INTEGRATED RESOURCE PLAN TECHNICAL ADVISORY COMMITTEE MEETING #5 BACKUP SLIDES

Transcription

1 INTEGRATED RESOURCE PLAN TECHNICAL ADVISORY COMMITTEE MEETING #5 BACKUP SLIDES Preliminary Analysis and Results for TAC Input February 28 & 29,

2 BACKUP SLIDES LOAD FORECAST

3 POTENTIAL LNG LOADS LNG3 3

4 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 GWh FORECAST - TOTAL INTEGRATED GROSS REQUIREMENTS WITH RATE IMPACTS WITH DSM (WITH LNG SCENARIOS AND HORN RIVER GAS ELECTRIFICATION) 100,000 80,000 60,000 40,000 20, Kitimat + LNG3 Shell +HRB High + Kitimat + LNG3 Shell +HRB Mid + Kitimat + LNG3 Shell Kitimat Forecast HRB (Horn River Basin) High refers to high gas production and high electrification scenario. Does not include Ft. Nelson loads. HRB Mid refers to mid gas and mid electrification scenario. Does not include Ft. Nelson loads 4

5 F11 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 GWh FORTIS BC SALES WITH RATE IMPACTS BEFORE DSM FORECAST VS FORECAST Forecast With Rates Before DSM 1,600 1,400 1,200 Forecast (GWh) 2010 Forecast (GWh) Less 2010 (GWh) Less 2010 (%) 1,000 F , % 800 F , % 600 F17 1,041 1, % 400 F21 1,041 1, % 200 F26 1,041 1, % 0 F31 1,041 1, % Forecast 2010 Forecast Forecast includes downward adjustment to account for recent lower purchases from FortisBC. Load is projected to reach 1,041 GWh by F2016 then be constant through the remainder of the forecast. 5

6 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 GW.h FORECAST - TOTAL INTEGRATED GROSS REQUIREMENTS WITH RATE IMPACTS BEFORE DSM (WITH KITIMAT LNG) Forecast With Rates Before DSM 100,000 90,000 80,000 70,000 Reference + Kitimat LNG (GWh) Reference Forecast (GWh) 60,000 F12 56,838 56,803 50,000 40,000 30,000 20,000 10,000 F13 59,285 59,260 F17 71,258 67,457 F21 77,757 72,476 F26 80,825 75,544 F31 87,356 82,075 0 Forecast+ Kitimat Forecast In the Reference Forecast, LNG loads beyond Kitimat (including supporting pipelines) are treated as discrete scenarios. The LNG loads in the first 4 years of the forecast are construction loads in Kitimat. The first phase of Kitimat LNG is assumed to be in service Q4, 2015 (F2016). 6

7 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 GW.h TOTAL INTEGRATED GROSS REQUIREMENTS WITH RATE IMPACTS BEFORE DSM (WITHOUT LNG) FORECAST VS 2010 FORECAST 85,000 80,000 75,000 Forecast (GWh) Forecast With Rates Before DSM 2010 Forecast (GWh) Less 2010 (GWh) Less 2010 (%) 70,000 F12 56,803 59,385 (2,582) -4.3% 65,000 F13 59,260 61,283 (2,023) -3.3% 60,000 55,000 F17 F21 F26 67,457 68,070 (613) -0.9% 72,476 70,651 1, % 75,544 76,136 (592) -0.8% 50,000 F31 82,075 81, % Forecast 2010 Forecast Total Integrated Requirements = Total Gross Requirements minus Non-Integrated Area (NIA) Short term: Forecast lower due to lower expected sales in all load categories Medium term: higher due to deferred mine shutdowns Long term: higher, due to stronger General sales No adjustments made in 2010 Forecast to align base years for DSM savings realized in F. With alignment, the 2010 Forecast would drop approximately 500 GWh per year. 7

8 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 GW.h GENERAL SALES WITH RATE IMPACTS BEFORE DSM FORECAST VS FORECAST 27,000 25,000 23,000 21,000 19,000 Forecast (GWh) Forecast With Rates Before DSM 2010 Forecast (GWh) Less 2010 (GWh) Less 2010 (%) F12 18,393 18,900 (507) -2.7% F13 19,011 19,238 (227) -1.2% F17 20,689 20, % F21 22,160 21, % 17,000 15,000 F26 23,778 23, % F31 26,162 24,804 1, % Forecast 2010 Forecast This is a summation of the Commercial and Industrial General Sales categories 8

