a.17-06-030 sce 2018 grc phase 2 november 2017 … · • request for access must be su bmitted to...

Overview of Marginal Cost, Revenue Allocation & Rate Design Proposals

November 2, 2017

SCE 2018 GRC Phase 2 WorkshopA.17-06-030

Southern California Edison

Agenda

11:00 a.m. Introductions & Objectives• Safety• Housekeeping Items• GRC Phase 2 Overview & Policy

• Erin Pulgar• Russ Garwacki

Noon Lunch

12:30 p.m. Marginal Cost Overview & Proposals • 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 • Rob Thomas• Shue Cheng

4:00 p.m. Models, Tools & Work Papers • Shue Cheng• Ruben Pardo

4:50 p.m. Wrap Up / Next Steps • Erin Pulgar

5:00 p.m. Conclude

2

Safety, Introductions & Housekeeping Items


Safety

4

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…


Introductions

5

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

Non‐SCE Attendees

• Commission• Customer Advocacy Groups• Phone Attendees


Housekeeping ItemsWorkshop Location: Call‐In Information:Opera Plaza Community Room (626) 543‐6758601 Van Ness Avenue, Suite 2045 Participant Code: 9795462#San Francisco, CA 94102

Application (A.)17‐06‐030 (filed June 30, 2017)• Commissioner Peterman• ALJ Cooke

Exhibits:• SCE‐01 – Policy• SCE‐02 – Marginal Cost 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, SCET: (626) 302‐2509 / M: (626) 863‐3715 / [email protected]

6


Data Request (DR) Process

7

• DRs should be sent to Erin Pulgar at [email protected] and the applicable SCE attorney

• 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 ([email protected]), cc Erin Pulgar ([email protected])

• Confidential data requests require a non-disclosure agreement (NDA)• Contact SCE’s Case Admin ([email protected]), cc Erin Pulgar

([email protected]) to initiate the NDA process

SCE Attorney Subject Area

Russell Archer ([email protected]) Marginal Costs, Revenue Allocation, DA/CCA, Large Power Rate Proposals

Walker “Al” Matthews ([email protected]) Agricultural and Pumping Rate Proposals

Jane Lee Cole ([email protected]) Small Commercial Rate Proposals, Residential Rate Proposals, Street and Area Lighting Proposals

Robin Meidhof ([email protected]) Economic Development Rate Proposal


Objectives

8

• 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

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


GRC Phase 2 OverviewHow Rates Are Determined

10

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 Marginal Costs (MCs) Revenue Allocation Rate Design

Calculate MCs‒ Generation

‒ Capacity‒ Energy

‒ Distribution‒ Design

Demand‒ Customer

Functionalize Cost Categories‒ Generation‒ Distribution‒ Transmission‒ Nonbypassables

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

• Authorized Revenue Requirements = cost of providing utility services thatthe 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 forutility service (e.g., energy charges, demand, charges, customer charges)


Proceeding / Status:

Alignment With Other Proceedings

11

• 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

Phase 2 Impacts:

2016 RDW (A.16‐09‐003)PD expected Dec/Jan

• Dictated requirements for TOU period grandfathering and guidelines for setting TOU periods used in Phase 2 (D.17‐01‐006)

TOU OIR (R.15‐12‐012)Closed

• Provides glidepath for tiered rates

• Default TOU and fixed charge proposals will be filed in December RDW applications

RROIR (R.12‐06‐013)Open / Preparing TOU Default RDW Filings

• Requested funding to implement new customer technology platform (CSRP)

• Necessitates Q1 2019 implementation of Phase 2 decision (and 2016 RDW)

• Impacts certain rate migrations

GRC Phase 1 (A.16‐09‐001)Awaiting PD


Proceeding / Status:

Alignment With Other Proceedings (cont.)

12

• 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

Phase 2 Impacts:

2018‐2020 Demand Response (A.17‐01‐018)PD expected in Nov

• Updated existing EV rates due to uncertainty in TE rate implementation timing

• Proposed to grandfather existing EV customers on dual‐metering/single‐demand‐charge feature when transitioned to new TE EV rates

TE (A.17‐01‐021)Filing Briefs in Nov / Awaiting PD on Priority Projects

• Exhibit SCE‐03 continues to use existing CRS methodology for revenue allocation

PCIA OIR (R.17‐06‐026)Testimony to be filed March 2018; PD scheduled for July 2018


