RESOURCE COST AND POTENTIAL 1. Background and Introduction Potential and costs were all updated in late 2013 by Black & Veatch Information from internal

RESOURCE COST AND POTENTIAL 1

Background and Introduction Potential and costs were all updated in late 2013 by Black & Veatch Information from internal sources, market data, and other literature (LBNL, DOE, CEC) When possible, previously-vetted information from other Black & Veatch stakeholder projects was used and updated: Renewable Energy Transmission Initiative (2008-2010) Western Renewable Energy Zones (2009, 2012-2013) SB1122 Biomass Feed-in Tariff (2013) NREL Renewable Electricity Futures (2010) 2

Approach General Methodology Capital Cost Updates Costs are all-in installed costs and include EPC + owners costs (soft costs) Costs include costs through the interconnection to the T&D system Costs are for 2013 projects cost forecast curves developed for all technologies as well Operation and Maintenance (O&M) Cost Updates O&M cost estimates include all other annual costs, including land lease, insurance, and property tax (exclusion to be updated) Resource potential and performance was updated for all technologies compared to the RETI assessment Major methodology changes made for wind and solar PV Small-scale bioenergy from SB 1122 analysis Minor updates to all other resources (Solar Thermal, Geothermal, Biomass) Full detail for the approach can be see in the PPT, RPS_CalcV6.0_ResourcePotentialandCost on the CPUC website 3

Summary of Changes to Solar PV Cost updated for systems from 1 to 20+ MW (ac rating) Fixed Tilt and Single Axis Tracking Black & Veatch assumes little appreciable economies-of-scale after 20 MW. Therefore a single estimate is provided for systems that size and larger. Smaller-scale rooftop systems also included (250 kWac) Higher performance systems assumed Increased dc to ac ratio, also known as inverter loading ratio (up to 1.4) Higher ac capacity factors Capital costs include a $200/kW allowance for interconnection costs (except for rooftop, where interconnection costs are assumed to be minor and included in the system costs) 4 While overall trend is decreasing solar PV costs, higher performance is achieved by increasing inverter loading ratio which increases capital cost

Solar PV Performance Significantly Higher than Previously Estimated (RETI 1B Max CF = 28%, now 35+%) 5 Fixed Tilt Tracking Capacity Factor (ac) 5

Solar PV Capital Costs 6

Planned Solar Cost Updates Costs continue to decline; down roughly 25% since the estimates were performed for v.6.0 Will use market data and Black & Veatch design data to refresh current costs and performance for v.6.1 Modify future cost curves and evaluate as part of sensitivity cases Source: LBNL 7

Wind Performance Most high capacity factor sites in California have been developed Black & Veatch re-assessed wind potential in California applying newer low wind speed turbines as appropriate Many new areas included, especially northern California 8 Similar approach as RETI

Results 9 Apply exclusions and project size limitations LCOE state- wind estimates NCF at identified utility scale project sites 9

Northern California Previously Identified CREZ (2008-2010) 10 Geothermal Wind

Northern California Current Potential Wind Projects 11 Previously Identified CREZ (2008-2010)

Capital Cost Assumptions BASE COSTS: Steeper terrain makes some areas more expensive to develop. Modifiers based on slope were used to account for terrain: Direct Costs calculated as: Base Turbine Costs + (Slope Multiplier)*(BOP/erection + Switchyard) Owners cost was assumed to be 15% of the direct costs 12 CategoryClass I, 80mClass II, 80mClass III, 100m Turbine ($/kW)9501,1001,250 BOP/erection ($/kW)400420475 Switchyard ($/kW)150 SlopeMultiplier Less than 4 percent1.00 Between 4 percent and 8 percent1.16 Between 8 percent and 16 percent1.22 Greater than 16 percent1.55

Wind and Other Resource Updates Wind costs down roughly 5 percent since the v.6.0 estimates were performed Will use market data and Black & Veatch design data to estimate current costs and performance Updates to biomass, geothermal, and solar thermal will largely reflect general escalation only Source: LBNL 13

