SCE 2018 GRC Phase 2 Workshop A

Transcription

1 SCE 2018 GRC Phase 2 Workshop A Overview of Marginal Cost, Revenue Allocation & Rate Design Proposals November 2, 2017

2 Agenda 11:00 a.m. Noon Introductions & Objectives Safety Housekeeping Items GRC Phase 2 Overview & Policy Lunch 12:30 p.m. Marginal Cost Overview & Proposals Erin Pulgar Russ Garwacki Reuben Behlihomji Ben Baker 1:30 p.m. Revenue Allocation Overview & Proposals Ruben Pardo 2:30 p.m. Break 2:45 p.m. Rate Design Overview & Proposals 4:00 p.m. Models, Tools & Work Papers Rob Thomas Shue Cheng Shue Cheng Ruben Pardo 4:50 p.m. Wrap Up / Next Steps Erin Pulgar 5:00 p.m. Conclude 2

3 Safety, Introductions & Housekeeping Items

4 Safety Review exit route and assembly location Please ensure you signed in so we have an accurate list of attendees in the event of an emergency Reminder to duck, cover and hold in the event of an earthquake Evacuate when it is safe to do so Call 911: Erin Pulgar Meet First Responders: Ben Baker CPR Trained: Volunteers 4

5 Introductions SCE Attendees Non SCE Attendees Erin Pulgar Case Manager Russell Garwacki Director, Pricing, Design & Research Rob Thomas Principal Manager, Rate Design Reuben Behlihomji Senior Manager, Modeling, Forecasting & Economic Analysis Ruben Pardo Senior Project Manager, Rate Design & Research Shue Cheng Senior Analyst, Rate Design & Research Ben Baker Senior Analyst, Analytics Jane Lee Cole Senior Attorney Al Matthews Senior Attorney Commission Customer Advocacy Groups Phone Attendees 5

6 Housekeeping Items Workshop Location: Call In Information: Opera Plaza Community Room (626) Van Ness Avenue, Suite 2045 Participant Code: # San Francisco, CA Application (A.) (filed June 30, 2017) Commissioner Peterman ALJ Cooke Exhibits: SCE 01 Policy SCE 02 MarginalCost and Sales Forecast Proposals SCE 03 Revenue Allocation Proposals SCE 04 Rate Design Proposal SCE 05 Witness Qualifications SCE 06 Amended Residential Rate Design Proposals SCE 07 Supplemental Small Business ME&O and DG/Storage Study Plan Proposals Case Manager: Erin Pulgar, SCE T: (626) / M: (626) / erin.pulgar@sce.com 6

7 Data Request (DR) Process DRs should be sent to Erin Pulgar at and the applicable SCE attorney SCE Attorney Russell Archer Walker Al Matthews Jane Lee Cole Robin Meidhof Subject Area Marginal Costs, Revenue Allocation, DA/CCA, Large Power Rate Proposals Agricultural and Pumping Rate Proposals Small Commercial Rate Proposals, Residential Rate Proposals, Street and Area Lighting Proposals Economic Development Rate Proposal Standard response times are not to exceed 10 business days from the date of receipt (extensions may be requested) SCE s non-confidential data request responses can be accessed via SCE s extranet site Request for access must be submitted to SCE s Case Admin (case.admin@sce.com), cc Erin Pulgar (erin.pulgar@sce.com) Confidential data requests require a non-disclosure agreement (NDA) Contact SCE s Case Admin (case.admin@sce.com), cc Erin Pulgar (erin.pulgar@sce.com) to initiate the NDA process 7

8 Objectives Provide an overview of the GRC Phase 2 process How rates are determined Alignment with other proceedings Policy New elements in this case Discuss SCE s key marginal cost, revenue allocation and rate design proposals and solicit feedback / input Explore SCE s models, tools and work papers, and how to access and use them Workshop is meant to be educational and interactive attendees are encouraged to ask questions and provide their perspectives on the proposals Discussion will be kept on schedule to ensure all objectives are covered 8

9 GRC Phase 2 Overview How Rates are Determined Alignment with Other Proceedings Policy Goals

10 GRC Phase 2 Overview How Rates Are Determined Authorized Revenue Requirements = cost of providing utility services that the CPUC has determined are appropriate to recover through customer rates Rate Groups = categories into which similar types of customers are grouped (e.g., residential, small commercial, ag & pump, etc.) Rates = regulated (tariffed) prices charged to customers in each rate group for utility service (e.g., energy charges, demand, charges, customer charges) Objective: Equitably recover a utility s authorized revenue requirement through fair revenue allocation and rate designs based on cost-to-serve principles Historically resolved via settlement agreements with litigation only on narrow unresolved issues Typically include diverse representation of customer advocacy groups Process: Authorized Revenue Requirements Functionalize Cost Categories Generation Distribution Transmission Nonbypassables Marginal Costs (MCs) Revenue Allocation Rate Design Calculate MCs Generation Capacity Energy Distribution Design Demand Customer Divide responsibility for revenue requirement among customer classes based on MCs and class usage patterns Assign rate group revenue to each rate schedule, determine rate components and structures 10

11 Alignment With Other Proceedings Proceeding / Status: 2016 RDW (A ) PD expected Dec/Jan TOU OIR (R ) Closed RROIR (R ) Open / Preparing TOU Default RDW Filings GRC Phase 1 (A ) Awaiting PD Phase 2 Impacts: Revised TOU periods serve as basis for MC/RA studies Rate designs reflect and are based on proposed TOU periods Aligning implementation w/ Phase 2 Dictated requirements for TOU period grandfathering and guidelines for setting TOU periods used in Phase 2 (D ) Provides glidepath for tiered rates Default TOU and fixed charge proposals will be filed in December RDW applications Requested funding to implement new customer technology platform (CSRP) Necessitates Q implementation of Phase 2 decision (and 2016 RDW) Impacts certain rate migrations 11

