1. WECC Capital Cost Recommendations June 4, 2012 Arne Olson, Partner Nick Schlag, Consultant Gabe Kwok, Associate

2. History In 2009, E3 provided WECC with recommendations for capital costs of new electric generation technologies to use in its 10-year study cycles Prior to this effort, the relative costs of WECC’s study cases could only be compared on a variable-cost basis (using PROMOD results) This effort provided WECC with a framework to quantify relative scenario costs on a basis reflecting their actual prospective costs to ratepayers by combining variable & fixed costs In 2011, WECC asked E3 to review the capital costs to ensure continued accuracy Due to the continued evolution of solar PV technologies, E3 lowered its estimates of photovoltaic capital costs 2 Total Cost Variable Costs (PROMOD) Fixed Costs (E3 Capital Cost Tool) =+

3. Background In the midst of its 10- and 20-year study plans, WECC has asked E3 to provide guidance on resource cost and performance to use in those studies These capital costs will serve as inputs to the 10- and 20-year studies: Including capital costs in the 10-year study cycles enables comparisons of total costs between scenarios Capital costs will serve as an input to the 20-year study’s LTPT, allowing for the development of robust scenarios through cost minimization 3

4. Updates E3 presented its initial recommendations to stakeholders on May 15, 2012 Based on stakeholder feedback and comments, E3 has reviewed its recommendations for wind and solar costs Minor revisions were made to several of the present day solar PV costs to better capture expected cost differentials between system types and sizes E3 has revised some of the data inputs used to forecast of cost declines for solar PV and solar thermal technologies: Forecasts of installed capacity for solar PV and solar thermal have been revised to account for near-term projections of global market dynamics Learning rate for solar thermal has been adjusted to reflect greater potential for technological improvements than originally anticipated

5. Modeling Framework 5 Capital Costs (E3 Capital Cost Tool) 2022 Study 2032 Study Resource Performance (NREL) Resource Performance (WREZ) PROMOD LTPT/NXT Resource Portfolio Capital Costs (E3 Capital Cost Tool) Total Scenario Costs Resource Portfolio Total Scenario Cost

6. Scope of Updates E3’s Capital Cost Tool considers a broad range of potential new generation technologies The scope for E3’s update is divided into two phases: Near term (integrated in this year’s study cycle): update costs for wind and solar technologies Long term (integrated into subsequent study cycles): review costs for all technologies This division prioritizes updating those costs that are most likely to have changed given the limited time before the start of this study cycle 6 TechnologySubtypes Biomass BiogasLandfill, Other Gas CT Gas CCGT CHPSmall, Large CoalSteam, IGCC Nuclear HydroSmall, Large, Upgrade Solar PVFixed Tilt, Tracking Solar ThermalNo Storage, 6hrs Storage WindOnshore Technologies in E3’s Capital Cost Tool

7. Technologies Covered E3’s current update encompasses the following technologies—an expanded set compared to the original Capital Cost Tool 7 Solar PV Large Utility (20 MW +) Fixed Tilt Tracking Solar ThermalWind No Storage 6hrs Storage Onshore Small Utility (1-20 MW) Fixed Tilt Tracking Rooftop Commercial Residential Modeled in Prior WECC Studies New to This Year’s Study Cycle New technology characterizations are needed to represent increasing specificity of photovoltaic resources modeled by WECC, especially in the High DG/DSM Case

8. Approach 1.Determine the cost to install a power plant today (2012) Given limited time, focus is on wind and solar technologies Prior recommendations for other technologies are carried forward 2.Use learning curves to forecast declines in technology capital costs over the next two decades 3.Determine the appropriate applicability of federal tax incentives for renewable technologies over the 10- and 20-year study cycles 4.Develop and apply updated regional multipliers to capture geographic variations in resource costs around the WECC 8

9. Notes on Resource Performance With the limited time available before the commencement of the present study cycles, E3’s present scope of work focuses on updating resource costs WECC staff is developing assumptions on resource performance for use in the current study cycle Over a longer timeframe, E3 will work with WECC to ensure that cost and performance assumptions are consistent with one another and represent our best expectations of future development patterns 9

