Updated Testimony Energy Resource Recovery … Testimony Energy Resource Recovery Account ... 2018...

A.17-05-006

Exhibit No.: SCE-5 Witnesses: T. Cameron S. DiBernardo T. Kimura E. Lavik E. Martinez M. Sheriff R. Thomas D. Wong

(U 338-E)

Updated Testimony Energy Resource Recovery Account (ERRA) 2018 Forecast of Operations PUBLIC VERSION

Before the

Public Utilities Commission of the State of California

Rosemead, California

November 9, 2017

SCE-5: ERRA Resource Recovery Account (ERRA) 2018 Forecast of Operations

Table Of Contents

Section Page Witness

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I. INTRODUCTION .............................................................................................1 S. DiBernardo

II. UPDATED 2018 ERRA FORECAST PROCEEDING REVIEW REQUIREMENT ...............................................................................................3

A. 2018 ERRA Forecast Proceeding Revenue Requirement ......................3

a) ERRA-Related Generation Service Revenue Requirement ...................................................................6

b) ERRA-Related Delivery Service Revenue Requirement ...................................................................7

III. SCE'S BUNDLED ENERGY FORECAST ......................................................8 E. Martinez

A. Retail Sales Forecast Summary .............................................................8

B. Sales Forecast Used for Rate Setting .....................................................9 R. Thomas

C. Total Retail Sales Forecasts by Customer Class ....................................9

D. Customer Forecast .................................................................................9

E. Annual and Monthly Bundled Energy .................................................10

IV. UPDATED FORECAST ENERGY PRODUCTION AND COSTS FROM SCE’S PORTFOLIO OF RESOURCES .............................................12 E. Lavik

A. Introduction ..........................................................................................12

B. Energy Production Forecast Methodology ..........................................12

C. 2018 Energy and Cost Forecast Summary ...........................................14

D. SCE’s Utility-Owned Generation and Purchased Power Contracts ..............................................................................................18

1. Hydro Facilities ........................................................................18

E. Validation of SCE’s Energy Production Forecast ...............................19

1. CHP and Renewables ...............................................................20


Table Of Contents (Continued)


-ii-

a) Energy Forecast ...........................................................20

b) Payment Forecast .........................................................21

c) Energy and Capacity Prices .........................................21

2. Utility-Owned Natural Gas Facilities ......................................22

a) SCE Peakers .................................................................22

(1) Production ........................................................22

(2) Costs .................................................................22

b) Mountainview Generating Station ...............................22

3. New System Generation CAM Contracts ................................23

a) Production ....................................................................23

b) Costs .............................................................................23

4. 2013 Bilateral Contracts Production ........................................23

a) Production ....................................................................23

b) Costs .............................................................................24

5. Generic and Bilateral RA Contracts ........................................24

a) Production ....................................................................24

6. Local Capacity Requirements (LCR) Contracts ......................24

a) Production ....................................................................25

b) Costs .............................................................................25

7. Preferred Resource Pilot (PRP) ...............................................25

a) Production ....................................................................25

b) Costs .............................................................................25

F. CAISO Costs and Short-Term Market Activity...................................25




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1. Short-Term Market Activity Costs ..........................................26

G. Gas Price Sensitivity ............................................................................26

H. Direct GHG Costs ................................................................................27

V. UPDATED FINANCING COSTS ..................................................................28 T. Cameron

A. Commission Decisions Regarding Financing Costs and Collateral Costs ....................................................................................28

B. SCE’s Current Short-Term Financings ................................................28

1. Credit Facilities (Revolvers) ....................................................28

2. Collateral Requirements ...........................................................29

3. Fixed Rate Bonds Supporting Fuel Inventories .......................30

4. Commercial Paper ....................................................................30

5. Costs of Collateral Issuance .....................................................31

C. Additional Options Supporting Collateral ...........................................31

VI. UPDATED CARRYING COSTS....................................................................32 T. Cameron

A. Fuel Inventory Carrying Costs .............................................................32

B. GHG Compliance Carrying Costs .......................................................33

C. Collateral Carrying Costs .....................................................................33

VII. UPDATED 2018 GHG FORECAST COSTS AND REVENUES AND RECONCILIATION ..............................................................................35

A. Overview ..............................................................................................35 M. Sherrif

B. Updated 2018 GHG Emissions and Cap-and-Trade Costs ..................36 T. Kimura

C. Updated 2018 Administrative and Customer Outreach Expenses ..............................................................................................39 M. Sheriff

D. Updated 2018 GHG Allowance Revenue Forecast .............................39 T. Kimura




-iv-

E. Updated 2018 GHG Revenue Return ..................................................41 M. Sheriff

F. Updated 2018 GHG Cost and Revenue Distribution for EITE and Volumetric Returns by Rate Schedule ..........................................44 T. Kimura

VIII. UPDATED 2018 FORECAST REVENUE REQUIREMENT AND RATEMAKING PROPOSAL .........................................................................47 S. DiBernardo

A. Introduction ..........................................................................................47

B. Updated Estimate of 2018 ERRA-Related Generation Service Revenue Requirement ..........................................................................48

1. Updated Estimate 2018 Fuel and Purchased Power Revenue Requirement ..............................................................48

a) Fuel Expense ................................................................50

b) Purchased Power Expense ...........................................50

2. Updated December 31, 2017 ERRA Balance ..........................51

3. Updated Energy Settlement Refunds and Litigation Costs .........................................................................................52

C. Updated 2018 ERRA-Related Delivery Service Revenue Requirement .........................................................................................52

1. Updated New System Generation Net Capacity CAM-Related Cost...................................................................53

2. Updated December 31, 2017 NSGBA Balancing Account ....................................................................................53

IX. UPDATED COST RESPONSIBILITY SURCHARGES (DIRECT ACCESS, DEPARTING LOAD, AND COMMUNITY CHOICE AGGREGATION) ...........................................................................................54 D. Wong

A. Finalization of the 2018 MPB ..............................................................55

B. Implementation of SCE’s Pre-2009 Vintage UOG Proposal ...............56

C. Commission’s Implementation of RA Program Changes ....................57




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D. Implementation of Minor Changes to Common PCIA Template Approved in D.17-08-026 ....................................................58

X. UPDATED PRESENT RATE REVENUE .....................................................59 R. Thomas

Appendix A Estimated December 31, 2017 Balancing Account Balances

Appendix B Indifference Rate Calculation

Appendix C Calculation of Climate Credit Prior to Inclusion of SB92 Methodology

Appendix D Witness Qualifications and Confidentiality Declarations

SCE-5: ERRA Resource Recovery Account (ERRA) 2018 Forecast of Operations List of Tables

Table Page

-vi-

Table II-1 Updated and May 2018 ERRA Forecast Revenue Requirement Changes

($000) .....................................................................................................................................................4

Table II-2 2018 Updated Revenue Requirement vs. Current Rates (October 2017) ($000) .......................5

Table II-3 Updated and May 2018 ERRA Forecast Proceeding Revenue Requirement

Changes ($000) ......................................................................................................................................6

Table III-4 2018 Bundled Customer Load Forecast (GWh) ........................................................................8

Table III-5 Annual Retail Sales by Customer Class (GWh) ........................................................................9

Table III-6 Year-End Customers by Customer Class ................................................................................10

Table III-7 Bundled Energy at CAISO (GWh) ..........................................................................................11

