Generation and Transmission Resource Cost Update 2019

1. Generation and Transmission Resource Cost Update 2019 Prepared for WECC June 30, 2019

2. Contents • Background, approach, and sources • Transmission resource capital cost update • B&V cost framework and recent inflation metrics • Benchmarking vs. estimated Tx project costs • Generation resource capital cost update • In-depth review of resources with rapidly declining costs: • Comparison of costs across public sources for solar PV, wind, Li-ion battery storage • Benchmarking vs. recent public PPA prices and RFP bids • Recommended cost updates for all other resources and comparison vs. prior cost reports for WECC • Levelized Cost Calculator inputs and assumptions • Levelized cost model overview • FO&M and financing cost assumptions over time • State-by-state adjustments for tax rates, labor costs, etc. • Example LCOE outputs from model

3. Background • 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 • This effort allowed WECC to quantify relative scenario costs on a basis reflecting their actual prospective costs to ratepayers by combining variable and fixed costs • E3 has updated these capital cost assumptions several times to capture major changes in technology costs (e.g. solar PV) and ensure continued accuracy • Most recent update: 2016/2017 Fixed Cost (E3 Levelized Cost Tool) Total Cost Fuel and Variable Costs = +

4. Approach • In preparation for its upcoming 20-year study plan, WECC has asked E3 to provide guidance on resource cost to use in that study • These capital costs will serve as an input to the 20-year study’s LTPT, allowing for the development of robust scenarios through cost minimization • Capital costs will serve as inputs to pro forma model (“Levelized Cost Calculator”) that applies standard lifetime, financing, and O&M assumptions to calculate levelized costs of each resource • This efforts builds on similar work performed in late 2016–early 2017 20-Year Study INPUTS MODELS STUDY RESULTS Long-Term Planning Tools (Capital Expansion Optimization) Twenty-Year Capital Expansion Plan Gen Capital Costs SCDT Generation Portfolio Tx Capital Costs NXT Transmission Topology Other Constraints

5. Capital costs versus levelized costs • Resource costs are typically quoted in either upfront capital costs ($/kW) or levelized costs ($/MWh) that are indicative of likely PPA prices for renewables • Levelized costs include several other cost factors and assumptions beyond the project’s upfront capital cost • Financing costs: cost of capital, financing lifetime, tax rates and incentives • Operating costs: fixed and variable O&M of plant operations (“opex”), including fuel • Performance assumptions: amount of energy generation over which fixed costs are spread, i.e. average capacity factor, is a major driver of LCOE • E3’s pro forma is a discounted cash flow model that calculates levelized costs of energy ($/MWh) or capacity ($/kW-yr) under typical project financing structures Levelized costs Capital costs Pro forma financial model for project cash flows Financing costs Operating costs Performance

6. Defining a capital cost reference point Average Wind Speed • Resource costs vary significantly from project to project due to a variety of local and project-specific factors • Local climate: wind speed, solar irradiance, temperature • Local terrain: greenfield vs. brownfield, flat vs. hilly, forested vs. desert • Local development costs: labor, permitting, taxes, interconnection • Project-specific: offtaker risk and financing costs, developer economies of scale, etc. • These factors explain the wide range of reported costs that E3 has observed • In this 2019 capital cost report, E3 has identified a reference cost for each technology associated with an average project in WECC • The Capital Cost Calculator incorporates state-specific cost assumptions that reflect differences in labor costs, wind resource quality, and local tax rates Forest Cover High-Voltage Transmission

7. Sources of resource cost data E3 forms its resource cost estimates by reviewing a wide range of public sources including national lab studies, industry analyst reports, and IRPs from utilities within WECC, including: • NREL • Annual Technology Baseline 2018 • US Solar PV System Cost. Benchmark: Q1 2018 • 2017 Cost of Wind Energy Review • 2018 US Utility-Scale PV Plus-Energy Storage System Costs Benchmark • LBNL • Tracking the Sun 2018 • 2017 Wind Technologies Market Report • Lazard • Levelized Cost of Energy Analysis v12.0 • Levelized Cost of Storage Analysis v4.0 • IRENA • Renewable Power Generation Costs in 2017 • Electricity Storage Costs in 2017 • APS – 2017 IRP • Avista – 2017 IRP • Idaho Power Company – 2017 IRP • Pacificorp – 2017 IRP Update • Puget Sound Energy – 2017 IRP