10. Present Day Wind and Solar Costs

11. Present-Day Costs To derive estimates of present-day wind and solar costs, E3 has reviewed a wide range of recent studies and publications For developing technologies, precise capital costs are a moving target that are difficult to pin down A review of literature provides both… …outdated forecasts of what costs would be today; and …retrospective analysis of actual costs from several years ago E3 has used this information to develop its best estimates of costs to install wind and solar plants in 2012 All costs are expressed in 2010 dollars 11

12. Historical Trends in Solar PV Costs Installed solar PV costs continue to decrease: Average U.S. behind-the-meter PV data from 1998-2010 (Left) California Solar Initiative (CSI) data from 2009-2011 (right) CSI is focused on rooftop PV Less data available for utility-scale PV and solar thermal 12 Tracking the Sun IV: An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998 to 2010 California Solar Statistics

13. Current Trends in Solar PV Prices 13 Market data and experience have shown substantial movement in PV prices over the past two years, suggesting we are on a relatively steep portion of the “learning curve.” This makes identifying current prices a challenging exercise. Source: Technical Potential for Local Distributed Photovoltaics in California

14. Historical Trends in Wind Costs Average 2010 installed cost was similar to 2009 14 2010 Wind Technologies Market Report (June 2011)

15. Data Sources 15 AuthorReport Name Publication Date Installation Year Historical or Forward CPUC33% RPS Calculator UpdateMay 20122012Forward E3/CPUC Technical Potential for Local Distributed Photovoltaics in California Mar. 20122009 – 2020Both B&V/NRELCost and Performance Data for Power Generation TechnologiesFeb. 20122010 - 2050Both NREL Residential, Commercial, and Utility-Scale Photovoltaic (PV) System Prices in the United States: Current Drivers and Cost- Reduction Opportunities Feb. 20122010Historical DOESunShot Vision StudyFeb. 20122010 – 2020Both CSICalifornia Solar StatisticsJan. 20122009 - 2011Historical LBNL Tracking the Sun IV: An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998 to 2010 Sept. 20112010Historical LBNL2010 Wind Technologies ReportJune 20112010Historical LazardLevelized Cost of Energy Analysis – Version 5.0June 20112012Forward SandiaPower Tower Technology Roadmap and Cost Reduction PlanApril 20112013Forward EIA Updated Capital Cost Estimates for Electricity Generation PlantsUpdated Capital Cost Estimates for Electricity Generation Plants (for AEO2011) Nov. 20102011Forward NWPCCSixth Northwest Conservation and Electric Power PlanFeb. 20102010Forward CEC Comparative Costs of California Central Station Electricity Generation Jan. 20102010Forward

16. Solar PV – Fixed Utility (20 MW+) TEPPC 2011 Current Update 16 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes RETI 2B$3,230201020Thin Film LTPP$3,4002010 EIA$3,9632011180 TEPPC 2011$3,4002012100 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes B&V/NREL$2,3962015100 NREL$3,8002010187.5 CPUC$2,3802012150California Recommended$2,550$1172012100 Capital costs for solar PV technologies shown here are expressed relative to the DC nameplate rating. To convert to an AC capital cost, these costs should be multiplied by 1.18 (assuming DC-AC conversion of 85%).

17. Solar PV – Tracking Utility (20 MW+) TEPPC 2011 Current Update 17 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes NWPCC$7,294200825Crystalline RETI 2B$3,825201020Crystalline LTPP$3,9952010 CEC$4,626201025 TEPPC 2011$3,9952012100 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes B&V/NREL$2,6642015100 NREL$4,4002010187.5 CPUC$2,8002012150California Recommended$2,800$1232012100 Capital costs shown relative to DC nameplate rating

18. Solar PV – Fixed Utility (1-20 MW) Technology has not been represented in past WECC modeling efforts 18 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes EIA$5,04220118.4 B&V/NREL$2,877 - $3,53820101 - 10 B&V/NREL$2,593 - $3,23320151 - 10 CPUC$2,590 - $2,73020125 - 20California Lazard$2,750201210Crystalline Recommende d $2,975$13520121 - 20 Capital costs shown relative to DC nameplate rating

