SCE-03 - Revenue Allocation Proposals · 5 total system revenue requirement to individual rate groups. SCE allocates the unbundled revenue ... 4 rate groups for recovery from bundled

Application No.: A.17-06-XXX Exhibit No.: SCE-03 Witnesses: R. Pardo

R. Thomas

(U 338-E)

Phase 2 of 2018 General Rate Case

Revenue Allocation Proposals

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaJune 30, 2017

SCE-03 – Revenue Allocation Proposals

GRC Phase 2

Table Of Contents

Section Page Witness

-i-

I. REVENUE ALLOCATION ..............................................................................1 R. Pardo

A. Introduction and Summary ....................................................................1

B. Unbundled Revenue Requirements........................................................5

C. Proposed Revenue Allocation ................................................................5

1. Present Rate Revenues ...............................................................6

2. Allocation of FERC-Jurisdictional Transmission Revenue Requirement .........................................6

3. Allocation of CPUC-Jurisdictional Generation and Distribution Revenue Requirements .............................................................................7

a) Generation ......................................................................7

b) CRS Adjustment .........................................................10 R. Thomas

c) Distribution ..................................................................11 R. Pardo

d) Greenhouse Gas ...........................................................14

4. Treatment of Interruptible Credits and Dynamic Pricing Program Imbalances ....................................15

5. Non-Allocated Revenues .........................................................17

6. Allocation of the CARE Discount ...........................................17

7. Allocation of Nuclear Decommissioning and Public Purpose Program Revenue Requirements ...........................................................................19

8. Allocation of the Conservation Incentive Adjustment ...............................................................................20

D. Final Revenue Allocation ....................................................................21

Appendix A Summary of Revenue Allocators ................................................................

SCE-03 – Revenue Allocation Proposals

GRC Phase 2

Table Of Contents (Continued)

Section Page Witness

-ii-

Appendix B Comparison of Revenue Allocation Results Using 2015 GRC Phase 2 Methodologies ......................................................................

1

I. 1

REVENUE ALLOCATION 2

A. Introduction and Summary 3

This exhibit describes the proposed allocation of Southern California Edison Company’s (SCE’s) 4

total system revenue requirement to individual rate groups. SCE allocates the unbundled revenue 5

requirements for generation, transmission, distribution, nuclear decommissioning (NDC), new system 6

generation service (NSGS), and public purpose programs (PPP) to rate groups based on established 7

principles and new proposals discussed in this testimony. 8

In this Application, and as further discussed in Exhibit SCE-01, SCE outlines how it determines 9

distribution and generation revenue allocation consistent with the time-of-use (TOU) periods proposed 10

in Application (A.)16-09-003, Application of Southern California Edison Company for Approval of its 11

2016 Rate Design Window Proposals (2016 RDW), filed on September 1, 2016. In addition, SCE 12

proposes to use a revised methodology for determining distribution and generation marginal cost 13

revenue responsibility (MCRR) that incorporates the marginal cost elements discussed in Exhibit 14

SCE-02. For distribution revenue allocation, SCE proposes to distinguish and split distribution design 15

demand into two sub-components: a grid-related component and a peak-capacity-related component. 16

For generation capacity, in addition to the traditional loss-of-load-expectation (LOLE) methodology 17

used to allocate peak capacity costs, SCE proposes a LOLE allocation that incorporates events 18

associated with a split generation capacity resource that provides both system and flexible ramping 19

capacity needs. Section I.C.3 describes the process and methods SCE will use to establish MCRR for 20

the allocation of distribution and generation revenues. 21

Consistent with its proposal in Phase 2 of its 2015 General Rate Case (GRC), SCE proposes to 22

allocate revenue requirements for delivery services to all retail customers, i.e., bundled service, 23

community choice aggregation (CCA) and direct access (DA) customers, because these services are 24

2

provided to all customers.1 For purposes of comparing proposed revenues with those produced under 1

current rates, SCE divides delivery service revenues between bundled service, DA and CCA customers 2

based on forecasted billing determinants. The revenue requirement for SCE generation is allocated to 3

rate groups for recovery from bundled service customers only, after adjusting for forecasted 4

contributions from DA and CCA customers through the cost responsibility surcharges (CRS). 5

The rates presented in this testimony reflect SCE’s marginal cost revenue allocation, and rate 6

design proposals using the 2017 present rate revenues to establish overall rate levels. The 2017 present 7

rate revenues are derived by applying January 1, 2017 rates to the forecasted 2018 billing determinants. 8

When rates are implemented based on a final decision in this proceeding, they will ultimately reflect 9

SCE’s then-current, authorized revenue requirements. Contributions by DA and CCA customers to the 10

generation revenue requirement will be a function of the individual CRS components authorized in 11

SCE’s annual energy resource recovery account (ERRA) forecast proceedings. The CRS revenues 12

reflected in the present rate revenue calculation represent a weighted average of 2001-2016 vintage 13

years based on SCE’s current DA and CCA participation levels, and the current methodology for 14

determining the CRS, as described in Schedules DA-CRS and CCA-CRS.2 Sales and revenue 15

requirements associated with each vintage year are expected to change as customers return to bundled 16

service or move to DA (assuming the DA cap is unchanged) or CCA service. 17

The generation revenue requirements allocated to each rate group are combined with bundled 18

service delivery revenues and Department of Water Resources (DWR) bond charge revenue 19

requirements to calculate total rate group revenue requirements and to establish class average rates for 20

bundled service under SCE’s revenue allocation proposal. Delivery service revenue requirements for 21

1 Delivery service revenue requirements include transmission and distribution as well as NDC, PPP, and the

NSGC.

2 As described more fully in Exhibit SCE-01, on June 29, 2017, the Commission opened a rulemaking to review, revise and consider alternatives to the power charge indifference adjustment (PCIA). To the extent modifications to the methodology used to determine cost responsibility of DA and CCA customers is modified via this new rulemaking, such modifications may impact revenue allocation in this proceeding or future GRC Phase 2 filings.

3

DA and CCA customers are combined with their CRS obligations to produce total revenue requirements 1

by rate groups and to establish proposed class average rates for DA and CCA service. 2

SCE proposes to allocate its CPUC- jurisdictional revenue requirements for distribution and 3

generation services based on the marginal costs presented in Exhibit SCE-02. Rate designs reflecting 4

the revenue requirement allocated to each rate group and SCE’s forecast of billing determinants for 2017 5

are discussed in Exhibit SCE-04 for both delivery and generation services. 6

Table I-1 presents SCE’s proposed retail system revenue requirement allocation by revenue 7

component using January 1, 2017 revenue requirements, prior to the adjustments to revenue allocation 8

described in Section I.C. 9

Table I-1 Proposed System Retail Revenue Allocation

($ Millions)

Trans. Dist. Gen. NDC PPP DWR BondRetail Total

Total Domestic 435.6$ 2,538.1$ 2,153.3$ 0.3$ 285.6$ 111.0$ 5,523.8$

TOU-GS-1 82.1 384.6 362.7 0.1 43.1 31.7 904.3TC-1 0.5 5.5 3.3 0.0 0.5 0.3 10.1TOU-GS-2 192.3 901.9 812.1 0.1 102.6 79.4 2,088.4TOU-GS-3 100.2 431.9 385.6 0.1 51.5 44.9 1,014.2Total LSMP 375.1 1,723.9 1,563.7 0.3 197.6 156.3 4,017.0

TOU-8-Sec 93.8 378.7 375.6 0.1 47.7 45.6 941.4TOU-8-Pri 56.4 228.7 226.4 0.1 29.4 30.8 571.8TOU-8-Sub 52.0 84.0 218.3 0.1 21.9 32.8 409.2