8. Cost benchmarking vs. recent PPAs • After reviewing public sources of resource cost data, E3 benchmarks reported capital costs versus recent project prices to ensure its assumptions reflect the latest market trends • Public sources often rely on historical data 1-3 years old and may be outdated by the time they are published • Market prices reflect actual transactable costs for new or future projects • PPA benchmarking was performed for resources with greatest cost uncertainty due to rapid cost declines: solar, wind, and battery storage • Because PPA prices are quoted as levelized costs, E3 has calculated the implied capital costs from different PPA prices using standard opex and financing assumptions • For solar and wind, benchmarking is straightforward, as capital costs are the primary driver of total levelized costs (O&M costs are minimal) • Capital and financing is approximately 70% of wind cost and 90% of solar cost • Storage costs are more comparable on a levelized fixed-cost basis for several reasons, thus are benchmarked to PPAs by that metric

9. Cost vintaging and forecast methodology • For consistency, all cost data points are reported in real 2018$ and indexed to year of commercial operation date as best possible • National lab and industry analyst reports are mix of retrospective and prospective • IRPs and PPAs quote cost for near-term procurement, COD 1-2 years in future • Past E3 cost studies have used learning curve methodology to estimate future cost declines for renewable technologies • Learning curve approach is suitable for macro analysis of technology costs driven by single component (e.g. PV modules), but difficult to apply to soft costs and other factors (global supply chain and policy incentives) • E3 proposes using NREL ATB’s low, mid, and constant forecast scenarios as sensitivities in place of single cost forecast in this study NREL Historical price IRPs Forecast price PPAs Market price 2018 2020 2040 2016

10. Transmission Resource Cost Update

11. Transmission cost update approach • Build off existing B&V TEPPC cost calculator while benchmarking vs. external sources • 2014 Transmission Capacity Cost Calculator spreadsheet and report • Maintain same cost factors for terrain, technology types • Check inputs/outputs vs. RETI and other public Tx planning sources • Update 2014 costs to revised 2018 figures using following inputs: • Inflation multipliers on commodity prices of raw materials and industrial construction costs: Bureau of Labor Statistics (BLS) • CPI inflation for generic project admin costs: BLS • Right of way costs per acre: Bureau of Land Management (BLM) Linear Right of Way Schedule • Check cost assumptions vs. other public studies, planning reports, and new or proposed transmission projects

12. BLM Right-of-Way (ROW) cost updates • The BLM publishes zonal schedules of ROW rent and corresponding annual adjustments • Released once every 10 years • Latest update was released in 2016 • Zonal designations across the U.S. are made on a county level basis based on census data and can change with each release • B&V Transmission Cost Calculator has been updated with the 2018 rent schedule

13. Inflation updates to B&V Tx costs • Black & Veatch estimated generic inflators for Tx and substation costs of 1.5% from 2012 to 2013 and 2.0% from 2013 to 2014 • E3 used inflation data for the primary components of Tx capital costs (materials, labor, and general overhead) to update calculator for 2018 • Refined update for full 2012 to 2018 period, including re-estimate of 2012 to 2014 • Approach increases transmission resource costs by 10.5% in nominal terms since 2012, equivalent to 1.7% annual inflation • Real cost increase of 1.3% above US-CPI inflation from 2012 to 2018

14. Inflation indices underlying forecasts show relatively consistent trend Price Indices Used for Inflation Benchmarks Metals prices have been volatile, declining in 2015-2016 before increasing again in 2017-2018

15. Annual inflation of B&V Tx costs from 2012 to 2018 • Commodity cost indices for aluminum and steel drive recent uptick in Tx costs since 2016 after slight decline from 2014 to 2016 • All-in capital costs for Tx are estimated to have increased 10.5% in nominal terms since 2012 study, or 1.3% in real terms Calculated Capital Cost per Mile for 230 kV Single Circuit Line (Nominal $) Calculated Capital Cost per Mile for 230 kV Single Circuit Line (Real 2018 $)

16. Benchmarking vs. actual Tx projects • Benchmarking source: EEI’s “2016 Transmission Projects: At a Glance” • Approximate project costs and high-level summaries of major transmission projects completed in 2015 or expected to be completed within next 4 years • E3 updated cost calculator benchmarked to within 5%-10% of EEI’s 2016 reported costs for three sample transmission projects modeled