Table IV-8 2018 Energy Forecast of the SCE Portfolio (GWh) Confidential ...........................................15

Table IV-9 2018 Forecast of Fuel and Purchased Power Costs ($000) Confidential ................................16

Table IV-10 Annual Capacity Factors by Technology ..............................................................................21

Table IV-11 2018 Forecast of Posted Energy and Capacity Prices ...........................................................22

Table VI-12 Estimate of 2018 Carrying Costs ($000) ...............................................................................32

Table VI-13 Estimated 2018 Fuel Inventory Carrying Costs ($000) ........................................................33

Table VI-14 Estimated 2018 GHG Compliance Carrying Costs ($000) ...................................................33

Table VI-15 Estimated 2018 Procurement Collateral Carrying Costs ($000) ...........................................34

Table VII-16 SCE’s Updated Forecast of 2018 GHG Emissions Volumes (Metric Tons

CO2e) ...................................................................................................................................................36

Table VII-17 SCE’s Updated Forecast of 2018 GHG Costs ($000) ..........................................................36

Table VII-18 Updated Annual GHG Emissions and Associated Costs (Template D-2) ..........................37

Table VII-19 Updated Weighted Average Cost of GHG Compliance Instruments

Calculation (Template C-1) ................................................................................................................38

Table VII-20 Updated Detail of Outreach and Administrative Expenses (Template D-3) ......................39


List of Tables (Continued)

Table Page

vii

Table VII-21 SCE’s Updated 2018 Forecast Consignment in ARB Auctions (Metric

Tons CO2e ............................................................................................................................................40

Table VII-22 SCE’s Updated Forecast 2018 Allowance Revenue ($000) ...............................................40

Table VII-23 SCE’s Updated Recorded/Forecast 2017 Allowance Revenue ...........................................41

Table VII-24 Updated Annual Allowance Revenue Receipts and Customer Returns

(Template D-1) .....................................................................................................................................43

Table VII-25 Updated GHG Allowance Revenue Allocation by Class ....................................................45

Table VII-26 Updated GHG Costs and Revenues by Rate Schedule (Template D-4) ..............................46

Table VII-27 Updated History of GHG Revenues, Costs, and Emissions Intensity

(Template D-5) .....................................................................................................................................46

Table VIII-28 Updated Estimate of 2018 ERRA Forecast Proceeding Revenue

Requirement ($000) .............................................................................................................................47

Table VIII-29 Updated Estimate of 2018 Fuel and Purchased Power Revenue

Requirement ($000) .............................................................................................................................49

Table VIII-30 Updated Estimate of 2018 Estimated Fuel Expense ($000) ...............................................50

Table VIII-31 Updated Estimate of 2018 Purchased Power Expense ($000) ...........................................51

Table VIII-32 Updated Estimate of 2018 CAM-Related Revenue Requirement ($000) ..........................53

Table IX-33 Comparison of MPBs Over Time..........................................................................................55

Table X-34 SCE 2018 ERRA Forecast Class Average Rates ....................................................................59

Table X-35 Average Generation Rates ......................................................................................................60

1

I. 1

INTRODUCTION 2

The purpose of this Update Testimony is to: (1) update SCE’s Energy Resource Recovery 3

Account (ERRA) 2018 Forecast proceeding revenue requirement, including the kilowatt-hour (kWh) 4

load and sales forecast, fuel and purchased power costs, financing costs, and estimated December 31, 5

2017 balances in applicable balancing accounts; (2) update the 2018 Cost Allocation Methodology 6

(CAM)-related revenue requirement; (3) provide an estimate of the 2018 Cost Responsibility Surcharge 7

(CRS) components for Direct Access (DA), Departing Load (DL), and Community Choice Aggregation 8

(CCA) customers; and (4) update the 2018 Forecast of Greenhouse Gas (GHG)-related costs and GHG 9

allowance revenue and revenue returns to eligible customers. 10

SCE requests the Commission to authorize SCE’s updated 2018 Forecast proceeding revenue 11

requirement in the amount of $4.556 billion based on updated estimates of such factors as kWh sales and 12

load, natural gas and power prices, and an estimate of the December 31, 2017 balancing account 13

balances included in this revenue requirement. 14

In this update, SCE also proposes to return a total of $376.087 million in net available GHG 15

allowance revenues (Line 7 of Table II-1) to eligible customers in 2018 based on the Commission-16

adopted methodologies and utilizing GHG revenues and cap-and-trade costs, including administrative 17

and customer outreach costs, as proposed and supported in this testimony. Based on SCE’s estimated 18

GHG allowance revenues available for return to eligible customers in 2018, residential customers can 19

expect a semi-annual, on-bill California Climate Credit of $36.00 in 2018.1 20

A discussion of SCE’s estimated 2018 ERRA Forecast proceeding revenue requirement and the 21

resulting rate change are presented in Chapter II, and the remaining chapters of this testimony address 22

the following: 23

1 The proposed semi-annual residential California Climate Credit of $36.00 is net of SCE’s 2018 SB92

allocation of GHG revenues for Multi-Family Affordable Housing Solar Roofs Program as discussed in Chapter VII of this exhibit.

2

• Chapter III, SCE’s Updated Bundled Energy Forecast 1

• Chapter IV, Updated Forecast Energy Production and Costs from SCE’s Portfolio of 2

Resources 3

• Chapter V, Updated Financing Costs 4

• Chapter VI, Updated Carrying Costs 5

• Chapter VII, Updated GHG Forecast Costs and Revenues and Reconciliation 6

• Chapter VIII, Updated 2018 Forecast Revenue Requirement and Ratemaking Issues 7

• Chapter IX, Updated Cost Responsibility Surcharges (Direct Access, Departing Load, and 8

Community Choice Aggregation) 9

• Appendix A, Updated Estimated December 31, 2017 Balancing Account Balances 10

• Appendix B, Updated Indifference Rate Calculation 11

• Appendix C, Calculation of Climate Credit Prior to Inclusion of SB92 Methodology 12

• Appendix D, Declarations Regarding the Confidentiality of Certain Data 13

3

II. 1

UPDATED 2018 ERRA FORECAST PROCEEDING REVIEW REQUIREMENT 2

A. 2018 ERRA Forecast Proceeding Revenue Requirement 3

Based on updated forecast costs and assumptions as set forth in this testimony, SCE requests the 4

Commission to authorize an updated 2018 ERRA Forecast proceeding revenue requirement in the 5

amount of $4.556 billion beginning January 1, 2018. This updated 2018 ERRA Forecast revenue 6

requirement represents an increase of $372.1 million from the estimated 2018 ERRA Forecast revenue 7

requirement presented in the May 1, 2017 Application and supporting testimony, and an increase of 8

$70.6 million from the revenue requirement currently reflected in customers’ 2017 ERRA rates. 9

As shown in Table II-1, this Update Testimony presents an increase (as compared to SCE’s 10

initial May filing) in the estimated 2018 fuel and purchased power costs of approximately $28.3 million 11

as described in more detail in Chapter IV, an increase of $293.9 million due to updated estimates of 12

year-end 2017 ERRA and New System Generation (NSG) balancing account balances, an increase in the 13

Energy Settlement Memorandum Account – Net Amount of $0.056 million, and an increase of $49.9 14

million attributable to the net impact of updated GHG cap-and-trade costs and GHG allowance 15

revenues. 16

4

Table II-1 Updated and May 2018 ERRA Forecast Revenue Requirement Changes

($000)

As discussed in more detail below and in Chapter IV, the primary reasons for the increase in the 1

estimated 2018 fuel and purchased power expenses from the amounts included in the May filing are 2

summarized below: 3

1. SCE expects higher fuel-related costs from its natural gas-fueled UOG and tolling resources 4

due to an increase in forecast natural gas prices; 5

2. SCE expects higher open market costs due to higher forecast SP-15 forward market power 6

prices; and 7

3. SCE expects higher Short-Run Avoided Cost (SRAC) payments due to higher forecast market 8

prices. 9

As shown in Table II-2 below, the updated 2018 ERRA Forecast revenue requirement of $4.556 10

billion represents an increase of $70.6 million as compared to the revenue requirement used to set rates 11

in effect today.2 12 2 D.16-12-054 (2017 ERRA Revenue Requirement) implemented January 1, 2017 (Advice Letter 3515-E-A).