Total Large Power 202.3 691.5 820.3 0.2 98.9 109.2 1,922.4

TOU-PA-2 17.2 102.7 114.1 0.0 11.0 10.6 255.7TOU-PA-3 11.0 55.8 77.9 0.0 6.6 7.4 158.8Total Ag.&Pumping 28.2 158.5 192.0 0.0 17.7 18.0 414.5

Total Street Lighting 5.5 90.2 34.5 0.0 6.0 4.2 140.3

STANDBY/SEC 2.2 9.9 9.8 0.0 1.2 1.2 24.4STANDBY/PRI 7.6 35.2 33.9 0.0 4.3 4.3 85.3STANDBY/SUB 16.1 39.5 98.3 0.0 8.0 12.3 174.2Total Standby 25.9 84.7 142.0 0.0 13.5 17.9 283.9

Total System $1,072.6 $5,286.8 $4,905.8 $0.8 $619.2 $416.7 $12,302.0

4

Delivery services revenue requirements (consisting of transmission, distribution, NDC, NSGS, 1

and PPP revenues) are allocated to all retail customers, both bundled service, CCA and DA. However, 2

SCE generation revenue requirements are adjusted by the competition transition charge (CTC) and 3

PCIA, recovered from DA and CCA customers, before generation revenues are allocated to bundled 4

service customers. Table I-2 and Table I-3, below, address delivery service and generation revenue 5

requirements separately in order to illustrate functional level revenue requirements. This allows a 6

comparison of SCE’s January 1, 2017 rates to the proposed GRC rates for both bundled service and DA 7

and CCA customers. 8

In Decision (D.) 99-10-057, the Commission explicitly deferred authority to FERC regarding the 9

revenue requirement, cost allocation and rate design for transmission services. SCE’s proposals include 10

the revenue requirement and rate design consistent with the Annual Update Base Transmission rates 11

approved by FERC and effective on January 1, 2017 in Docket Number ER11-3697. Multiplying SCE’s 12

FERC transmission rates (including those reflected in the Transmission Owners Tariff Charge 13

Adjustments (TOTCA))3 by forecasted 2018 billing determinants produces the transmission revenues 14

shown in all revenue allocation tables, which are included for purposes of determining total revenue 15

requirements, by rate group. 16

Estimated unbundled revenue requirements for generation and distribution are allocated to retail 17

rate groups based on marginal costs developed in Exhibit SCE-02. Unbundled NDC, NSGS, and PPP 18

revenue requirements are allocated based on methods adopted in prior proceedings, including those 19

adopted in D.16-03-030. 20

As outlined in Exhibit SCE-01, SCE is currently participating, or will be participating, in other 21

Commission proceedings, including those related to residential rate design, cost responsibility for DA 22

and CCA customers, distributed energy resources (DERs), energy efficiency (EE) programs, and 23

3 TOTCA rate components are updated annually. Reliability Services Balancing Account Adjustment

(RSBAA) and Transmission Revenue Balancing Account Adjustment (TRBAA) components became effective January 1, 2017. The current Transmission Access Charge Balancing Account Adjustment (TACBAA) component became effective June 1, 2016.

5

demand response (DR) programs. The possible impact of these proceedings on SCE’s revenue 1

requirement and allocation proposals in this Application is discussed in Section I.C. SCE proposes to 2

incorporate any authorized changes in revenue requirement or rate design resulting from other 3

proceedings when implementing the final Commission decision in this proceeding. 4

B. Unbundled Revenue Requirements 5

To develop SCE’s proposed 2018 GRC rates and rate structures, SCE used a 2018 total system 6

revenue requirement consisting of the following components: SCE generation, FERC-jurisdictional 7

transmission, distribution, PPP, NDC, DWRBC, and the NSGS. 8

In addition to the allocated revenues, the distribution and PPP rates shown in SCE’s tariffs 9

include credits and surcharges related to specific programs. For example, the discount for residential 10

customers in the California Alternate Rates for Energy (CARE) program is reflected in the distribution 11

revenue component for the domestic rate group while the CARE surcharge, which recovers the resulting 12

distribution revenue deficiency, is recovered through the PPP revenue component. This results in the 13

allocation of a distribution revenue deficiency of roughly $384 million in CARE discounts to other 14

non-CARE residential customers and to other rate groups.4 Similarly, the cost of credits provided to 15

customers who choose non-firm service or participate in other reliability programs are recovered from 16

all customers, which modifies distribution revenue allocation from those derived from the MCRR. 17

The impact of this reallocation is discussed in detail in the following sections. 18

C. Proposed Revenue Allocation 19

This section describes SCE’s revenue allocation proposal for the following CPUC-jurisdictional 20

costs: generation, distribution, NDC, PPP and NSGS. This unbundling of costs is necessary to bill 21

customers for the services they obtain from SCE, and the methodology is consistent with the approach 22

4 CARE surcharge revenue is allocated to all non-CARE customers, including non-CARE domestic customers,

with the exception of street and area lighting customers.

6

previously adopted by the Commission. SCE proposes to allocate CPUC-jurisdictional generation and 1

distribution costs based on system marginal cost revenues using the unit marginal costs developed in 2

Exhibit SCE-02. All other cost components are allocated based on methods approved in prior 3

Commission decisions. 4

1. Present Rate Revenues 5

The development of present rate revenues (PRRs) by rate group is an important step in 6

the revenue allocation process and in evaluating the revenue allocation results. SCE has developed 7

separate forecasts of PRRs for bundled service and DA and CCA customers, as different charges apply 8

to these customers based on the services provided to them. PRRs are based on forecasted 2018 sales and 9

January 1, 2017 (“current”) rates. SCE utilizes the forecast of PRRs for 2018 to compare current rates to 10

proposed rate group average rates in Table I-7 in Section I.D of this exhibit, and for development of the 11

system average percentage (SAP) allocator. 12

2. Allocation of FERC-Jurisdictional Transmission Revenue Requirement 13

For illustrative purposes, SCE derives the total system transmission revenue requirement 14

by multiplying SCE’s FERC-jurisdictional transmission rates, as filed in FERC Docket ER11-3697, by 15

the 2018 forecast retail billing determinants. In addition, currently effective FERC-jurisdictional rates 16

for recovery of the Transmission Revenue Balancing Account Adjustment (TRBAA), Reliability 17

Services Balancing Account Adjustment (RSBAA), and Transmission Access Charge Balancing 18

Account Adjustment (TACBAA) are used to determine the total transmission revenue requirement. 19

The individual transmission rate components are added to the CPUC-jurisdictional distribution, NDC, 20

PPPC and NSGS rates adopted in this proceeding to determine SCE’s total delivery service rates. 21

7

3. Allocation of CPUC-Jurisdictional Generation and Distribution Revenue 1

Requirements 2

Generation and distribution revenue requirements are allocated separately by rate group 3

based on generation and distribution marginal cost revenues, which are developed consistent with the 4

marginal cost principles described in Exhibit SCE-02. SCE proposes to continue allocating the 5

CPUC-jurisdictional revenue components on a functional marginal cost basis, as described in the 6

following sections. 7

a) Generation 8

The generation revenue is comprised of base generation costs as defined by SCE 9

in SCE’s 2018 GRC Phase 1 proceeding (A.16-09-001), and fuel and purchased power (F&PP) expenses 10

determined in the ERRA proceeding. Base generation costs consist of CPUC-jurisdictional generation 11

capital, operation and maintenance (O&M) expense, administrative and general (A&G) expense, and 12

taxes. The F&PP component consist of qualifying facilities (QF) contract costs, inter-utility and 13

bilateral contract costs, procurement-related costs, and DR program costs. 14

SCE develops marginal generation cost revenues based solely on cost drivers 15

reflecting bundled service customers’ usage characteristics within each rate group. Bundled service 16

generation revenues are then assigned to rate groups by multiplying the authorized revenue requirement 17

by the generation marginal cost factors. Total retail generation revenue requirements are separated 18

between bundled service and DA and CCA customers as described above and shown in Table I-2. 19