19. Solar PV – Tracking Utility (1-20 MW) Technology has not been represented in past WECC modeling efforts 19 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes B&V/NREL$3,142 - $3,84420101 - 10 B&V/NREL$2,827 - $3,47720151 - 10 CPUC$3,32520121 - 5 Lazard$3,500201210Crystalline Recommende d $3,225$13820121 - 20 Capital costs shown relative to DC nameplate rating

20. Solar PV - Commercial Technology has not been represented in past WECC modeling efforts 20 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (kW) Notes LBNL$5,8002010100 – 500 NREL$4,5902010217 CSI$5,622201156California B&V/NREL$4,8702010100 B&V/NREL$3,9042015100 Recommended$5,000$2562012 Capital costs shown relative to DC nameplate rating

21. Solar PV - Residential Technology has not been represented in past WECC modeling efforts 21 Author Cost ($/kW DC ) Generic LCOE ($/MWh) Installation Vintage Size (kW) Notes LBNL$6,60020105 – 10 NREL$5,71020104.9 CSI$6,47220115.5California B&V/NREL$6,05020104 B&V/NREL$4,41320154 Recommended$6,000$3012012<10 Capital costs shown relative to DC nameplate rating

22. Solar Thermal – Without Storage TEPPC 2011 Current Update 22 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes NWPCC$4,7612008100Trough CEC COG$3,6872010250Trough; California RETI 2B$5,350 - $5,550Trough; California LTPP$5,300Trough; California EIA$4,7142011100Trough; Wet-cooled EIA$4,6922011100Tower; Wet-cooled TEPPC 2011$5,3502012 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes B&V/NREL$4,9922010200Trough B&V/NREL$4,7992015200Trough DOE SunShot$4,5002010100Trough; Wet-cooled Lazard$5,000 - $5,4002012250Trough Recommended$4,900$1872012

23. Solar Thermal – With Storage TEPPC 2011 Current Update 23 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes RETI 2B$7,650 - $7,850California LTPP$7,500California TEPPC 2011$7,500 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes B&V/NREL$7,1782010200Trough, 6hrs B&V/NREL$6,9142015200Trough, 6hrs DOE SunShot$7,8702015250Trough, 6hrs Lazard$6,300 - $6,5002012250Trough, 3hrs B&V/NREL$7,1582010200Tower, 6hrs Sandia$7,4272013100Tower, 9 hrs DOE SunShot$5,9402015100Tower, 6 hrs Recommended$7,100$1992012Generic, 6 hrs

24. Wind TEPPC 2011 Current Update 24 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes NWPCC$2,1272008100NW RETI 2B$2,150 - $2,600CA LTPP$2,350CA EIA$2,4382011100 TEPPC 2011$2,350 Author Cost ($/kW) Generic LCOE ($/MWh) Installation Vintage Size (MW) Notes CEC COG$2,023201050CA LBNL$2,1482009-2010US B&V/NREL$2,0132010 Lazard$1,300 - $1,9002012100 Recommended$2,000$632012

25. Recommended Resource Costs Technolog y Subtype DC Capital Cost ($/kW DC ) AC Capital Cost ($/kW) Generic AC Capacity Factor (%) Generic LCOE ($/MWh) Solar PV Fixed (>20 MW)$2,550$3,00027%$117 Tracking (>20 MW)$2,800$3,30029%$123 Fixed (1-20 MW)$2,975$3,50027%$135 Tracking (1-20MW)$3,225$3,80029%$138 Comm Roof$5,000$5,90023%$256 Res Roof$6,000$7,10023%$301 Solar Thermal No Storagen/a$4,90028%$187 6hr storagen/a$7,10036%$199 WindOnshoren/a$2,00037%$63 25 Cost Summary (2010 $) Capital costs for solar PV are converted from DC to AC by multiplying by 1.18 (assuming DC-AC conversion of 85%).

