INTEGRATED RESOURCE PLAN TECHNICAL ADVISORY COMMITTEE MEETING #5 DAY 2

Transcription

1 INTEGRATED RESOURCE PLAN TECHNICAL ADVISORY COMMITTEE MEETING #5 DAY 2 Preliminary Analysis and Results for TAC Input February 28 & 29, 2012 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 1

2 ACQUISITIONS KATHY LEE

3 ACQUISITION ANALYSIS RESULTS 1. THE VOLUME AND TIMING OF NEW CLEAN RESOURCES NEEDED OVER 20 YEARS Portfolio costs (present value) How results change with a change in gap size or market scenario Relative rate effects 2. SENSITIVITY OF FACTORS THAT MAY AFFECT RESOURCE MIX PREFERENCES Renewable energy credits Wind integration cost, limit and diversity benefit Freshet oversupply IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 3

4 RELEVANT CEA OBJECTIVES Relevant CEA Objectives At least 93% generation from clean or renewable resources To ensure the authority s rates remain among the most competitive of rates charged by public utilities in North America To reduce greenhouse gas emissions To encourage communities to reduce GHG emissions and use energy efficiently To reduce waste by encourage the use of waste heat, biogas and biomass To encourage economic development and the creation and retention of jobs To foster the development of First Nation and rural communities To maximize the value of B.C. s generation and transmission assets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 4

5 ACQUISITION NEED F2017 F2021 F Mid Load Forecast After DSM (DSM Option 1) (1,381) (6,697) (15,069) 2011 Mid Load Forecast After DSM (DSM Option 2) (863) (5,741) (13,671) 2011 Mid Load Forecast After DSM (DSM Option 3) (614) (4,980) (12,448) 2011 Mid Load Forecast After DSM (DSM Option 4) (596) (4,729) (10,541) 2011 Mid Load Forecast After DSM (DSM Option 5) (586) (4,701) (10,241) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 5

6 Adjusted Firm Unit Energy Cost ($/MWh) ACQUISITIONS RESOURCE OPTIONS SUPPLY CURVE $1,400 Clean Resource Potential Supply Curve Summary Adjusted Firm UEC ($/MWh) * $1,200 $1,000 $800 $600 $400 $200 Geothermal Excluded Geothermal Included $0 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90, , , , , , ,000 Firm Energy (GWh) Notes: 1.Tidal, Wave and Solar potentials are excluded. The lowest adjusted firm UEC starts at $222/MWh. 2. Supply curves have not reflected network upgrade (NU) costs. $6/MWh is the weighted average NU cost for CPC. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 6

7 Adjusted Firm Unit Energy Cost ($/MWh) ACQUISITIONS RESOURCE OPTIONS SUPPLY CURVE Clean Resource Potential Supply Curve Summary Adjusted Firm UEC ($/MWh) * $250 $200 $150 $129/MWh call price $100 $50 Geothermal Excluded Geothermal Included $0 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 Firm Energy (GWh) Notes: 1.Tidal, Wave and Solar potentials are excluded. The lowest adjusted firm UEC starts at $222/MWh. 2. Supply curves have not reflected network upgrade (NU) costs. $6/MWh is the weighted average NU cost for CPC. Network upgrade costs not included IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 7

8 MODELLING MAP IPP: GAP & MARKET SCENARIOS Uncertainties/Scenarios Gap Size Large Mid load, low DSM Mid Mid load, high DSM Small Market Scenario A B C D E North Coast Load KM LNG Only KM & LNG3 KM, LNG3 & Future IRP Policy Choices DSM Level DSM 1 DSM 2 DSM 3 DSM 4 DSM 5 Site C Site C in at EISD Site C is an option Site C is NOT an option Thermal Generation No additional thermal Yes additional thermal Modelling Assumptions & Parameters Wind Integration Cost ($/MWh) $5 $10 $15 Modelling Horizon (yrs) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 8

9 ACQUISITIONS: VOLUME SENSITIVITY TO GAP SIZE AND MARKET SCENARIOS Model builds to fill gap/meet needs In the small and mid gap cases, economic build opportunity for market scenarios with high electricity prices IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 9

10 ACQUISITION: PRESENT VALUE SENSITIVITY TO GAP SIZE AND MARKET SCENARIOS Market Scenario Likelihood PV in million $, 2011 real $, discounted to 2011 Small Gap Mid Gap Large Gap Weighted Average across gaps 10% 80% 10% A 10% 1,597 7,463 14,771 7,607 B 45% 2,858 8,029 14,533 8,163 C 25% 3,439 8,599 14,841 8,708 D 5% 1,681 7,268 14,190 7,401 E 15% 3,468 8,583 14,811 8,694 Weighted Average across scenarios 2,910 8,160 14,659 8,285 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 10

11 RESULTS OF RATE DIFFERENTIAL Small gap results updated March 05, 2012 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 11

12 ACQUISITIONS CONSIDERATIONS SOME FACTORS THAT MAY AFFECT RESOURCE MIX PREFERENCES: Renewable energy credits Wind integration cost, limit and diversity benefit Freshet oversupply IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 12

13 Firm Energy (GWh) RESOURCE MIX: REC INFLUENCE ORDERED IN INCREASING REC Mid Gap (without Site C) In increasing REC order Other Small Hydro Wind A D B C E A D B C E A D B C E IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 13

14 Rate Increase RESULTS OF RATE DIFFERENTIAL 2.0% IRP Market Price Scenario Incremental Rate Impact over Mkt C 0.0% -2.0% -4.0% -6.0% -8.0% -10.0% -12.0% F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 Market Price A Market Price B Market Price D Market Price E IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 14

15 RESOURCE MIX: REC INFLUENCE OBSERVATIONS: Higher REC cases show preference for more RPS eligible resources However, high REC does not result in portfolios with only RPS eligible resources Resource selection depends on REC as well as relative cost competitiveness between resource options IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 15

16 RESOURCE MIX: WIND INTEGRATION COST WIND INTEGRATION COST CONSISTS OF: Cost of incremental within-hour reserve capacity required to support intermittency of wind generation Costs of foregone trades in the day-ahead market due to reserves set aside to deal with day-ahead forecast errors IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 16

17 RESOURCE MIX: WIND INTEGRATION COST Reserve Cost + Day-Ahead Opportunity* Economic Dispatch, CAPEX 2010/11 Study Year 2020/21 Study Year per MWh of wind energy per kw installed wind capacity per month per MWh of wind energy per kw installed wind capacity per month 15% (1,500 MW) $10.79 $2.84 $12.79 $3.36 Economic Dispatch, CAPEX 25% (2,500 MW) $15.58 $4.09 $19.41 $5.10 Economic Dispatch, CAPEX 35% (3,500 MW) $13.57 $3.37 $16.57 $4.11 High Diversity, 15% (1,500 MW) $5.39 $1.14 $6.04 $1.28 High Diversity, 25% (2,500 MW) $6.36 $1.35 $7.31 $1.55 High Diversity, 35% (3,500 MW) $7.64 $1.62 $8.51 $1.80 Base assumption for wind integration cost in IRP analysis: $10/MWh $5/MWh and $15/MWh used for sensitivity analysis (approximate low and high values in the study associated with various diversity and wind penetration level scenarios) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 17