Line Description

Updated 2018 Revenue

Requirement

(Filed May 2017) 2018 Proposed

Revenue Requirement

Rev. Req. Change

(a) (b) (c) (d) (e) = (c) - (d)

1. Fuel and Purchased Power 1/ 4,412,513$ 4,384,196$ 28,316$ 2. ERRA Balancing Account 360,872$ (42,764)$ 403,636$ 3. Energy Settlements Memorandum Account - Net Amount 2/ (7,060)$ (7,115)$ 56$ 4. New System Generation Balancing Account (151,822)$ (42,051)$ (109,771)$ 5. SUBTOTAL ERRA-RELATED 4,614,503$ 4,292,266$ 322,238$

6. GHG Cap-and-Trade Costs 317,232$ 264,510$ 52,722$ 7. GHG Allowance Revenues (376,087)$ (373,300)$ (2,787)$ 8. SUBTOTAL GHG-RELATED (58,855)$ (108,790)$ 49,935$

9. TOTAL ERRA PROCEEDING REVENUE REQUIREMENT 4,555,648$ 4,183,476$ 372,172$

1/ Amounts include Spent Nuclear Fuel. 2/ Amount reflects 12/31/17 forecast ESMA refunds less forecast litigation-related costs.

5

Table II-2 2018 Updated Revenue Requirement vs. Current Rates (October 2017)

($000)

Table II-3 below compares the Update Testimony and May 2017 Application revenue 1

requirements in more detail, and includes the functionalization between the generation service and the 2

delivery service revenue requirements. The change in SCE’s updated forecast 2018 fuel and purchased 3

power cost estimate compared to the May Application is an increase of $28.3 million, as discussed in 4

Chapter IV. 5

Table II-3 also shows the change in the 2018 ERRA Forecast proceeding revenue requirement 6

resulting from changes in the December 31, 2017 estimated balances in the ERRA balancing account, 7

the Energy Settlements Memorandum Account (ESMA) net of the estimated balance in the Litigation 8

Cost Tracking Account (LCTA), and the NSG Balancing Account (NSGBA), using recorded data 9

through October 31, 2017, and estimated November through December 2017 activity. As indicated in 10

Table II-3 the updated cumulative balances in these three accounts results in a $293.9 million increase 11

from the estimated December 31, 2017 balances included in the May Application. Appendix A, 12

Line Description


Requirement In Rates Change(a) (b) (c) (d) (e) = (c) - (d)

1. Fuel and Purchased Power 1/ 4,412,513$ 4,584,334$ (171,821)$ 2. ERRA Balancing Account 360,872$ (94,007)$ 454,879$ 3. Energy Settlements Memorandum Account - Net Amount 2/ (7,060)$ -$ (7,060)$ 4. New System Generation Balancing Account (151,822)$ 8,896$ (160,718)$ 5. SUBTOTAL ERRA-RELATED 4,614,503$ 4,499,222$ 115,281$

6. GHG Cap-and-Trade Costs 317,232$ 313,776$ 3,456$ 7. GHG Allowance Revenues (376,087)$ (327,941)$ (48,146)$ 8. SUBTOTAL GHG-RELATED (58,855)$ (14,165)$ (44,690)$


1/ Amounts include Spent Nuclear Fuel. 2/ Amount reflects 12/31/17 forecast ESMA refunds less forecast litigation-related costs.

6

attached hereto, includes the updated balancing account tables supporting the amounts included in 1

SCE’s updated 2018 ERRA Forecast revenue requirement request. 2

Table II-3 Updated and May 2018 ERRA Forecast Proceeding Revenue Requirement Changes

($000)

a) ERRA-Related Generation Service Revenue Requirement 3

As shown on Line No. 6 in Table II-3 above, the increase of $566.3 million in SCE’s 2018 4

ERRA forecast generation service revenue requirement is due to a $162.6 million increase in the fuel 5

and purchased power cost estimates, including GHG Cap-and-Trade costs, as shown on Lines Nos. 2 6

and 5 of Table II-3, combined with an increase of $403.6 million in the estimated year-end ERRA 7

Line

Description


Requirement

(Filed May 2017) 2018 Proposed

Revenue Requirement

Rev. Req. Change

1. Generation Service

2. Fuel and Purchased Power 3,874,918$ 3,765,021$ 109,898$ 3. ERRA Balancing Account 360,872$ (42,764)$ 403,636$ 4. Generator Refunds (7,060)$ (7,115)$ 56$ 5. GHG Cap-and-Trade Costs 317,232$ 264,510$ 52,722$ $ 6. TOTAL ERRA PROCEEDING GENERATION SERVICE 4,545,962$ 3,979,651$ 566,311$ 7. Delivery Service

8. New System Generation Rate Component:9. F&PP New System Generation 505,700$ 574,859$ (69,159)$ 10. NSG Balancing Account (151,822)$ (42,051)$ (109,771)$ 11. Total New System Generation 353,878$ 532,808$ (178,930)$

12. Nuclear Decommissioning Rate Component:13. Spent Nuclear Fuel 4,361$ 4,361$ -$ 14. Total Nuclear Decommissioning 4,361$ 4,361$ -$

15. Distribution Rate Component16. LCR F&PP Distribution 11,753$ 11,753$ -$ 17. GHG Allowance Revenues (376,087)$ (373,300)$ (2,787)$ 18. Total Distribution (364,334)$ (361,547)$ (2,787)$

19. Public Purpose Programs Charge (PPPC)20. LCR F&PP PPPC 15,780$ 28,202$ (12,422)$ 21. Total Distribution 15,780$ 28,202$ (12,422)$

22. TOTAL ERRA PROCEEDING DELIVERY SERVICE 9,686$ 203,825$ (194,139)$


7

balancing account balance as shown on Line No. 3 of Table II-3, and an increase of approximately 1

$0.056 million associated with net Generator refunds related to the 2000-2001 California Energy Crisis 2

settlements approved by the Federal Energy Regulatory Commission (FERC). 3

b) ERRA-Related Delivery Service Revenue Requirement 4

In addition to the bundled service generation revenue requirement identified in Table II-3 above, 5

SCE’s estimated 2018 ERRA Forecast revenue requirement also includes delivery service amounts. As 6

shown on Line No. 22 in Table II-3 above, the decrease of $194.1 million in SCE’s 2018 ERRA forecast 7

delivery service revenue requirement is due to a decrease in the New System Generation (i.e., CAM-8

related) revenue requirement of $69.2 million, a decrease of $109.8 million associated with SCE’s year-9

end 2017 NSGBA balance, an increase of $0 associated with spent nuclear fuel costs, a decrease of 10