Implementation Constraints

13

2017 2018 2019 2020 2021

Key Regulatory Milestones

Default TOU Pilot AL

Current Rate Transition Plans

Res TOU Opt‐in Pilot Res TOU Default Pilot

Customer ToolsRate Tool enhanced for opt‐out and new rates (Q4) Rate Tool automation

and add Non‐Res

Res/NEM Bill Redesign

Estimated Reg Approval Dates

Section 745 Decision

Plan Analyze Design Build Test Deploy StabilizeCSRP Timeline

400k

CSRP Test Freeze

600k GRC Ph 2/ RDW/ Non‐Res TOU/CPP

Statewide/SCE Messaging for Res TOU*

Planning

Non‐Res Bill Redesign

RDW

GRC Ph2

21k customers Summer Pause

3.43M customers

2017 2018 2019 2020 2021

Appliance Shifter

Text Alerts

Res TOU Full Rollout

CPP 2019/ 2020 Annual Migration

2.5k TOU‐OIR Solar Migration

40k Non‐Solar A,B, and T customers

106k

*Tentative pending CPUC Decision

Rate Findings from Default Pilot

Assigned Com. Ruling on Default Rates

Estimated Filing Dates

Estimated Implementation


Policy Goals

14

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


2018 GRC Phase 2 – What’s New…

15

Updated TOU Periods

(based on 2016 RDW proposals)

• 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

Inclusion of Flexible Generation Capacity

• 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

Time‐Differentiated Distribution

• 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 time‐differentiated distribution rates

• Current: Legacy TOU periods reflecting 12‐6 pm summer weekday peak period

• Proposed: Updated TOU periods reflecting impacts of RPS duck curve

• Current: Peak• Proposed: Peak + Flex

• 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

• Minimizes differences in customer charge when customers move between rate groups due to usage changes

• 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)

New / updated rate design proposals are covered in a later section…


Proposed TOU Periods

16

Season Existing Proposed

On‐Peak Summer Weekdays: 12‐6pm Weekdays: 4‐9pm

Mid‐PeakSummer Weekdays: 8am‐12pm; 6pm‐11pm Weekends: 4‐9pm

Winter Weekdays: 8am‐9pm Weekdays and Weekends: 4‐9pm

Off‐PeakSummer Weekdays: 11pm‐8am

Weekends: AllWeekdays and Weekends: All except 4‐9pm

Winter Weekdays: 9pm‐8amWeekends: All Weekdays and Weekends: 9pm‐8am

Super‐Off‐Peak Winter N/A Weekdays and Weekends: 8am‐4pm

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


Overview of Marginal Costs

18

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)

1. Electricity Usage2. Delivery‐Related Design Demand3. # of Customers

Three Cost Drivers

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)


Marginal Cost Elements

19

CategoryCost Driver Allocation Methodology Proposed Valuation Notes

Generation

Marginal Energy Costs (MECs) Energy Price forecast using production

simulation model (PLEXOS)

Annual: 3.654 ¢/kWhSummer• On‐Peak: 4.884 ¢/kWh• Mid‐Peak: 4.397 ¢/kWh• Off‐Peak: 3.559 ¢/kWhWinter• Mid‐Peak: 4.622 ¢/kWh• Off‐Peak: 3.906 ¢/kWh• SOP: 2.475 ¢/kWh

• Associated with electricity usage cost driver

• Aggregated in TOU periods

Marginal Generation CapacityCosts (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 NERA Regression Method /Peak Load Risk Factor (PLRF) $83.0/kW‐yr • Time‐

differentiated

Grid NERA Regression Method /Effective Demand Factor (EDF) $84.9/kW‐yr

• 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


Marginal Costs - GenerationMarginal Energy Costs (MECs)

20

• 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

• 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

PLEXOS Inputs• 90% of renewable

generation is scheduled in the ISO day‐ahead market

• Small hydro, geothermal and biomass are self‐scheduled; price‐sensitive bids for wind and solar

• CA exports during periods of over‐gen are allowed

Key Assumptions

¹Includes incremental fuel, variable O&M, GHG compliance, start‐up, no‐load fuel costs & costs related to congestion and line losses

Note – additional information on inputs and assumptions can be found in Appendix C of Exhibit SCE‐02A


Marginal Costs – Generation (cont.)Marginal Energy Costs (MECs)

21

RESULTS


Marginal Costs - GenerationMarginal Generation Capacity Costs (MGCCs)

22

• 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)


Marginal Costs – Generation (cont.)Marginal Generation Capacity Costs (MGCCs)

23

• 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



24

LOLE Methodology

Randomly sample ~5% of all daily combinations (wind and solar randomly selected in month)

1 year wind data

30 Load Years

1 year solar data

Evaluate sample for

LOLE by hour for whole year

• Probability that available resources minus outages cannot serve need

Scale needs up or down until a 1-in-10 LOLE is

achieved

• Repeat previous steps after scaling the peak and ramp needs

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

Example draw for a day:All data scaled to energy in study year

30 January 1st 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



25

Results

25

• 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


Marginal Costs - DistributionDesign Demand Marginal Costs (DDMCs)