18 MODELLING MAP WIND INTEGRATION Uncertainties/Scenarios Gap Size Large Mid load, low DSM Mid Mid load, high DSM Small Market Scenario A B C D E North Coast Load KM LNG Only KM & LNG3 KM, LNG3 & Future IRP Policy Choices DSM Level DSM 1 DSM 2 DSM 3 DSM 4 DSM 5 Site C Site C in at EISD Site C is an option Site C is NOT an option Thermal Generation No additional thermal Yes additional thermal Modelling Assumptions & Parameters Wind Integration Cost ($/MWh) $5 $10 $15 Modelling Horizon (yrs) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 18

19 Firm Energy (GWh) RESOURCE MIX: WIND INTEGRATION COST Portfolios assuming higher wind integration cost select less wind resources Mid Gap, DSM 2, With Site C Site C Other Small Hydro Wind IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 19

20 RESOURCE MIX: WIND INTEGRATION COST Geographical diversity benefits (~$5-12/MWh at full diversity) are less than the increased cost of acquiring diversified wind projects (e.g., outside of the Peace Region) IRP Wind Energy Supply Curve (Costs to POI) > $5-12/MWh IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 20

21 Adjusted Unit Energy Cost ($/MWh) ACQUISITIONS COMPARISON OF SUPPLY CURVES FOR WIND, RUN-OF-RIVER AND BIOMASS - Adjusted to reflect Lower Mainland delivery (network upgrade costs not included) ,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 Firm Energy (GWh) Biogas Biomass - WW - Sawmill/Roadside Biomass - WW - Standing Timber MSW Run-of-River Hydro Wind - Offshore Wind - Onshore IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 21

22 ACQUISITIONS: WIND INTEGRATION COST SUMMARY OF FINDINGS: Lower wind integration costs show preference for more wind For the next few thousands of GWh, the economic benefits of wind diversity on wind integration cost is outweighed by the cost of acquiring diversified wind projects Given the range of wind integration costs tested, it does not result in all-wind portfolio nor no-wind portfolio Resource selection depends on wind integration cost as well as relative cost competitiveness between resource options IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 22

23 ACQUISITIONS: WIND INTEGRATION LIMIT Previous preliminary study shows a limit of 3,000 MW Based on historical system operation data (1 year) Assumes that wind integration is limited by the amount of dispatchable generation available from Automated Generation Control (AGC) plants Does not consider transmission constraints, market constraints for surplus wind energy, and trade-offs with spilling and/or wind curtailment Does not include system build-out (Rev 5/6, Mica 5/6, Site C) With Rev 5/6, Mica 5/6, and Site C, limit may increase to ~ 5,000 MW Further analysis required IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 23

24 Modelled Installed Wind Capacity (MW) ACQUISITIONS: WIND INTEGRATION LIMIT 6,000 Mid Gap, DSM 2, With Site C 5,000 Currently estimated wind integration 5000 MW with Mica 5/6, Rev 5/6 and Site C (to be updated) 4,000 3,000 Currently estimated wind integration 3000 MW (to be updated) 2,000 1,000 0 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 24

25 Modelled Installed Wind Capacity (MW) ACQUISITIONS: WIND INTEGRATION LIMIT 6,000 Large Gap, DSM 2, With Site C 5,000 Currently estimated wind integration 5000 MW with Mica 5/6, Rev 5/6 and Site C (to be updated) 4,000 3,000 Currently estimated wind integration 3000 MW (to be updated) 2,000 1,000 0 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 25

26 ACQUISITIONS: WIND INTEGRATION LIMIT IMPLICATIONS: Currently estimated wind integration limit does not appear to be a near-term issue, but could be under other high load scenarios. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 26

27 GWh/month ACQUISITIONS: FRESHET OVERSUPPLY 7,000 6,000 FLEXIBILITY DURING FRESHET - WET YEAR BC HYDRO SUPPLY AND DEMAND BC Hydro Load Curtail 2018 Freshet period: negative electricity market prices observed in recent years Surplus Energy Spill or Export (at min. generation) 5,000 4,000 Gap To be filled with BC Hydro Discretionary Generation and Imports 3,000 Supply from Non Discretionary BC Hydro Hydro Generation (Minimum Generation) 2,000 with Min. ICG 1,000 Supply from IPPs and Resource Smart 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 27

28 ACQUISITIONS: FRESHET OVERSUPPLY IMPLICATIONS: LNG almost flat load profile could help freshet oversupply issue General load may continue to grow with winter high freshet low demand annual profile Energy acquisitions during freshet still needs to be managed IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 28

29 FORT NELSON (FN) SUPPLY AND ELECTRIFICATION OF THE HORN RIVER BASIN (HRB) JOHN RICH BASIL STUMBORG KATHY LEE

30 FORT NELSON AND HORN RIVER BASIN FORT NELSON Extreme Northeast of Province Not part of Integrated System (connected to Alberta) 73 MW FNG CCGT serves area HORN RIVER BASIN (HRB) Large natural gas development Even further north No electrical connection No requests for electric service STRONG LINK TO LNG DEVELOPMENT Significant HRB development unlikely absent LNG export opportunity IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 30

31 CLIMATE CHANGE POLICY CONSIDERATIONS BUSINESS AS USUAL (PRODUCER SELF-SUPPLY) Significant GHG production associated with HRB 65% to 70% formation CO 2 (12% of natural gas production) 30% to 35% combustion CO 2 Adds 7.5 MT/y from HRB in mid scenario 10.4 MT/y in the high scenario POTENTIAL EFFECT OF ELECTRIFICATION OF HRB Electrification and carbon capture & sequestration (CCS) are possible opportunities to meet both objectives Producers consider electric service as a means of managing GHG IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 31

32 HIGH LEVEL ISSUES NATURAL GAS FROM THE HRB HAS A LARGE CARBON FOOTPRINT: If developed, HRB will materially affect the Province s GHG reduction targets, unless GHG mitigation steps are taken Producer group processing plant activity decentralizing CASCADE OF ISSUES AND UNCERTAINTIES: To what extent will the Horn River Basin (HRB) be developed? If developed, will industry (customers) request electric service of BC Hydro? If requests are made, can BC Hydro respond in time for industry s needs? If served by BC Hydro, is natural gas-fired local generation, including at-site cogeneration, an option? If not, the service would be with clean energy from the integrated system PARALLEL ISSUES: If served, who pays i.e., application of Tariff Supplement #6 or equivalent? If (or to the extent) industry pays, what is the impact on HRB competitiveness in natural gas markets? If electrified, what spinoff benefits can/might be expected? Value of avoided emissions to industry? IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 32