26. Comparison of Updated Costs to Prior Recommendations WECC 20112012 Update TechnologySubtype Generic AC Capacity Factor (%) AC Capital Cost ($/kW) Generic LCOE ($/MWh) AC Capital Cost ($/kW) Generic LCOE ($/MWh) Solar PV Fixed (>20 MW)27%$4,000$150$3,000$117 Tracking (>20 MW)29%$4,700$164$3,300$122 Fixed (1-20 MW)27%n/a $3,500$135 Tracking (1-20MW)29%n/a $3,800$138 Comm Roof23%n/a $5,900$256 Res Roof23%n/a $7,100$301 Solar Thermal No Storage28%$5,350$200$4,900$187 6hr storage36%$7,500$208$7,100$199 WindOnshore37%$2,350$75$2,000$63 26 Cost Summary (2010 $)

27. Forecasting Future Costs for Wind and Solar

28. Considerations in Forecasting Technology Cost Technology cost changes As nascent technologies become increasingly mature, they may experience cost declines as a result of learning by doing and increased scale of manufacturing Technology costs are sensitive to other factors as well: Trends in the costs of raw materials Relationship of supply and demand Tax credit expiration ITC for solar technologies is set to expire in 2017 PTC for wind expires in 2013; for other technologies in 2012

29. Learning curves describe an observed empirical relationship between the cumulative experience in the production of a good and the cost to produce it Increased experience leads to lower costs due to efficiency gains in the production process The functional form for the learning curve is empirically derived and does not have a direct theoretical foundation Learning Curve Theory The learning rate (LR) is used to describe the expected decrease in costs with a doubling of experience 29 The theory of learning curves in economics was formalized by Kenneth Arrow in 1962 in “The Economic Implications of Learning by Doing”. This empirical relationship has since been affirmed in a number of works that span many sectors of the economy.

30. Learning Curves and Solar PV Declines in solar PV module price have tracked the functional form of the learning curve with a learning rate of approximately 20% since 1976 30 Source: Global Overview on Grid-Parity Event Dynamics (Breyer and Gerlach) Past performance does not indicate future potential Recent cost reductions have not followed the longer-term trends of historical learning

31. Learning Curves and Solar PV Module costs represent only a fraction of solar PV system costs; total system costs have historically declined at a slightly lower learning rate (~17%) 31 Source: Navigant Consulting

32. Uncertainty in Future Costs 32 Past trends do not guarantee future declines, and other factors influence technology costs Optimistic Path Solar PV continues to reap benefits of a high learning rate Global installed capacity grows rapidly Pessimistic Path Today’s low prices caused by excess supply followed by a rebound as markets re-equilibrate Cost of raw materials rise Int’l markets saturate and US growth slows as the ITC expires

33. Uncertainty in Global Installed Capacity Future growth of solar PV can vary widely, as shown by the IEA’s 2010 Energy Technology Perspectives scenarios IEA BLUE, High Renewables: renewables serve 75% of load in 2050 IEA BLUE Map: global CO2 emissions reduced to half of 2005 levels IEA Baseline: business-as-usual; no new policies affect energy sector 33

34. Sensitivity of Learning Curves to Global Installations Forecast The choice of a forecast of future installations has a significant impact on anticipated future cost declines The impact of an additional MW of capacity declines as the cumulative installed capacity increases 34 Forecast declines based on a 10% learning rate

35. Near-Term Outlook for Solar PV E3 has reviewed additional predictions of trends in global installed capacity for solar PV The European Photovoltaic Industry Association’s Global Market Outlook predicts between 208 and 343 GW of solar PV by 2016 35 Policy Driven Scenario: continuation of support mechanisms (FiTs) and strong political favor for solar PV Moderate Scenario: pessimistic market behavior, reduced policy support for PV development

36. Forecasting Solar PV Global Installations Through 2032 Short-term market outlook is generally consistent with IEA’s long-term vision The average trajectory of the EPIA’s forecasts results in approximately 1,000 GW of solar globally by 2030 E3 uses the average of the EPIA-derived long-term forecasts to forecast cost reductions for solar PV 36