12 Alignment With Other Proceedings (cont.) Proceeding / Status: Demand Response (A ) PD expected in Nov TE (A ) Filing Briefs in Nov / Awaiting PD on Priority Projects PCIA OIR (R ) Testimony to be filed March 2018; PD scheduled for July 2018 Phase 2 Impacts: Uses incentive levels for BIP, AP I and SDP as proposed in DR application, but restructured credit levels to align w/ proposed Option D rates Updated existing EV rates due to uncertainty in TE rate implementation timing Proposed to grandfather existing EV customers on dualmetering/singledemand charge feature when transitioned to new TE EV rates Exhibit SCE 03 continues to use existing CRS methodology for revenue allocation 12

13 Implementation Constraints CSRP Timeline Planning Plan Analyze Design Build Test Deploy Stabilize CSRP Test Freeze Estimated Reg Approval Dates Estimated Filing Dates Estimated Implementation Key Regulatory Milestones Default TOU Pilot AL Section 745 Decision Rate Findings from Default Pilot RDW Assigned Com. Ruling on Default Rates GRC Ph2 3.43M customers Current Rate Transition Plans 21k customers Res TOU Opt in Pilot 400k Res TOU Default Pilot 600k GRC Ph 2/ RDW/ Non Res TOU/CPP 40k 106k Summer Pause Res TOU Full Rollout Non Solar A,B, and T customers CPP 2019/ 2020 Annual Migration 2.5k TOU OIR Solar Migration Res/NEM Bill Redesign Non Res Bill Redesign Customer Tools *Tentative pending CPUC Decision Rate Tool enhanced for opt out and new rates (Q4) Appliance Shifter Text Alerts Rate Tool automation and add Non Res Statewide/SCE Messaging for Res TOU*

14 Policy Goals Alignment with California s Clean Energy Goals SB 32 / SB 350 (GHG reductions / DER adoption) CPUC s DER Action Plan Updated TOU Periods (address duck curve issues) Adherence to Established Rate Design Principles Cost of Service Affordable Electricity Conservation Customer Acceptance Rate Stability Rate Simplification 14

15 2018 GRC Phase 2 What s New Updated TOU Periods (based on 2016 RDW proposals) Current: Legacy TOU periods reflecting 12 6 pm summer weekday peak period Proposed: Updated TOU periods reflecting impacts of RPS duck curve Inclusion of Flexible Generation Capacity Current: Peak Proposed: Peak + Flex Time Differentiated Distribution Current: Use EDF methodology to allocate distribution design demand costs Proposed: PLRF (Peak) + EDF (Grid) methodologies to allocate distribution design demand costs Customer Charge Modifications Current: Recovers none or a portion of FLT costs via $/mo customer charge with balance recovered via FRD charges Proposed: Recover FLT costs via grid portion of distribution charge (50 kva and below; >20 kw) Later peak period (12 6pm 4 9pm) Weekends no longer 100% off peak New winter super off peak (SOP) period from 8am 4pm Implementation of grandfathered rates for eligible solar customers Flex capacity needed to meet duck curve ramp Distributes marginal generation capacity costs over more months / periods (including the winter season), instead of just the summer on peak period Bifurcating distribution design demand costs between peak and grid, which is similar to generation energy and capacity split Using peak load risk factor (PLRF) methodology to time differentiate peak costs and EDF methodology to allocate grid costs Allows for timedifferentiated distribution rates Minimizes differences in customer charge when customers move between rate groups due to usage changes New / updated rate design proposals are covered in a later section 15

16 Proposed TOU Periods Season Existing Proposed On Peak Summer Weekdays: 12 6pm Weekdays: 4 9pm Mid Peak Summer Winter Weekdays: 8am 12pm; 6pm 11pm Weekdays: 8am 9pm Weekends: 4 9pm Weekdays and Weekends: 4 9pm Off Peak Super Off Peak Summer Winter Weekdays: 11pm 8am Weekends: All Weekdays: 9pm 8am Weekends: All Weekdays and Weekends: All except 4 9pm Weekdays and Weekends: 9pm 8am Winter N/A Weekdays and Weekends: 8am 4pm 16

17 Marginal Costs¹ Overview Generation Marginal Energy Costs (MECs) Marginal Generation Capacity Costs (MGCCs) Distribution Design Demand Marginal Costs (DDMC) Customer Marginal Costs Sales and Customer Forecast ¹Due to time constraints, specifics on street light marginal costs are not being addressed in this workshop but can be discussed in subsequent meetings, if necessary

18 Overview of Marginal Costs CPUC relies on marginal cost (MC) pricing to assign authorized revenue requirements to customers by rate group and as guidance for setting the level of individual rate components Marginal Cost = the change in costs incurred (or avoided) to serve a small increment (or decrement) in demand for utility service Used to calculate marginal cost revenues (revenues that SCE would collect if the rates equaled marginal cost¹), which are then used in the revenue allocation process Enable economically efficient energy usage decisions, for consumers and DER providers Use both long run (e.g., MGCCs, DDMCs) and short run (e.g., MECs) marginal costs Identify cost drivers for meeting customer electricity requirements Calculate change in each cost driver at the functionalized level (e.g., generation, delivery, customer) Attribute to measurable aspects of customer req (e.g., energy, demand, customer type) Three Cost Drivers 1. Electricity Usage 2. Delivery Related Design Demand 3. # of Customers ¹Use equal percent of marginal costs (EPMC) methodology to assign utility s authorized rev req in proportion to MC revenues (utility rev req is usually higher than MC) 18