17. Tx benchmarking assumptions Input assumptions to E3 updated B&V Tx cost calculator

18. Tx cost update summary • Despite volatile commodity costs, all-in Tx capital costs have not changed significantly in real terms since 2012, increasing just 1.3% • E3 has updated the 2012 B&V Tx cost calculator with the latest inflation factors and it appears to benchmark well to the reported or estimated costs of a small sampling of recent Tx projects • E3 has also corrected a small formula error in the original B&V Tx cost calculator and will provide an updated version to WECC

19. Generation Resource Cost Update

20. Approach, resources considered, and changes from prior studies • E3 first surveyed recent reports on costs of new resources • National lab studies, utility IRPs, industry analyst reports • All technologies assessed in prior cost studies were included in this review • Next, E3 and WECC selected core technologies for closer study • Resources that were studied in the past and are no longer economically competitive were filtered out (e.g. single-axis tracking solar is now more economic than fixed-tilt solar and is employed on all new grid-scale projects in WECC, thus fixed-tilt was removed from study) • E3 performed additional research and cost benchmarking for core technologies with rapidly evolving cost profiles • Benchmarking of public capital cost estimates versus implied capital costs from PPA prices in recent WECC-area RFPs • Examination of research reports with future cost forecasts

21. Specific resources studied • Gas • CT: Aero/Frame • CCGT: Wet/Dry, Conventional/Advanced, with and without CCS • Reciprocating Engine • Other renewables • Geothermal: Binary/Flash, Standard/Enhanced • Small Hydro • Biomass/Biogas • Solar Thermal • Other thermal • Combined Heat and Power (CHP) • Coal: PC without CCS and IGCC with CCS • Nuclear: Large • Nuclear: Small modular • Solar PV • Grid-scale – tracking, ground-mounted PV • Wind • Onshore and offshore (fixed-base and floating) • Further variations in interconnection, capital cost associated with wind quality, etc. to be handled in more detail in next phase • Energy Storage • Lithium-ion battery storage • Utility-scale, with and without paired solar • Costs broken out by capacity (kW) and energy (kWh) • Flow battery storage • Pumped hydro storage • Compressed air energy storage (CAES) • Distributed energy resources (DERs) • Residential solar – fixed tilt, rooftop PV • Commercial solar – fixed tilt, rooftop PV • Lithium-ion battery storage – BTM • Costs broken out by capacity (kW) and energy (kWh)

22. Solar

23. Utility-scale tracking solar Recommended Capital Cost, Real 2018$ Capital Cost Estimate by Source

24. Utility-scale solar PV cost benchmarking PPAs and levelization assumptions • Many recent solar PV projects with public PPA prices available • E3 estimated implied capital costs with FO&M and financing costs based on 2018 NREL ATB • FO&M of ~$11/kW-yr from NREL ATB • WACC of 7.2% based on NREL ATB methodology + E3 cost of capital update • E3 assumed project capacity factors and PPA escalation terms based on publicly available data or E3 best estimates if not disclosed in PPA

25. Utility-scale solar PV cost benchmarking results show wide range, accurate midpoint • Implied capital costs from benchmark PPAs show a wide spread, likely due to sensitivity to financing, O&M, and capacity factor assumptions • Average PPA benchmarked price of $935/kW-dc is between NREL “Low” and “Mid” case forecasts of $886 to $1,003/kW-dc in 2020 • E3 recommended cost of $1,100/kW-dc in 2018 is close to NREL Mid case and suggests further cost decline of ~15% by 2020 is already priced into new PPAs being signed today

26. Solar PV capital cost forecasts • Three capital cost trajectories are projected • Low, Mid, and Constant (no cost reductions beyond 2021) • Based on the NREL 2018 Annual Technology Baseline • E3 recommended cost for 2018 and PPA benchmarking for 2020 suggest that NREL Mid cost case is accurate baseline forecast • Low-cost trajectory may provide a useful sensitivity Utility-Scale Solar PV Capital Cost Forecast PPA benchmarking implied 2020 costs E3 2018 recommended cost

27. Solar PV, preliminary LCOEs 2018 Levelized Cost Estimates – Mid Scenario • LCOE for solar PV depends on both capital cost and a number of other factors • Financing cost • O&M costs • ITC • Operating lifetime • Capacity factor • E3 assumes that several cost factors will evolve in the future • ITC step-up • Declining capital costs • Declining O&M costs Solar PV Levelized Cost Forecast Scenarios