26

• 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

¹The capacity that SCE’s grid would carry under normal operating conditions

Peak

• 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

Grid

• 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


Marginal Costs – Distribution (cont.)Design Demand Marginal Costs

27

DDMC Methodology• Computed using the incremental cost of adding capacity from the NERA regression method

¹SCE switched to using planned capacity instead of recorded load in 2012 GRC to minimize cost‐to‐growth distortions

FERC Basis of Recording Costs

• Use FERC classification to categorize costs by asset type

• Distribution Plant:• 360‐362 =

Substation Assets• 364‐367 =

Distribution Circuits• Sub‐Transmission Plant:

• 350, 352‐353 = Substation Assets

• 354‐359 = Subtransmission Circuit

NERA Regression Method

• 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)



28

Functionalizing Costs Between Grid and Peak

Distribution Circuits

• 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‐ISO‐

jurisdictional 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%)

• 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

A‐Banks & B‐Banks

• Functionalized as peak costs• Generally planned and designed for peak level of coincident load

SubtransmissionCircuits

• 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)


Errata Testimony – Served 11/1

29

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 andredistributes the O&M between the two asset types

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


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

30


Marginal Costs - DistributionDesign Demand Marginal Costs

31

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

Relating Design Demand Marginal Costs to Measurable Customer Attributes

• PLRF = peak‐capacity driven costs• EDF = grid‐related costs



32

PLRF Methodology (cont.)• Introduced in 2016 RDW proceeding• Basis of assigning a time‐sensitive allocation of peak capacity‐related costs

2

• 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

3

• 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



33

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

Relating Design Demand Marginal Costs to Measurable Customer Attributes

• PLRF = peak‐capacity driven costs• EDF = grid‐related costs

1. # of customers by rate group determined for each circuit

Used to develop typical circuit profiles (calculated for each customer type)

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

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


Marginal Costs - DistributionCustomer Marginal Costs

34

• 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

¹Differences in size, service voltage, metering requirements and other factors

Results are shown in Table I‐22 of Exhibit SCE‐02A


Sales and Customer Forecast

35

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 2018‐2020 period

• Use econometric models to construct sales forecasts for major customer classes

• Forecast produced monthly and summed to an annual value

Revenue Allocation• Overview• Generation• Distribution • Other


Overview of Revenue Allocation

37

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

Comparison of revenue allocation results using 2015 GRC Phase 2 methodologies included in Appendix B of Exhibit SCE‐03A


Revenue Allocation - Generation

38

• 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%)

• 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

Generation Capacity MCRR(42%)

• 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

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.

• Peak‐Related MCRR = 76%• Flex‐Related MCRR = 24%


Revenue Allocation - Distribution

39

• 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


Revenue Allocation - Other

40

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.16‐03‐030

CARE Discount • 32.5% effective discount, based on methodology adopted in D.15‐07‐001• 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.16‐03‐030

GHG • Based on methodology adopted in D.12‐12‐033• Allocating based on authorized 2017 amounts• Allowances set per D.12‐12‐033• 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.06‐07‐029

Non‐Allocated Revenues

• Street light and power factor revenues, directly assigned

DR Rev Req • Consistent with adopted methodology in D.16‐03‐030• 50% based on same allocation as PPPC; 50% based on distribution marginal costs

Treatment of Interruptible Credits / Dynamic Programs

• 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.16‐03‐030

Base Transmission & TOTCA

• FERC uses a 12‐CP methodology• Based on current authorized FERC rates


Revenue Allocation Results

41Note: “DA” also includes “CCA”


Revenue Allocation Results (cont.)2015 GRC Revenue Allocation Comparison

42Note: “DA” also includes “CCA”

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


Overview of Rate Design

45

• 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

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

Residential Rates

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


Rate Design Elements

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Component Non‐Residential Rates Residential RatesCustomer 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 grid‐related 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.17‐09‐035


Rate Design Elements (cont.)