Cost Sensitivities Cost inputs can be changed as desired in the calculator to test sensitivities Version 6.1 of calculator could have the functionality to more easily run alternatives if desired. Options include (1) scenarios, (2) sensitivities, and (3) Monte Carlo. 14

Out of State Resources Out-of-state resources may be competitive in certain instances All out-of-state of resource estimates from updated Western Renewable Energy Zones Project (WREZ) Wind Solar PV Solar Thermal Geothermal Hydro 15

Out of State Updates Calculator currently differentiates out of state resources by performance but not cost Plan to apply new analysis performed by Black & Veatch differentiating the performance, capital cost, O&M cost, and LCOE throughout the US in V6.1 Will not create new zone boundaries 16

17 SUPER CREZ IDENTIFICATION

Zone Identification From 2008-2010, Black & Veatch worked with stakeholders to identify Competitive Renewable Energy Zones (CREZ) as part of the Renewable Energy Transmission Initiative (RETI) These zones were subsequently used in various different processes by various stakeholders In 2013-2014, Black & Veatch reassessed renewable resources to address significant improvements in technology, particularly with wind and solar PV Resource availability much more widespread Many new wind resources in northern California Updated zone definitions are needed to reflect the updated resource assessment 18

Updated Renewable Resource Assessment Wind, Biomass, Geothermal, and Solar Thermal Project Locations Solar PV not shown, but is available across the state (see next slide) For wind, substantial shift north, into non- CREZ areas 19

Solar PV Resource (Tracking PV) Widespread and generally good quality throughout California Most of resource is outside previous CREZ boundaries 20

Principles For Updating Zone Boundaries New zones based on: Legacy 2010 CREZ to the extent possible Locations of ~150 projects which have been tagged to zones in the CPUCs 2012 RPS calculator Project Development Status Reports CEC Renewable Energy Action Team Expanded resource assessment (tried to not split newly identified projects into two zones) Transmission topology Geographic constraints County boundaries 21

Differences From Previous CREZs Previous CREZ identified the best resources for large scale transmission development considering technical, economic and environmental factors Very specific boundaries, sometimes capturing specific project boundaries and interconnection lines Purposefully made as small as possible (shrink-wrapped) to minimize perceived environmental footprint Current zones are intended to capture most of the resources in California regardless of relative economic or environmental considerations Not for siting or environmental assessment - used for categorization and assigning transmission upgrade cost More comprehensive coverage - puzzle pieces Boundaries less meaningful No particular advantage to being in a zone 22

Legacy CREZ (Westlands Area) 23

2012 Utility Contracts Tagged To CREZ 24

2012 Utility Contracts Tagged To CREZ 25

New Super CREZ 26

New Super CREZ Boundaries All of these zones correspond with a legacy zone name or a zone in the 2012 RPS calculator (Los Banos, Central Valley North) No new zones identified by B&V, except Sacramento River Valley Resources outsides zones summarized by county 27

Super CREZ Environmental Exclusions Intent of the calculator is to not prejudge permitting or provide opinion on preferred development location Only removed stakeholder-vetted lands where development is prohibited or practically impossible: RETI Category 1 WECC EDTF Category 4 Feinstein California Desert Protection Act Environmental ranking and scoring would be the next step to prioritize particular areas Future workshops will address incorporation of environmental ranking and consideration of further additional environmental screens Super CREZ resource potential incorporates environmental exclusions even though the boundaries are not drawn with this intent 28

2010 Monterey Area CREZ 29

Constraints, Resources and Infrastructure 30

New Monterey Area Renewable Resources 31

Monterey County Super CREZ 32

Super CREZ Transmission Super CREZ sizing and transmission Concern that expanded CREZs may in some cases be too inclusive and include areas with differing transmission conditions and costs Discussed issue with CAISO; follow up on this issue will be addressed in a wider discussion regarding process development for updates to the RPS Calculator Cost updates Will be working with CAISO to update both in-state and out-of-state transmission costs 33