19 Marginal Cost Elements Generation Category Marginal Energy Costs (MECs) Cost Driver Allocation Methodology Proposed Valuation Notes Energy Price forecast using production simulation model (PLEXOS) Annual: /kwh Summer On Peak: /kwh Mid Peak: /kwh Off Peak: /kwh Winter Mid Peak: /kwh Off Peak: /kwh SOP: /kwh Associated with electricity usage cost driver Aggregated in TOU periods Marginal Generation Capacity Costs (MGCCs) $134.5/kW yr Peak (61%) Loss of Load Expectation (LOLE) $94.4/kW yr ($82 w/o RA) Using CT Proxy Flex (39%) Loss of Load (Ramp) Expectation (LOLE) $52.5/kW yr Using CT Proxy Distribution Design Demand Marginal Costs Peak Grid NERA Regression Method / Peak Load Risk Factor (PLRF) NERA Regression Method / Effective Demand Factor (EDF) $83.0/kW yr $84.9/kW yr Timedifferentiated Recovered on a non time variant basis Customer Related Marginal Costs Access / Customer Service Real Economic Carrying Charge (RECC) Varies by customer class Refined proposals made in 2016 RDW proceeding, but generally consistent 19

20 Marginal Costs - Generation Marginal Energy Costs (MECs) MECs = the hourly marginal market clearing price of the ISO wholesale power market Forecast through production simulation models of market clearing prices PLEXOS model (fundamental power price forecast) Forecasted hourly energy prices¹ reflect the level of hourly net load served by dispatchable generation resources and their production cost MECs are aggregated and averaged for each TOU period PLEXOS Inputs Gross load projections (include effects of on site load impacts due to DERs) Natural gas price forecasts for each hub GHG compliance costs Transmission line & interface limitations RPS trajectory for major LSEs Generation profiles for IOUs RPS eligible wind and solar resources Key Assumptions 90% of renewable generation is scheduled in the ISO day ahead market Small hydro, geothermal and biomass are selfscheduled; price sensitive bids for wind and solar CA exports during periods of over gen are allowed Note additional information on inputs and assumptions can be found in Appendix C of Exhibit SCE 02A ¹Includes incremental fuel, variable O&M, GHG compliance, start up, no load fuel costs & costs related to congestion and line losses 20

21 Marginal Costs Generation (cont.) Marginal Energy Costs (MECs) RESULTS 21

22 Marginal Costs - Generation Marginal Generation Capacity Costs (MGCCs) Measured by annualizing the expected costs of a utility built combustion turbine (CT) as a proxy (long run MC) (used instant cost of an advanced 200 MW CT = LMS100) Levelized cost of a new CT calculate energy rents based on future power prices using Ventyx price dispatch model remove levelized energy rents from levelized CT cost NEW: Functionalizing costs between peak and flex capacity Flex capacity is associated with the ramping need created by increased renewables and shrinking demand (leading to a new grid operation concern) Ramp Need / Flexible Capacity = ability of generation resources to sustain or increase output during the greatest upward 3 hour net load ramp in each month MGCCs are assigned to TOU periods using a loss of load expectation (LOLE) methodology Peak capacity was historically the primary reliability issue Now have to manage for peak and ramp Potential to use customer rates to also help manage ramp concerns (similar to what has been done in pricing to manage peak concerns) 22

23 Marginal Costs Generation (cont.) Marginal Generation Capacity Costs (MGCCs) Need to identify when a potential reliability concern could occur due to peak or ramp in order to send proper price signals to mitigate capacity constraints Use LOLE methodology to identify these periods Perform evaluations to determine hours that are more likely to experience a 1 day in 10 year outage event (1 in 10 LOLE) Stochastic model used to compare capacity needs vs. available capacity for many local, wind and solar outcomes Results used to allocate capacity costs to hours in a year 23

24 Marginal Costs Generation (cont.) Marginal Generation Capacity Costs (MGCCs) LOLE Methodology 30 Load Years 1 year wind data 1 year solar data Evaluate sample for LOLE by hour for whole year Probability that available resources minus outages cannot serve need Randomly sample ~5% of all daily combinations (wind and solar randomly selected in month) Scale needs up or down until a 1-in-10 LOLE is achieved Repeat previous steps after scaling the peak and ramp needs Example draw for a day: All data scaled to energy in study year 30 January 1 st Days - 30 January Solar Days - 30 January Wind Days Sample ~5% of all load, wind, and solar combinations to create net load and net load ramp daily curves Combine 1-in- 10 LOLE results for both ramp and peak Utilizes an independent weighting factor that simulates the changing grid constraints between peak and ramp 24

25 Marginal Costs Generation (cont.) Marginal Generation Capacity Costs (MGCCs) Results The ratio between peak and ramp was derived by taking the maximum of the monthly average ramps (MW) and the maximum of the monthly average net load peaks (MW) that occurred during peak and ramp LOLE events Given the evolving nature of ramp constraints on the system, SCE chose a near term estimate based on the year 2018 when functionalizing generation capacity marginal costs 25