37. Solar PV Learning Rate Recommendation E3 recommends a learning rate of 10% for solar PV, which is applied to the entire capital cost (not just modules) No guarantee that historical rates (17%) will continue Learning rates for mature technologies (coal & gas) have decreased with technology maturation As balance-of-systems components begin to represent larger shares of system costs, learning rates are likely to decrease 37 Coupled with the EPIA-derived long- term PV forecast, this learning rate yields the following estimates of long- term cost reductions

38. Comparison of Recommended PV Costs to Other Sources 38

39. Forecasting Solar Thermal Global Installed Capacity by 2032 IEA’s BLUE Map Scenario includes 600 GW of solar thermal capacity by 2050 To reach this goal, solar thermal global installed capacity would have to reach approximately 200 GW by 2030 European Solar Thermal Electricity Association’s Solar Thermal Electricity 2025 anticipates a cumulative total between 60 and 100 GW by 2025—substantially less E3 has developed a forecast based on the ESTELA forecast that reflects lower anticipated near-term installations of solar thermal facilities Total global capacity installed by 2032 is forecast to be 51 GW 39 Aspirational Pessimistic

40. Solar Thermal Learning Recommendation Based on stakeholder feedback, a learning rate of 10% was selected for solar thermal Combined with the forecast of global installed capacity from the prior slide, this learning rate yields the following projection of solar thermal cost reductions: 40

41. Wind Learning Recommendation Wind is a much more mature technology than either solar PV or solar thermal, with a global installed capacity of close to 200 GW Estimates of learning rates for wind range from 0% - 15%; E3 has adopted a rate of 5% 41 In combination with IEA’s BLUE Map scenario (2,000 GW of wind by 2050), this assumption results in a 12% reduction in wind capital costs by 2032

42. Federal Tax Credit Landscape Current federal tax policy provides large incentives to wind and solar developers: Accelerated depreciation (5-yr MACRS for wind and solar) Investment tax credit (30% of capital costs for solar) Production tax credit ($22/MWh for wind) 42

43. Expiration of Federal Tax Credits Federal tax credits are scheduled to retire in the near future Investment tax credit reverts from 30% to 10% in 2017 Production tax credit ($22/MWh for wind) expires in 2013 PTC for other technologies expires in 2014 The 5-year MACRS, as part of the general tax code, is assumed to remain in place 43

44. Combined Impact of Tax Credit Expiration and Technology Learning Increased resource costs resulting from the expiration of tax credits are largely offset by technological progress over the next two decades 44

45. Recommended Resource Costs TechnologySubtype201220222032 Solar PV Fixed (>20 MW)$3,000$2,322$2,121 Tracking (>20 MW)$3,300$2,554$2,333 Fixed (1-20 MW)$3,500$2,709$2,475 Tracking (1-20MW)$3,800$2,941$2,687 Comm Roof$5,900$4,567$4,171 Res Roof$7,100$5,496$5,020 Solar Thermal No storage$4,900$3,455$2,992 6hr storage$7,100$5,007$4,336 WindOnshore$2,000$1,834$1,711 45 AC Capital Costs by Installation Year (2010 $/kW) Recommendations that have been modified since May 15 are highlighted in orange

46. Resulting LCOEs TechnologySubtype AC Capacity Factor (%) 201220222032 Solar PV Fixed (>20 MW)27%$117 $109 Tracking (>20 MW)29%$123$122$114 Fixed (1-20 MW)27%$135$134$124 Tracking (1-20MW)29%$138$137$127 Comm Roof23%$256$254$235 Res Roof23%$301$299$276 Solar Thermal No storage28%$187$172$153 6hr storage36%$199$182$161 WindOnshore37%$63$82$80 46 Levelized Cost of Energy by Installation Year (2010 $/MWh)

47. Average vs. Marginal

48. The cost to install one additional MW of solar in 2022 will not equal to the average cost of the solar resources installed between present day and 2022 A large fraction of the solar resources installed by 2022 will have been installed gradually over the next decade 48

