2011 IRP Public Input Meeting. December 15, Pacific Power Rocky Mountain Power PacifiCorp Energy

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1 2011 IRP Public Input Meeting December 15, 2010 Pacific Power Rocky Mountain Power PacifiCorp Energy

2 Agenda 2011 IRP schedule update and next steps Resource portfolio development status Supply Side Resources update Final capacity/energy load & resource balances Capacity expansion model set-up Stochastic model parameter update Proposed preferred portfolio selection approach 2

3 IRP Schedule Update and Next Steps Pete Warnken Pacific Power Rocky Mountain Power PacifiCorp Energy 3

4 Recent Milestones Distributed Loss of Load Study on November 18, 2010 PacifiCorp selected a 13% planning reserve margin for portfolio development Distributed October 5 IRP public input meeting report and dispersed generation resource attribute workbook Distributed updated Portfolio Development Case List on November 18, 2010 Completed analysis of sustained hydro peaking capability will distribute associated report in December

5 Remaining 2011 IRP Schedule Dec Jan Feb March IRP Public Meetings* General Public Meetings 15 X X Wind integration study follow-up Model tutorial To Be Determined To Be Determined Status report/issue resolution conference calls To Be Determined * Specific meeting dates will be determined after considering state regulatory calendars, participant availability, and meeting preparation requirements. IRP Development Schedule Hydro capacity accounting methodology assessment Stochastic parameter update (loads, CO2 price) System Optimizer portfolio development, sensitivity cases PaR stochastic simulations and results reporting Preferred portfolio analysis and selection Action Plan development/contingency planning Market reliance and hedging analysis Stochastic analysis of illiquid market scenario Western market assessment Hedging IRP report preparation, 1st draft Public review of draft IRP report (30 days) IRP report preparation, final draft Commission filing, 3/31/2010 X X X 5

6 Next Steps Next public meeting, to be scheduled for mid- January 2011, will focus on: Portfolio development and stochastic results Preferred portfolio selection Portfolio sensitivity cases Status update on market reliance and hedging analysis Model tutorial February 2011? Presentation development activities starting in January 2010 Working with Ventyx on non-disclosure agreement 6