26 Marginal Costs - Distribution Design Demand Marginal Costs (DDMCs) Design demand cost driver is a function of both the amount and the configuration of planned capacity¹ determined to be necessary to serve additional demand expected on the distribution system Use planned loading limits (PLLs) NEW: Functionalized into peak and grid, with an added level of granularity between asset type (substations and circuits) and asset category (distribution and subtransmission) Appropriate due to paradigm shift caused by DERs and advances in metering NEW: Use of the Peak Load Risk Factor (PLRF) methodology to account for the time varying nature when peak usage impacts the capacity related portion of DDMCs Identifies the hours of the year when distribution assets experience peak capacity constraints Continued use of Effective Demand Factor (EDF) methodology for grid portion Peak Grid Peak capacity function to meet time sensitive peak customer demand Use PLRF methodology to account for time varying nature when peak usage impacts capacity related portion of DDMCs Allows for the introduction of time differentiated distribution rates Primarily needed for connectivity (bi directional transfer of energy between customers) Continued use of EDF methodology Some time sensitivity due to coincidence with circuit peaks, but generally recovered via non time differentiated demand charges ¹The capacity that SCE s grid would carry under normal operating conditions 26

27 Marginal Costs Distribution (cont.) Design Demand Marginal Costs DDMC Methodology Computed using the incremental cost of adding capacity from the NERA regression method FERC Basis of Recording Costs NERA Regression Method Use FERC classification to categorize costs by asset type Distribution Plant: = Substation Assets = Distribution Circuits Sub Transmission Plant: 350, = Substation Assets = Subtransmission Circuit Apply a regression methodology to 10 years of historical and 5 years of forecast capital expenditure data Cumulative capex = independent variable Cumulative planned capacity¹ = dependent variable OLS method to deduce trend line (slope value) Slope value multiplied by RECC factor (capital component) Add O&M cost component Asset Type Categorization (new to this GRC) ¹SCE switched to using planned capacity instead of recorded load in 2012 GRC to minimize cost to growth distortions 27

28 Marginal Costs Distribution (cont.) Design Demand Marginal Costs Distribution Circuits Functionalizing Costs Between Grid and Peak Use the split between main line circuit miles and radial line circuit miles (including secondaries) Consistent w/ FERC method of using transmission circuit miles to allocate costs between ISO and non ISOjurisdictional transmission assets Main Line (26%) Primary voltage circuit miles form the basis of apportioning distribution line costs to peak Largest sized conductor/cable; primarily accommodate peak coincident load needs Radial / Secondary Lines (74%) A Banks & B Banks Subtransmission Circuits Primary voltage circuit miles (including secondary voltage circuit miles) form the basis of apportioning distribution line costs to grid Allow for connectivity to mainline / backbone system Functionalized as peak costs Generally planned and designed for peak level of coincident load Functionalized as grid costs Design and configuration that primarily functions as a network that allows the transfer of energy in the event of a contingency (de minimus functionality as a peak capacity resource) 28

29 Errata Testimony Served 11/1 Corrects an error in the calculation of distribution design demand marginal costs Mistakenly omitted the installed capacity (PLL MW) of sub transmission lines in two planning regions when performing the regression analysis (included the $) Desert Region and San Jacinto Valley Region Resulted in incorrect amounts and growth rates being used for the A Bank Marginal Costs and the Subtransmission Line Marginal Costs Main correction made in Exhibit SCE 02; also impacts Exhibit SCE 01, Exhibit SCE 03, Exhibit SCE 04 and Exhibit SCE 06 A Bank Marginal Costs Increased from $30.34/kW yrs to $31.17/kW yrs Subtransmission Line Marginal Costs Decreased from $15.64/kW yrs to $8.77/kW yrs Updated numbers are the result of including the omitted installed capacity MW, which adjusts the load growth rate from 1.86 percent to 2.74 percent and redistributes the O&M between the two asset types 29

30 Errata Testimony Served 11/1 (cont.) Updated Average Rate Summary by Rate Group 30

31 Marginal Costs - Distribution Design Demand Marginal Costs Relating Design Demand Marginal Costs to Measurable Customer Attributes PLRF = peak capacity driven costs EDF = grid related costs PLRF Methodology Introduced in 2016 RDW proceeding Basis of assigning a time sensitive allocation of peak capacity related costs 1 PLRF methodology is meant to assign the time differentiated element to distribution costs Thresholds: Distribution Circuits = 73% avg PLL threshold (consistent with trigger for reviewing capacity needs on a circuit) Substations = 90% PLL threshold Hours below thresholds = 0; Hours above = 1 Summed for all assets in each hour; relative ratio for hourly peak load values is determined (PLRF) Accounts for load diversity 31

32 Marginal Costs Distribution (cont.) Design Demand Marginal Costs PLRF Methodology (cont.) Introduced in 2016 RDW proceeding Basis of assigning a time sensitive allocation of peak capacity related costs 2 3 To be forward looking, PLRF methodology is applied to 2021 forecasted circuit load with DG penetration netted out PLRFs calculated based on netted load shape Once a PLRF is assigned to each hour of the year in 2021, the percentages are summed by proposed TOU periods and used for revenue allocation 32

33 Marginal Costs Distribution (cont.) Design Demand Marginal Costs Relating Design Demand Marginal Costs to Measurable Customer Attributes PLRF = peak capacity driven costs EDF = grid related costs EDF Methodology Used to link grid related design demand to measurable customer attributes Ratio of a customer s contribution to the peak load on a transmission or distribution circuit to the customer s annual non coincident peak demand Vary by customer and circuit voltage level Takes into account intergroup diversity Distribution circuit EDFs vary from 28 37% for residential / small agricultural to 61 76% for larger C&I 1. # of customers by rate group determined for each circuit 2. Use Monte Carlo simulation method to randomly populate each typical circuit type with customers from load research samples 3. Individual customers on each simulated circuit are selected, and the contribution of the customer to the circuit peak is determined Used to develop typical circuit profiles (calculated for each customer type) Results found in Appendix B of Exhibit SCE 02A MC Revenues = product of rate group s annual non coincident peak demand x rate group EDF x MC per unit of design demand 33