TRANSMISSION COSTS 34

Transmission Cost in RPS Calculator The availability and cost of transmission are primary components in the calculation used to rank competing resources They reflect the cost to deliver new renewable generation to California loads The methodology of identifying available capacity and transmission costs in v.6.0 is generally the same as previous version, additional updates planned RPS Calculator Valuation Framework Levelized Cost of Energy Transmission Cost Capacity Value Energy Value Net Resource Cost Integration Cost* = + + + Curtailment Cost + 35

RPS Calculator in Transmission Planning RPS Calculator receives information from and provides information to CAISO transmission planning processes Transmission projects included in CAISO Transmission Planning Process (TPP) are recovered through the Transmission Access Charge (TAC) levied on all users of the transmission system TAC costs are passed on to ratepayers Generation projects accessing transmission lines in the TPP may avoid additional delivery network upgrade (DNU) costs Since the CAISO TPP is based on the CPUCs RPS Calculator portfolios, it is critical the overall process shown here works CAISO GIDAP Transmission Inputs Available Capacity [MW] Delivery Network Upgrade (DNU) Costs [$/kW-yr] RPS Calculator RPS Portfolios Commercial Projects [MW] Generic Projects [MW] CAISO TPP CPUC LTPP Iterative - informs next cycle and other processes 36

Summary of Planned Updates to Transmission Cost Transmission availability and cost estimates for all transmission upgrades will be updated in v.6.1 of the RPS Calculator to reflect all available CAISO study information Additional information on data sources provided in this presentation The CPUC is considering stakeholder process alignment to formalize a process for future transmission cost updates. Also identified major resource areas for which new transmission cost estimates may be needed (Sacramento River Valley) 37

Methodology Overview Transmission costs split in three categories Interconnection Cost Delivery Network Upgrades (minor and major upgrades) Out-of-state Transmission 38

Interconnection Cost Gen-tie line Substation New switching station New breaker position at existing station 39

Interconnection Unit Cost Source interconnection cost estimates based on the CAISO Participating Transmission Owner unit cost estimates. Costs vary depending on interconnecting utility. http://www.caiso.com/informed/Pages/StakeholderProcesses/Particip atingTransmissionOwnerPerUnitCosts.aspx http://www.caiso.com/informed/Pages/StakeholderProcesses/Particip atingTransmissionOwnerPerUnitCosts.aspx 40

RPS calculator applies IOU unit costs to calculate the total interconnection equipment costs (gen tie, line tap, bay expansion, etc.) for each project Two substation options based on project location: Project A is within reasonable gen-tie distance new breaker position at existing substation Project B is not within reasonable gen-tie distance, but can connect to the 115 kV line new switching station Project A 20 MW Project B 20 MW Sub A 115 kV Sub B 115 kV 115 kV Line Interconnection Cost Estimates 41

Interconnection Cost Updates Latest available version of unit costs from annual CAISO Stakeholder process will be implemented in Version 6.1 of the RPS Calculator. Additional environmental cost categories that are not considered could be implemented through the CAISOs annual process. 42

Delivery Network Upgrade (DNU) Costs DNU costs consist of minor and major upgrades Three categories: Available transmission capacity with no upgrades Available transmission capacity with minor upgrades Available transmission capacity with major upgrades Costs do not reflect any sunk costs (e.g., Tehachapi) 43

Delivery Network Upgrade (DNU) Cost Sources CAISO provides DNU costs in the RPS Calculator for a subset of Super CREZ based on the following two primary sources: Participating Transmission Owner cost estimates from Interconnection Studies Investor Owned Utility estimates for policy driven studies included in Transmission Planning Process (TPP) CAISO will provide stakeholders references to specific studies used to develop the DNU costs in the calculator In general, TPP studies are available on the CAISO website and interconnection studies can be accessed through the CAISO Market Participant Portal For transmission projects for which CAISO does not provide input, generic assumptions are used to calculate the cost of a new conceptual transmission project 44

Available transmission capacity in 2020 on existing transmission (no additional upgrades) Transmission Capacity (GW) Round Mountain Sacramento River Valley Tehachapi Kramer Riverside Imperial Eldorado Solano Carrizo Mountain Pass (GW) 3.8 GW 45