The development of the bundled service generation marginal cost revenue requirement and allocation 20

factors are shown in work papers and are summarized in Appendix A to this exhibit. 21

SCE’s total generation revenue requirement is allocated to bundled service 22

customers in each rate group based on marginal generation costs, after first being adjusted for expected 23

CRS revenue from DA and CCA customers. SCE is authorized to recover above market generation 24

costs from DA and CCA customers through the CTC and PCIA components of the CRS, as determined 25

using the methodology adopted in decisions issued in the DA Rulemaking, (R).07-05-025.5 CTC and 26

5 See Footnote 2 of this exhibit.

8

PCIA revenues are returned directly to bundled service customers through a reduction in the SCE 1

bundled generation revenue requirement. 2

Generation MCRR represents the combined revenue responsibility associated 3

with both energy and capacity marginal costs. Generation energy MCRR is determined by multiplying 4

marginal energy costs by the forecasted TOU sales in each rate class, where the TOU sales are grouped 5

in the proposed TOU periods. In prior GRCs, SCE’s generation MCRR was comprised of two 6

components: energy and system capacity. Historically, capacity has reflected the costs of a proxy 7

combustion turbine (CT) resource intended to provide additional capacity primarily at the times of 8

system peak. However, as discussed in Exhibit SCE-02, SCE developed a generation capacity 9

framework that accounts for the change in capacity constraints on the system due to the increased 10

procurement of renewable resources.6 Under this framework, a single resource provides both system 11

and flexible capacity needs. The allocation of system and flexible capacity costs is thus based on the 12

relative use of such a resource when providing the specific type of capacity that is required during 13

system peak conditions as well during the ramp period.7 For both system and flexible capacity, SCE 14

uses an LOLE analysis to identify the hours where an event (i.e., loss of peak capacity or loss of ramp 15

capacity) is likely to occur. While the LOLE studies were performed separately for each function, the 16

two studies were combined to simulate the pattern of events that would emerge if a single resource was 17

called upon to perform both functions over the course of a year. Using the resulting LOLE distribution 18

for peak and ramp events, SCE assigned the total value of capacity of the hours over a year. 19

As described in SCE-02, approximately 60 percent of the CT resource unit marginal costs (on a 20

dollar-per-kW-yr basis) are allocated to the system capacity function, and the balance (approximately 40 21

percent) is allocated to ramp capacity function.8 22

6 To comply with the increased Renewables Portfolio Standard (RPS) mandates as discussed in Exhibit

SCE-01, there is an increased procurement of renewable supply resources that have caused excess generation predominantly during mid-day periods. System capacity constraints tend to also be driven by the times of system ramp as more of these resources come online. Ramp is the portion of the duck curve where there is a general propensity for renewable resources to go offline, while system load remains steady or is increasing gradually.

7 SCE determines ramp events consistent with the CAISO Flexible Resource Adequacy Criteria Must Offer Obligation (FRAC-MOO) guidance document as the maximum three-hour positive ramp in a day. See https://www.caiso.com/informed/Pages/StakeholderProcesses/FlexibleResourceAdequacyCriteria-MustOfferObligations.aspx.

8 Exhibit SCE-02, p. 23.

9

In determining the overall generation capacity MCRR, SCE applies the functional 1

level unit marginal costs to their respective cost drivers represented by MWs of demand at the time of 2

system peak or ramp. As discussed in Exhibit SCE-01, the increased procurement of renewables has 3

added an abundance of renewable generation supply during daylight hours. Excess supply is most 4

limited in the late afternoon and early evening hours. As a result, generation marginal costs are 5

increasingly correlated to the evolving net load curve as California’s policy mandates require the 6

integration of an increasing amount of renewable energy into California’s resource mix.9 When 7

allocating generation capacity costs to rate groups, it is therefore essential to identify the hours that are 8

critical to the peak and ramp constraints reflected in the net load curve. Allocation to peak capacity and 9

flexible capacity costs are based on the relevant top 100 hours of net loads.10 Rate group contributions 10

in these top 100 hours were determined by ranking the hours for the proxy 2021 net loads, derived using 11

the 2015 gross load and the forecasted distributed generation, EV load, and utility scale renewable wind 12

and solar supply for the year 2021. This results in a proxy 2021 net load curve that can be directly 13

linked to the rate groups’ 2015 recorded loads. Based on the 2021 net load proxy, SCE identified the top 14

100 peak net load hours for peak capacity costs and top 100 largest 3-hour net load ramp hours for 15

flexible capacity costs.11 Rate group contributions were then derived for these hours. For peak capacity 16

costs, allocation is based on the average rate group load (MW) during the top 100 net load hours of the 17

year as a percent of the total average net loads in the top 100 hours. For flexible capacity costs, 18

allocation is based on the three-hour average rate group load (MW) as a portion of the total three-hour 19

average load during the top 100 largest 3-hour net load ramp hours of the year.12 This process results in 20

9 The net 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 difference between gross load minus the forecast of distributed generation load, plus the forecast of EV load.

10 Historically, generation followed load and therefore generation capacity constraints typically corresponded to the top-100 peak demand hours in a given year, measured as the level of customer driven load on the system. With increased integration of renewable resources that have minimal to no load-following capability, generation marginal costs (energy and capacity) are increasingly correlated to the net load curve.

11 The size of the ramp is defined as total change in MWs over a continuous 3-hour period. For the top 100 ramps, each of the three rank ordered net load hours is selected.

12 Because SCE utilizes the same definition of ramp consistent with the CAISO’s maximum three-hour net load ramp in the day, when estimating rate group contributions to flexible capacity costs, SCE averages the rate group load (MW) across all three hours of the ramp.

10

a peak-related generation capacity MCRR of 76 percent, and a flexible generation capacity MCRR of 24 1

percent. 2

The final generation allocation factors represent each rate groups’ proportional 3

contribution to total generation-related marginal costs, inclusive of energy, system capacity and flexible 4

capacity costs. In this Application, generation energy comprises 58 percent of generation MCRR, with 5

capacity comprising the balance of 42 percent. 6

For the purposes of generation revenue allocation, the supplemental billing 7

determinants for the Standby rate group are moved to their corresponding Non-Standby rate class 8

(TOU-8-SEC, TOU-8-PRI, and TOU-8-SUB), and the MCRR for the Non-Standby rate class is 9

calculated with that group’s cost drivers. The back-up billing determinants alone comprise the Standby 10

rate group for purposes of revenue allocation. This methodology was adopted in SCE’s 2015 GRC.13 11

b) CRS Adjustment 14 12

The revenue levels shown in Table I-1 reflect full cost responsibility for bundled 13

service customers, and assume the CRS is set at levels consistent with Resolution E-4475 and the 2017 14

ERRA Market Price Benchmark. 15

The allocation of the generation revenue requirement, including the revenue 16

adjustments attributable to PCIA and CTC revenues, is shown in Table I-2. The CRS is calculated 17

according to the methodology set forth in Resolution E-4475, which compares the total portfolio costs 18

with the market price benchmark (MPB) to determine the above market costs, and includes the use of an 19

RPS adder in determining the MPB.15 DA and CCA customers are assigned a vintaged CRS, reflecting 20

cost responsibility applicable to the timing of their departure from bundled service, pursuant to 21

D.08-09-012. As noted above, the CRS revenues included in this proposal reflect the weighted average 22