33 RELEVANT CEA OBJECTIVES Relevant CEA Objective To reduce expected increase in demand for electricity by the year 2020 by at least 66% To ensure the authority s rates remain among the most competitive of rates charged by public utilities in North America To reduce GHG emissions To encourage fuel switching to other resources that decrease GHG emissions To encourage economic development and the creation and retention of jobs To maximize the value of B.C. s generation and transmission assets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 33

34 LOAD UNCERTAINTY CONTINUED UNCERTAINTY AS TO HOW THE HRB WILL DEVELOP Production volumes are up, but the range (low to high) is similar Slightly delayed from last year Recent pipeline application to serve HRB provides forecast similar to BC Hydro mid scenario IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 34

35 ANALYTICAL APPROACH FOR IRP BC HYDRO SUPPLY ALTERNATIVES STUDIED: Alternative 1 System Clean Electricity Electrify HRB region Build North East Transmission Line (NETL) from Peace region to FN to HRB Alternative 2 Regional Thermal Supply (no NETL) Electrify HRB region Alt 2a: With a line from FN to HRB 2a(1): supply with co-generation at one or more processing plant 2a(2): supply with CCGTs at FN Alt 2b: No interconnection from FN to HRB Supply with co-generation at one or more processing plant Alternative 3 Fort Nelson-Only Supply BC Hydro only supplies existing FN network Alt 3a: Continue reliance from Alberta Alt 3b: Replace reliance on Alberta with new thermal at FN Industry self-supplies HRB region (business-as-usual) Industry costs are outside IRP scope IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 35

36 Preliminary Results CP MW CP MW CP MW CP MW LOADS SERVED BY BC HYDRO AND BY ALTERNATIVE Alternative 1, 2a Alternative 2b Alternative 3 BCH - Network 1 BCH System* Load BCH - Network 1 BCH Thermal Load at FN BCH - Network 1 BCH Thermal Load at FN *System means resources supplied from an integrated system: clean (NETL) or thermal BCH - Network 2 BCH Thermal Load at HRB IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 36

37 Preliminary Results PARAMETERS BEING MONITORED IMPACTS BEING ADDRESSED THROUGH THE ANALYSIS FOR EACH ALTERNATIVE: PV of energy supplied Clean Thermal BC Hydro costs PV of costs $/MWh average GHG impact (CO 2 being vented to atmosphere) GHG emitted in 2030 (as an example) Combustion CO 2 and formation CO 2 estimated separately Natural gas combustion volumes (BC Hydro and Producer) PV of Petajoules burned BC Hydro overall system per cent clean electricity IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 37

38 PRELIMINARY DRAFT RESULTS (MARKET SCENARIO C) Scenario Mid HRB production Alt 1 With Sequestration Alternative 2 Alternative 3 No Sequestration Alternative 3 Mid Electrification A1(1) A1(2) A2(1) A2(2) B A1 A2 A1 A2 Scen C: Low Gas/Elec Low GHG 1 Cogen 2 Cogen FNG FNG 1 Cogen New FN Reserve New FN Reserve Plant Plants GE LM6000 GE F6F Plant AESO LMS100 AESO LMS100 BC Hydro energy supplied Clean PV GWh 38, Thermal PV GWh ,872 42,766 42,872 42,872 38,726 4,368 4,368 4,368 4,368 Total PV GWh 39,674 42,872 42,766 42,872 42,872 38,726 4,368 4,368 4,368 4,368 BC Hydro Costs Total Cost PV $M 5,914 4,514 4,318 4,569 4,633 3, BC Hydro Effective $/MWh $/MWh BC Hydro System % Clean ( ) Avg % 95.3% 91.1% 91.1% 91.1% 91.1% 91.5% 95.1% 95.1% 95.1% 95.1% FN/HRB Region (combined) Natural gas burned PV PJ GHG volumes Combustion CO2 PV MT Formation CO2 (vented) PV MT Total CO2 vented PV MT Resulting GHG Abatement PV MT GHG volumes (2030 Annual) Combustion CO MT Formation CO MT Total 2030 MT GHG % Reduction from BAU 2030 MT 78% 63% 66% 65% 64% 66% 61% 61% GHG % Red after sequestration 17% 2% 5% 4% 3% 5% IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 38

39 PRELIMINARY DRAFT RESULTS (MARKET SCENARIO B) Scenario Mid HRB production Alt 1 With Sequestration Alternative 2 Alternative 3 No Sequestration Alternative 3 Mid Electrification A1(1) A1(2) A2(1) A2(2) B A1 A2 A1 A2 Scen B: Mid Gas/Elec Mid GHG 1 Cogen 2 Cogen FNG FNG 1 Cogen New FN Reserve New FN Reserve Plant Plants GE LM6000 GE F6F Plant AESO LMS100 AESO LMS100 BC Hydro energy supplied Clean PV GWh 38, Thermal PV GWh ,872 42,766 42,872 42,872 38,726 4,368 4,368 4,368 4,368 Total PV GWh 39,674 42,872 42,766 42,872 42,872 38,726 4,368 4,368 4,368 4,368 BC Hydro Costs Total Cost PV $M 6,160 7,032 6,621 6,679 6,869 5, BC Hydro Effective $/MWh $/MWh BC Hydro System % Clean ( ) Avg % 95.3% 91.1% 91.1% 91.1% 91.1% 91.5% 95.1% 95.1% 95.1% 95.1% FN/HRB Region (combined) Natural gas burned PV PJ GHG volumes Combustion CO2 PV MT Formation CO2 (vented) PV MT Total CO2 vented PV MT Resulting GHG Abatement PV MT GHG volumes (2030 Annual) Combustion CO MT Formation CO MT Total 2030 MT GHG % Reduction from BAU 2030 MT 78% 63% 66% 65% 64% 66% 61% 61% GHG % Red after sequestration 17% 2% 5% 4% 3% 5% IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 39