28. Wind

29. Onshore wind Recommended Capital Cost, Real 2018$ Capital Cost Estimate by Source • Significant variance in wind costs by source likely reflects regional differences in wind quality and installation and interconnection costs

30. Onshore wind cost benchmarking • Very few recent PPA prices available for wind projects in WECC • E3 estimated implied capital costs using two sets of assumptions with high and low FO&M and financing costs based on NREL scenarios • FO&M of ~$11/kW-yr from NREL ATB • WACC of 7.2% based on NREL ATB methodology + E3 cost of capital update • E3 assumed project capacity factors and PPA escalation terms based on publicly available data or E3 best estimates if not disclosed in PPA

31. Onshore wind cost benchmarking results show same wide range, accurate midpoint • Implied capital costs from benchmark PPAs show a wide spread, due primarily to sensitivity to financing cost assumptions • Average PPA benchmarked price of $1,550/kW is aligned reasonably well with NREL “Mid” case forecast of $1,622/kW in 2020 • E3 recommended cost of $1,650/kW in 2018 is close to NREL Mid case and suggests further cost decline of ~4% by 2020 is already priced into new PPAs being signed today

32. Onshore Wind capital cost forecasts • Three capital cost trajectories are projected • Low, Mid, and Constant (no cost change beyond 2017) • Based on the NREL 2018 Annual Technology Baseline NREL 2018 ATB: Onshore Wind Capital Cost Forecast E3 2018 recommended cost PPA benchmarking implied 2020 costs

33. Onshore Wind, preliminary LCOEs 2018 Levelized Cost Estimates- Mid Scenario • LCOE for onshore wind depends on both capital cost and a number of other factors • Financing cost • O&M costs • PTC • Operating lifetime • Capacity factor • E3 assumes that several cost factors will evolve in the future • PTC step-up and expiration • Declining capital costs • Declining O&M costs Onshore Wind Levelized Cost Forecast Scenarios Preliminary

34. Offshore wind Recommended Capital Cost, Real 2018$ Capital Cost Estimate by Source • Floating base offshore wind added to represent potential future west coast projects. Fixed base offshore wind is not viable in most of WECC given seafloor depth off WA/OR/CA

35. Offshore Wind capital cost forecasts • Three capital cost trajectories are projected • Low, Mid, and Constant (no cost change beyond 2017) • Based on the NREL 2018 Annual Technology Baseline Floating Base Offshore Wind – TRG 10 Capital Cost Forecast

36. Floating Offshore Wind, preliminary LCOEs • LCOE for onshore wind depends on both capital cost and a number of other factors • Financing cost • O&M costs • ITC • Operating lifetime • Capacity factor • E3 assumes that several cost factors will evolve in the future • ITC step-up and expiration • Declining capital costs • Declining O&M costs Onshore Wind Levelized Cost Forecast Scenarios Lack of large-scale floating offshore wind projects to date adds significant uncertainty to cost forecasts

37. Energy Storage

38. Lithium-ion battery cost breakdown by power capacity and duration Utility-scale 4-hr Battery Cost by Component • Battery costs vary significantly by system specifications • For modeling purposes, costs are commonly broken into two categories • Costs that scale with power (“capacity”), quoted in $/kW • Costs that scale with energy (“duration”), quoted in $/kWh • Battery modules are the largest and best understood component of system cost and the one that scales most linearly with duration • Each kWh of duration adds around $300 today, but is declining rapidly • Fixed capacity cost including inverter and interconnection varies significantly by report • For storage paired with solar, these costs may be minimal Utility-scale Battery Cost by Duration

39. Lithium-ion battery storage Recommended Capital Cost Capital Cost Estimate by Source

40. Recent RFP bids for solar+storage • To benchmark against recent storage PPA prices, E3 examined solar+storage prices in three recent RFPs • TEP - 2017 • Under $45/MWh for 100 MW / 30 MW / 4-hr NextEra solar+storage project in May 2017 • Xcel - 2017 • No explicit guidance on how solar+storage contracts should be structured. Appears they bid as bundled PPAs for generation and capacity, presumably with utility dispatch • Standalone storage: $11,300/MW-mo median (4- to 10-hr durations) • Hybrid bids with storage add $2.90/MWh (wind median) or $6.50/MWh (solar median) • Preferred portfolio, approved by CPUC, included 275 MW of storage • All three storage projects selected are solar hybrid plants • NV Energy - 2018 • Explicit instruction for hybrid projects: at least 100 MW RE, 25 MW storage, 4-hr duration • Hybrids bid two separate contracts: one for solar generation ($/MWh) and one for capacity ($/MW-mo) • Storage contracts at $6,110-$7,755/MW-mo • Solar capacity, battery capacity as % of solar, and battery duration were all near minimum in winning bids • NextEra: Dodge Flats 200 MW/50 MW/4-hr • NextEra: Fish Springs 100 MW/25 MW/4-hr • Cypress Creek: 101 MW/25 MW/4-hr Crescent Valley project (Battle Mountain Solar)