34 Marginal Costs - Distribution Customer Marginal Costs Cost Driver = number and type¹ of customers Costs viewed as fixed (i.e., not dependent on level of demand or usage) Use RECC methodology Access Investment related equipment costs associated with connecting a customer to the grid and related ongoing O&M Final line transformer (FLT), service drop, meter Use long run MC (long life capital equipment) Customer Service Activities Customer expenses related to customer communications, metering and billing Short run MC Results are shown in Table I 22 of Exhibit SCE 02A ¹Differences in size, service voltage, metering requirements and other factors 34

35 Sales and Customer Forecast Using kwh sales forecast for 2018 as the basis for the billing determinant forecast and rate design proposals Reflects the energy that SCE expects to deliver to Bundled Service, DA and CCA customers in its service territory during the period Use econometric models to construct sales forecasts for major customer classes Forecast produced monthly and summed to an annual value 35

36 Revenue Allocation Overview Generation Distribution Other

37 Overview of Revenue Allocation Comparison of revenue allocation results using 2015 GRC Phase 2 methodologies included in Appendix B of Exhibit SCE 03A Revenue Allocation = the allocation of revenue requirement recovery among rate groups based on usage patterns that contribute to incurrence of marginal costs Marginal Cost Revenue Requirement = sum of various marginal costs x related class billing determinants, scaled to meet revenue requirements Using 2018 total system revenue requirements consisting of the following unbundled components: SCE generation, FERC jurisdictional transmission, distribution, nuclear decommissioning (NDC), new system generation (NSGC), Department of Water Resources Bond Charge (DWRBC) and public purpose programs (PPP) Propose to allocate CPUC jurisdictional generation and distribution costs based on system marginal cost revenues using the marginal costs from Exhibit SCE 02A All other cost components are allocated based on methods approved in prior Commission decisions NEW: Allocation of generation revenue to account for peak / flex split NEW: Allocation of distribution revenue to account for peak / grid split New: Allocation based on updated TOU periods proposed in 2016 RDW Present Rate Revenues (PRRs) Developed separate forecasts of PRRs for Bundled Service, DA and CCA customers Based on forecasted 2018 sales and January 1, 2017 rates Used to compare current and proposed rates and in the development of the system average percentage (SAP) allocator 37

38 Revenue Allocation - Generation Bundled generation revenue requirement allocated to Bundled Service customers only Generation MCRR = combined revenue responsibility associated with both energy and capacity marginal costs Generation Energy MCRR (58%) Generation Capacity MCRR (42%) Determined by multiplying MECs by the forecasted TOU sales in each rate class, where the TOU sales are grouped in the TOU periods proposed in SCE s 2016 RDW Allocation based on relevant top 100 hours of net loads¹ (used proxy 2021 net loads) Peak Capacity Costs = identified top 100 peak net load hours Flex Capacity Costs = identified top 100 largest 3 hour net load ramp hours Derived rate group contributions for these hours Peak Capacity Costs = allocation based on average rate group load (MW) during the top 100 net load hours of the year as a % of the total average net loads in the top 100 hours Flex Capacity Costs = allocated based on the 3 hr average rate group load (MW) as a portion of the total 3 hr average load during the top 100 largest 3 hr net load ramp hours of the year Peak Related MCRR = 76% Flex Related MCRR = 24% ¹Net load in each hour is typically defined as the difference between customer driven managed load and the amount of renewable supply generated in the hour. SCE defines managed load as the gross load minus the forecast of DG load plus the forecast of EV load. 38

39 Revenue Allocation - Distribution Distribution revenue requirements allocated to rate groups based on distribution marginal cost revenues Reflects total retail load on the distribution system Remove non allocated distribution revenues (e.g., power factor, street light facilities) Distribution MCRR = combined revenue responsibility associated with both customer and design demand marginal costs Customer Cost MCRR Determined by multiplying the marginal customer costs by the number of forecasted customers Design Demand MCRR Grid Related MCRR = product of the rate group non coincident demand (MW), the EDFs and the grid related components of distribution design MC (NCP x EDF x Cost) Peak Related MCRR = determined using PLRF weighted average rate group load (MW) during the peak load risk hours of the year MCRR values are summed, by rate group, and the ratio of each rate group s marginal distribution cost revenues to the system total produces the distribution cost allocator 39

40 Revenue Allocation - Other PPPC Maintain current methodology, based on SAPC, with generation revenues for DA and CCA imputed as Bundled CARE balancing account revenues based on SAP (excluding CARE and street lights), consistent w/ methodology adopted in D CARE Discount 32.5% effective discount, based on methodology adopted in D Deficiency costs are allocated to all customer sales (excluding street lights and CARE customers) SGIP Allocated based on SAPC, excluding CARE, FERA and street light facilities Consistent with methodology approved in D GHG Based on methodology adopted in D Allocating based on authorized 2017 amounts Allowances set per D GHG costs allocated by generation MCRR NDC Allocated to all retail customers on equal cents per kwh, based on previously adopted methodologies NSGC Based on 12 CP, consistent with methodology adopted in D Non Allocated Street light and power factor revenues, directly assigned Revenues DR Rev Req Consistent with adopted methodology in D % based on same allocation as PPPC; 50% based on distribution marginal costs Treatment of Interruptible Credits / Dynamic Programs Base Transmission & TOTCA Credits allocated in distribution rates since benefit all retail customers Costs allocated on basis of marginal costs of retail generation, consistent w/ methodology approved in D FERC uses a 12 CP methodology Based on current authorized FERC rates 40