40 SUMMARY OF FINDINGS, DISCUSSION COST SUMMARY: Using thermal-based resources to serve FN/HRB appears equal to or lower cost than system clean/netl alternative but at the expense of higher GHG emissions All thermal options serving FN/HRB run up against the 93% Clean Energy target Cogeneration appears to be most cost-effective thermal option, but only if there is a good, long-term balance and consistency in heat load and electric load and commercial risks can be adequately addressed Where BC Hydro only serves FN load, a peaking gas turbine is more cost-effective than increased service from Alberta GHG SUMMARY: Formation CO 2 is most important GHG component 60% reduction of formation CO 2 if sequestration successfully implemented Incremental savings from electrification (assuming formation CO 2 in place) Thermal (cogen or CCGT) can reduce GHG emissions a further 2%-6%; or Clean electricity can reduce GHG emissions by 15% to 22% Remaining GHG is from prior to electrification or processes that cannot be electrified IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 40

41 ADDITIONAL ANALYSIS, DISCUSSION OTHER BENEFITS OF ALTERNATIVE 1 (NETL) NOT MENTIONED: NETL allows for lower cost integration of renewable resources in the North Peace region and loads that would otherwise not be electrified Integration benefit does not offset total cost relative to thermal options IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 41

42 UNCERTAINTIES, DISCUSSION HRB DEVELOPMENT UNCERTAINTY: How Much? How? North America increasingly competitive gas market; how economic is the HRB? Broad range of gas production volumes for HRB Ultimate level of potential electrification? Development to date is more decentralized than assumed for electricity integration Market players relatively fluid Can commercial arrangements be made given uncertainties/risks and market dynamics? GHG Emissions Value Uncertainty Formation CO 2 currently not regulated; carbon tax on combustion CO 2 What is the value to industry of reducing emissions? Cost, asset or no value? IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 42

43 FORT NELSON BACKGROUND SLIDES IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 43

44 Analytical Approach DETAILS OF ALTERNATIVES STUDIED Alt 3: Fort Nelson-only supply BC Hydro serving one network (FN as it currently exists) HRB supply situation Producers self supply BC Hydro does not provide service to HRB FN supply situation Supply from FNG New supply from thermal at FNG Alt A(1): continue AESO firm service Alt A(2): replace AESO service with thermal at FNG P2 P2 P2 Gathering and Primary Compression P3 P1 P3 P1 P3 P1 GMS NPR RGT 3 RGT 2 RGT 1 Fort Nelson Gas Processing, and Carbon Sequestration Spectra Fort Nelson AESO Integration to the Electrical System Horn River Basin Quicksilver Spectra Spectra North Cabin TCPL / NGTL Natural Gas Transmission System Future CCS/EOR IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 44

45 Analytical Approach DETAILS OF ALTERNATIVES STUDIED Alt 2b: Regional thermal supply BC Hydro serving two networks (FN and HRB separately) 2b: HRB network No interconnection to FNG HRB network supply situation Supply with co-generation at one or more processing plants Processing plants utilize waste heat from generation FN supply situation Supply from FNG New supply from thermal at FNG Option A(1): continue AESO firm service Option A(2): replace AESO service with thermal at FNG P2 P2 P2 Gathering and Primary Compression P3 P1 P3 P1 P3 P1 GMS NPR RGT 3 RGT 2 RGT 1 Fort Nelson Gas Processing, and Carbon Sequestration Spectra Fort Nelson AESO Integration to the Electrical System Horn River Basin Quicksilver Spectra Spectra North Cabin TCPL / NGTL Natural Gas Transmission System Future CCS/EOR IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 45

46 Analytical Approach DETAILS OF ALTERNATIVES STUDIED Alt 2a: Regional thermal supply BC Hydro serving one network (FN/HRB together) 2a: FN/HRB network Build line from FNG to Cabin FN/HRB supply situation 2a(1): Supply with co-generation at one or more processing plants Processing plants utilize waste heat from generation 2a(2): Supply load with centralized CCGTs located at FNG No use of waste heat; possible economies of scale P2 P2 P2 Gathering and Primary Compression P3 P1 P3 P1 P3 P1 GMS NPR RGT 3 RGT 2 RGT 1 Fort Nelson Gas Processing, and Carbon Sequestration Spectra Fort Nelson AESO Integration to the Electrical System Horn River Basin Quicksilver Spectra Spectra North Cabin TCPL / NGTL Natural Gas Transmission System Future CCS/EOR IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 46

47 Analytical Approach DETAILS OF ALTERNATIVES STUDIED Alt 1: System clean electricity One BC Hydro network for FN/HRB that is interconnected to the integrated system Transmission line from GMS to Fort Nelson and Cabin Processing Plant Also referred to as NETL (North East Transmission Line) Possible new substation in the North Peace Supplied by system clean energy and capacity Cancel firm service from Alberta P2 P2 P2 Gathering and Primary Compression P3 P1 P3 P1 P3 P1 GMS NPR RGT 3 RGT 2 RGT 1 Fort Nelson Gas Processing, and Carbon Sequestration Spectra Fort Nelson AESO Integration to the Electrical System Horn River Basin Quicksilver Spectra Spectra North Cabin TCPL / NGTL Natural Gas Transmission System Future CCS/EOR IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 47

48 Analytical Approach RESOURCE ASSUMPTIONS BC HYDRO RESOURCE ALTERNATIVES System clean capacity and energy Combined Cycle Gas Turbines (CCGT) GE LM6000 s (clones of FNG) 75 MW GE Frame 6FA 110 MW Co-generation Based on GE LM MW Based on GE Frame 7E* MW Peaking gas turbines GE LMS MW Transmission requirements Currently being updated as part of parallel study PRODUCER LOCAL SUPPLY OPTIONS (FOR ESTIMATING GHG EMISSIONS) Small compressor drives 1.8 MW Wartsillia engines 8.8 MW Co-generation based on GE LM MW * A third party has proposed a concept with similar machines, and based on their assumptions of life-cycle base load electricity, heat sales and offsets, claim plant-gate electricity cost could be in the order of $60 to $65/MWh. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 48

49 NORTH COAST KATHY LEE

50 NORTH COAST Currently, the North Coast (NC) is connected to the rest of the BC Hydro system by a single 500 kv circuit from Williston sub-station to Skeena substation. The Northwest Transmission Line (NTL) will extend northwards from Skeena and is expected to be in-service by end of The combined NC/NTL load, including Kitimat LNG (KM LNG) is estimated to be around 1200 MW by 2020 according to the 2011 reference load forecast. Capacity needs of the region are met primarily through the 500 kv line from Williston with some contribution from Rio Tinto Alcan s Kemano facility located in the region. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 50

51 LOAD SCENARIOS IN NORTH COAST + LNG3 F2021 F2031 Shell LNG3 LNG 9,617 12,823 High Future Mining 1,950 1, % Mining 5,439 5,759 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 51

52 LOAD SCENARIOS IN NORTH COAST + LNG3 F2021 F2031 Shell LNG3 LNG 1,239 1,652 High Future Mining % Mining IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 52