49. Recommendations for Installed Cost Vintages To account for the many mitigating factors that will affect resource development over the, E3 recommends using the 2015 installed cost for resources installed in the first decade and the 2027 installed cost for resources installed in the second decade To simplify this analysis, E3 also recommends assuming that the PTC is extended through the same time horizon as the ITC, expiring in 2017 49 First Decade Most new resources (especially solar) will come online relatively soon to claim tax credits The choice of 2015 for “average” resource costing reflects this expectation Second Decade No resources can claim tax credits Year-by-year development of renewables is highly uncertain, so the midpoint of the range (2022-2032) is used as a basis for installed costs

50. Regional Multipliers

51. Regional Multiplier Methodology The original Capital Cost Tool included state- specific estimates of technology costs derived from “regional multipliers” Regional multiplier methodology captures geographical differences in costs of labor and materials As part of this update, E3 has explored several questions related to this subject: 1.With the release of an update to the Civil Works Construction Cost Index System, should the regional cost multipliers be updated? 2.What other factors besides construction cost contribute to geographic difference in resource cost and can easily be incorporated into E3’s capital cost tool? 51

52. Regional Multiplier Methodology E3 derives technology-specific regional multipliers based on: The relative proportions of equipment, material, and labor that constitute a plant’s costs The Civil Works Construction Cost Index System’s (CWCCIS) state adjustment factors The CWCCIS is a construction-based cost indexing system developed by the US Army Corps of Engineers State adjustment factors capture approximate geographic cost differences in generic construction projects Since equipment costs represent a larger share of costs in power plant construction than in other construction applications, E3 applies state adjustment factors only to the shares of a plant’s cost associated with materials and labor 52

53. Sample Comparison of Regional Multiplier Calculations 53 ABCDEF CWCCIS State Adjustment Factor Category Percent of Total Costs Percent Variable by Location Total Weight {=D x [B x E + (1-E)]} California1.21 Equipment70%0%0.700 Materials10%50%0.111 Labor20%100%0.242 Total100%1.053 Wyoming0.90 Equipment70%0%0.70 Materials10%50%0.095 Labor20%100%0.180 Total100%0.975 Example regional multiplier calculations, Gas CCGTs in California and Wyoming

54. CWCCIS Update The Army Corps of Engineers released an update to the CWCCIS in March 2011 E3’s prior work was based on CWCCIS from March 2008 54 Changes to state adjustment factors are minimal but are easy to incorporate into TEPPC pro-forma

55. Benchmarking Regional Adjustment Factors E3’s adjustment factors capture the same general regional trends as those used by EIA (created by RW Beck) 55

56. Other Factors Affecting Relative Geographic Costs State and local tax codes vary widely by location and that have important implications for plant costs The table below shows different tax policies for wind projects in WECC states and their resulting impact on project LCOEs, which range from $88 to $101/MWh 56 AZCACOIDMTNVNMORUTWAWY State Income Tax (%)7.0%8.8%4.6%7.6%6.8%7.6%7.9%5.0% Sales Tax (%)2.4%0.8%4.3%6.0%3.0%0.7%3.9%5.4% Property Tax (%)0.3%1.0%0.4%1.2%0.5%1.0%0.6%1.0%0.7% Gross Receipts Tax (%)3.0%6.5%0.5% Tax Credit ($/MWh)$10 $3.50 Excise Tax ($/MWh)$1 Generic Wind Cost ($/MWh)$88$96$94$96$94$96$91$92 $101$99 Source of information: Tax policies based on E3’s Wyoming Wind Energy Costing Model Generic wind cost calculated assuming capital cost of $2,000 and a capacity factor of 30%

57. Incorporating State Income Tax One significant variant in state-by-state tax codes that affects the cost of development is the state income tax Ranges from 0% (NV, WA and WY) to 9% (CA) Can be easily integrated into E3’s updated pro-forma In addition to an update of regional multipliers, E3 proposes to incorporate state-by-state income tax rates into the pro-forma to enhance the geographic differentiation of project costs 57