW Pumped Storage DRAFT Note: Resource option information was prepared for BC Hydro's electricity planning purposes only. This information should not be relied upon by others for design, financing, or development decision-making. Actual technical and financial project information may vary from that shown above and is subject to change. 109

110 2008 LTAP Work Plan ROU is close to completion ROU components to be added when available (e.g. DSM) Work on collecting or updating remaining inputs is underway: Load forecast Gas & electricity forecast GHG forecasts Existing & committed supply potential Portfolio analysis and risk framework to be completed in early 2008 Next LTAP expected to be filed in Spring

111 Summary Nadja Holowaty

112 Summary of AM Session Drivers of change of ROU information Energy Plan Construction cost increases affected all options Increased granularity on some options Increased alignment with transmission regions Some ROU information is still outstanding Summary of feedback from a.m. 112

113 Comments? by December 14th: Presentation to be posted at this week Supporting documentation will be posted as available. A notification will be sent. Thank you! 113