53 MW NTL CAPACITY < POTENTIAL MINING LOAD Probability weighted mining load Capability of 287 kv NTL Line All mines with service requests IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 53

54 NEED FOR REGIONAL T INFRASTRUCTURE UPGRADES TO MEET REFERENCE LOAD FORECAST WITH KITIMAT (KM) LNG USING CLEAN RESOURCES FROM THE INTEGRATED SYSTEM AS PER DIRECTION FROM GOVERNMENT: Series compensation of the 500 kv line from Williston to Skeena is required by 2016 Increases East to West line capacity from 800 MW to around 1380 MW The transmission line from Skeena to Kitimat (Minette sub-station) would also need to be upgraded A new substation near Minette would also be required IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 54

55 HEADROOM LEFT ON THE CENTRAL INTERIOR TO NORTH COAST TRANSMISSION LINE Capability of line after upgrades Flow on line when NC resources are at DGC Flow on line when NC resources are at Max Capacity Capability of existing line IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 55

56 LOAD SCENARIOS ANALYZED TWO ADDITIONAL LOAD SCENARIOS WERE MODELLED: LNG3 Up to 1400 MW of additional loads with majority occurring in the timeframe LNG3 and High Future Mining loads: Up to 1700 MW of additional loads with majority occurring in the timeframe Assumes NTL serves mining loads up to its full capability of 465 MW Probability of some mining loads in the NC (not connected to NTL) also increased to 100% IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 56

57 SUPPLY OPTIONS Dependable generation potential in the NC/NTL region is limited. Local resource options are primarily wind, small hydro, and biomass. OPTIONS IN SUPPLYING INCREMENTAL LOAD SCENARIOS: Clean Energy backed up by Gas capacity as required Energy need supplied from integrated system via the single 500 kv transmission line up to its capability with additional clean energy sourced from the NC/NTL Use gas-fired generation to provide dependable capacity Clean Supply via new Transmission Clean energy and capacity sourced from around the integrated system Additional transmission lines also required IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 57

58 SUPPLY OPTIONS POTENTIAL ISSUES OR DRAWBACKS: Clean Supply via new Transmission Earliest in-service date of another 500 kv line is 2018 This in-service date is uncertain and could pose challenges to meeting load that could occur in the timeframe Clean Energy backed up by Gas capacity as required Requires more detailed studies to confirm technical feasibility including the ability of the system to integrate renewables and to survive transmission system disturbances Studies have been initiated IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 58

59 RELEVANT CEA OBJECTIVES Relevant CEA Objective To reduce expected increase in demand for electricity by the year 2020 by at least 66% To ensure the authority s rates remain among the most competitive of rates charged by public utilities in North America To reduce GHG emissions To encourage fuel switching to other resources that decrease GHG emissions To encourage economic development and the creation and retention of jobs To maximize the value of BC s generation and transmission assets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 59

60 MODELLING MAP NORTH COAST Uncertainties/Scenarios Gap Size Large Mid load, low DSM Mid Mid load, high DSM Small Market Scenario A B C D E North Coast Load KM LNG Only KM & LNG3 KM, LNG3 & Future IRP Policy Choices DSM Level DSM 1 DSM 2 DSM 3 DSM 4 DSM 5 Site C Site C in at EISD Site C is an option Site C is NOT an option Thermal Generation No additional thermal Gas peakers w 93% clean target Modelling Assumptions & Parameters Wind Integration Cost ($/MWh) $5 $10 $15 Modelling Horizon (yrs) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 60

61 GAS UNITS NEEDED FOR CLEAN ENERGY BACKED UP BY GAS CAPACITY OPTION MW of gas-fired generation built LNG3 Load Scenario LNG3 and High Mining Load Scenario TOTAL IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 61

62 COST OF SUPPLY OPTIONS Clean Supply via Transmission (A) Clean energy backed up by gas capacity (B) PV of Supply Options ($ Millions) LNG Load Scenario LNG and High Mining Load Scenario 15,590 17,851 15,002 17,056 DIFFERENCE (A-B) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 62

63 LOCATION VALUE OF GAS-FIRED GENERATION Comparing the cost of siting gas-fired generation in the integrated system (at Kelly) vs. in the North Coast within the 7% room for gas Clean energy backed up by gas capacity in North Coast (same as Supply Option B) Clean and Gas Energy/Capacity from the system via Transmission Benefit of siting gas in the integrated system Portfolio PV cost ($M) to meet LNG3 Load Scenario 15,002 14, (within modelling uncertainty) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 63

64 ENVIRONMENTAL FOOTPRINTS CALCULATED FOR TWO LOAD SCENARIOS: LNG3 load alone LNG3 load and High Mining Load Gas reduces land and water impacts of Transmission, Generation Measure Clean Power with Transmission Clean with SCGTs (within 93% limit) Land total hectares 28,200 22,300 Marine (valued ecological features) total hectares Affected Stream Length km IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 64

65 ENVIRONMENTAL FOOTPRINTS Relying on gas generation increases emissions of Local Air Contaminants Same story with LNG3 and mining loads, but differences are greater Measure Clean Power with Transmission Clean with SCGTs (within 93% limit) GHG Emissions C02e ( 000 t) 3,800 16,400 Local Air Contaminants Local Air Contaminants Oxides of Nitrogen (kt/yr) Carbon Monoxide (kt/yr) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 65

66 ECONOMIC DEVELOPMENT IMPLICATIONS Relying on gas generation reduces some Economic Development Benefits Same pattern with higher loads Measure Clean Power with Transmission Clean with SCGTs (within 93% limit) GDP $M NPV 16,200 16,000 Employment FTEs 338, ,000 Government Revenues $M NPV 2,700 2,600 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 66

67 OTHER CONSIDERATIONS A NUMBER OF ADDITIONAL FACTORS WILL BE TAKEN INTO CONSIDERATION BEFORE A BEST COURSE OF ACTION IS IDENTIFIED: Technical feasibility work currently underway on this Reliability Customer acceptance Government policy and objectives IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 67

68 ELECTRIFICATION WARREN BELL KATHY LEE

69 RELEVANT CEA OBJECTIVES Relevant CEA Objectives To ensure the authority s rates remain among the most competitive of rates charged by public utilities in North America To reduce GHG emissions To encourage fuel switching to other resources that decrease GHG emissions To encourage communities to reduce GHG emission and use energy efficiently To encourage economic development and the creation and retention of jobs The maximize the value of B.C. s generation and transmission assets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 69

70 ELECTRIFICATION FOCUS AREAS: 1. What if strong global action to achieve deep reductions? What new loads might emerge? What resources will be needed, how much, when? 2. Potential large new industrial loads in the northeast and the northwest (separate presentation) CONSIDERATIONS: Uncertainty of future climate policy: globally and in B.C. Cost-effectiveness of GHG reductions: electrification vs. other Economic development and obligation to serve Adequacy/costs of resources and transmission Environmental impacts of building additional resources Risk of stranded investment IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 70

