1. Preliminary Electricity Rate and Time of Use Rate Scenarios
2017 Integrated Energy Policy Report
California Energy Commission
DAWG, July 14, 2017
Lynn Marshall
Supply Analysis Office
Energy Assessment Division

2. Electric Rate Projections: Annual and Time-of-Use (TOU)

3. Inputs for Preliminary Rate Forecast
Preliminary natural gas and carbon credit prices
Revised renewable PPA Prices
Limited updates to other revenue requirements;
CED 2016 Update demand forecast
Revised rates will incorporate
Analysis of Form 8.1’s submitted June 2017 and recent rate actions
Revised hub prices
Preliminary demand forecast
Natural gas supply basins
Connected to
Interstate and Intrastate Pipelines
Demand centers

4. Preliminary Natural Gas Prices
Hub prices will be revised for final demand forecasts
Source: Supply Analysis Office NamGas Model, April 4,2017

5. PPA Price for New Renewable Purchases
Source: Supply Analysis Office Cost of Generation Model, April 4,2017

6. Preliminary Carbon Allowance Price ProjectionsAB
AB 398 would be most likely to affect the high price scenario; price containment will tend to lower the probability reaching the APCR price.
Natural gas supply basins
Connected to
Interstate and Intrastate Pipelines
Demand centers

7. Wholesale Energy Price Projections

8. Rate Scenarios Mid Energy Demand Case:
Mid demand, natural gas, and carbon prices
Capital expenditure consistent with existing infrastructure plans, and customer and peak forecast
High Energy Demand Case (Low Rates)
Low natural gas and carbon prices
More sales to recover transmission and distribution and other relatively fixed costs
Less investment in infrastructure
Low Energy Demand Case (High Rates)
High natural gas and carbon prices
Lower demand means fixed costs per kwh of sales are higher
More investment to support distributed resources

9. PG&E Residential Rates
Revised rates will incorporate additional preferred resources

10. SCE Residential Rates

11. SDG&E Residential Rates

12. LADWP Residential Rates

13. NCNC Residential Rates

14. Background on Residential TOU Activity
IOUs
Opt-in pilot of various rate designs began summer 2016 and continues through 2017
Default pilot begins 2018 (700,000 customers)
Residential Default rollout in 2019
Decision on exempt customers in 2017
SMUD Rate Action to implement standard residential TOD rate in 2019
Natural gas supply basins
Connected to
Interstate and Intrastate Pipelines
Demand centers

15. Modeling Incremental TOU impacts
Calculate elasticities by forecast zone, building type, month, and day, using utility load profiles
TOU rate calculated to be revenue neutral to the average bundled rate in the planning area rate projections, to capture incremental price effects
Estimate number of participating customers
Apply elasticities to produce load impact by TOU period, and apply percent change to adjusted hourly loads.

16. Key Assumptions Start with Statewide Pricing Pilot elasticities
Use for potential PV adopters
But response does not always vary strictly linearly with price ratio (next slides)
Apply to utility 2015 household load profiles by building type, zone and strata
Reduce estimated load impacts based on SMUD SPO to adjust for complacent and unaware participants:

17. Impacts from Price-Only Pricing Tests Average Percent Impacts from 6 to 9 PM Across Rates
Source: Arcturus: International Evidence on Dynamic Pricing, Ahmad Faruqui, Sanem Sergici, The Electricity Journal, Volume 26, Issue 7, August–September 2013 Figure 5

18. PG&E Opt-in Pilot Rate Comparison Average Percent Impacts from 6 to 9 PM Across Rates
Positive values represent load reductions, negative values represent load increases Source: California Statewide Opt-in Time-of-Use Pricing Pilot Interim Evaluation April 11, 2017, Nexant, Figure , p.101

19. Participation Rates
Small customers are probably more like to be likely to be excluded

20. Preliminary Test Scenarios
Mid Case
Gradual increase in peak-to-off peak rate differential from 2018 pilot rates – 0.7 % average annual increase
Moderate opt-out/unawareness adjustment 35%
Low Demand/High Rates/High Engagement
peak-to-off peak rate increase 1.4%
Engagement adjustment = 25%
High Demand/Low Rates/Low Engagement
Maintain differential at starting point
Engagement adjustment = 45%
All cases 65% eligible and 5% opt-out rate

21. Preliminary Test Scenarios SCE Peak Period Average August Weekday

22. Preliminary Test Scenarios PG&E Peak Period Average August Weekday

23. Preliminary Test Results – Mid Case Average Weekday by Month

24. Schedule and Coordination
August/Sept. –Revise impacts to include CPUC decisions and consider full-year survey research and load impact results
Sept./October – DAWG to review scenarios
November – revised load impacts for 2017 IEPR demand forecast