1. DG Projections in the Western Interconnection
March 22, 2016
Zach Ming, Consultant
Nick Schlag, Managing Consultant
Arne Olson, Partner

2. Previous Results Last Week’s Results
E3 presented draft results last week
Concerns from DWG about high penetration in some states
Questions about methodology taking into account certain factors
Concerns about implications for percentage of households adopting
12,218 MW CEC IEPR

3. Changes this Week
E3 implemented two changes to the model based on DGW feedback – both result a lower DG forecast
Removal of ‘Green Premium’ of $0.01/kWh
The green premium was a relic from the previous TEPPC case used to represent the preference a customer might have toward solar PV
Lower Technical Potential
NREL released a new study with updated technical potential values for every state
These values do not take into account home/building ownership or limitations for customers sizing to their own load so E3 applied a
67% factor for home/building ownership
80% factor for customer sizing mismatch
NREL source:

4. Updated Results
Updated results reflect the two changes to the model and assumptions
12,218 MW CEC IEPR

5. Additional Results

6. 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

7. Appendix

8. 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

9. Market-Driven Adoption
Determine payback period
Determine max market share and factor in technical potential
Fit logistic curve
Example

10. 1) Determining Payback
PV capital cost forecast and regional multipliers

11. 1) Determining Payback Retail rates from EIA 861 Federal ITC
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

12. 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

13. 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

14. 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