$12.4 million associated with Local Capacity Requirement (LCR) contracts and a decrease of $2.8 11

million associated with GHG allowance revenues to be returned to eligible customers. SCE discusses 12

the background for recovering these costs through CAM in more detail in Chapter VIII. The GHG 13

allowance revenue forecast is discussed in Chapter VII. 14

8

III. 1

SCE'S BUNDLED ENERGY FORECAST 2

This chapter presents a summary of SCE’s forecast of 2018 bundled service customer energy 3

load in its service area and includes its CCA departing load forecast change for 2018. 4

A. Retail Sales Forecast Summary 5

SCE developed its bundled service customer energy forecast for this update testimony based on 6

the same retail customer sales forecast that was completed on December 4, 2016 and used in SCE’s 7

initial 2018 ERRA Forecast Filing. However, the bundled sales forecast used in this update reflects 8

SCE’s most recent estimate of the CCA departing load changes, consistent with the discussion in SCE’s 9

direct testimony and in its October 13, 2017 Reply Brief. In particular, SCE accounted for the CCA 10

departing load estimate derived from the total number of customers in 2018 for the Pico Rivera CCA, 11

known as Pico Rivera Innovative Municipal Energy (PRIME), which began operation on September 1, 12

2017. 13

For 2018, the retail sales forecast of 83,227 GWh less of DA sales and 14

of CCA sales yields a forecast of bundled service customer sales of (See Table III-4). The 15

corresponding bundled service customer energy forecast at the CAISO interface is estimated at 16

in 2018. It is the bundled service customer energy at the CAISO interface for which SCE must 17

obtain supply, and this is the forecast that SCE is submitting for the purposes of this proceeding. 18

Table III-4 2018 Bundled Customer Load Forecast

(GWh)

Line Description 2016 2017 20181. Total Retail Sales (@meter) 85,448 83,415 83,2272. Direct Access Sales (@meter) 11,1993. CCA Sales (@meter) 6264. Bundled Service Sales (@meter) 73,6235. Bundled Energy at ISO 78,115

Shaded areas are confidential per D.06-06-066, Matrix section V.C.

9

B. Sales Forecast Used for Rate Setting 1

SCE applies a 2% downward adjustment to its sales forecast in the rate setting process to account 2

for the difference between delivered and billed kWh resulting from NEM adoption. NEM bills are 3

rendered using the net of energy delivered to the site and energy exported to the grid. SCE therefore 4

applies the sales adjustment to account for the NEM billing process reduces the level of sales available 5

to recover the authorized revenues. 6

C. Total Retail Sales Forecasts by Customer Class 7

Table III-5 below presents SCE’s forecast of total electricity sales by customer class. The table 8

shows actual recorded sales in 2016 and forecast numbers for 2017 and 2018. The projected average 9

annual growth in total retail sales is negative 2.4 percent in 2017 and negative 2.6 percent in 2018, 10

relative to recorded retail sales in 2016. 11

Table III-5 Annual Retail Sales by Customer Class

(GWh)

D. Customer Forecast 12

Table III-6 shows SCE’s forecast of total electricity distribution customers. SCE expects the 13

number of customers to increase 1.0 percent in 2017 and 0.9 percent in 2018. 14

10

Table III-6 Year-End Customers by Customer Class

E. Annual and Monthly Bundled Energy 1

CCA-related departing load will increase for SCE in 2017 and 2018 as compared to 2016. SCE 2

has incorporated its estimate of the migrating CCA load to this application based on information SCE 3

has received including the start of Pico Rivera Innovative Municipal Energy (PRIME) in September 4

2017,3 and SCE’s internal forecasting criteria as explained in its direct testimony. As a result, SCE’s 5

bundled sales growth in 2018 has been reduced relative to retail sales growth. 6

Table III-7 presents actual recorded bundled monthly energy at CAISO in 2016 and the forecast 7

of monthly bundled energy at ISO in 2017 and 2018. 8

3 SCE assumed a 6% opt-out rate for non-municipal PRIME accounts.

11

Table III-7 Bundled Energy at CAISO

(GWh)

12

IV. 1

UPDATED FORECAST ENERGY PRODUCTION AND COSTS FROM SCE’S PORTFOLIO 2

OF RESOURCES 3

A. Introduction 4

This chapter describes SCE’s resource portfolio and the associated forecast costs that SCE 5

proposes to recover in its ERRA balancing account. SCE’s resource portfolio is comprised of its utility-6

owned generation (UOG), which includes nuclear, natural gas, hydroelectric, fuel cells, and renewable 7

generation resources; SCE’s purchased power resources, including CHP and renewable resources, 8

interutility contracts, and bilateral contracts; and proxy4 (i.e., generic) costs from anticipated future 9

solicitations and market purchases. SCE’s 2018 forecast also includes executed contracts from SCE’s 10

Local Capacity Requirements (LCR) solicitations for the Western Los Angeles (LA) Basin and 11

Moorpark regions, as approved in D.15-11-041 and proposed in A.14-11-016, respectively. 12

The increase in SCE’s 2018 fuel and purchased power cost forecast can be generally attributed to 13

three major factors. First, SCE expects higher fuel-related costs than the initial 2018 ERRA forecast due 14

to an increase in forecast natural gas prices. Second, SCE expects higher open market costs due to 15

higher forecast SP-15 forward market power prices. Third, SCE expects higher SRAC payments due to 16

higher forecast market prices. SCE used $18.84/kW-year as the proxy price to meet Generic Capacity 17

need as outlined in the CPUC’s 2016 Resource Adequacy Report.5 18

B. Energy Production Forecast Methodology 19

In this ERRA Forecast application, as in its past forecast applications, SCE forecasts energy 20

production from its portfolio primarily using the Ventyx Planning and Risk (PROSYM) software.6 The 21

4 The proxy capacity costs are further discussed in Section IV.E. 5 CPUC’s 2016 RA Report can be found at

http://www.cpuc.ca.gov/WorkArea/DownloadAsset.aspx?id=6442453942. Please refer to CAISO System Weighted Average Price ($/kW-month) from "Table 7, Aggregated RA Contract Prices, 2016-2020".

6 Ventyx is the current owner of the originally developed Henwood PROSYM tool. Ventyx’s Planning and Risk Software is primarily powered by the PROSYM engine.

13

Ventyx models are used to: (1) forecast the least-cost dispatch (LCD) of dispatchable resources in 1

SCE’s portfolio; (2) optimize hydro dispatch; and (3) perform Monte Carlo simulations of forced outage 2

rates of individual units. 3

The simulated dispatch is based on a forecast of power, gas, and GHG prices,7 physical 4

constraints of each generating unit, and contractual limitations. SCE’s forecast methodology 5

economically dispatches resources in a least-cost manner as directed by the Commission, rather than 6

force-dispatching resources to meet SCE’s forecast of bundled customer demand. Under the LCD 7

principle, a generating resource or contract is simulated to dispatch if its marginal operating cost is less 8

than the market price of power, while simultaneously observing all operating constraints.8 For a given 9

hour, the difference between the forecast bundled load and the total forecast economic dispatch of SCE’s 10

resource portfolio constitutes SCE’s projected open position for the hour. 11

SCE based its updated 2018 power price forecast on the forward power broker quotes for 2018 in 12

effect as of September 20, 2017. The 24-hour flat price as of September 20, 2017 was $32.42/MWh for 13

2018.9 SCE derived its hourly price forecast by applying on-peak and off-peak hourly price profiles to 14

the respective monthly on-peak and off-peak forward quotes for 2018 in effect as of September 20, 15

2017,10 such that the simple averages of the hourly on-peak and off-peak forecast prices for a particular 16

7 The Ventyx models were not used to develop forecasts of competitive market power or GHG prices. These

prices were developed independently, as discussed in the following paragraphs. The GHG price forecast was incorporated as part of the resource dispatch cost similar to natural gas prices in order to reflect the additional GHG cost for the generation resources that have GHG emissions.