CRS revenue from 2001-2016 vintage DA and CCA customers. 23

13 D.16-03-030, p. 27.

14 See Footnote 2.

15 See D.11-12-018, Ordering Paragraphs (OPs) 4 and 5.

11

Table I-2 Retail Generation Services – Revenue Allocation

($ Millions)

c) Distribution 1

The distribution revenue requirement is allocated to rate groups based on 2

distribution marginal cost revenues. Because all retail customers, bundled service, CCA and DA alike, 3

utilize SCE’s distribution services, the distribution revenue requirement is allocated based on 4

distribution marginal cost revenues reflecting total retail load on the distribution system. Distribution 5

revenue requirements directly assigned to particular rate groups, referred to as non-allocated revenues, 6

are removed prior to allocation. Examples of non-allocated distribution revenues include revenues 7

Preliminary Retail Total

SCE Bundled Generation

DA/CCA Generation

Contribution

DA/CCA CTC/PCIA

Total Domestic 2,153.3$ 2,165.7$ (15.8)$ 3.3$

TOU-GS-1 362.7 364.4 (2.7) 1.0 TC-1 3.3 3.3 (0.0) 0.0 TOU-GS-2 812.1 809.9 (5.9) 8.1 TOU-GS-3 385.6 382.4 (2.8) 6.0 Total LSMP 1,563.7 1,560.0 (11.4) 15.1

TOU-8-Sec 375.6 371.4 (2.7) 6.9 TOU-8-Pri 226.4 223.5 (1.6) 4.6 TOU-8-Sub 218.3 216.1 (1.7) 3.9

Total Large Power 820.3 810.9 (6.0) 15.4

TOU-PA-2 114.1 114.7 (0.8) 0.2 TOU-PA-3 77.9 78.4 (0.6) 0.1 Total Ag.&Pumping 192.0 193.1 (1.4) 0.3

Total Street Lighting 34.5 34.8 (0.3) 0.0

STANDBY/SEC 9.8 9.8 (0.1) 0.1 STANDBY/PRI 33.9 33.1 (0.2) 1.0 STANDBY/SUB 98.3 98.3 (0.6) 0.6 Total Standby 142.0 141.2 (0.9) 1.7

Total System $4,905.8 $4,905.8 ($35.8) $35.8

Allocated Generation Revenue

12

associated with the recovery of power factor costs and street lighting facilities costs. The resulting 1

distribution revenue is then allocated to all rate groups in the same manner as generation revenues 2

except that SCE utilizes the distribution cost allocator described below. The unit marginal costs of 3

distribution, developed in Exhibit SCE-02, are multiplied by the appropriate cost drivers to produce 4

marginal distribution cost revenues by rate group. 5

Distribution MCRR is traditionally comprised of two parts, the customer and the 6

design demand marginal cost revenues. In this Application, SCE is proposing a time-related component 7

of the distribution design demand marginal costs. Traditionally, SCE determined the customer cost 8

MCRR by multiplying the marginal customer costs times the number of forecasted customers. 9

This methodology remains the same; however, the design demand portion now includes a two-part 10

allocation, where one component is associated with grid-related costs and the second with peak 11

capacity-related costs. The grid-related MCRR is determined using the current methodology based on 12

the product of the rate group non-coincident demand (MW), the effective demand factors (EDFs), and 13

the grid-related components of distribution design demand marginal costs. The distribution peak 14

capacity-related MCRR is determined through a new methodology, called the Peak Load Risk Factor 15

(PLRF), which is similar in concept to the LOLE methodology used in the allocation of generation 16

capacity.16 As discussed in Exhibit SCE-02, the PLRF represents a relative measure of the time-17

sensitive nature of peak capacity constraints on the distribution system.17 The distribution peak MCRR 18

is determined using PLRF-weighted average rate group load (MW) during the peak load risk hours of 19

the year.18 20

16 Similar to the LOLE methodology, the PLRF is a deterministic variant that allocates the distribution peak-

capacity-related marginal costs across the hours of the year.

17 As described in SCE-02, hourly PLRF profiles were developed for each cost component (distribution and subtransmission) and the relevant peak capacity asset type (circuits, distribution substations (B-banks)), and subtransmission substations (A-banks).

18 Rate group load at the system level was identified for each of the 8760 hours of the year. The rate group contribution in each hour to relevant peak-capacity-related distribution marginal costs was then calculated as the product of the system level rate group load and the PLRF estimated in each hour. This PLRF-weighted estimate of rate group load was derived for each asset type.

13

Therefore, the total distribution MCRR costs are comprised of the marginal 1

customer, grid-related design demand, and distribution peak-capacity-related design demand revenues 2

by rate class. These marginal cost revenues are then summed, by rate group, and the ratio of each rate 3

group’s marginal distribution cost revenues to the system total produces the distribution cost allocator. 4

Multiplying these allocation factors by the distribution revenue requirement produces distribution 5

revenue requirement by rate group. Non-allocated revenues are then assigned to the appropriate rate 6

groups to complete the allocation of the distribution revenue requirement. 7

SCE includes Self-Generation Incentive Program (SGIP) costs in distribution 8

revenue requirements for all non-CARE and non-FERA (Family Electric Rate Assistance) usage. 9

Consistent with the methodology approved in D.16-03-030, SCE first allocates the authorized SGIP 10

revenue requirements by rate group based on each rate group’s proportion of system average percent 11

change (SAPC) revenues, excluding CARE and FERA customers, and street light facilities. Allocating 12

the SGIP costs based on SAPC revenues, which exclude CARE, FERA19 and street light facilities, 13

spreads the cost of the discounts and/or statutory exemptions for these customers across all rate groups, 14

as opposed to maintaining the cost of the exemption within the residential rate group. This treatment is 15

consistent with the methodology adopted by the Commission in Pacific Gas and Electric Company’s 16

(PG&E’s) GRC in D.07-09-004. Consistent with the methodology approved in D.16-03-030, NSGS 17

revenue requirements are allocated using the 12-month system coincident peak (12-CP), and DR 18

revenue requirements are allocated such that 50 percent of the DR revenue requirements are allocated by 19

each rate group’s proportional share of system revenues, with generation revenues for DA and CCA 20

customers imputed as bundled, and the remaining 50 percent of the DR revenue requirements allocated 21

on the basis of distribution marginal cost revenues. 22

Retail delivery services revenues, including a proposed allocation of distribution 23

revenues as described above, are shown in Table I-3. The development of the retail service distribution 24

19 Per D.15-07-001, eligible FERA customers receive a 12 percent discount off the non-CARE bill.

14

marginal cost revenue requirement and allocation factors is shown in work papers and summarized in 1

Appendix A to this exhibit. 2

Similar to generation, for the purposes of distribution revenue allocation, the 3

supplemental billing determinants for the Standby rate group are moved to their corresponding 4

Non-Standby rate class (TOU-8-SEC, TOU-8-PRI, and TOU-8-SUB), and the MCRR for the 5

Non-Standby rate class is calculated with that class’ cost drivers. The details of Standby rate design are 6

discussed in Exhibit SCE-04. 7

d) Greenhouse Gas 8

SCE proposes to implement the greenhouse gas (GHG) allowance revenue 9

allocation methodology adopted in D.12-12-033 and D.13-12-041. D.12-12-033 adopted a methodology 10

for allocating GHG allowance revenues received by California’s investor-owned utilities as part of 11

California’s Cap-and-Trade Program. GHG allowance revenues are allocated to all applicable customer 12

groups as set forth in D.12-12-033, inclusive of DA and CCA customers as required by the Cap-and-13

Trade regulation. GHG compliance costs are included in the generation component of rates, and are 14

allocated by generation MCRR ratios to bundled service customers only. 15

For the purpose of this filing, SCE is including the authorized 2017 semi-annual 16

California Climate Credit amount,20 and modifies all residential rate schedules and applicable small 17

business general service and agricultural and pumping rate schedules to include the volumetric dollars 18

per kilowatt hour (kWh) distribution rate credit to offset all of the authorized portions of the 19

Cap-and-Trade costs in generation rates. SCE includes the allocated generation cost dollars per kWh in 20

rates to collect authorized Cap-and-Trade costs. 21

20 Currently, residential customers receive an authorized semi-annual California Climate Credit of $31.00 on

their April and October 2017 billing statements.