71 RECAP TWO LOAD SCENARIOS DEVELOPED BY E3 SCENARIO 2: LOW GHG REDUCTIONS In the WECC, 30% reduction in GHG emissions by 2050, relative to 2008 Offsets can account for 10% of emissions reductions; 20% of target achieved through reductions in western states and provinces fossil-fuelbased GHGs B.C. is assumed to surpass the scenario target, achieving a 50% reduction in GHG emissions relative to 2008 by 2050 For B.C., 35% of total 2050 emissions savings come from offsets. SCENARIO 3: HIGH GHG REDUCTIONS 80% reduction in GHG emissions by 2050, relative to 2008 Offsets can account for 30% of emissions reductions; 50% achieved through reductions in western states and provinces fossil-fuel-based GHGs B.C. meets the overall GHG target with 35% of 2050 total emissions savings coming from offsets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 71

72 ELECTRIFICATION POTENTIAL REVIEW DRILL DOWN INTO E3 SCENARIOS: How do market and policy conditions affect electrification? How will electrification affect load growth and GHG emissions? IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 72

73 FRAMEWORK OF ANALYSIS CIMS - simulates the evolution of the energy-using capital stock to 2050 under reference and policy scenarios Assumptions aligned with IRP Evaluate electrification under three GHG price scenarios, three gas price scenarios Input Energy Prices Sector Activity CIMS Output GHG emissions Energy Consumption Framework Detailed representation of technologies and sectors Realistic consumer behaviour Balance of energy supply and demand Macro-economic feedbacks IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 73

74 GHG Price, 2005 $/tco2e GHG PRICE SCENARIOS High and medium scenarios assume other jurisdictions enact climate policies High, scenario D from IRP Medium, scenario B from IRP Low, B.C. only 30 $/t Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 74

75 GHG Abatement, Mt CO2e from BAU ELECTRIFICATION ABATEMENT (LOW GHG, BASE NG) Provincial target Electrification abatement Other abatement Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 75

76 GHG Abatement, Mt CO2e from BAU ELECTRIFICATION ABATEMENT (HIGH GHG, BASE NG) Provincial target 30 Other abatement Electrification abatement Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 76

77 GHG Abatement, Mt CO2e from BAU ABATEMENT BY SECTOR (HIGH GHG, BASE NG) Methane control Efficiency Manufacturing & mining Transportation CCS Liquid biofuels 10 NG production Commercial Residential Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 77

78 Electricity Demand (TWh/yr) B.C. ELECTRICITY DEMAND- GHG PRICE SCENARIOS (BASE NG PRICE) High GHG Medium GHG Low GHG Reference Case Demand Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 78

79 Additional Electricity Demand (TWh/yr) ADDITIONAL ELECTRICITY DEMAND (RELATIVE TO REF) BY SECTOR (LOW GHG, BASE NG) Transportation Natural Gas Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 79

80 Additional Electricity Demand (TWh/yr) ADDITIONAL ELECTRICITY DEMAND (RELATIVE TO REF) BY SECTOR (HIGH GHG, BASE NG) Industrial (other manufacturing and mining) Natural Gas Transportation Commercial Residential Year IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 80

81 CONCLUSIONS Deep GHG reductions require large amounts of zero-emissions electricity Roughly double current generation by 2050 More electricity use across all sectors IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 81

82 ELECTRIFICATION SCENARIOS (E3): ENERGY F2021 F2031 Electrification ,549 Electrification 3 1,362 8,888 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 82

83 ELECTRIFICATION SCENARIOS (E3): CAPACITY F2021 F2031 Electrification ,703 Electrification ,564 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 83

84 EXPORT ROHAN SOULSBY

85 TWO TYPES OF ENERGY FOR EXPORT TYPE 1: TRADITIONAL EXPORTS (CURRENT APPROACH) Any energy surplus associated with meeting Self Sufficiency requirement System capability is largely used to manage domestic needs Optimization of system variability results in some energy for exports Surplus beyond what arises for domestic need arises due to variability of water conditions and/or non-firm energy delivered from IPPs Given the new planning criteria, could have surplus or deficit for any given year TYPE 2: CLEAN GENERATION FOR EXPORT Exports that would come from the aggregation of renewable energy acquired from IPPs in B.C. solely for the purpose of exporting to markets outside B.C. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 85

86 EXPORT (TYPE 2) CLEAN ENERGY ACT OBJECTIVE: Explore and pursue opportunity to develop and sell clean energy into interprovincial and international markets, reaping an economic benefit for British Columbians and displacing fossil fuel derived electricity with a renewable, sustainable and GHG neutral supply THE CLEAN ENERGY ACT REQUIRES THE IRP TO INCLUDE: As assessment of the market demand for renewable energy in markets that could be served by BCH, An estimate of the market share that BCH expects to capture, and An estimate of the expenditures for exports from aggregation. Clean Energy Act provides that when IRP is submitted to Government, Government may direct BCH to commence a process of acquiring energy from IPPs in B.C. for aggregation and sale to destination markets outside B.C. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 86

87 COMPETIVENESS CONCLUSION Currently, a number of factors are working against B.C. resources being competitive longer distance to market more difficult building locations uneven playing field (persistence of PTC/ACP) A small portion of B.C.'s most favorable resources are competitive (500MW) with no PTC/ACP and a shaped product Large uncertainty around the market variables which can increase risk Gas, GHG, Electricity Prices RPS Policy / REC Markets Transmission access to Markets Only Under High Market Prices or with no PTC and a shaped product that B.C. resources are marginally competitive IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 87

88 THEORETICAL ANALYSIS CONFIRMED Theoretical analysis has concluded that B.C. resources are at best only marginally competitive only under very high market prices Confirmed over last 12 months by Powerex s actual experience in markets PG&E term sheet offered Responded to Nevada RFP Aggregation deal before CPUC Bi-lateral discussions with various entities LADWP Palo Alto Roseville With regulatory uncertainty, no appetite to enter into long-term deals CNC project has been abandoned by Project Proponents. PG&E made a FERC filing to recover CNC costs PG&E on October 13 said the project should be abandoned because of a dwindling pool of project participants, a lack of competitively priced renewable generation and transmission by British Columbia Hydro and a recent California law restricting some renewable energy imports. FERC on December 12 found "that PG&E's project was abandoned for reasons beyond its control and, therefore, we grant its request to recover the prudently incurred project costs" (Docket No. ER12-37). IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 88