7 Supply Side Resource Update Jim Lacey Pacific Power Rocky Mountain Power PacifiCorp Energy 7

8 East Side Resources Location / Timing Plant Details Outage Information Costs Supply Side Resources DRAFT (IRP PIM December 15, 2010) Description Installation Location Earliest In- Service Date Annual Average Heat Rate HHV (BTU/kWh) Average Design Capacity Plant Life MW in Years EAST SIDE RESOURCE OPTIONS Maint. Outage Rate Equivalent Forced Outage Rate (EFOR) Low Estimate Capital Cost ($/kw) High Estimate Capital Cost ($/kw ) Var. O&M ($/MWh) Fixed O&M ($/kw-yr) Coal Utah PC without Carbon Capture & Sequestration Utah , % 4.0% $2,923 $3,692 $0.96 $38.80 Utah PC with Carbon Capture & Sequestration Utah , % 5.0% $5,285 $6,676 $6.71 $66.07 Utah IGCC with Carbon Capture & Sequestration Utah , % 8.0% $5,117 $6,463 $11.28 $53.24 Wyoming PC without Carbon Capture & Sequestration Wyoming , % 4.0% $3,310 $4,181 $1.27 $36.00 Wyoming PC with Carbon Capture & Sequestration Wyoming , % 5.0% $5,985 $7,559 $7.26 $61.37 Wyoming IGCC with Carbon Capture & Sequestration Wyoming , % 8.0% $5,794 $7,318 $13.52 $58.00 Existing PC with Carbon Capture & Sequestration (500 MW) Utah/Wyo 2025 (139) 20 14, % 5.0% $1,314 $1,660 $6.71 $66.07 Natural Gas (4500 feet) Utility Cogeneration Utah , % 8.0% $4,449 $5,619 $23.29 $1.86 Fuel Cell - Large Utah , % 3.0% $1,668 $2,106 $0.03 $8.40 SCCT Aero Utah , % 2.6% $1,047 $1,322 $5.63 $9.95 Intercooled Aero SCCT Utah , % 2.9% $1,229 $1,553 $3.93 $7.01 Internal Combustion Engines Utah , % 1.0% $1,204 $1,521 $5.50 $6.49 SCCT Frame (2 Frame "F") Utah , % 2.7% $1,037 $1,310 $7.16 $5.41 CCCT (Wet "F" 1x1) Utah , % 2.7% $1,253 $1,583 $2.94 $13.04 CCCT Duct Firing (Wet "F" 1x1) Utah , % 2.7% $511 $646 $0.39 $0.00 CCCT (Wet "F" 2x1) Utah , % 2.7% $1,014 $1,280 $2.98 $8.19 CCCT Duct Firing (Wet "F" 2x1) Utah , % 2.7% $511 $646 $0.55 $0.00 CCCT (Dry "F" 2x1) Utah , % 2.7% $1,134 $1,433 $3.35 $9.69 CCCT Duct Firing (Dry "F" 2x1) Utah , % 2.7% $571 $721 $0.11 $0.00 CCCT (Wet "G" 1x1) Utah , % 2.7% $1,185 $1,497 $4.56 $6.75 CCCT Duct Firing (Wet "G" 1x1) Utah , % 2.7% $502 $634 $0.36 $0.00 CCCT Advanced (Wet) Utah , % 2.7% $1,308 $1,653 $4.56 $6.75 CCCT Advanced Duct Firing (Wet) Utah , % 2.7% $642 $811 $0.36 $0.00 Other - Renewables Wyoming Wind (35% CF) Wyoming n/a n/a n/a $2,015 $2,686 $0.00 $31.43 Utah Wind (30% CF) Utah n/a n/a n/a $2,015 $2,686 $0.00 $31.43 East Side Geothermal Utah n/a 5.0% 5.0% $4,063 $5,132 $5.94 $ Greenfield Geothermal Utah / Idaho n/a 5.0% 5.0% $5,826 $7,359 $5.94 $ Battery Storage All , % 5.0% $1,924 $2,431 $10.00 $1.00 Pumped Storage Nevada , % 5.0% $1,636 $2,067 $4.30 $4.30 Compressed Air Energy Storage (CAES) Wyoming , % 2.7% $1,241 $1,568 $5.50 $3.80 Nuclear Utah , , % 7.7% $5,041 $6,368 $1.63 $ Solar (PV) - 19% CF Utah n/a n/a n/a $3,982 $5,030 $0.00 $59.50 Solar Concentrating (natural gas backup) - 25% solar Utah n/a n/a n/a $3,831 $4,839 $0.00 $ Solar Concentrating (thermal storage) - 30% solar Utah n/a n/a n/a $4,293 $5,423 $0.00 $

