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 Lynn.Marshall@energy.ca.gov/916-654-4767

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

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

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

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

Preliminary Carbon Allowance Price Projections AB 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

Wholesale Energy Price Projections

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

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

SCE Residential Rates

SDG&E Residential Rates

LADWP Residential Rates

NCNC Residential Rates

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

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.

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:

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

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 4.3-15 , p.101

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

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

Preliminary Test Scenarios SCE Peak Period Average August Weekday

Preliminary Test Scenarios PG&E Peak Period Average August Weekday

Preliminary Test Results – Mid Case Average Weekday by Month

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