9 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 GW.h RESIDENTIAL SALES WITH RATE IMPACTS BEFORE DSM FORECAST VS FORECAST 28,000 26,000 24,000 22,000 Forecast With Rates Before DSM Forecast (GWh) 2010 Forecast (GWh) Less 2010 (GWh) Less 2010 (%) 20,000 18,000 16,000 14,000 12,000 10,000 F12 18,199 18, % F13 18,652 19, % F17 20,089 20, % F21 21,766 22, % F26 24,080 24, % F31 26,613 26, % Forecast 2010 Forecast Drivers of forecast: use per account times the number of accounts. Number of accounts forecast is lower than last year s due to lower housing starts projections. In the near term (F12-14), the current housing start projections are on average roughly 1,000 units (-4%) lower than the previous forecast. In addition, last year s forecast of account growth was lower than anticipated. This lower starting point combined with the near term lower housing starts projection has put downward pressure on the account growth over the long term. Residential sales were relatively flat on a weather adjusted basis between F10 and F11, therefore the starting point of this years forecast is lower than in The growth in population is somewhat higher, while the person income remains stable relative to previous forecast. In the long term, use per account reflects a balance between generally stronger economic drivers and higher end use penetration. Penetration in Other end uses, including secondary refrigeration, electric dryer, TV/home entertainment, clothes washer and cooking are higher than the previous forecast. Offsetting this is increased efficiencies due to the assumed enactment of efficiency standards and codes (prior to BC-based DSM). 9

10 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 GW.h COMMERCIAL GENERAL SALES WITH RATE IMPACTS BEFORE DSM FORECAST VS FORECAST 22,000 20,000 18,000 16,000 14,000 12,000 Forecast With Rates Before DSM Forecast (GWh) 2010 Forecast (GWh) Less 2010 (GWh) Less 2010 (%) F12 14,551 14, % F13 14,892 14, % F17 16,107 15, % F21 17,378 16, % F26 18,869 18, % 10,000 F31 21,085 20,021 1, % Forecast 2010 Forecast Commercial General is 80 percent of the total General Service sales Drivers of the forecast include commercial end-use efficiencies and projections of retail sales, employment and commercial output. In the medium to long term, the forecast is higher due to lower end-use equipment efficiency projections from the US Energy Information Administration. Heating and cooling efficiencies show the largest change, while other end-use efficiencies are somewhat improved. 10

11 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 MW TOTAL INTEGRATED PEAK WITH RATE IMPACTS BEFORE DSM (WITHOUT LNG) FORECAST VS FORECAST 16,000 15,000 14,000 13,000 12,000 11,000 10,000 F12 F13 F17 F21 F26 F31 Forecast With Rates Before DSM Forecast (MW) 2010 Forecast (MW) Less 2010 (MW) Less 2010 (%) 10,651 11,063 (412) -3.7% 11,026 11,324 (297) -2.6% 12,389 12, % 13,053 12, % 13,891 13, % 14,945 14,959 (15) -0.1% Forecast 2010 Forecast In the near-term, distribution peak is reduced with a lower account projection. In addition, near-term oil and gas and wood sector sales are lower. Therefore, both residential and general growth in the peak is lower relative to last year. In the medium term, due to mine closure deferrals, the transmission peak demand is above last year, consistent with energy forecast trends. In the long term, peak forecast is close to the 2010 forecast as the long term energy forecast is in line with the 2010 projection. No adjustments made in 2010 Forecast to align base years for DSM savings realized in F. With alignment, the 2010 Forecast would drop approximately 80 MW. 11

12 BACKUP SLIDES MARKET FORECAST REVIEW

13 MARKET/GHG SCENARIOS D A B E C 13

14 Henry Hub gas prieces (2010$/MMBTU) 2010 GAS PRICES (REVIEW) $14 $12 $10 $8 $6 $4 $2 $ Historical 2010 Low Price Scenario 2008 Low Gas 2008 Mid Gas 2008/10 High Gas 2010 Mid Gas 14

15 Real 2010 $/short ton 2010 GHG PRICES (REVIEW) $200 $180 $160 $140 $120 $100 $80 $60 $40 $20 $ Scenario A Scenario B Scenario C Scenario D Scenario E 15

16 ELECTRICITY PRICE INPUTS Electricity Price Inputs BCH Scenario # A B C D E GHG Price Level: Mid GHG Mid GHG Low GHG HighGHG No GHG Gov Actor National Reg/Nat Reg/Nat Regional Regional Load Growth High Mid Low High Low Gas Price Level: High Mid Low Mid Low Gas Price Source CEC Case 2 Ventyx Fall B&V Update Ventyx Fall Black & Veatch Gas Price Vintage Database Source CEC Case 2 Ventyx Spring CEC Case 5B+ Ventyx Spring CEC Case 5B+ Database Vintage B&V = Black and Veatch BRP = Base Resource Plan CEC = California Energy Commission 16

17 Electricity Price (Real 2010 USD/MWh) 2010 ELECTRICITY FORECAST Dec 2010 MidC Electricity Price Forecasts (Real 2010 US/MWh) Low Electricity (Low GHG) C Mid Electricity (High GHG) D High Electricity (Mid GHG) A Low Electricity (No GHG) E Mid Electricity (Mid GHG) B Year Electricity Market Real or Nominal $ Currency 17