41 Revenue Allocation Results Note: DA also includes CCA 41

42 Revenue Allocation Results (cont.) 2015 GRC Revenue Allocation Comparison Note: DA also includes CCA 42

43 BREAK

44 Rate Design Overview Base Rate Design Optional Rates Grandfathered Rates Residential Small & Medium Commercial & Industrial (C&I) Large Power Agricultural & Pumping (A&P) Street & Area Lighting Economic Development Rate Food Bank Rate Illustrative Rates / Bill Impacts

45 Overview of Rate Design Rev Req = authorized functional revenues that SCE used to establish rates in January 2017 Sales Forecast = system usage for Bundled Service customers adjusted for departing load in 2018 C&I / A&P Rates Residential Rates Two Basic Structures = 1. Option D (similar to existing Option B) 2. Option E (similar to existing Options A/R) Differ in the recovery of generation peak capacity costs and distribution peak related costs Option D recovers more via demand charges Option E recovers more via energy charges Also proposing grandfathered rate structures with legacy TOU periods for eligible solar customers Default Tiered Rates Continue to recover almost all costs via volumetric, non TOU energy charges Include small fixed and minimum charges (fixed charges will be addressed in SCE s December 2017 residential RDW application) Modifications pursuant to the provisions adopted in RROIR, with updated marginal cost and revenue allocations Seasonal rate differentials being addressed in December 2017 RDW Optional TOU Rates Introducing time differentiated distribution Legacy TOU Periods TOU D T TOU D A TOU D B TOU EV 1 Updated TOU Periods Default Rate 1 Default Rate 2 TOU D C 45

46 Rate Design Elements Component Non Residential Rates Residential Rates Customer Charge ($/meter) Used to recover all of a portion of the customer related distribution MCs NEW: For customers with demands >20 kw, propose to recover first 50 kva of FLT transformation via the distribution gridrelated charge, w/ balance recovered via the customer charge Softens bill impacts for transitioning customers Set at full EPMC levels Any new or revised fixed customer charges are being addressed in SCE s upcoming December 2017 RDW application, pursuant to the direction provided in D

47 Rate Design Elements (cont.) Component Non Residential Rates Residential Rates Energy Charges ($/kwh) Time Related Demand (TRD) Charges ($/kw) Facilities Related Demand (FRD) Charges ($/kw) Mostly time variant Used to recover: Generation energy Generation capacity (peak and flex) depending on rate option Distribution design demand (peak and grid) depending on rate option Nuclear decommissioning costs New system generation charges DWR bond costs Public purpose program costs FERC transmission (for non demand metered customers and balancing accounts) Time variant (coincident) Used to recover: Generation capacity (peak and flex) depending on rate option Distribution peak capacity depending on rate option Non time variant (non coincident) Used to recover: Distribution grid related costs depending on rate option Higher (>50 kva) transformer capacity Used almost exclusively to recover all costs Tiered rates = not time variant TOU rates = time variant N/A N/A 47

48 Proposed Option D Rate Design Current Option B Proposed Option D* Generation Energy TOU energy charges ($/kwh) TOU energy charges ($/kwh) Generation Capacity Peak Generation Capacity Flex Distribution Design Demand Peak Distribution Design Demand Grid No peak / flex split Recovered via TRD charges No peak / grid split 100% recovered via FRD charge Summer on peak and winter mid peak costs recovered via TRD charges Summer mid peak and off peak costs recovered via TOU energy charges 50% recovered via TOU energy charges Balance of Summer On Peak recovered via TRD charge Balance of all other periods recovered via FRD charge 100% recovered via FRD charge Smoothed the time variant energy price for peak distribution to flatten the retail rate across TOU periods Flattening is accomplished by using a calculated weighted average to combine the summer on and midand winter mid peak periods The same weighted average method is applied to the summer and winter off peak periods (didn t adjust winter SOP period) Purpose = reduce volatility in TOU rates (pretty high on peak rate without the smoothing) *TRD charges apply on non holiday weekdays only; not on weekends or holidays 48

49 Proposed Option E Rate Design Current Option R Proposed Option E Generation Energy TOU energy charges ($/kwh) TOU energy charges ($/kwh) Generation Capacity Peak No peak / flex split Generation Capacity Flex Recovered via TOU energy charges Distribution Design Demand Peak Distribution Design Demand Grid No peak / grid split Used EDF comparison methodology to determine amount of recovery in TOU energy charges and FRD charge 100% recovered via TOU energy charges 100% recovered via TOU energy charges 100% recovered via FRD charge Proposed Option E structure eliminates the needs for separate Option A and Option R structures 49