Available transmission capacity in 2020 on existing transmission (no additional upgrades) Minor upgrades Tehachapi: $0.1B Westlands : $1.5B Transmission Capacity (GW) Round Mountain Sacramento River Valley Kramer Riverside Imperial Eldorado Solano Carrizo Mountain Pass (GW) Westlands Tehachapi 46

Available transmission capacity in 2020 on existing transmission (no additional upgrades) Minor upgrades Tehachapi: $0.1B Westlands : $1.5B Major upgrades Kramer: $0.4B Imperial: $0.9B Riverside 1: $1B Riverside 2: $1.8B Transmission Capacity (GW) Round Mountain Sacramento River Valley Kramer Riverside Imperial Eldorado Solano Carrizo Mountain Pass (GW) Westlands Tehachapi 47

Conceptual Transmission Costs For SuperCREZs where CAISO does not provide information on the cost or availability of new transmission, costs of new high voltage transmission projects are estimated based on unit cost information Costs for such conceptual projects in v.6.0 are taken directly from v.5.0 Based on E3s transmission costing model developed for the GHG Calculator Black & Veatch will updated costs for conceptual projects in v.6.1 using the utilities PTO unit costs 48

DNU Cost Updates: Key Challenges Updated resources are assigned to new Super CREZ because many resources are outside of the original CREZ boundaries 49

DNU Cost Updates: Key Challenges Transmission Infrastructure in Central California Some new Super CREZ are very large These Super CREZ face common major transmission constraints CAISO has not yet developed more granular cost estimates for constraints within these zones May change as new information is developed 50

Delivery Network Upgrade (DNU) Costs Updates: Key Challenges CAISO has not studied all areas and so transmission availability and costs for minor and major upgrades in numerous areas have not been established. Capacity limited to amount in queue Limited number of minor upgrade solutions Minor upgrades are typically classified as local network upgrades and are implemented to mitigate local issues on the system Often accounted for in interconnection studies and costs 51

Out of State Transmission Costs Largely based on previously vetted initiatives: RETI 2B (2010) B&V work for WECC on transmission costs (2012-2014) WREZ Generation and Transmission Cost Model (2009-2013) Given the size and magnitude of new out of state projects being proposed, assumes that no existing transmission is available 52

Out of State Transmission Approach Out-of-state transmission costs Delivered to gateway CREZs (e.g., Mountain Pass) Routing from WREZ Generation and Transmission model Updated cost basis: 500 kV single- circuit ac transmission, 1500 MW capacity, $2.0 million/mile (2015 dollars) In-state transmission costs: Added CAISO DNU costs to OOS costs using same approach as California projects When Energy Only is implemented into the calculator, projects that do not require full deliverability, will not incur DNU costs 53

Out of State Transmission Costs Update Transmission costs were inflated at 1.5% from 2012 to 2013, and at 2.0% from 2013 to 2014. Based on inflation values assumed for the 2014 WECC Transmission Cost Calculator update. https://www.wecc.biz/Reliability/2014_TEPPC_Transmission_CapCost _Report_B+V.pdf https://www.wecc.biz/Reliability/2014_TEPPC_Transmission_CapCost _Report_B+V.pdf Transmission costs were inflated at 2% from 2014 to 2015. Inflation cost was based on commodity prices, Consumer Price Index, and ENR Construction Cost Index. 54

Out of State Transmission Costs Updates Original cost basis for OOS lines assumed 500 kV ac lines for all lines High Voltage Direct Current (HVDC) may be economically feasible for longer distance lines 600 kV HVDC Cost Basis: +/- 600 kV bipole circuit 3000 MW capacity $1.6 million / mile 600 kV HVDC converter station: $517 million DC line losses also likely lower 55