9 West Side Resources Location / Timing Plant Details Outage Information Costs Supply Side Resources DRAFT (IRP PIM December 15, 2010) Description Installation Location Earliest In- Service Date Average Capacity MW Design Plant Life in Years Annual Average Heat Rate HHV (BTU/kWh) Maint. Outage Rate Equivalent Forced Outage Rate (EFOR) Low Estimate Capital Cost ($/kw) High Estimate Capital Cost ($/kw ) Var. O&M ($/MWh) Fixed O&M ($/kw-yr) WEST SIDE RESOURCE OPTIONS West Side Options (1500 feet) Natural Gas Utility Cogeneration Northwest , % 8.00% $4,044 $5,109 $21.17 $1.69 SCCT Aero Northwest , % 2.60% $952 $1,202 $5.12 $9.04 Intercooled Aero SCCT Northwest , % 2.90% $1,117 $1,412 $3.57 $6.37 Internal Combustion Engines Northwest , % 1.00% $1,094 $1,383 $5.50 $6.49 SCCT Frame (2 Frame "F") Northwest , % 2.70% $943 $1,191 $6.51 $4.92 CCCT (Wet "F" 1x1) Northwest , % 2.70% $1,139 $1,439 $2.67 $11.86 CCCT Duct Firing (Wet "F" 1x1) Northwest , % 2.70% $465 $587 $0.36 $0.00 CCCT (Wet "F" 2x1) Northwest , % 2.70% $1,029 $1,300 $2.67 $7.21 CCCT Duct Firing (Wet "F" 2x1) Northwest , % 2.70% $519 $656 $0.36 $0.00 CCCT (Wet "G" 1x1) Northwest , % 2.70% $1,077 $1,361 $4.14 $6.13 CCCT Duct Firing (Wet "G" 1x1) Northwest , % 2.70% $456 $576 $0.33 $0.00 CCCT Advanced (Wet) Northwest , % 2.70% $1,189 $1,503 $4.14 $6.13 CCCT Advanced Duct Firing (Wet) Northwest , % 2.70% $584 $737 $0.33 $0.00 Other - Renewables Oregon / Washington Wind (35% CF) Northwest n/a n/a 5.00% $2,145 $2,860 $0.00 $31.43 Greenfield Geothermal Northwest n/a 5.00% 5.00% $5,826 $7,359 $5.94 $ Solar (PV) - 19% CF Northwest n/a n/a n/a $3,982 $5,030 0 $59.50 West Side Options at ISO Conditions (Sea Level) Natural Gas Utility Cogeneration Northwest , % 8.00% $3,868 $4,886 $21.17 $1.69 SCCT Aero Northwest , % 2.60% $910 $1,150 $4.89 $8.65 Intercooled Aero SCCT Northwest , % 2.90% $1,069 $1,350 $3.42 $6.10 Internal Combustion Engines Northwest , % 1.00% $1,047 $1,322 $5.50 $6.49 SCCT Frame (2 Frame "F") Northwest , % 2.70% $902 $1,139 $6.23 $4.70 CCCT (Wet "F" 1x1) Northwest , % 2.70% $1,090 $1,377 $2.56 $11.34 CCCT Duct Firing (Wet "F" 1x1) Northwest , % 2.70% $445 $562 $0.34 $0.00 CCCT (Wet "F" 2x1) Northwest , % 2.70% $984 $1,243 $2.56 $6.89 CCCT Duct Firing (Wet "F" 2x1) Northwest , % 2.70% $497 $627 $0.34 $0.00 CCCT (Wet "G" 1x1) Northwest , % 2.70% $1,030 $1,302 $3.96 $5.87 CCCT Duct Firing (Wet "G" 1x1) Northwest , % 2.70% $436 $551 $0.31 $0.00 CCCT Advanced (Wet) Northwest , % 2.70% $1,138 $1,437 $3.96 $5.87 CCCT Advanced Duct Firing (Wet) Northwest , % 2.70% $558 $705 $0.31 $0.00 Other - Renewables Oregon / Washington Wind (28% CF) Northwest n/a n/a 5.00% $2,145 $2,860 $0.00 $31.43 Biomass Northwest , % 4.00% $3,334 $4,211 $0.96 $38.80 Nuclear Northwest , , % 7.70% $5,041 $6,368 $1.63 $ Hydrokinetic (Wave) - 21% CF Northwest n/a n/a n/a $5,539 $6,997 $ Solar (PV) - 19% CF Northwest n/a n/a n/a $3,982 $5,030 $0.00 $

10 Final Load and Resource Balances Brian Osborn Pacific Power Rocky Mountain Power PacifiCorp Energy 10

11 Load and Resource Balance Changes Load and resource balance development based on a 13% planning reserve margin (Loss of Load study conclusion) Change to Idaho irrigation dispatchable load control: peak contribution reduced by 139 MW for all years Reflects revised expectation of load reductions available at the time of dispatch Acknowledges system stability issues at certain substations arising from growth in the irrigator network Incorporates updated hydro energy forecast Incorporates new east-side wind PURPA Qualifying Facilities Pioneer wind I / II, and Power County Wind Park North / South 11