50 Grandfathered Rates D (TOU OIR) adopted TOU period grandfathering for eligible solar customers (slightly modified by D ) Grandfathered customers allowed to maintain legacy TOU periods Other changes in rate design (including allocating marginal costs to TOU periods and setting specific rate levels) should be updated to reflect the new marginal cost allocation But legacy TOU periods must remain directionally intact (i.e., legacy peak period must be highest priced period, followed by mid peak, etc.) Process: 1. Utilized the updated cost studies and revenue allocations previously discussed 2. Redistributed the hourly MECs, LOLE generation capacity costs and PLRF distribution peak capacity costs into legacy TOU periods 3. Results in underlying TOU marginal cost based rates, which are then scaled on a functional basis to establish the grandfathering rates 4. At this stage, grandfathered rates demonstrated inverted pricing differentials between TOU periods 5. Adjusted the grandfathered rates to ensure price differentials were directionally consistent across legacy TOU periods General Service Propose Option R and B structures Additional Option C structure for TOU GS 1 RES BCT customers and Option A structure for TOU 8 S customers Ag & Pump Propose Option A and B structures 50

51 Demand Response Rates D directed SCE to propose incentive levels for BIP, AP I and SDP in its DR application rather than GRC Phase 2 proceedings Not proposing to recalculate the overall incentive levels in the Phase 2 proceeding Illustrative BIP, AP I and SDP credit levels shown in Appendix B of Exhibit SCE 04A retain the overall value proposed in SCE s DR Application (A ) but have been restructured to align with the Option D rate structures 51

52 Residential Rate Design Proposals Exhibit SCE-06 (Amended Testimony filed September 27) 1. Basic Baseline Allocation 2. Time Differentiated Distribution Charges for TOU Rates 3. Grandfathered Rate Options Proposal to increase the baseline allocation for basic customers from 53% to 60% Brings tiered rates more directionally in line with costs Mitigates the reduction in baseline caused by declining average residential usage Proposal to introduce a time related component of distribution design demand marginal cost in TOU rates using a 2 part allocation Peak component recovered via timevariant energy charges ($/kwh) Grid component recovered via flat energy charge across all TOU periods ($/kwh) Purpose is to provide a pricing signal that better reflects grid conditions, including when and how to use DERs Proposal to grandfather eligible customers on existing TOU D A, TOU D B, TOU D T and TOU EV 1 rates D = NEM 2.0 customers allowed to stay on existing TOU rate for 5 years from the date they commenced service on the rate D = Eligible solar customers (excluding NEM 2.0) eligible to retain legacy TOU periods for 5 years from PTO date Update underlying MC & RA 52

53 Residential Rate Design Proposals (cont.) Exhibit SCE-06 (Amended Testimony filed September 27) 4. Closing & Eliminating Existing TOU Rates w/ Legacy TOU Periods 5. New Optional TOU Rate (TOU D C) 6. Updated Default TOU Rate for NEM 2.0 Customers Proposal to close (to new) and eliminate (to all) TOU D A, TOU D B, TOU D T and TOU EV 1 Rates with legacy TOU periods being replaced with new TOU rate options with later peak periods Close rates to new customers in February 2019 Migrate grandfathered customers starting in Q Eliminate rates in Q (assess TOU EV 1 in 2022) Replacement for Option TOU D B Updated 4 9pm peak period No baseline credit $16/mo fixed charge Time differentiated distribution charges Tailored for higher usage customers, including those with EVs Change NEM 2.0 TOU default rate from TOU D A to Default Rate 1 Need a replacement default rate since TOU D A will close to new customers in Feb 2019 Analysis showed NEM customers benefit more on Default Rate 1 Ultimately will align NEM 2.0 default rate with TOU default rate adopted for all residential customers Customers can select another TOU rate option 53

54 Small & Medium C&I Rate Design Proposals Available Rate Options TOU GS 1 (20 kw & below) = Option D (formerly B), Option E (formerly A), Option LG (formerly C) & Option CPP Option E is the default rate (may change to Option CPP as proposed in A ) TOU GS 2 (>20 kw to <200 kw) = Option D (formerly B), Option E (formerly R) & Option CPP Option D is the default rate (may change to Option CPP as proposed in A ) TOU GS 3 (200 kw to 500 kw) = Option D (formerly B), Option E (formerly R) & Option CPP Option CPP is the default rate GS APS E = interruptible summer discount plan; incentive levels being determined in A TOU EV 3 / TOU EV 4 = applicable solely to the charging of EVs (will eventually be replaced by TOU EV 7 / TOU EV 8 as proposed in A ); incorporate distribution grid and peak bifurcation RTP = as modified in 2016 RDW proceeding; also include time differentiated distribution charges TC 1 = for traffic control fixtures; maintain 73%/27% volumetric/fixed charge cost recovery split adopted in 2015 GRC Phase 2 proceeding (mitigates bill impacts caused by rev req changes) WTR = wireless technology rate; unmetered rate option Standby = customers must be served on Option D (exception for RES BCT customers); $/kw capacity reservation charge on the monthly Standby demand kw; maintaining Standby algorithm adopted in 2015 GRC Phase 2 proceeding Grandfathered Rates Elimination of TOU GS 3 SOP TOU GS 1 C is only applicable to RES BCT generating accounts Options D and E have a winter SOP period from 8 a.m. to 4 p.m. Rate was previously used to facilitate EV adoption; SCE has proposed new EV rates in A

55 Large Power Rate Design Proposals Available Rate Options Option D = similar to current Option B Option E = similar to current Options A/R Option CPP = default rate Option RTP = as modified in 2016 RDW proceeding; also includes time differentiated distribution charges TOU 8 S = utilizes Option D structure; supplemental & back up charges; continues use of Standby algorithm adopted in 2015 GRC Phase 2 proceeding TOU EV 6 = applicable solely to the charging of EVs (will eventually be replaced by TOU EV 9 as proposed in A ); incorporate distribution grid and peak bifurcation TOU BIP = credits based on avoided capacity valuation in A TOU 8 RBU = provides customers with an additional service connection for reliability back up service Grandfathered Rates TOU 8 S A is only applicable to RES BCT generating accounts 55