Out of State Transmission Costs Updates Example 725 Mile, 600 kV HV DC line to bring 3000 MW out of state resource to CA. Assumed HVDC converter station required on each end. 600 kV DC500 kV Single AC Base Cost per mile, $/mile$1,645,000$1,958,000 Distance, miles725 Line cost, $$1,192,965,000$1,419,430,000 Converter Stations / Substations Cost, $$1,033,830,000$195,784,000 Total Cost, $$2,226,795,000$1,615,214,000 Capacity, MW30001500 $/kw$742$1,077 56

AC vs. DC Transmission Capital Costs ac dc Numerous other factors influence the selection of line type 57

DISTRIBUTED GENERATION 58

Presentation Overview Introduction Resource Potential Update DG Costs and Value Future RPS Calculator Inputs and DG Sizing 59

Role of DG Analysis in the RPS Calculator DG has seen near exponential growth and reached over 3,000 MWac State incentives under CSI and other programs have historically driven DG growth However, in 2014, the majority of behind the meter PV installations were completed without state incentives There is non-solar PV DG (e.g. wind and bioenergy) state incentives, such as SB 1122, driving additional development Growth of Behind the Meter DG in California, 1998-2014 [1] [1] [1] Black & Veatch estimate based on historical state incentive program data and Greentech Media Research reports on installed PV capacity in 2012-2014 DG projects included in the RPS Calculator demonstrate likely offsets in transmission and generation investment required for scenarios of high DG installation 60

DG Implementation in the RPS Calculator B&V High Resolution GIS Analysis B&V Capital Cost Estimates E3/LDPV Cost Estimate (will be revised by DRP) B&V Cost Estimate for SCE (will be revised by DRP) DG Supply Curve DG Scenarios in RPS Calculator DG Interconnection Cost Substation Level ($/kW) DG Cost/Value Substation Level ($/kW) DG Capital Cost Parcel Level ($/kW) Resource Potential Parcel Level (MW) + RPS Calculator Input (from above sources) RPS Calculator Input (15% of peak load, in the future may be revised by DRP) 61

RPS Calculator and the Distribution Resources Plan (DRP) RPS Calculator will focus on impacts at the transmission level Aggregates parcel, feeder and distribution resolution Impacts of DG between Super CREZ DRP will focus on impacts at the feeder and distribution substation level Impacts of DG within a Super CREZ Resource valuation being examined in the DRP will be applied to the RPS Calculator to extent they are consistent with Calculator functionality Details of the DRPs DG valuation are currently undetermined, but inputs will be anticipated in Version 6.1 of the RPS calculator Much of DRP will be submitted to the Commission July 1, 2015 Prior to release of DRP submittals, information from Black & Veatch updated resource assessment and E3s Local Distributed PV study will be used in the Calculator 62

Refined Resource Assessment In September 2013, Black & Veatch completed a Southern California DG Potential Study to identify PV potential around key SCE 230 kV substations affected by SONGS retirement New analysis techniques to identify potential project size and cost of energy Included residential and commercial/industrial rooftops First ever assessment of parking lots Study identified significant PV in urban areas, especially for high concentration DG (HCDG) connected to subtransmission system 20+ MW projects Expansion of this analysis begun for the entire state; will take into consideration geographic and transmission limits 63

AREA NEAR JOHN WAYNE AIRPORT 64 Technical Potential Capacity, MWdc 0.25 > 3 64

EXAMPLE DETAIL (1.1 MWDC ROOFTOP, 7 MWDC PARKING LOT, APPROX. $120/MWH) 65 Technical Potential Capacity, MWdc 0.25 > 3 The assessment found significantly more potential than previous studies particularly by including potential for PV development on parking lots 65

Resource Potential Comments Majority of respondents favored updates to the PV resource potential Past assessments have been limited Current model is constrained when exploring future policies emphasizing high PV penetration Helps to inform DRP process Identify potential for high concentration DG within Local Capacity Requirements (LCR) areas Improves future siting 66

Updated Resource Assessment Approach Expanded version of the Southern California assessment Use previously described approach to quantify PV potential for: Commercial and industrial (C&I) roofs Parking lots Residential parcels (average size assumed by zip code) Gather parcel data and USGS aerial imagery data for large metro areas in California Limit to areas within the CAISO (excludes Los Angeles and Sacramento) Calculator will assume wholesale DG for residential, commercial, and industrial locations No resource updates planned for wind or bioenergy 67