15

Table I-3 Proposed System Retail Delivery Services – Revenue Allocation

($ Millions)

4. Treatment of Interruptible Credits and Dynamic Pricing Program Imbalances 1

SCE currently offers several interruptible programs for large power and agricultural and 2

pumping customers, as well as an air conditioner cycling (AC cycling) program that allows SCE to cycle 3

air conditioning units of participating residential and commercial customers. The interruptible and AC 4

cycling tariffs provide credits to participating customers in return for the customers’ obligation to curtail 5

load when required by SCE or the CAISO. These programs benefit all retail customers by providing 6

additional generation capacity during critical periods. Thus, the credits provided to program participants 7

are allocated to, and recovered from, all rate groups in distribution rates. By adjusting distribution rates 8

this way, SCE ensures that all retail customers share the cost, as well as the benefit, of load curtailment 9

Tran. Dist. NDC PPP DWR BCRetail Total

Total Domestic 435.6$ 2,538.1$ 0.3$ 285.6$ 111.0$ 3,370.6$

TOU-GS-1 82.1 384.6 0.1 43.1 31.7 541.6TC-1 0.5 5.5 0.0 0.5 0.3 6.8TOU-GS-2 192.3 901.9 0.1 102.6 79.4 1,276.3TOU-GS-3 100.2 431.9 0.1 51.5 44.9 628.6Total LSMP 375.1 1,723.9 0.3 197.6 156.3 2,453.2

TOU-8-Sec 93.8 378.7 0.1 47.7 45.6 565.8TOU-8-Pri 56.4 228.7 0.1 29.4 30.8 345.4TOU-8-Sub 52.0 84.0 0.1 21.9 32.8 190.9

Total Large Power 202.3 691.5 0.2 98.9 109.2 1,102.1

TOU-PA-2 17.2 102.7 0.0 11.0 10.6 141.6TOU-PA-3 11.0 55.8 0.0 6.6 7.4 80.9Total Ag.&Pumping 28.2 158.5 0.0 17.7 18.0 222.5

Total Street Lighting 5.5 90.2 0.0 6.0 4.2 105.8

STANDBY/SEC 2.2 9.9 0.0 1.2 1.2 14.6STANDBY/PRI 7.6 35.2 0.0 4.3 4.3 51.5STANDBY/SUB 16.1 39.5 0.0 8.0 12.3 75.9Total Standby 25.9 84.7 0.0 13.5 17.9 142.0

Total System $1,072.6 $5,286.8 $0.8 $619.2 $416.7 $7,396.2

16

programs.21 These cost-based credits are allocated to rate groups based on the marginal cost of 1

generation methodology.22 Total allocated revenues, as described in prior sections, are adjusted to 2

reflect these credits and the corresponding surcharges for these programs. For the purpose of revenue 3

allocation, SCE used the incentives proposed in its 2018-2022 DR Programs Funding Application 4

(A.17-01-018) to determine the amount of incentive revenue that would need to be recovered through a 5

surcharge. SCE will update its assumption regarding incentive revenues based on a final decision in 6

A.17-01-018. 7

SCE also offers dynamic pricing rate options such as the Peak Time Rebate (PTR) 8

program, also known as “Save Power Day,” for residential customers, and Critical Peak Pricing (CPP) 9

rates for residential and non-residential customers. Both PTR and CPP provide incentives to customers 10

to reduce load during critical peak events. For the PTR program, customers receive credits when they 11

reduce usage below an average customer-specific reference level during an event. For the CPP program, 12

however, customers receive a significantly higher capacity-based energy charges during CPP event 13

periods in exchange for lower rates for non-event period usage or a credit applied to time-related 14

demand charges. Both programs can result in revenue imbalances. Consistent with D.16-03-030, SCE 15

proposes to assign the PTR credits to be recovered from all rate groups through the ERRA balancing 16

account mechanism. SCE will continue to use the same methodology to address revenue deficiencies 17

associated with the CPP program. Specifically, because the CPP programs are designed not to account 18

for revenue deficiencies (unlike PTR), any revenue deficiencies due to actual response by CPP 19

customers are recovered through the ERRA balancing account. 20

21 D.02-11-022, OP 28, p. 138.

22 Because the cost of these programs are recovered from all retail (i.e., bundled and departing load) customers, SCE allocates the revenue associated with program credits based on the marginal cost of generation revenue requirement for all retail sales.

17

5. Non-Allocated Revenues 1

Whereas allocated distribution revenues are spread to all customer groups based on 2

distribution marginal cost, non-allocated revenues are assigned directly to particular rate groups and are 3

intended to recover the cost of equipment or services that are incurred solely for the benefit of that rate 4

group. Non-allocated revenues consist solely of street light facilities’ costs and power factor adjustment 5

revenues. SCE assigns these revenues directly to the specific rate groups responsible for incurring the 6

costs. To keep rates stable for street light customers, SCE proposes to set the non-allocated revenue 7

requirement at $76,650,000, which is a 5 percent escalation on the non-allocated revenue requirement 8

reached in the 2015 GRC Phase 2 Streetlight and Traffic Control Rate Group Settlement Agreement.23 9

6. Allocation of the CARE Discount 10

Based on CARE rates approved in D.16-03-030, the CARE program currently provides 11

an approximately 32.5 percent effective discount to participating low-income residential customers.24 In 12

this Application, SCE proposes to set the CARE discount based on the methodology adopted in the 13

D.15-07-001. CARE discounts are funded by a surcharge added to all non-participating customers’ rates 14

(i.e., excluding street and area lighting and CARE customers) and will continue as required by Public 15

Utilities Code Section 382. SCE proposes to apply the methodology adopted in D.06-06-067 to 16

determine the cents-per-kWh discounts received by residential CARE customers, resulting in a 17

deficiency of approximately $384 million when applied to forecasted 2018 CARE-eligible sales.25 The 18

costs associated with the CARE discount are allocated to other rate groups based on each rate group’s 19

23 See Section 4.B.3 of the Streetlight and Traffic Control Rate Group Settlement Agreement, dated October 6,

2015.

24 This amount represents the total effective discount. In determining the discount amount recovered by other rates groups, exemptions for the DWR bond charge are taken into account. The commercial CARE program provides a discount to eligible customers served on commercial tariff schedules.

25 The $384 million reduction to distribution revenue requirement is offset by the recovery of an equivalent amount through the PPP charge (see Table I-6). SCE transfers this revenue to the distribution ratemaking account to ensure recovery of the authorized distribution revenue requirement.

18

percentage of total system kWh sales. The kWh sales associated with CARE and street lighting 1

customers are removed before the CARE surcharge is allocated to all other customers. 2

Allocated distribution revenues, adjusted to reflect the treatment of interruptible and AC 3

cycling programs and CARE discounts, as well as the reallocation of street lighting facilities costs, are 4

shown in Table I-4. 5

Table I-4 Retail Distribution Services – Revenue Allocation (Adjusted)

($ Millions)

Preliminary Retail Dist.

Allocated Dist.

Non-Allocated

Dist.