41. Declining capital costs and capture of ITC drive low storage bid prices when paired with solar • NextEra claims storage adds a premium of $15/MWh for solar projects completed in 2017-2018 • Approximate capacity price of $160-$175/kW-yr for storage assuming typical sizing and solar capacity factor • Typically 4-hr storage at 25% of solar capacity (e.g. 100 MW solar plant, 25 MW / 100 MWh storage) • In recent RFPs, this premium has fallen to $6-$7/MWh for projects with COD in 2021-22 • Capacity price of $73 to $94/kW-yr for hybrid projects with unbundled storage prices (NV Energy) • NextEra projects storage premium will fall to $5/MWh by mid-2020s, or under $60/kW-yr with typical sizing ratio Levelized cost of storage when paired with solar – E3 vs NextEra Gross CONE in 2018 $/kW-yr Current hybrid storage bids reflect aggressive price decline assumptions, capture of the ITC, and other cost savings from pairing with solar such as reduced interconnection costs Result? Discount of 25% to 40% versus standalone storage levelized costs Recent NV Energy RFP winners NextEra forecast

42. Modeling solar plus storage dispatch • Hybrid solar-plus-storage projects have been contracted under a variety of arrangements regarding the role of scheduling coordinator • Different contract arrangements may favor use for shifting solar vs. providing ancillary services such as frequency regulation or spinning reserves • To qualify for the ITC, storage must be charged from solar for the first five years of operation • Finally, DC vs. AC coupled storage may offer different amounts of flexibility in dispatch depending on the given project’s interconnection capacity • E3 recommends modeling hybrid storage as a dispatchable resource independent from solar, but restricted to charging from co-located solar during the first five years of project life if possible

43. Flow battery storage Recommended Capital Cost Capital Cost Estimate by Source • Flow battery estimated costs have declined nearly as rapidly as Li-ion, but limited commercial experience adds significant uncertainty. No major utility-scale PPAs have been signed for flow batteries in the US to date

44. Distributed Energy Resources

45. DER overview • In addition to grid-scale resources, E3 has provided cost estimates for distributed energy resources typically located behind the meter (BTM) • DERs are a less commoditized type of resource due to site-specific cost factors that vary greatly from project to project • For example, rooftop solar costs will vary from building to building depending upon roof size and accessibility, mounting options, etc. • This variability makes DER costs difficult to generalize • Given their smaller scale and higher soft costs associated with customer acquisition, installation, overhead, etc. DERs are typically more expensive than utility-scale resources of the same technology • However, DERs also present different value streams, such as retail bill savings and potential for T&D deferral

46. BTM residential solar (rooftop) Recommended Capital Cost, Real 2018$ Capital Cost Estimate by Source

47. BTM commercial solar (rooftop) Recommended Capital Cost, Real 2018$ Capital Cost Estimate by Source

48. BTM Li-ion battery storage • Two-hour duration is most typical for BTM storage today, which is primarily used for demand charge clipping • As with solar, BTM storage is significantly more expensive than utility-scale storage due to smaller scale, higher soft costs, etc. • Likewise, BTM storage is generally assumed to be non-dispatchable for system modeling purposes, though some DR programs (e.g. CA DRAM) have contracted with BTM storage • E3 did not find any precedents for BTM storage paired with solar qualifying for the ITC, thus BTM storage is modeled as a single use case

49. Gas

50. Gas- and oil-fired generation Recommended Capital Cost • Cost reports reviewed by E3 show minimal changes since prior study • Gas CCGT with CCS was added as a category that is represented by a cost premium over Advanced CCGT plant costs without CCS • CCGTs with CCS will be subject to different operational assumptions, such as increased heat rates (lower efficiency), decreased flexibility (no daily cycling), and variable costs that incorporate the value of tax credits for CCS