Updated DG Resource Assessment: Study Area Utility-scale PV resources located in orange-red areas in map Urbanized areas shown in black 68

Updated DG Resource Assessment: Study Area Major metro areas were focused upon to capture the majority of the potential Captures 11 largest municipalities (~20 million residents) and the majority of the potential in the Bay Area, LA Metro (x-LADWP), and San Diego For rooftop potential in other areas, the level of granularity was not considered useful at Super CREZ level All areas also within LCR zones, though not all LCR zones in analysis 69

Study Area Southern California Example 70

Study Area Orange County 71

Study Area Orange County Previously performed assessment 72

PV Potential will be Plotted Against Interconnection Maps Published by Utilities 73

DG Capital Cost Updates LCOEs for DG resources are typically higher than utility scale units: Solar: Based on Black & Veatch large rooftop identification in 2009 and E3 Local Distributed PV study in 2012 Wind : New 2013 assessment; 20 percent adder to large scale costs for dis-economies of scale Bioenergy: Used SB 1122 cost and resource assumptions Methodology and assumptions described in California Renewable Energy Resource Potential and Cost Update presentation 74

DG Capital Cost Updates Capital costs for solar DG resources will be updated in a manner similar to utility-scale renewable resources Solar: ~25% decline in capital cost Wind: ~5% decline in capital cost Biomass: increase with general escalation 75

DG Value Calculator uses same methodology to value large and small-scale resources Potential direct ratepayer benefits that small-scale projects located near loads may provide: Reduced system losses Avoided congestion costs Avoided need for generation in capacity-constrained areas such as LCR areas Deferral/avoidance of investments in transmission infrastructure Deferral/avoidance of investments in distribution infrastructure Currently: RPS Calculator does not assign transmission costs to small-scale resources (other than interconnection costs) RPS Calculator thus calculates trade-off between small-scale and transmission-constrained renewables based solely on avoided transmission costs 76

DG Value Comments Differing opinions on the value of DG. Majority of the responses indicated that DG value was challenging to quantify, very site specific, and the potential benefits may be captured by utility-scale resource as well depending on the location. The cost/benefit for DG is under extensive study in the DRP process: DRP Study ElementsRPS Calculator Locational Net Benefits Will use DRP values Previously based on LDPV study results Barriers Will consider adding based on DRP findings Not presently included in Calculator Capacity Assessment in Urban Areas Will use DRP findings when available Interim approach will assume percent of minimum load at subtransmission substation 77

Interconnection Cost Assumptions The DRP is expected to provide improved information on the cost to interconnect DG in different IOU service areas Until results from the DRP are available, simplified approach to interconnection costs based on penetration of substation capacity: Low cost interconnection limit to be 30% of transmission and distribution substation capacity First 15% of systems can be accommodated by existing distribution system with minor upgrades Estimated cost $100/kW or less Second 15% (up to 30%) will require more extensive upgrades similar to those identified in the Navigant study for SCE Estimated cost $300/kW or less Individual and aggregated systems above 30% local penetration will require additional upgrades (such as dedicated feeders). Estimated cost $500/kW or less PV potential above 100% penetration will be quantified as theoretical, but not technical potential 78

Future RPS Calculator Inputs and Parameters Input DG supply curve generated from new resource potential site identification and project capital costs Cost/Benefit Parameters will be defined based on outcome of DRP Generation carve outs can be applied to account for existing incentive programs (e.g. SB 1122) Substation load can be adjusted to represent assumptions in behind the meter DG installations 79

Creating DG Portfolios Present approach will be to limit DG output based on percentage of peak load at urban transmission substations Present assumption is 15% of peak load, but this will be a controllable parameter in the calculator Estimate the value that a high DG case would need to provide in order to favor DG resources over utility scale projects 80

Documents

RESOURCE COST AND POTENTIAL 1. Background and Introduction Potential and costs were all updated in late 2013 by Black & Veatch Information from internal