8 Energy- and use-limited hydroelectric and peaking resources are also dispatched pursuant to LCD; this analysis also incorporates opportunity cost principles regarding water availability and permitted emissions limitations, respectively, to ensure that such units are dispatched during higher-priced hours, when it is most economic to do so.

9 SCE has contracts in NP-15. SCE used relevant prices to forecast the cost of those contracts. 10 SCE used forward prices from the same trading day for power, GHG, and natural gas price forecasts to

maintain the consistency of the forward-market outlook.

14

month match the forward on-peak and off-peak power prices for that month. SCE updated its existing 1

MRTU-based statistical models to generate hourly price profiles for the SP-15 and NP-15 zones.11 2

SCE used the Intercontinental Exchange’s (ICE) settlement price of a 2018-vintage GHG 3

allowance as the basis for its 2018 GHG price forecast. The ICE settlement price as of September 20, 4

2017, was $15.52/MT for 2018. This price is assumed to be constant for any GHG emissions produced 5

in 2018.12 Lastly, SCE based its daily natural gas price forecast on monthly NYMEX forward prices at 6

the SoCal Border in effect as of September 20, 2017, plus intrastate transportation charges from 7

Southern California Gas Company (SoCalGas), as applicable.13 The 12-month average NYMEX 8

forward gas price as of September 20, 2017 was $2.86/MMBtu for 2018. Within a given month, SCE 9

assumed that the daily gas price forecast is equal to the monthly forward price. 10

C. 2018 Energy and Cost Forecast Summary 11

Because this ERRA application is designed to forecast SCE’s energy-related costs that will 12

ultimately be used to establish retail generation rates in 2018, a single expected scenario forecast is 13

utilized. All production and residual open position forecasts provided in this section are reflected at the 14

CAISO system interface. To accomplish this, SCE reduced generation production forecasts by the 15

forecast transmission line losses and grossed up the forecast retail load by the forecast distribution line 16

losses. Table IV-8 summarizes the monthly forecast production from SCE’s portfolio and SCE’s open 17

energy positions. Table IV-9 summarizes the monthly forecast cost of SCE’s purchased power 18

resources accounted for in the ERRA balancing account. The remainder of this chapter provides 19

detailed descriptions of the resources and the underlying forecast assumptions.20

11 The statistical models incorporated historical MRTU data from the CAISO’s Integrated Forward Market

(IFM). 12 In prior years, direct and indirect GHG costs were reviewed in a separate GHG Cost and Revenue Forecast

application. Pursuant to D.14-10-033, they are now reviewed in this proceeding, and are discussed in further detail in Chapter VII.

13 Not all generating resources in SCE’s portfolio utilize transportation service from SoCalGas.

15

Table IV-8 2018 Energy Forecast of the SCE Portfolio

(GWh) Confidential

16

Table IV-9 2018 Forecast of Fuel and Purchased Power Costs14

($000) Confidential

14 The CHP and Renewables line item includes $56.732 million associated with the forecast costs of SCE’s Tree Mortality Power Purchase Agreements

(Tree Mortality costs). SCE’s proposed cost recovery methodology for Tree Mortality costs is currently before the Commission in A.16-11-005, and Tree Mortality costs are currently being recorded in SCE’s BioRAM and BioMASS memorandum accounts. As such, the forecast fuel and purchased power cost that will be included in SCE’s 2018 revenue requirement is $4,672,175,000.

Line No. Category Item Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Total

1 CHP & Renewables

2 Energy

3 Capacity

4 Recontracting

5 Total CHP & Renewables

6 Green Rate Program

7 Total Green Rate Program 77 77 77 77 77 77 77 77 77 77 77 77 925

8 SCE Peakers

9 Fixed Costs

10 Variable Costs

11 Total SCE Peakers

12 Inter-Uti l i ty Contracts

13 Fixed Costs - Hoover SCE

14 Variable Costs

15 Total Inter-Utility

16 Mounta inview

17 Fixed Costs

18 Variable Costs

19 Total Mountainview

20 Other UOG Fuel Costs

21 Palo Verde Nuclear Fuel Expenses

22 Cata l ina Diesel Costs 420 420 420 420 420 420 420 420 420 420 420 420 5 040

23 Cata l ina Propane Costs 11 11 11 11 11 11 11 11 11 11 11 11 135

24 PV Storage Costs 2 2 2 2 2 2 2 2 2 2 2 2 21

25 SONGS Interim Storage 358 358 358 358 358 358 358 358 358 358 358 358 4 290

26 Total Other UOG Fuel Costs

27 Demand Response

28 Fixed Costs - - - - - - - - - - - - -

29 Variable Costs - - - - - - - - - - - - -

30 Total Demand Response - - - - - - - - - - - - -

31 2013 Bi latera l

32 Fixed Costs

33 Variable Costs

34 Total 2013 Bilateral

35 LCR Contracts

36 Fixed Costs

37 Total LCR Contract

38 PRP Sol i ci tation

39 PRP(BTM Storage)

40 Variable Costs

41 Total PRP Solicitation

17

Table IV-9 (Con’t)

2018 Forecast of Fuel and Purchased Power Costs ($000)

Confidential

18

D. SCE’s Utility-Owned Generation and Purchased Power Contracts 1

1. Hydro Facilities 2

SCE’s hydro resources consist of 33 powerhouses in central and southern California, which 3

provide 1,176 MW of nameplate capacity. SCE’s hydro division is organized into two regions, Northern 4

and Eastern. The Northern Division hydro region, also known as the Big Creek Project, is located in 5

central California about 50 miles east of Fresno in the western Sierra Nevada Mountains. Big Creek’s 6

nine powerhouses provide 1,015 MW of nameplate capacity. The Eastern Division hydro region 7

consists of SCE’s powerhouses located in the eastern and southern Sierra Nevada Mountains, as well as 8

in the San Bernardino and San Gabriel Mountains of southern California. The Eastern Division hydro 9

region’s 24 powerhouses provide 161 MW of nameplate capacity. 10

The Big Creek hydro system is a flexible, dispatchable resource, except during the period of 11

spring run-off. During this period, in a normal water year, the generating units typically need to operate 12

near maximum capacity for 24 hours per day to ensure that spill is minimized. For ERRA forecast 13

purposes, SCE optimizes the Big Creek Project by operating at full capacity (when operationally 14

possible) during the highest economic value hours. When Big Creek does not operate at full capacity, it 15

can generally provide ancillary services to the CAISO market. 16

Eastwood powerhouse is a pump-storage unit providing 199.8 MW of nameplate generating 17

capacity, and is part of the Big Creek Project. The pumpback efficiency is approximately 75 percent, 18

meaning that approximately 1.33 MWh of pumping energy is required to pump enough water back into 19

the forebay to generate 1 MWh of energy at a later time. Pumpback duration generally varies from two 20

to six hours and consumes approximately 180 MWh per hour. Every three hours of pumpback stores 21

enough water to generate for approximately two hours at 199.8 MW. Pumpback and generation 22

dispatch for Eastwood are modeled on an hourly basis assuming economic dispatch. To maximize the 23

value of the resource, pumpback normally takes place during off-peak hours when energy prices are 24

lower, and dispatch normally takes place during peak hours when energy prices are higher. 25