89 TRANSMISSION AMIR AMJADI KATHY LEE

90 TRANSMISSION STRATEGIC TRANSMISSION ADVANCEMENT ENABLING FUTURE NEEDS BUT MINIMIZING COSTS PLANNING PERSPECTIVE: Transmission requires a long lead time of 8+ years Right of ways are difficult to secure What are the system reinforcements that will be needed? Should we pre-build major reinforcements for high resource potential and high growth potential areas? IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 90

91 RELEVANT CEA OBJECTIVES Relevant CEA Objective At least 93% generation from clean or renewable resources To ensure the authority s rates remain among the most competitive of rates charged by public utilities in North America To encourage economic development and the creation and retention of jobs To foster the development of First Nation and rural communities The maximize the value of B.C. s generation and transmission assets IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 91

92 TRANSMISSION: TWO PART ANALYSIS 1. SYSTEM REINFORCEMENT ANALYSIS 2. CLUSTER ANALYSIS KEY PORTFOLIO MODELLING ASSUMPTION: Pumped storage assumed as a capacity proxy available in Lower Mainland starting 2021 The availability of pumped storage or other capacity options in the Lower Mainland is highly uncertain, it is a major transmission contingency consideration Portfolios where the availability of pumped storage in Lower Mainland does not materialize have yet to be studied as part of the IRP IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 92

93 TRANSMISSION SYSTEM REINFORCEMENT 500kV BACKBONE IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 93

94 TRANSMISSION SYSTEM REINFORCEMENT 20 YEAR ANALYSIS (load with Kitimat LNG) SET OF PORTFOLIOS EVALUATED INCLUDE: Range of DSM options With and without Site C Large gap to small gap Across market scenarios FINDINGS: Majority of the reviewed portfolios do not require any new bulk transmission lines. Majority of reviewed portfolios will require voltage support in the Peace and Columbia transmission systems. North Coast needs series compensation on 5L61 (WSN-GLN), 5L62 (GLN-TKW) & 5L63(TKW-SKA). Voltage support and local transmission upgrades near Kitimat will also be needed. Large gap portfolios often result in reinforcement of the GMS-WSN-KLY corridor with new 500 kv circuits between 2027 and IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 94

95 TRANSMISSION SYSTEM REINFORCEMENT 20 YEAR ANALYSIS (load scenarios incremental to mid gap with Kitimat LNG) PORTFOLIOS THAT CONSIDERED THE FOLLOWING LOAD SCENARIOS WERE EVALUATED: LNG3 scenario LNG3 with High Future Mining scenario Fort Nelson/Horn River Basin scenarios FINDINGS: Supplying LNG3 load scenario and LNG3 with Future Mining load scenario may lead to the addition of new GMS-WSN circuit between 2020 and Supplying LNG3 load scenario and LNG3 with Future Mining load scenario would require new line from WSN to SKA at earliest in service date. (only if go with Clean energy with Transmission Line supply option). Supplying Fort Nelson/Horn River Basin load scenarios with clean energy would require the Northeast Transmission Line. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 95

96 TRANSMISSION SYSTEM REINFORCEMENT 30-YEAR ANALYSIS (load with Kitimat LNG) PORTFOLIO EVALUATED: Mid gap, with Site C, DSM Option 2, no gas option, Market scenario C FINDINGS: Reinforcement of the GMS-WSN-KLY corridor by new 500 kv circuits would be required in the 2030s 30 YEAR ANALYSIS (load scenarios incremental to mid gap with Kitimat LNG) Portfolios that consider combinations of load scenarios have yet to be evaluated IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 96

97 TRANSMISSION CLUSTER ANALYSIS BUNDLES (traditional T planning) vs. CLUSTERS (pre-building T into certain areas) Figure 1 Transmission Bundles P1 P2 P3 P4 Figure 2 A Transmission Cluster P3 P1 New Substation P2 P4 Figure 1 bundles of generation resources connected to the grid P5 Existing Grid P5 Existing Grid T1 P6 T1 T2 P6 T3 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 97

98 TRANSMISSION CLUSTER ANALYSIS CBL (existing) Point of interconnection for BUI, KTI, NVI IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 98

99 MODELLING MAP CLUSTER ANALYSIS Uncertainties/Scenarios Gap Size Large Mid load, low DSM Mid Mid load, high DSM Small Market Scenario A B C D E North Coast Load KM LNG Only KM & LNG3 KM, LNG3 & Future IRP Policy Choices DSM Level DSM 1 DSM 2 DSM 3 DSM 4 DSM 5 Site C Site C in at EISD Site C is an option Site C is NOT an option Thermal Generation No additional thermal Yes additional thermal Modelling Assumptions & Parameters Model Transmission topology Bundle Cluster Modelling Horizon (yrs) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 99

100 TRANSMISSION CLUSTER ANALYSIS (Clusters picked in portfolio) THE FOLLOWING CLUSTERS ARE SELECTED: Cluster Picked Year Picked BUI (Bute Inlet) 2017 KTI (Knight Inlet) 2020 NPR (North Peace River) 2033 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 100

101 TRANSMISSION CLUSTER ANALYSIS (PORTFOLIO COSTS) When financially attractive clusters are available for planning, do they reduce modelled portfolio costs? 30 year PV Bundle Cluster Difference G& T Resource cost - $ millions 11,727 11, Trade Revenue - $ millions (1,136) (1,140) 4 DSM Option cost - $ millions 3,996 3,996 - Total Portfolio Cost - $ millions 14,587 14,393 PORTFOLIO MODELLING FINDING: Some financial benefits to pre-building T Financial benefits are small OTHER CONSIDERATIONS: Modelling done with perfect foresight of future generation needs Risk of stranded assets 195 <2% IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 101

102 NORTH PEACE RIVER CLUSTER The cost and benefit for accessing the NPR cluster may DLK change as a result of the supply option decision for Fort Nelson/Horn River Basin TGC LRD FTN The earliest in service date for the Northeast Transmission BQN Line (NETL) is 2018 NPR A new NETL NPR substation can be added at a cost of ~$70M NC HCT Have yet to estimate potential benefits for the NPR cluster if NETL is a sunk decision KTI NVI BUI Potential benefit would have a wide range of uncertainties, e.g. Need for new IPP supply VI LM Supply from NPR region materializing and at the prices studied USA-1 KLY NIC PR CI MCA REV ACK SEL USA-2 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 102

103 ENVIRONMENTAL IMPLICATIONS CHOICE BETWEEN CLUSTER AND BUNDLE APPROACH TO TRANSMISSION: THE CLUSTER APPROACH: Reduces environmental impacts across most measures But some exceptions to this, as different projects are picked Measure Bundle Cluster Land total hectares 25,100 23,000 Affected Stream Length Marine (valued ecological features) km total hectares IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 103