47

Component Non‐Residential Rates Residential RatesEnergy Charges ($/kWh)

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)

Used almost exclusively to recover all costs

Tiered rates = not time‐variant

TOU rates = time‐variant

Time‐Related Demand (TRD)Charges ($/kW)

Time‐variant (coincident)

Used to recover:• Generation capacity (peak and flex) depending on

rate option• Distribution peak‐capacity depending on rate

option

N/A

Facilities‐RelatedDemand (FRD) Charges ($/kW)

Non‐time‐variant (non‐coincident)

Used to recover:• Distribution grid‐related costs depending on rate

option• Higher (>50 kVA) transformer capacity

N/A


Proposed Option D Rate Design

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Current Option B Proposed Option D*Generation Energy • TOU energy charges ($/kWh) • TOU energy charges ($/kWh)

Generation Capacity – Peak• No peak / flex split• Recovered via TRD charges

• Summer on‐peak and winter mid‐peak costs recovered via TRD charges

• Summer mid‐peak and off‐peak costs recovered via TOU energy charges

Generation Capacity – Flex

Distribution Design Demand –Peak

• No peak / grid split• 100% recovered via FRD charge

• 50% recovered via TOU energy charges• Balance of Summer On‐Peak recovered

via TRD charge• Balance of all other periods recovered

via FRD charge

Distribution Design Demand –Grid

• 100% recovered via FRD charge

*TRD charges apply on non‐holiday weekdays only; not on weekends or holidays

“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 mid‐

and 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)


Proposed Option E Rate Design

49

Current Option R Proposed Option EGeneration Energy • TOU energy charges ($/kWh) • TOU energy charges ($/kWh)

Generation Capacity – Peak • No peak / flex split• Recovered via TOU energy charges

• 100% recovered via TOU energy chargesGeneration Capacity – Flex

Distribution Design Demand –Peak

• 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

Distribution Design Demand –Grid

• 100% recovered via FRD charge

• Proposed Option E structure eliminates the needs for separate Option A and Option R structures


Grandfathered Rates

50

D.17‐01‐006 (TOU OIR) adopted TOU period grandfathering for eligible solar customers (slightly modified by D.17‐10‐018)• 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 discussed2. Redistributed the hourly MECs, LOLE generation capacity costs and PLRF distribution‐peak capacity

costs into legacy TOU periods3. Results in underlying TOU marginal cost‐based rates, which are then scaled on a functional basis to

establish the grandfathering rates4. At this stage, grandfathered rates demonstrated inverted pricing differentials between TOU periods5. 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


Demand Response Rates

51

• D.16‐06‐028 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 2018‐2022 DR Application (A.17‐01‐018) but have been restructured to align with the Option D rate structures


Residential Rate Design ProposalsExhibit SCE-06 (Amended Testimony filed September 27)

52

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

1. Basic Baseline Allocation

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 time‐variant 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

2. Time‐Differentiated Distribution Charges

for TOU Rates

Proposal to grandfather eligible customers on existing TOU‐D‐A, TOU‐D‐B, TOU‐D‐T and TOU‐EV‐1 rates• D.16‐01‐044 = NEM 2.0

customers allowed to stay on existing TOU rate for 5 years from the date they commenced service on the rate

• D.17‐01‐006 = Eligible solar customers (excluding NEM 2.0) eligible to retain legacy TOU periods for 5 years from PTO date

• Update underlying MC & RA

3. Grandfathered Rate Options


Residential Rate Design Proposals (cont.)Exhibit SCE-06 (Amended Testimony filed September 27)

53

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 Q4 2020

• Eliminate rates in Q1 2024 (assess TOU‐EV‐1 in 2022)

4. Closing & Eliminating Existing TOU Rates w/ Legacy TOU Periods

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

5. New Optional TOU Rate (TOU‐D‐C)

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

6. Updated Default TOU Rate for NEM 2.0

Customers


Small & Medium C&I Rate Design Proposals

54

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.16‐09‐003)

• 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.16‐09‐003)

• 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.17‐01‐018• 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.17‐01‐021); 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

TOU‐GS‐1‐C is only applicable to RES‐BCT generating accounts

Elimination of TOU‐GS‐3‐SOP

• 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.17‐01‐021


Large Power Rate Design Proposals

55


• 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.17‐

01‐021); incorporate distribution grid and peak bifurcation• TOU‐BIP = credits based on avoided capacity valuation in A.17‐01‐018• 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


Agricultural & Pumping Rate Design Proposals

56


• 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.17‐01‐018

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


Street & Area Lighting Rate Design Proposals

57


• 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.13‐03‐031• 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/or2. Street light total facilities count exceeds 8,000; and/or3. 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


Economic Development Rate (EDR)

58

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 • 5 years

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


Food Bank Rate

59

Implement food bank rate assistance program required by AB 2218 (Bradford, 2014) and PU Code Section 793.3

• 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


Illustrative Rates / Bill Impacts

60

• 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

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


Model, Tools & Work Papers

62

• Re-served work papers on 11/1 to reflect errata updates

• 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

Models & Tools

Wrap Up / Next Steps


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 2018

Proposed Schedule

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Thank You!

Contact: Erin PulgarT: (626) 302-2509

[email protected]

a.17-06-030 sce 2018 grc phase 2 november 2017 … · • request for access must be su bmitted to...

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