19

SCE’s Eastern Division hydro facilities are predominantly run-of-the-river, non-dispatchable 1

resources and their actual MW output varies based on hydrological conditions. As a result, the forecast 2

energy production is largely deterministic. 3

For 2018, SCE’s forecast of its UOG Hydro production, inclusive of pumpback operations, is 4

shown in Table IV-8. This forecast assumes a slightly-above-normal hydrological year for 2018, and 5

also incorporates SCE’s best estimate of upcoming major planned outages of Big Creek and Eastern 6

Hydro units in 2018. 7

E. Validation of SCE’s Energy Production Forecast 8

SCE follows a consistent process to forecast its energy production and costs for the subsequent 9

calendar year, supported by a robust internal validation process. SCE’s forecast process is discussed 10

below. 11

The first stage of SCE’s forecast process involves developing all forecast inputs. These inputs 12

include, but are not limited to, SCE’s forecast of power, gas, and GHG prices; production from UOG 13

resources (nuclear, hydro, gas, fuel cells and renewable facilities); CHP and renewable energy 14

production and costs; gas hedging costs; CAISO costs, etc. These inputs are developed and vetted by 15

various business groups or divisions responsible for each input and then submitted to senior managers in 16

SCE’s Energy Procurement & Management Organizational Unit for further review and approval. 17

Once approved, the forecast inputs are utilized in PROSYM, which is an industry-standard 18

production cost model capable of modeling various types of resources with differing constraints. SCE 19

uses PROSYM to forecast its LCD activities. Once the dispatch results are produced, SCE conducts a 20

thorough validation of the dispatch outcomes by resource.15 If necessary, SCE will rerun the previous 21

forecast steps if it believes more accurate dispatch results can be realized. 22

Once dispatch results are validated, all energy and cost forecasts are input into SCE’s ERRA 23

forecasting tool, an internally-developed, automated software program that aggregates the hourly energy 24

15 For example, SCE compares its dispatch results against prior ERRA forecasts and reviews any significant

discrepancies to ensure that its results are reasonably justified.

20

production and cost forecast data. The ERRA forecasting tool produces the ERRA forecast tables 1

included in the following section(s). Prior to inclusion in SCE’s ERRA Forecast filing, the forecast 2

tables are reviewed and approved by SCE’s senior management. 3

1. CHP and Renewables 4

a) Energy Forecast 5

For the 2018 Forecast Period, SCE expects 16 of energy deliveries at the CAISO 6

interface as shown in Table IV-8 from CHP (combined heat and power) and renewable projects. The 7

energy deliveries from cogeneration and renewable projects are effectively “must take” energy. There 8

are some gas-fired contracts that are dispatched based on market prices. 9

Energy deliveries at the generators’ meters are forecast to be The 322 projects 10

delivering energy have approximately 9,701 MW of contract capacity allocated as follows: 11

• 1,113 MW of CHP capacity; 12

• 8,588 MW of renewable capacity.17 13

In addition and not included in the above capacity numbers, SCE has contracted an additional 14

174 MW of dispatchable capacity through the CHP Program Settlement requests for offers. 15

SCE uses the historical performance of each project to forecast monthly energy deliveries. From 16

November 2017 through December 2018, 19 projects are expected to begin delivering energy. Some of 17

these projects have been delivering energy and signed new contracts. Others are new projects under 18

development and are adjusted by their probability of successful development and commercial operation. 19

The total capacity for these projects is approximately 329 MW. Of the 19 projects, 11 are new projects 20

(10 solar and 1 wind) that are expected to begin delivering energy during the period from November 21

2017 through December 2018. Because there is no historical performance data for these new projects, 22

16 includes generation losses and excludes 11 GWh allocated to serve Green Tariff customers as a

part of the GTSR Program described in Section E.10. 17 The contract capacity for a project that is not developed is weighted by the project’s expected commercially-

operable success rate.

21

forecast energy deliveries are based on contractual expectations discounted by their expected 1

probabilities of successful development. 2

Table IV-10 lists the average annual capacity factors for each of the six technologies. These 3

average annual capacity factors are based on expected annual energy and contract capacity for each 4

project aggregated by technology. In addition, for new, undeveloped projects, both the energy and 5

capacity forecast values are weighted by each project’s respective probability of successful 6

development. 7

Table IV-10 Annual Capacity Factors by Technology

b) Payment Forecast 8

Payments to CHP and renewable projects delivering energy during 2018 are forecast to be 9

approximately 18 energy payments of and capacity payments of 10

. The expected monthly energy, energy payments, and capacity are shown in Table IV-9. 11

c) Energy and Capacity Prices 12

Energy and capacity prices for each of the CHP and renewable projects are based on the 13

individual project’s contract. Many of these projects have contract-specific energy prices. A number of 14

QF projects are paid at the posted avoided cost of energy price. For QF projects with the Standard Offer 15

Contract, the project’s paid capacity price is the firm or as-available avoided capacity price depending 16

18 SCE estimates a cost of from the Shell Off-take agreement, other out-of-state renewable management

costs, and CHP Dispatchable costs. Shell Off-take energy is adjusted to SCE’s open market exposure.

Biomass 81.3%Cogeneration 68.9%Geothermal 81.9%Small Hydro 36.2%Solar 28.9%Wind 26.8%

22

on the project’s specific dedicated capacity. For older QF projects, many of the projects have capacity 1

prices that are contract-specific. 2

Most of the QF projects are paid at the avoided cost of energy. The SRAC for energy is based 3

on the average 12-month forward heat rates. The monthly forecast of SRAC energy prices is included in 4

Table IV-11 below. 5

Table IV-11 2018 Forecast of Posted Energy and Capacity Prices

Finally, forecast curtailments are captured in the 2018 ERRA forecast period. SCE anticipates 6

that a small amount of energy deliveries from solar and wind projects will be curtailed because of 7

limited transmission availability. The impact of curtailed energy deliveries is included in the energy and 8

payment forecasts. 9

2. Utility-Owned Natural Gas Facilities 10

a) SCE Peakers 11

(1) Production 12

SCE included its forecast of UOG peaking unit generation in Table IV-8. 13

(2) Costs 14

Effective with SCE’s 2009 GRC decision, SCE transitioned to GRC-based rate recovery for all 15

capacity and non-fuel variable costs associated with its UOG Peakers. The natural gas fuel cost forecast 16

for these peaking units is included in Table IV-9. 17

b) Mountainview Generating Station 18

On July 1, 2009, Mountainview Power Company, LLC (MVL), a wholly-owned subsidiary of 19

SCE, transferred ownership of the Mountainview Generating Station (Mountainview) to SCE. The 20

Commission approved the transfer as part of SCE’s 2009 GRC, in D.09-03-025. As a result, 21

Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18Avoided Cost Energy ¢/kWh 3 66 3 58 3 42 3 04 3 03 3 08 3 22 3 30 3 18 3 08 3 25 3 60Avoided Cost of Firm Capacity$/kW-year $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97 $91 97

Avoided Cost of As-Available Capacity $/kW-year $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33 $55 33

23

Mountainview’s capital costs are no longer recovered as purchased power costs through the ERRA, but 1

instead are recovered in SCE’s authorized base generation revenue requirement and through base rates. 2

However, Mountainview fuel costs and availability and heat rate incentive payments continue to be 3

recorded in the ERRA balancing account.19 SCE included its Mountainview generation forecast in 4

Table IV-8. The natural gas forecast for Mountainview is included in Table IV-9. 5

3. New System Generation CAM Contracts 6

a) Production 7

Pursuant to D.07-09-044 and the Joint Party Proposal (JPP) adopted in that decision, SCE will 8

hold the dispatch rights for all New Gen contracts in 2018. SCE included its bundled service customer 9

share of energy in the portfolio position forecast. 10

b) Costs 11

Consistent with the New Generation cost allocation decisions,20 SCE accounted for the forecast 12

of total net capacity costs for all the New Generation contracts that are expected to operate in 2018. The 13

total forecasted New Generation CAM costs, found in Table IV-9 reflect the total of the capacity costs 14

net of estimated expected market revenue and production cost. SCE’s bundled service customers are 15

responsible for their assessed load-share responsibility. 16

4. 2013 Bilateral Contracts Production 17

a) Production 18

In July 2012, SCE and JPMorgan, on behalf of BE CA LLC, began bilateral negotiations. On 19

February 15, 2013, SCE filed Advice Letter 2853-E to seek CPUC approval of this bilaterally-negotiated 20

capacity and tolling agreement between SCE and BE CA LLC. This agreement was approved by the 21

19 See SCE’s 2009 GRC Application, A.07-11-011, Exhibit SCE-02, Vol. 9, Ch. 1, dated November 2007, in

which SCE proposed to include the concepts of the PPA incentive mechanisms in the ERRA proceeding. 20 In D.06-07-029, the Commission adopted a CAM that allocates the benefits and costs of new generation to all

customers in an IOU’s service area. The decision also ordered the IOUs to develop energy auction implementation plans. Subsequently, D.07-09-044 adopted specific auction processes for the distribution of energy rights in new generation contracts, including specific products and cost-and-benefit sharing mechanisms.

24

CPUC on May 9, 2013. The projected total production in 2018 from this contract is shown in Table IV-1

8. 2

b) Costs 3

The four general cost categories for SCE’s 2013 Bilateral Contracts are (1) natural gas fuel costs; 4

(2) GHG costs; (3) variable charges; and (4) capacity payments. Table IV-9 provides the forecast 5

monthly costs for these contracts. 6

5. Generic and Bilateral RA Contracts 7

a) Production 8

For 2018, SCE estimates a system capacity need and a local area capacity need that varies by 9

month. Within this calculation, SCE forecasts the RA requirement it will need to meet in 2018. This 10

requirement, less RA contracts already procured, then determines SCE’s forecast remaining 2018 RA 11

need. SCE further assumed that RA contracts will be procured at a forecast generic cost to meet this 12

projected RA need for 2018.21 Table IV-9 provides the forecasted monthly capacity costs for both the 13

generic and bilateral RA contracts. 14

6. Local Capacity Requirements (LCR) Contracts 15

On September 12, 2013, SCE launched its LCR RFO to procure specified amounts of Preferred 16

Resources,22 Energy Storage, and Gas Fired Generation (GFG) in the Western LA Basin and Moorpark 17

local reliability areas to meet long-term local capacity requirements. SCE filed A.14-11-01223 and 18

A.14-11-01624 (LCR RFO Applications) for approval of all contracts entered into as a result of the 19

21 SCE applied the capacity price of $18.84/kW-year, based on the CPUC’s 2016 RA Report. Please refer to

CAISO System Weighted Average Price ($/kW-month) from “Table 7, Aggregated RA Contract Prices, 2016-2020” and converting it as yearly.

22 Preferred Resources defined as cost-effective energy efficiency, demand response, renewable resources, and distributed generation. See State Energy Action Plan II at page 2.

23 Application for Approval of the Results of its 2013 LCR RFO for the Western LA Basin Sub-Area was approved, in part, in D.15-11-041 on November 19, 2015.

24 Application for Approval of the Results of its 2013 LCR RFO for the Moorpark Sub-Area was approved, in part, in D.16-05-050 on May 26, 2016.

25

procurement. Pursuant to the Long Term Procurement Plan (LTPP) Track 1 and 4 decisions25 and as 1

proposed in the LCR RFO Applications, the net cost of the capacity26 is allocated to all benefitting 2

customers. 3

a) Production 4

The LCR contracts included in the forecast are behind-the-meter as well as in-front-of-the-meter 5

resources. Table IV-9 provides the forecasted monthly energy from the in-front-of-the-meter LCR 6

resources. Behind-the-meter LCR resources reduce the overall bundled load requirement. 7

b) Costs 8

The capacity costs are forecasted in the LCR Costs line item in Table IV-9. 9

7. Preferred Resource Pilot (PRP) 10

On September 24, 2015 SCE launched its PRP RFO #2 to solicit electrical energy, capacity and 11

renewable attributes from eligible resources such as Demand Response, Renewable Distributed 12

Generation, Energy Storage, Renewable Distributed Generation paired with Energy Storage and 13

Permanent Load Shifting. On November 4, 2016, SCE submitted an application seeking approval for 14

the contracts executed during the PRP solicitation. Some of the contracts that are executed as a result of 15

this solicitation are expected to operate during 2018. 16

a) Production 17

The PRP contracts that are expected to operate in 2018 are behind-the-meter energy storage 18

resources. Behind-the-meter resources reduce the overall bundled load requirement. 19

b) Costs 20

The capacity costs are forecasted in the PRP Costs line item in Table IV-9.27 21

25 D.13-02-015 (Track 1 decision) OP 15 and D.14-03-004 OP 13. 26 The energy and capacity components of the newly-acquired generation are disaggregated. The net capacity

cost is calculated as the net of the total cost of the contract minus the energy revenues associated with the dispatch of the resource.

27 As described on pages 81-83 of SCE-01 in A.16-11-002, SCE proposes to recover the costs of the PRP behind-the-meter energy storage contracts from customers through the Public Purpose Programs Charge.