18 SUMMARY Scenario Name Price Range Key Factors C Low Gas/electricity prices ~ $36/MWh with Low GHG GHG prices increases electricity prices Low Gas price forecast decreases due to shale gas E ~ $32/MWh Zero GHGprice forecast removes all GHG price uplift in the electricity Low Gas/electricity prices with No GHG price forecast. Gas same as Scenario C B Mid Gas/electricity prices $50-70/MWh Lower gas prices due to shale gas which puts a downward pressure with Mid GHG on the electricity prices Mid GHG price forecast uplifts electricity prices about $10-15/MWh higher (from to 2031) than the 2008 forecast. D Mid Gas/electricity prices with High GHG $65-95/MWh Same gas assumptions as the Mid Gas Mid GHG scenario (Scenario B) High GHG forecast uplifts the electricity prices about $20-30/MWh higher (from to 2031) than the 2008 forecast. A High Gas/electricity prices $70-110/MWh Same Gas forecast from 2008 LTAP with Mid GHG Mid GHG price forecast uplifts electricity prices about $10-15/MWh higher (from to 2031) than the 2008 forecast. 18

19 BACKUP SLIDES EXPORT

20 TRANSMISSION TO MARKET RECAP CONSIDERATIONS FROM LAST YEAR: To facilitate type 2 export, new transmission capacity to market is needed and is on critical path To maintain options for access to markets pending resolution of uncertainties, B.C. may need to continue to pursue and preserve options for additional transmission capacity BC Hydro was a sponsor of the Canada to Northern California (CNC) transmission project (going from Selkirk substation near Castlegar in SE B.C. to U.S. market) UPDATE: Given results of competitiveness study, BCH and its partners have abandoned the proposed CNC project 20

21 COMPETIVENESS STUDY REC Market Size Competitiveness under the 5 Market Scenario (A, B, C, D, E) Competiveness sensitivities for Scenario B: BC Hydro shaped product No PTC and ACP after 2016 No PTC and ACP after 2016 with a BC Hydro Shaped product RE Premium = (Levelized Cost of Energy + Transmission + Losses) (Energy Value + Capacity Value) 21

22 REC MARKET SIZE The SBX1-2 limitations are as follows: 1. Renewable resources directly connected, or dynamically transferred, to a California balancing authority without substitution from another energy source (minimum of 50% by 2013, 65% by 2016, 75% by 2020) 2. Firmed and shaped energy scheduled into a California balancing authority 3. Any eligible renewable energy not meeting the requirements of the first two categories including unbundled renewable energy credits (maximum of 25% by 2013, 15% by 2016, 10% by 2020) CPUC 33% RPS by 2020 High Growth Scenario Baseline Scenario Flat Growth Scenario Total RPS Demand (33%) 101, , ,600 86,500 SBX1-2 (25% Limit on Firming/Shaping) 1 16,600 23,200 18,500 12,800 SBX1-2 (10% Limit on Firming/Shaping) Incremental Market Potential (After WECC Study supply) 2 54,200 80,800 62,100 39,000 Incremental Market Potential (after IOU Contracts supply) 3 46,700 73,200 54,500 31,500 Note: 1500 MW shaped 60% capacity factor is about 7900 GWh. 22

23 Cost ($/MWh) COST COMPARISON 250 Ilistrative Comparison of BC Shapped Product vs. Wyoming Wind Delivered to California in Gap Filled by REC Value Gap Filled by REC Value BC Shape Product Cost BC Shape Product Value Wyoming Wind Cost Wyoming Wind Value LCOE Shape Internal Tran Tran. REC PTC Cap Value Energy Value Note: Gap is larger in BC vs. Wyoming 23

24 MARKET COMPETITIVENESS A B C & E D 24

25 Capacity (MW) SENSITIVITY 1: SHAPED PRODUCT Export Shaped Profile: preferential profile to get rid of excess spring/early summer runoff and meet high demand in summer from biggest potential market buyer 1,600 1,400 1,200 1, January February March April May June July August September October November December Month 25

26 SENSITIVITIES ON SCENARIO B 2017 BC supply cost comparison: SC B Sensitivity 1 Sensitivity 2 Sensitivity 3 (1&2) Base Shaping Only No PTC/ACP Shaping and No PTC/ATC Rec Premium need in 2017 $86/MWh $70/MWh $86/MWh $70/MWh REC Value in 2017 (CA) $30/MWh $30/MWh $68/MWh $68/MWh In Money for $56/MWh -$40/MWh -$18/MWh -$2/MWh Shaping benefits: 1. Capacity value in US increases to $14 from $4/MWh (-10) 2. Transmission cost decrease by about $10/MWh (-10) 3. LCOE cost increases by $4/MWh (wind integration adder) (+4) Net decrease $16/MWh (-$10-$10+$4) Sc B REC Prices No PTC/ACP REC Prices 26

27 RELEVANT CEA OBJECTIVES To reduce GHG emissions Relevant CEA Objective To encourage economic development and the creation and retention of jobs To maximize the value of BC s generation and transmission assets To be a net exporter of electricity 27

28 BACKUP SLIDES FORT NESLON

29 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 29

30 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 30

31 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 31

32 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 32

33 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. 33

34 BACKUP SLIDES SITE C

35 SITE C SMALL GAP ENERGY 35

36 SITE C MID GAP ENERGY 36

37 SITE C LARGE GAP ENERGY 37

38 SITE C SMALL GAP CAPACITY 38

39 SITE C MID GAP CAPACITY 39

40 SITE C LARGE GAP CAPACITY 40