56 Agricultural & Pumping Rate Design Proposals Available Rate Options Option D = similar to current Option B Option E = similar to current Option A but also moves peak capacity portion of distribution design demand into TOU energy charges Option CPP = potentially the new default rate for TOU PA 3 Option RTP = as modified in 2016 RDW proceeding; also include time differentiated distribution charges AP I = credits based on avoided capacity valuation in A Grandfathered Rates (for eligible solar customers) Elimination of Existing SOP Rates Options D and E have a winter SOP period from 8 a.m. to 4 p.m. Indicated willingness in testimony to discuss impacts of no longer offering A&P customers a midnight 6 a.m. everyday SOP rate option Other Proposals Removal of the 500 kw threshold for all TOU PA 3 Agricultural Power Service customers Adding definitions of General Water and Sewerage Pumping to Rule 1 56

57 Street & Area Lighting Rate Design Proposals Available Rate Options LS 1 = utility owned, non metered street lights OL 1 = utility owned, non metered outdoor lighting LS 2 = customer owned, non metered street lights DWL = residential walkway lighting (unmetered) LS 3 = customer owned, metered street lights AL 2 = area lighting (metered) Non Allocated Rev Req Continue to use the annual net book value of street light assets recorded in FERC account 373 to determine the street light non allocated rev req ($76,650,000) Allocation based on MCRR methodology established in D Continue to apply rate change triggers limiting adjustments to non allocated street light revenue adopted in SCE s 2015 GRC Phase 2 proceeding (adjustments limited to 5% for each attrition year): 1. Street light lamp count exceeds 50,000; and/or 2. Street light total facilities count exceeds 8,000; and/or 3. Street light total facilities transfer exceeds 50,000 Modifications to LS 3 & AL 2 Distribution Pole Mounted Rate Option Revert rates back to a flat $/kwh energy charge (reflect proportional contribution to cost of service of forecasted nighttime lighting and daytime loads) Introduce an automatic review of daytime usage (preceding 12 months usage between 8am 4pm cannot exceed 30% of account s total usage) Requirement from 2015 GRC Phase 2 Settlement Agreement Rate option for lamps located on SCE s distribution poles (LS 1 only) Provides a credit of $4.13/lamp Available to transfer cities or non transfer cities who pay a inventory fee of $1.58/lamp 57

58 Economic Development Rate (EDR) Program Size 200 MW Retention, attraction or expansion load located within SCE s service territory Eligibility Non residential, non governmental accounts w/ demands >200 kw Open to Bundled Service, DA and CCA customers Term 5years Proposed Discount 15% off customer s otherwise applicable tariff (OAT) Not proposing an enhanced discount Comparison of Marginal Cost and Retail OAT Average Rate for Standard EDR Bundled Service Customers 58

59 Food Bank Rate Implement food bank rate assistance program required by AB 2218 (Bradford, 2014) and PU Code Section Provide eligible food banks¹ a 20% discount on their OAT bill Appropriately less than 30 35% CARE discount since CARE discount is meant to ensure access to all energy service, whereas AB 2218 only applies to refrigeration needs of perishable items Consistent with the 20% food bank discount adopted by the Commission in SDG&E s recent Phase 2 decision and the policy discussion therein SCE currently has 8 customers that qualify Results in ~$60,000 revenue shortfall, to be recovered from all non CARE customers through the PPPC ¹A qualified eligible recipient agency that has executed an agreement with the State Department of Social Services in order to participate in the Emergency Food Assistance Program administered by the Food and Nutrition Service of the United States Department of Agriculture 59

60 Illustrative Rates / Bill Impacts Exhibit SCE-04A, Appendix B = Illustrative Rates Compares January 2017 rates (current) with Phase 2 rates (proposed) Exhibit SCE-04A, Appendix C = Bill Impacts Histograms 60

61 Models, Tools & Work Papers Work Papers Rate Design Model LOLE Tool GRC Tool

62 Model, Tools & Work Papers Re-served work papers on 11/1 to reflect errata updates Models & Tools Rate Design Model (found in SCE-03 work paper folder) Consists of 15 Excel spreadsheets LOLE Model (found in SCE-02 work paper folder) GRC Tool (found in SCE-02 work paper folder) Provides marginal costs at the hourly level Inputs allow changes in the valuation and distribution of the different marginal costs, enabling the user to identify and visualize the concentration of those costs for each of the 8760 hours of the year Hours are then summarized into time segments of interest, such as seasons, months, specific TOU periods 62

63 Wrap Up / Next Steps

64 Proposed Schedule Activity Date SCE Files Application June 30, 2017 Protests / Responses to Application August 7, 2017 SCE s Reply August 17, 2017 SCE Submits Amended Testimony September 27, 2017 SCE Submits Supplemental Testimony November 1, 2017 Prehearing Conference November 2, 2017 Scoping Memo Issued TBD (after November 14, 2017) ORA Testimony Due February 16, 2018 Other Parties Testimony Due March 16, 2018 Settlement Discussions March through June 2018 Rebuttal Testimony Due All Parties June 2018 Evidentiary Hearings (if necessary) July 2018 Concurrent Opening Briefs August 2018 Reply Briefs August 2018 ALJ Proposed Decision (PD) October / November 2018 Opening Comments on PD 20 Days from Issuance of PD [October / November 2018] Reply Comments on PD 5 Days after Opening Comments [October / November 2018] CPUC Final Decision December

65 Thank You! Contact: Erin Pulgar T: (626)