12 Megawatts Initial Capacity Load and Resource Balance (Final) 16,000 14, Resource Gap: 1,601 MW 2020 Resource Gap: 3,852 MW Planning Reserves 12,000 10,000 West Existing Resources 8,000 6,000 East Existing Resources 4,000 2,000 Obligation + 13% Planning Reserves - System Obligation

13 Initial Capacity L&R Balance (Final), Line Item Details Calendar Year East Thermal 6,019 6,026 6,028 6,028 6,028 6,046 6,046 6,046 6,046 6,046 Hydro Class 1 DSM Renewable Purchase Qualifying Facilities Interruptible Transfers East Existing Resources 8,553 8,290 8,174 7,916 7,768 7,949 7,997 7,749 7,811 7,778 Load 7,112 7,344 7,566 7,805 8,009 8,201 8,377 8,544 8,712 8,896 Sale , East Obligation 7,870 8,341 8,611 8,550 8,754 8,946 9,036 9,203 9,371 9,555 East Reserves ,032 1,063 1,090 1,117 1,129 1,151 1,173 1,196 East Obligation + Reserves 8,799 9,324 9,643 9,613 9,844 10,063 10,165 10,354 10,544 10,752 East Position (247) (1,034) (1,469) (1,698) (2,076) (2,114) (2,168) (2,605) (2,732) (2,974) East Reserve Margin 10% 1% (4%) (7%) (11%) (11%) (11%) (15%) (16%) (18%) West Thermal 2,552 2,552 2,556 2,556 2,556 2,556 2,541 2,550 2,550 2,550 Hydro 1, Class 1 DSM Renewable Purchase Qualifying Facilities Transfers (809) (452) (416) (457) (311) (499) (547) (300) (360) (330) West Existing Resources 3,915 3,512 3,636 3,489 3,631 3,447 3,415 3,684 3,584 3,414 Load 3,266 3,374 3,395 3,448 3,491 3,541 3,584 3,650 3,666 3,713 Sale West Obligation 3,556 3,632 3,653 3,706 3,649 3,649 3,692 3,758 3,774 3,821 Planning reserves Non-owned reserves West Reserves West Obligation + Reserves 3,913 4,079 4,092 4,165 4,101 4,100 4,145 4,218 4,234 4,293 West Position 2 (567) (456) (676) (470) (653) (730) (534) (650) (879) West Reserve Margin 13% (3%) 1% (5%) 0% (5%) (7%) (1%) (4%) (10%) System Total Resources 12,468 11,802 11,810 11,404 11,399 11,397 11,412 11,433 11,395 11,192 System Obligation 11,425 11,973 12,264 12,256 12,403 12,595 12,728 12,961 13,145 13,376 Reserves 1,287 1,430 1,470 1,522 1,542 1,569 1,582 1,611 1,633 1,668 Obligation + 13% Planning Reserves 12,712 13,403 13,735 13,778 13,945 14,164 14,310 14,572 14,777 15,044 System Position (244) (1,601) (1,925) (2,373) (2,546) (2,767) (2,898) (3,139) (3,383) (3,852) Reserve Margin 11% (0%) (3%) (6%) (8%) (9%) (10%) (11%) (13%) (16%) 13

14 Initial L&R Balance: Line Item Differences, Final less October 5 th Presentation Calendar Year East Thermal (1) (1) (1) (1) (1) (1) Hydro (3) (3) (3) (3) (3) Class 1 DSM (139) (139) (139) (139) (139) (139) (139) (139) (139) (139) Renewable Purchase Qualifying Facilities Interruptible Transfers (59) 47 (30) 147 (200) (45) 278 (285) 31 (256) East Existing Resources (197) (57) (114) 63 (285) (134) 189 (374) (58) (345) Load (1) Sale East Obligation (1) Planning reserves Non-owned reserves East Reserves East Obligation + Reserves East Position (281) (145) (206) (30) (380) (232) 92 (474) (159) (449) East Reserve Margin (3%) (1%) (1%) 1% (3%) (2%) 2% (4%) (1%) (4%) West Thermal (8) (20) (20) (32) (32) Hydro (32) (19) (18) (19) (23) (23) (23) (20) (23) (25) Class 1 DSM Renewable Purchase Qualifying Facilities Transfers 61 (48) 27 (150) (278) 284 (31) 254 West Existing Resources 29 (67) 12 (165) (321) 243 (86) 197 Load (1) (1) Sale West Obligation (1) (1) Planning reserves Non-owned reserves West Reserves West Obligation + Reserves West Position 3 (102) (22) (201) 148 (21) (357) 208 (121) 160 West Reserve Margin 1% (2%) 0% (4%) 5% 0% (9%) 7% (2%) 5% System Total Resources (168) (124) (102) (102) (104) (119) (132) (130) (144) (148) System Obligation (1) Reserves Obligation + Planning Reserves System Position (278) (247) (228) (231) (232) (253) (265) (265) (280) (289) Reserve Margin (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%) (1%) 14

