DG Projections in the Western Interconnection March 15, 2016 Zach Ming, Consultant Nick Schlag, Managing Consultant Arne Olson, Partner

2 Background Prior to the 2024 Common Case, WECC incorporated distributed solar PV assumptions consistent with state policy goals Recognizing the potential for additional “market-driven” DG, WECC and E3 worked to develop estimates for the potential size of the market for the 2024 Common Case For the 2026 Common Case, TAS has decided to use the CEC IEPR forecast for market-driven DG in California and E3 has updated the existing market-driven DG model to produce new projections for other jurisdictions within the WECC

MODEL METHODOLOGY

4 Market-Driven Adoption 1.Determine payback period 2.Determine max market share and factor in technical potential 3.Fit logistic curve4.Example

5 1) Determining Payback PV capital cost forecast and regional multipliers

6 1) Determining Payback Retail rates from EIA 861 Adjustments to CA residential to account for tiers Federal ITC All installations assumed to capture commercial ITC since third- party can finance and pass along to residential customers 30% through 2019; 26% in 2020; 22% in 2021; 10% post 2022 Incentives (non-inclusive) AZ – 25% res tax credit, max $1000; 10% com tax credit, max $25,000 CO – 3% com tax credit OR (PacifiCorp) - $0.75/W res up-front incentive, max $6000, 2018 sunset

7 2) Determining Max Market Share E3 functional form (blue) overlaid on NREL empirically derived payback curve (red and green) for residential customers Similar exercise for commercial with a lower payback curve Technical potential set at 50% of all customers and is multiplied against max market share result

8 3) Fit Logistic Curve ‘S-Curve’ uses logistic function to represent rate at which the market will adopt technology Based on NREL SolarDS model Example shows how max market share changes over time with payback and how annual adoption follows

9 Model Changes in Update Key model updates include California: relaxation of 5% NEM cap, residential rate reform (4-tier to 2-tier), NEM 2.0 reforms Federal ITC extension Nevada NEM reform (increased fixed charges, PV exports paid marginal utility avoided cost) Inclusion of several meaningful incentives in CO, AZ, MT, and OR Improved payback curve based on recent empirical NREL study Other model updates Latest installed PV costs and state-by-state differences Current utility retail rates Current installed DG quantities

ADDITIONAL RESULTS

11 High Level Results The Market-Driven DG forecast increases by 160% relative to previous iteration 2026 vs 2024 gives two extra years of adoption Market-Driven DG exceeds state-specific policy goals in all cases Largely driven by relaxation of NEM caps, ITC extension, state- specific incentives, and improved forecasting techniques For the 2024 Common Case, TAS adjusted the recommended values (shown to right) downward by 20% Previous ResultsCurrent Results 12,218 MW CEC IEPR Downward revision from 731 MW

12 Comparison to NREL In February 2016, NREL published a Distributed PV Adoption report Results from the reference scenario are shown at right as compared to the E3 forecast

13 WECC Year-by-Year incremental cumulative

14 California TAS has decided to use the CEC Mid IEPR forecast for California DG The chart shows a comparison between the model output and other public forecasts, including the CEC Mid IEPR incremental cumulative

15 State-by-State Results As % of peak demand % of peak = installed PV nameplate capacity / peak load not to be interpreted as PV contribution to peak load