Interruptible and APS Credits

Interruptible and APS

Surcharges

CARE/DE Program Discount

Retail Total

Total Domestic 2,538.1$ 2,538.1$ -$ (42.3)$ 52.9$ (383.6)$ 2,165.1$

TOU-GS-1 384.6 384.6 - (1.1) 9.1 (0.0) 392.5 TC-1 5.5 5.5 - - 0.1 - 5.6 TOU-GS-2 901.9 901.9 0.0 (6.0) 22.5 (0.2) 918.2 TOU-GS-3 431.9 423.5 8.4 (8.7) 12.4 - 435.7 Total LSMP 1,723.9 1,715.5 8.4 (15.8) 44.1 (0.3) 1,752.0

TOU-8-Sec 378.7 371.4 7.3 (20.1) 12.3 - 370.8 TOU-8-Pri 228.7 224.2 4.6 (17.1) 8.1 - 219.7 TOU-8-Sub 84.0 80.4 3.7 (22.8) 8.1 - 69.4

Total Large Power 691.5 675.9 15.6 (59.9) 28.4 660.0

TOU-PA-2 102.7 102.7 0.0 (4.0) 2.8 - 101.5 TOU-PA-3 55.8 54.2 1.6 (2.6) 2.0 - 55.2 Total Ag.&Pumping 158.5 156.9 1.6 (6.6) 4.8 156.7

Total Street Lighting 90.2 13.5 76.7 - 0.9 - 91.1

STANDBY/SEC 9.9 9.8 0.2 (0.5) 0.3 - 9.7 STANDBY/PRI 35.2 34.3 0.9 (1.5) 1.1 - 34.8 STANDBY/SUB 39.5 32.1 7.4 (8.9) 3.0 - 33.6 Total Standby 84.7 76.2 8.5 (11.0) 4.5 - 78.2

Total System $5,286.8 $5,176.0 $110.8 ($135.6) $135.6 ($383.9) $4,903.0

Adjustments to Allocated Distribution Revenue

19

7. Allocation of Nuclear Decommissioning and Public Purpose Program Revenue 1

Requirements 2

Pursuant to D.00-06-034, the NDC revenue requirement is allocated for recovery from all 3

retail customers to rate groups on an equal cents-per-kWh basis.26 The Commission found this 4

allocation methodology, which is based on each rate group’s total energy consumption, furthers its 5

policy of functionalizing costs.27 Allocated NDC revenues, by rate group, are shown in Table I-3. 6

SCE proposes to retain the current allocation methodology for the PPP revenue 7

requirement, assigning these revenues to rate groups on a SAP method with generation revenues for DA 8

and CCA customers imputed as if they were bundled service customers, which allocates costs to rate 9

groups in proportion to total system revenues. Rate group-level revenue, based on current rate levels, is 10

divided by total system revenues to develop the SAP allocation factors. The SAP allocation factors are 11

multiplied by the PPP revenue requirement, minus the CARE balancing account balance, to determine 12

the revenue allocated to each rate group. Revenue deficiencies associated with the CARE program are 13

tracked in the CARE balancing account. These revenues are allocated separately from the other PPP 14

revenues in order to exclude CARE and street lighting customers from recovery of this component. 15

The CARE balancing account revenues are allocated to the other non-exempt rate groups based on each 16

group’s share of total annual energy sales (excluding the exempt groups), in the same manner used to 17

develop going-forward CARE surcharges. In addition, pursuant to D.99-06-058,28 SCE reflects the 18

CARE surcharge in the PPP revenue component. Revised retail PPP revenues are shown in Table I-5, 19

below. The development of allocation factors for NDC and PPP are shown in work papers and 20

summarized in Appendix A to this exhibit. 21

26 D.00-06-034, p. 61.

27 D.00-06-034, p. 57.

28 D.99-06-058 adopted a stipulation between the Office of Ratepayer Advocates (ORA) and SCE regarding allocation and recovery of the CARE surcharge in the PPP charge.

20

8. Allocation of the Conservation Incentive Adjustment 1

The Commission approved the Conservation Incentive Adjustment (CIA) rate component 2

in D.09-08-028. The CIA restructured residential rates by moving the tiered rate differential to the CIA 3

component, which is reflected in the delivery portion of the bill, and by removing the tiered differential 4

from the generation rate. The CIA is designed to be revenue neutral within the residential rate group. 5

Any revenue imbalance produced by the CIA component is directly assigned and combined with the 6

residential PPP charge. 7

Table I-5 Retail Public Purpose Services – Revenue Allocation (Adjusted)

($ Millions)

Preliminary PPP Total

PPP TotalPPP CARE Balancing

CARE/DE Program

Surcharge

Retail Total

Total Domestic 285.6$ 293.1$ (7.5)$ 103.3$ 388.9$

TOU-GS-1 43.1 45.0 (1.9) 29.5 72.7 TC-1 0.5 0.5 (0.0) 0.3 0.8 TOU-GS-2 102.6 107.0 (4.5) 73.9 176.4 TOU-GS-3 51.5 53.7 (2.2) 41.8 93.2 Total LSMP 197.6 206.2 (8.6) 145.5 343.1

TOU-8-Sec 47.7 49.7 (2.1) 42.4 90.1 TOU-8-Pri 29.4 30.6 (1.3) 28.7 58.0 TOU-8-Sub 21.9 22.8 (1.0) 30.6 52.4

Total Large Power 98.9 103.2 (4.3) 101.6 200.6

TOU-PA-2 11.0 11.5 (0.5) 9.9 20.9 TOU-PA-3 6.6 6.9 (0.3) 6.9 13.5 Total Ag.&Pumping 17.7 18.4 (0.8) 16.8 34.5

Total Street Lighting 6.0 6.0 - 0.0 6.0

STANDBY/SEC 1.2 1.3 (0.1) 1.1 2.3 STANDBY/PRI 4.3 4.5 (0.2) 4.0 8.3 STANDBY/SUB 8.0 8.3 (0.3) 11.5 19.4 Total Standby 13.5 14.1 (0.6) 16.6 30.1

Total System $619.2 $641.0 ($21.8) $383.9 $1,003.1

Adjustments to Allocated Public Purpose Revenue

21

D. Final Revenue Allocation 1

Bundled service customers’ bills are composed of charges for delivery service, SCE generation 2

and DWR power charges. Unbundled delivery service revenue requirements reflecting all adjustments 3

described above for transmission, distribution, NDC, PPP, and NSGS are shown in Table I-6. 4

These allocated revenue requirements are the basis for the proposed retail delivery service charges 5

developed in Exhibit SCE-04. Delivery service revenues are allocated based on total retail sales, as 6

these services are provided to both bundled service and DA and CCA customers. To develop a total 7

bundled service average rate, the revenue requirements shown are separated between bundled service 8

and DA and CCA service customers based on the forecasted billing determinants for each rate group. 9

Generation revenues, after adjustment for DA and CCA cost responsibility, are allocated to rate 10

groups as described above based on bundled service sales. Bundled service delivery revenues are 11

combined with generation revenues, by rate group, to produce the total bundled service revenue 12

requirements shown below in Table I-6. 13

22

Table I-6 Proposed Bundled Service – Revenue Allocation

($ Millions)

The revenue requirements utilized for purposes of this exhibit are based on SCE’s present rate 1

revenues, using January 1, 2017 rates multiplied by SCE’s 2018 GRC sales forecast and appropriate 2

billing determinants. SCE filed its 2018 ERRA Forecast Application (A.17-05-006) on May 1, 2017 and 3

will provide an updated revenue requirement that will incorporate the revised consolidated revenue 4

requirements and will more accurately reflect rates that SCE would expect to implement in February 5

2019. 6

Dividing total allocated revenue requirements by forecast 2018 bundled service sales produces 7

SCE’s proposed class average rates for bundled service. These rates are displayed in Table I-7, for 8

comparison purposes with class average bundled service rates derived from the 2018 present rate 9