104 ECONOMIC DEVELOPMENT IMPLICATIONS CHOICE BETWEEN CLUSTER AND BUNDLE APPROACH TO TRANSMISSION: Does not really impact Economic Development issues Measure Bundle Cluster Total GDP $M NPV 13,900 14,600 Employment Total FTEs 350, ,200 Gov t Revenue $M NPV 2,200 2,300 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 104

105 CAPACITY AND CONTINGENCY RESOURCE PLANNING LINDSAY FANE

106 AGENDA Capacity Need Capacity Options Uncertainties Near-Term Capacity Planning Long-Term Capacity Planning IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 106

107 CAPACITY NEED IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 107

108 CAPACITY OPTIONS Category Options Potential (MW) Lead Time (years) Market variable Readily available, but not longterm Canadian Entitlement (CE) 1,200 Burrard Revelstoke Unit Conventional, clean and long-term but not available in near-term Site C 1,100 9 Resource Smart TBD TBD Conventional, not clean, available near-term and long-term Gas 100 (each unit) 4-5 Mica Pumped Storage Uncertain in terms of operations and/or development Pumped Storage (LM/VI) (each unit) 8 DSM Load Curtailment ~ DSM Capacity Programs ~200 2 IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 108

109 CAPACITY UNCERTAINTIES Category Uncertainty Potential Impact Leading Indicator Lead time: Signal to ISD (years) Near-Term, Possible Insufficient Reaction Time, Gradual LOAD DSM +/- 600 MW in F2017 +/- 400 MW in F2017 Year-by-year load growth Year-by-year load growth Near-Term, Possible Insufficient Reaction Time, Signpost Wind ELCC Up to -150 MW in F2017 Experience & Internal analysis 1-4 Near-Term, Sufficient Reaction Time, Signpost LNG3 & High Future Mining High FN / HRB / Montney + 1,500 MW in F ,300 MW in F2021 Customer requests 3-4 NETL commitment 4 Long-Term, Sufficient Reaction Time, Signpost Site C Material delay up to 1,100 MW Approvals to proceed; ISD 4 Long-Term, Sufficient Reaction Time, Gradual Electrification Growing to 2,600 MW in F2031 (E3) Gov t policy, load growth, technology IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input

110 CAPACITY GAP AFTER CONVENTIONAL CLEAN OPTIONS AND CAPACITY FROM ENERGY RESOURCES F2017 F2018 F2019 F2020 F2021 Capacity Surplus (Deficit) (901) (875) (550) (630) (736) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 110

111 NEAR-TERM CAPACITY OPTIONS BRIDGING OPTIONS: Market backed by Canadian Entitlement MW Self Sufficiency Requirement Burrard Up to 450 MW CEA/Burrard Regulation NEW SUPPLY OPTIONS: Gas (100 MW SCGTs) Lead Time Permitting 93% Clean IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 111

112 COST COMPARISON OF OPTIONS Bridging Option Near-Term Capacity Strategy Unit Capacity Cost* ($/kw-year) Market/CE Burrard Gas (100 MW SCGT) 71 Note: Range of costs for bridging option are preliminary estimates. IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 112

113 GAS OPTION RECAP FROM ROLE OF GAS DISCUSSION: Gas energy in the system has a cost advantage over clean energy Given the limited room for gas due to the 93% Clean Target, gas holds value for special situations Capacity option Transmission alternatives (regional value) Contingency option Considerations for using gas as capacity/contingency option When? Should it be used to address near-term capacity shortfalls? Where? What are the consequences of siting gas in the wrong place? (i.e., making the siting decision before regional load materializes) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 113

114 COST DIFFERENCE IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 114

115 CAPACITY DECISION TREE/RISKS Uncertain Near-Term Outcome Large Rely on Market backed by CE+BGS Mid BRP BRP = Base Resource Plan Near-Term Strategy Build 700 MW SCGTs only if Kitimat* Small Large Mid * in this analysis, gas plants are positioned in North Coast because: (1) given Kitimat LNG load, loss savings potential (2) potential high load growth area (e.g. if LNG3 and mining load materialize) Small IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 115

116 CONTINGENCY RESOURCE PLANNING CONTINGENCY RESOURCE PLANS (CRPS) ADDRESS: uncertainties (supply and demand) that would drive us from Base Resource Plan (BRP) future actions that can be undertaken if these events occur ways in which options can be advanced to speed reaction times IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 116

117 CRP DEMAND UNCERTAINTIES LOAD UNCERTAINTY: +/- ~ 600 MW in F2018 DSM UNCERTAINTY: Actual DSM 5 years out (F2018) could deliver: 350 MW to 500 MW less than expected; or 400 MW to 650 MW more than expected BLENDED LOAD & DSM UNCERTAINTY: Graph shows that there is a 10% probability that the gap could be this much smaller or bigger NOTES: Additional uncertainty around DSM capacity, IPP attrition, ELCC (+200 MW, DSM2 F2018) IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 117

118 CRP SUPPLY UNCERTAINTIES INTERMITTENT RESOURCES: Wind ELCC 24% of Installed Capacity Existing EPAs approx. 150 MW in LRB Concerns of Winter Peak Reliability What if Wind ELCC was 0%, 12% of Installed Capacity? Small Hydro ELCC 60% of Average December/January MW More consistent supply shape, less concern IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 118

119 REGRET FOR BRIDGING STRATEGY & LARGE GAP Near-Term Outcome Rely on Market backed by CE+BGS Large Mid Near-Term Choice Small BRP Large Build 700 MW SCGTs only if Kitimat* Mid Small IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 119

120 REGRET FOR BRIDGING STRATEGY & LARGE GAP IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 120

121 REGRET FOR NEW SUPPLY STRATEGY & LARGE GAP Large Rely on Market backed by CE+BGS Mid Small BRP Near-Term Choice Near-Term Outcome Build 700 MW SCGTs only if Kitimat* Large Mid Small IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 121

122 REGRET FOR NEW SUPPLY STRATEGY & LARGE GAP IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 122

123 REGRET FOR BRIDGING STRATEGY & SMALL GAP Large Near-Term Choice BRP Rely on Market backed by CE+BGS Near-Term Outcome Mid Small Large Build 700 MW SCGTs only if Kitimat* Mid Small IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 123

124 REGRET FOR BRIDGING STRATEGY & SMALL GAP IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 124

125 REGRET FOR NEW SUPPLY STRATEGY & SMALL GAP Large Rely on Market backed by CE+BGS Mid Small BRP Near-Term Choice Build 700 MW SCGTs only if Kitimat* Near-Term Outcome Large Mid Small IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 125

126 REGRET FOR NEW SUPPLY STRATEGY & SMALL GAP IRP TAC MTG #5: February 28 & 29, 2012 Preliminary Analysis and Results for TAC Input 126