15 MWa System Energy Position On Peak / Off Peak 3,000 System On-Peak / Off-Peak hours 2,500 2,000 1,500 1, (500) (1,000) (1,500) (2,000) System Off-Peak System On-Peak (2,500) 15

16 System Optimizer Model Settings Pacific Power Rocky Mountain Power PacifiCorp Energy 16

17 Topology Changes West side: Added four new bubbles and associated links to capture constraints relieved by Hemingway Boardman Bethel ( Cascade Crossing ) transmission project option Wind generation bubbles: Added to Oregon, Utah, and Wyoming to enable assignment of applicable incremental transmission investment costs to wind selected by the model 17

18 2011 IRP Topology Changes More Detailed West 2011 IRP West only Chehalis Yakima Mid-C $ Walla Walla BPA Portland / N. Coast Hermiston Wind Willamette Valley / Central Coast Bethel Chehalis 2008 IRP Update Yakima COB $ South-Central OR / N. California Borah Mid-C $ BPA Walla Walla Hermisto n Wind Bubbles: Used for selection of wind resources requiring incremental transmission investment beyond the base Energy Gateway footprint. West Main Borah COB $ 18

19 Front Office Transaction Limits East-side FOT limits are still under review; PacifiCorp will distribute a table that includes the east-side limits subsequent to this meeting. The table below covers only the west-side Market Hub / Proxy FOT Product 2011 IRP 2008 IRP Update West Main / 3 rd Quarter 6x16 50 MW 50 MW Mid-Columbia / Flat 7x24 and 3 rd Quarter 6x MW MW with 10% price premium 400 MW COB / Flat 7x24 and 3 rd Quarter 6x MW 400 MW For market hubs where both flat 7x24 and 3 rd quarter 6x16 products are available, only one product type can be selected in a given year 19

20 Wind Resource Representation New cost step approach to modeling wind resources Geographic zones based on Western Renewable Energy Zones (WREZ) initiative Phase 1 Capital costs based on a third party model have three cost steps that vary by wind resource quality Incremental transmission costs are the full portion of the Energy Gateway component necessary for the resource Three new wind-only bubbles: West, linked to BPA bubble ( Washington South, Oregon Northeast WREZ zones) Utah, linked to Utah South bubble ( Utah West WREZ zone) Wyoming, linked to Aeolus bubble (Wyoming East Central, East, South WREZ zones) Walla Walla and Yakima each able to accommodate 100 MW of new wind without new incremental transmission 20

21 Wind Resource Representation (continued) System Optimizer annual constraints 200 MW annual wind resource limit except for hard cap cases 500 MW annual limit for hard cap core cases Available dates 2012: Washington South (100 MW in Yakima without new transmission) and Oregon Northeast (100 MW in Yakima without new transmission) 2016: Idaho East, Oregon (Northeast, West), Utah West, Washington South 2018: Wyoming (East, East-central, South, North) Other considerations Existing wind energy shapes were used Resources modeled in 100 MW blocks; System Optimizer model can pick partial amounts Resources modeled with and without production tax credit (PTC) No update to capacity contribution 21