Transmission DistributionSCE

GenerationDWR Bond NDC PPP

Preliminary Total

Total Domestic 429.5$ 2,137.2$ 2,149.9$ 109.7$ 0.3$ 383.6$ 5,210.2$

TOU-GS-1 79.6 380.2 361.7 30.8 0.1 70.5 922.8TC-1 0.5 5.4 3.3 0.3 0.0 0.7 10.2TOU-GS-2 174.2 828.6 803.9 69.0 0.1 153.3 2,029.1TOU-GS-3 81.2 347.1 379.6 33.9 0.1 70.4 912.3Total LSMP 335.5 1,561.3 1,548.6 133.9 0.2 294.9 3,874.4






Total System $962.9 $4,477.3 $4,870.0 $355.1 $0.7 $881.3 $11,547.3

23

revenue analysis. The current average rates shown in Table I-7 reflect SCE’s January 1, 2017 rates, and 1

incorporate the transmission balancing account adjustments. SCE’s illustrative total system revenue 2

requirement results in a system average change of 0.0 percent for bundled service customers due to SCE 3

holding the revenue requirement constant, with the rate level changes among the rate classes driven by 4

the changes in allocation. 5

Table I-7 Proposed Bundled Service – Average Rates

By Rate Group (¢/kWh)

A comparison of currently effective and proposed class average rates for bundled service for the 6

cost-based allocation shown in Table I-7 indicates average rate impacts ranging from -6.6 percent to 7.2 7

percent. The variation around the system average rate for individual rate groups is primarily the result 8

Current (¢/kWh)

% of SARProposed (¢/kWh)

% of SAR % Change

Total Domestic 18.8 116% 19.6 121% 4.0%

TOU-GS-1 17.7 109% 16.5 102% -6.6%TC-1 18.3 113% 18.1 111% -1.1%TOU-GS-2 17.2 106% 16.2 100% -5.8%TOU-GS-3 15.4 95% 14.8 91% -3.7%Total LSMP 16.9 104% 15.9 98% -5.5%

TOU-8-Sec 13.8 85% 13.4 83% -2.6%TOU-8-Pri 12.6 77% 12.5 77% -0.4%TOU-8-Sub 8.7 54% 9.0 56% 4.0%

Total Large Power 12.0 74% 11.9 74% -0.6%

TOU-PA-2 13.5 83% 13.9 85% 2.3%TOU-PA-3 11.6 71% 12.4 77% 7.2%Total Ag.&Pumping 12.7 79% 13.3 82% 4.1%

Total Street Lighting 17.9 111% 19.0 117% 5.7%

STANDBY/SEC 13.4 82% 13.3 82% -0.4%STANDBY/PRI 13.0 80% 12.9 80% -0.7%STANDBY/SUB 8.4 52% 9.0 55% 6.4%Total Standby 9.8 60% 10.1 62% 3.7%

Total System 16.2 100% 16.2 100% 0.0%

24

of the movement towards full cost-based allocation from current rates,29 in addition to the changes to the 1

marginal cost determinations discussed in Exhibit SCE-02. Because SCE is using a constant revenue 2

requirement in this filing, changes to allocation and average rate levels are primarily driven by changes 3

to the key cost drivers described in Exhibit SCE-02 in addition to the removal caps. 4

For residential customers, the larger than average increase is a result of the capping of revenues 5

assigned to residential customers below their full EPMC level that was part of a settlement approved by 6

D.16-03-030, which now requires greater increases to reach full cost-based levels. Additionally, the 7

higher marginal energy costs (MECs) associated with the 4 p.m. to 9 p.m. period coincide with when 8

residential customers typically experience their peak usage. Customer classes that typically do not peak 9

during the 4 to 9 p.m. period generally experience a slight decrease in generation allocation due to lower 10

MECs in periods where they consume energy. For example, C&I customers who operate businesses 11

during normal business hours of 8 a.m. to 5 p.m. see a decrease in generation allocation. Also, the 12

introduction of flexible capacity throughout the year has allocated a share of generation capacity to rate 13

classes that typically received a smaller (or no) allocation when generation capacity costs were limited 14

to the summer season noon to 6 p.m. period, such as the residential class and street lights. 15

In previous GRCs, the street light rate class was not assigned any allocation of generation 16

capacity due to the top 100 hours typically occurring in the noon to 6 p.m. hours, when street lights have 17

no contribution to system peak hours. With the system peak shifting to later in the day, street lights now 18

contribute to this peak and are allocated some revenue responsibility for generation capacity costs as a 19

result. 20

The agricultural and pumping class increases are also due to the elimination of the rate caps that 21

resulted from the settlement adopted in D.16-03-030, and the fact that this class’ load shape has more 22

usage in the new higher cost periods, which results in a higher allocation of revenues. 23

29 D.16-03-030 adopted caps on the changes in the rate group functional revenue requirements. The proposed

revenue allocations generally eliminate the effect of those caps.

25

The TOU-8 subtransmission rate group increase of 4.0 percent also reflects the impact of prior 1

capping implemented in 2015. These results are illustrative. 2

Appendix A

Summary of Revenue Allocators

A-1

Table A-1 2018 GRC Revenue Allocation

Distribution

Generation (Bundled

Sales)

Generation Energy

(Bundled Sales)

Generation Capacity

(Bundled Sales)

Generation (System Sales)

Energy (with DA)

Energy (without DA)

SAP (with DA)

Total Residential 50.37% 44.15% 38.38% 52.25% 39.02% 32.69% 37.36% 38.86%

TOU-GS-1 7.84% 7.43% 7.81% 6.89% 6.69% 6.99% 7.86% 7.91%TC-1 0.12% 0.07% 0.08% 0.05% 0.06% 0.07% 0.08% 0.08%TOU-GS-2 17.27% 16.51% 17.39% 15.26% 16.63% 17.48% 17.60% 18.81%TOU-GS-3 7.93% 7.80% 8.50% 6.80% 9.16% 9.88% 8.65% 9.44%Total LSMP 33.16% 31.80% 33.78% 29.01% 32.54% 34.42% 34.18% 36.24%

TOU-8-Sec 6.96% 7.69% 8.64% 6.34% 9.19% 10.04% 8.74% 8.74%TOU-8-Pri 4.54% 5.02% 5.70% 4.06% 6.54% 6.79% 5.86% 5.38%TOU-8-Sub 1.23% 5.93% 7.00% 4.44% 7.61% 7.23% 7.38% 4.01%

Total Large Power 12.73% 18.63% 21.34% 14.84% 23.34% 24.06% 21.98% 18.14%

TOU-PA-2 2.05% 2.34% 2.65% 1.90% 2.09% 2.34% 2.65% 2.02%TOU-PA-3 1.03% 1.60% 1.83% 1.27% 1.44% 1.63% 1.84% 1.22%Total Ag.&Pump. 3.08% 3.94% 4.48% 3.18% 3.53% 3.97% 4.49% 3.24%

Total Street Lights 0.21% 0.71% 1.09% 0.17% 0.65% 0.92% 1.01% 1.05%

STANDBY/SEC 0.08% 0.08% 0.10% 0.06% 0.11% 0.27% 0.10% 0.22%STANDBY/PRI 0.23% 0.21% 0.24% 0.17% 0.24% 0.96% 0.25% 0.79%STANDBY/SUB 0.14% 0.48% 0.59% 0.31% 0.57% 2.71% 0.63% 1.46%Total Standby 0.45% 0.77% 0.94% 0.55% 0.92% 3.94% 0.98% 2.47%

SYSTEM 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%

Marginal Cost Revenue Responsibility (MCRR) Other Allocators

A-2

Table A-2 2015 GRC Revenue Allocation

Note: The 2015 GRC cost-based allocators are shown for comparison purposes to the 2018 GRC allocators.

Distribution

Generation (Bundled

Sales)

Generation Energy

(Bundled Sales)

Generation Capacity (Bundled

Sales)


Energy (with DA)

Energy (without DA)

SAP (with DA)








SYSTEM 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%


Appendix B

Comparison of Revenue Allocation Results Using 2015 GRC Phase 2 Methodologies

B-1

In this Appendix, SCE provides revenue allocation tables derived from the distribution

and generation marginal costs methodologies used in the 2015 GRC Phase 2 proceeding applied

to the proposed TOU periods from the SCE’s 2016 RDW Application. The intent of providing

these tables is to illustrate the difference between class-level revenue allocation based on

methods used in previous GRC Phase 2 proceedings and those proposed in this proceeding. SCE

highlights the difference between a single distribution design demand cost component, as used in

previous GRCs, and a bifurcated design demand structure comprised of grid- and peak-related

components. For generation marginal costs, the tables highlight the difference between a

structure based solely on system peak marginal generation capacity costs and pre-RPS generation

energy cost profiles, to one reflective of system and flexible capacity components and generation

energy inclusive of RPS-driven generation oversupply periods.

Table B-1 shows SCE’s 2017 retail system revenue requirement by revenue component

with updated TOU periods, and with MCRR determined using the methodology from the 2015

GRC Phase 2 proceeding. Generation marginal capacity costs are allocated using relative LOLE

values to indicate time-differentiated system capacity value based on the proposed TOU period

definitions. Generation energy MCRR is determined by multiplying marginal energy costs by

the forecasted TOU sales in each rate class, where the TOU sales are grouped in the proposed

TOU period from SCE’s 2016 RDW Application. Distribution MCRR is comprised of customer

and design demand cost components. The customer cost MCRR is calculated by multiplying the

marginal customer costs by the number of forecasted customers, and design demand cost MCRR

is determined based on the product of the rate group non-coincident demand (MW), the effective

demand factors (EDFs), and the design demand marginal costs.

B-2

Table B-1 System Retail Revenue Allocation Using Existing MCRR Methodology

($ Millions)

SCE updated the key inputs used to compute the MCRR based on the methodology from

previous GRCs. The key underlying marginal cost drivers (e.g., marginal energy cost, marginal

customer cost, design demand, $/kW capacity cost, LOLE, etc.) are shown in Tables B-2 and

B-3.

Trans. Dist. Gen. NDC PPP DWR BondRetail Total

Total Domestic 435.6$ 2,549.8$ 2,269.1$ 0.3$ 285.6$ 111.0$ 5,651.3$

TOU-GS-1 82.1 372.0 350.2 0.1 43.1 31.7 879.2TC-1 0.5 5.3 3.0 0.0 0.5 0.3 9.6TOU-GS-2 192.3 897.5 786.7 0.1 102.6 79.4 2,058.6TOU-GS-3 100.2 433.3 370.9 0.1 51.5 44.9 1,000.8Total LSMP 375.1 1,708.2 1,510.8 0.3 197.6 156.3 3,948.3






Total System $1,072.6 $5,286.8 $4,905.8 $0.8 $619.2 $416.7 $12,302.0

B-3

Table B-2

Electricity Usage-Related and Delivery-Related Design Demand Marginal Cost (2018$)

On-Peak Mid-Peak Off-Peak Mid-Peak Off-PeakSuper-Off-

PeakEnergy(¢/kWh)

3.654 4.884 4.397 3.559 4.622 3.906 2.475

Capacity ($/kW-yr.)

154.72 144.68 9.39 0.45 0.19 0.00 0.00

$/kW-yr.

106.77

58.72

Cost Components

Distribution

Subtransmission (Non-ISO)

Cost Components

AnnualSummer Winter

B-4

Table B-3 Customer Marginal Cost (RECC)

(2018$)

Table B-4 illustrates the class average rates derived by dividing total allocated revenue

requirements, shown in Table B-1, by the forecast 2018 bundled service sales. A comparison of

currently effective and proposed (Track 1) class average rates for bundled service for the cost-

based allocation shown in Table B-4 indicates average rate impacts ranging from -9.0 percent to

6.5 percent.

Domestic 124.25

TOU GS-1 196.63

TC-1 195.30

TOU GS-2 1,586.05

TOU GS-3 2,954.84

TOU-8

Secondary 4,236.37

Primary 2,200.81

Sub-Trans 15,322.55

TOU PA-2 1,141.04

TOU PA-3 3,317.24

Meter Street Lights 135.58

Unmetered Street Lights* Per Customer 27.21

LS-1 + Per Lamp 1.39

LS-2 + Per Lamp 0.57

OL + Per Lamp 1.60

DWL + Per Lamp 0.64

*Unmetered Street Light customer marginal cost is a per customer cost plus a per lamp cost.

Customer Costs (2018$) $/Customer/Yr.

B-5

Table B-4 Comparison of Bundled Service Average Rates

By Rate Group (¢/kWh)

This table illustrates the class average rate levels excluding the 2018 GRC Phase 2

proposed marginal cost methodologies. Any changes to allocation and average rate levels shown

in Table B-4 are primarily driven by changes to the key cost drivers and updated TOU periods in

addition to the removal of the caps.

Finally, the development of allocation factors for generation and distribution using the

existing methodology are shown in the Table B-5 below.

Current (¢/kWh) % of SAR

Track 1 (¢/kWh)

% Change from

Current % of SARProposed (¢/kWh)

% Change

from % of SAR

Total Domestic 18.8 116% 20.0 6.5% 124% 19.6 4.0% 121%

TOU-GS-1 17.7 109% 16.1 -9.0% 99% 16.5 -6.6% 102%TC-1 18.3 113% 17.2 -6.0% 106% 18.1 -1.1% 111%TOU-GS-2 17.2 106% 16.0 -7.1% 98% 16.2 -5.8% 100%TOU-GS-3 15.4 95% 14.6 -5.1% 90% 14.8 -3.7% 91%Total LSMP 16.9 104% 15.7 -7.1% 97% 15.9 -5.5% 98%

TOU-8-Sec 13.8 85% 13.2 -4.7% 81% 13.4 -2.6% 83%TOU-8-Pri 12.6 77% 12.2 -3.0% 75% 12.5 -0.4% 77%TOU-8-Sub 8.7 54% 8.8 1.5% 54% 9.0 4.0% 56%

Total Large Power 12.0 74% 11.7 -2.9% 72% 11.9 -0.6% 74%

TOU-PA-2 13.5 83% 13.3 -2.0% 82% 13.9 2.3% 85%TOU-PA-3 11.6 71% 12.0 3.3% 74% 12.4 7.2% 77%Total Ag.&Pumping 12.7 79% 12.7 0.0% 79% 13.3 4.1% 82%

Total Street Lighting 17.9 111% 18.0 0.4% 111% 19.0 5.7% 117%

STANDBY/SEC 13.4 82% 13.1 -1.8% 81% 13.3 -0.4% 82%STANDBY/PRI 13.0 80% 12.8 -1.3% 79% 12.9 -0.7% 80%STANDBY/SUB 8.4 52% 9.0 6.2% 55% 9.0 6.4% 55%Total Standby 9.8 60% 10.1 3.3% 62% 10.1 3.7% 62%

Total System 16.2 100% 16.2 -0.1% 100% 16.2 0.0% 100%

B-6

Table B-5 Summary of Allocators Using Exiting MCRR Methodology

Distribution

Generation (Bundled

Sales)

Generation Energy

(Bundled Sales)

Generation Capacity (Bundled

Sales)


Energy (with DA)

Energy (without DA)

SAP (with DA)








SYSTEM 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%


Documents

SCE-03 - Revenue Allocation Proposals · 5 total system revenue requirement to individual rate groups. SCE allocates the unbundled revenue ... 4 rate groups for recovery from bundled