22 WREZ Initiative Hub Map WREZ Map is found on page 5-5, figure 5-2 of the October 2009 Phase 1 report at 22

23 Out-year Resource Representation All resource types, subject to earliest in-service year constraints, are available throughout the 20- year simulation period In addition, growth resources are available after 2020 for additional system capacity balancing flexibility Similar to front office transactions, except that they are not transacted at market hubs System Optimizer can select a flat or third-quarter heavy load hour energy pattern priced at forward market prices appropriate for each load area 23

24 Stochastic Modeling Parameter Update Connie Clonch Pacific Power Rocky Mountain Power PacifiCorp Energy 24

25 Stochastic Modeling Parameter Update. Only the load stochastic parameters have been updated for the 2011 IRP Load stochastics Short-term load parameters updated in PaR Seasonal volatilities Mean reversions Seasonal correlations Long-term load volatilities set to zero to avoid highly unlikely load excursions in the out years Load Stochastics estimated by Transmission Area to Match PaR load topology. Prior IRP load stochastics were estimated by state Volatilities follow prior IRP estimates with Washington / West Main the most volatile and Wyoming the least 25

26 Stochastic Modeling Parameter Update Capturing CO 2 Price Uncertainty In the PaR model Three CO 2 price scenarios per portfolio No CO 2 price Medium: $19/ton * in 2015, exceeding $51/ton by 2036 Low-High: $12/ton * in 2015, exceeding $136/ton by 2036 CO 2 / natural gas price relationship enforced Using IPM, scenario-specific natural gas curves are produced as a function of CO 2 price Resultant gas curves are then coupled with corresponding CO 2 price curves in PaR * Nominal Dollars IPM is a North American production simulation model that optimizes electricity production costs under a given environmental paradigm. 26

27 Stochastic Modeling Parameter Update Potential Future Enhancements to Investigate Explore Incorporating CO 2 stochastics directly into PaR Lack of observable US market data limits ability to estimate CO 2 parameters European market data for CO 2 are available but have limited relevancy Test CO 2 parameters have been calculated using European and IPM - generated price movements. However, parameters need to be further refined Expand Stochastic Correlations to Include CO 2 / Coal Prices 27

28 Proposed Preferred Portfolio Selection Approach Pete Warnken Pacific Power Rocky Mountain Power PacifiCorp Energy 28

29 Upper-tail Mean PVRR, Billion $ Preferred Portfolio Selection Approach Step 1 Initial Screening Use stochastic average PVRR vs. stochastic uppertail PVRR scatter-plot diagrams for the three CO 2 price scenarios to identify efficient frontier portfolios; limit selection to no more than seven portfolios for further screening Sample Scatter Plot - 15 Portfolios Stochastic Mean PVRR, Billion $ Portfolio 14 Portfolio 9 Portfolio 8 Portfolio 7 Portfolio 6 Portfolio 11 Portfolio 15 Portfolio 2 Portfolio 4 Portfolio 1 Portfolio 3 Portfolio 5 Portfolio 10 Portfolio 12 Portfolio 13 29

30 Preferred Portfolio Selection Approach Step 2 Final Screening Evaluate relative performance of efficient frontier portfolios based on the following measures, listed in the order of importance Risk-adjusted PVRR Stochastic mean PVRR plus the expected value of the 95 th percentile PVRR 10-year customer rate impact Year by year and cumulative percentage rate change by 2020, relative to 2011 revenue requirement forecast Supply reliability average annual Energy Not Served (ENS) Carbon dioxide emissions (generator plus net market transaction contribution) 30

31 Preferred Portfolio Selection Approach Other portfolio performance measures will also be reported Ave. annual probability of ENS events for July exceeding 25 GWh Production cost standard deviation (alternate cost risk measure) Upper-tail ENS Scenario risk assessment using System Optimizer Determine range of deterministic PVRRs resulting from fixing portfolios in System Optimizer under varying gas/electricity and CO 2 price assumptions PacifiCorp will explain its preferred portfolio selection on the basis of the above measures and analysis, but does not intend to use numerical weights for portfolio ranking purposes 31