26

F. CAISO Costs and Short-Term Market Activity 1

CAISO implemented a new market design, known as MRTU, on April 1, 2009. The new market 2

design includes elements such as the IFM, locational marginal pricing (LMP), and congestion revenue 3

rights (CRRs), and operates in a dramatically different manner than the previous zonal market. Due to 4

the complexity of the CAISO market, SCE separated the total costs from the CAISO market into (1) the 5

non-energy-related CAISO costs (CAISO costs); and (2) energy-related short-term market activity cost 6

(short-term market activity costs). SCE forecast the CAISO costs and the short-term market activity 7

costs separately, applying different forecasting methodologies as described below. 8

1. Short-Term Market Activity Costs 9

SCE estimates its hourly open energy positions by netting its projected production from its 10

supply portfolio against its forecasted bundled load for each hour. SCE covers a major portion of its 11

open positions through the IFM,28 with bilateral transactions comprising a smaller portion. SCE also 12

covers a very small portion of its open positions in the CAISO hour-ahead and real-time (RT) markets. 13

For the purpose of this ERRA forecast application, SCE separated the forecast energy costs associated 14

with covering its open positions from the forecast CAISO costs discussed in the preceding section. All 15

forecast short-term market activity costs are reported separately in Table IV-9. 16

G. Gas Price Sensitivity 17

Pursuant to an agreement with ORA reached in A.10-08-001, SCE agreed to perform a two-18

standard-deviation gas price sensitivity analysis for ORA in support of its future ERRA forecasts for up 19

to five years. SCE performed the subject gas price sensitivity analysis and included the results in its 20

2011 ERRA Application (A.11-08-002) for the 2012 forecast calendar year.29 SCE conducted a similar 21

sensitivity analysis for this 2018 ERRA forecast. 22

28 The short-term market activity cost includes the net costs associated with covering the open energy positions

inclusive of estimated CRR revenues SCE expects to receive from future CRR holdings. 29 SCE provided the detailed description of the methodology SCE applied to its gas price sensitivity analysis in

A.11-08-022.

27

Using this sensitivity analysis, SCE’s forecasted 2018 ERRA costs are projected to increase or 1

decrease by similar amounts, approximately , with an approximate $0.06/MMBtu upward or 2

downward gas price movement from the base case forecast SoCal Border gas price of $2.86/MMBtu for 3

the 2018 12-month strip. 4

As SCE has stated in previous ERRA forecast proceedings, the gas price sensitivity analysis can 5

only serve as a “rough check” on the updated ERRA forecasts and cannot be used to determine forecast 6

accuracy. One cannot simply apply the gas price sensitivity analysis to assess the accuracy of ERRA 7

forecast updates due to the multiple changes of the major input drivers (e.g., SCE’s portfolio changes) 8

that occur. 9

H. Direct GHG Costs 10

Direct GHG costs are shown separately in Table IV-9. Indirect GHG costs are embedded in the 11

purchased power contracts and utility-owned generation forecasts, and are identified and discussed in 12

further detail in Chapter VII. 13

28

V. 1

UPDATED FINANCING COSTS 2

This chapter discusses financing costs that relate to SCE’s forecast power production and 3

procurement during 2018 that are recovered through the operation of the ERRA. 4

A. Commission Decisions Regarding Financing Costs and Collateral Costs 5

Existing Commission decisions authorize SCE to recover actual fuel inventory financing costs 6

and actual collateral costs. D.93-01-027 authorizes SCE to recover actual fuel inventory financing 7

costs.30 D.02-10-062, which established the ERRA, provides for recovery of fuel and credit costs, 8

including collateral costs.31 9

Provisions for the recovery of financing costs associated with ERRA balancing account 10

undercollections are specified in D.04-01-048. The decision states that once SCE is able to issue 11

commercial paper, the three-month commercial paper rate index will be applied to undercollected 12

balances.32 13

B. SCE’s Current Short-Term Financings 14

1. Credit Facilities (Revolvers) 15

SCE currently has a $2.75 billion multi-year revolving credit facility (also referred to as 16

“facility” or “revolver”) that supports its short-term borrowing requirements, including liquidity support 17

for commercial paper33 as well as letters of credit and cash collateral for procurement needs. 18

Furthermore, the credit facility carries only a marginal facility fee if no borrowings or other usage is 19

required. 20

Because SCE has exhausted both its one-year extension options under the credit facility, SCE 21

plans to amend the credit facility in 2018, in order to maintain a five-year term and add two one-year 22 30 D.93-01-027, Findings of Fact 23-26, 28, 30-32, Conclusion of Law 14, 47 CPUC 2d 682, 696-698. 31 D.02-10-062, Finding of Fact 23, mimeo, p. 71. 32 D.04-01-048, mimeo, p. 10, Ordering Paragraph 4, p. 23. 33 The SCE commercial paper program requires a backup credit facility so that SCE can redeem commercial

paper when it comes due, in the event that SCE cannot issue replacement commercial paper.

29

extension options. SCE expects the facility to have the following key features, similar to the existing 1

facility: 2

• $2.75 billion total amount 3

• July 2023 maturity 4

• Arrangement and up-front costs and fees of approximately $3.0 million 5

• Additional up-front costs and fees for exercising the two one-year extension options 6

• $20,000 annual administrative fee 7

• 10 basis point annual facility fee 8

• 90 basis point participation fee on any outstanding letters of credit 9

• 20 basis point issuer fees on any letters of credit 10

• LIBOR plus 90 basis points borrowing (loan) rate 11

Only a portion of the up-front costs and fees shown above is allocated to ERRA. 12

The total size of the revolver is based on projected collateral requirements, balancing account 13

undercollections, and short-term general purpose borrowing needs during the term of the revolver. 14

Therefore, a pro-rata share of the costs of the revolver, corresponding to the capacity required to support 15

potential collateral requirements and balancing account undercollections financed by the revolver, is 16

recovered through the ERRA. For 2018, SCE forecasts that of the five-year credit facility 17

will be dedicated to providing capacity for collateral and supporting balancing accounts. The facility 18

fees associated with this amount should therefore be recorded in the ERRA balancing 19

account. ERRA undercollections that are financed by the revolver should be charged the appropriate 20

interest rate on the undercollected balance pursuant to D.04-01-048. SCE intends to recover the 21

remaining facility and commitment fees that are associated with general corporate borrowing, along with 22

general purpose interest costs, through base rates. 23

2. Collateral Requirements 24

Collateral requirements vary with changes in power prices and must be provided to 25

counterparties within a few days of a collateral call. As a result, the capacity for the maximum collateral 26

draw must be maintained at all times. Up to of SCE’s current credit facility is dedicated 27

30

to supporting its collateral requirements and balancing account undercollections. The remaining 1

of SCE’s $2.75 billion credit facility is available capacity for general purpose working capital 2

needs. SCE’s collateral requirements will change if the Commission requires SCE to change its planned 3

procurement of reserves to meet resource adequacy requirements or requires SCE to sign additional 4

long-term contracts for other purposes. As a result, if SCE needs to increase its collateral capacity in 5

2018, it should be allowed to recover any such increased costs through the ERRA balancing account. 6

3. Fixed Rate Bonds Supporting Fuel Inventories 7

Currently, SCE has a $100 million fixed rate bond to support the minimum balance of all fuel 8

inventories projected through November 2017. The $100 million fixed rate bond matures in November 9

2017. SCE anticipates issuing a $125 million fixed rate 3-year fuel inventory bond in January 2018 to 10

replace the expired fixed rate bond support the minimum balance of all fuel inventories projected 11

through January 2021. SCE estimates approximately $1,000,000 in issuance costs and expenses for the 12

new fixed rate bond, which will be recorded at the time of offering, in January 2018. 13

4. Commercial Paper 14

In January 2011, SCE expanded its commercial paper program to $2.0 billion. In 2018, SCE’s 15

$2.0 billion commercial paper program will finance fuel inventories in excess of the amount covered by 16

the fixed rate bond.34 SCE’s 2018 forecast assumes that the market for A2/P1 commercial paper will 17

continue to remain stable, and that SCE will be able to utilize the commercial paper program for its 18

short-term borrowing needs. 19

SCE’s commercial paper program has the following features: 20

• $2 billion capacity; 21

• A2/P1/F2 rating; and 22

• 5 basis point annualized dealer fee on each issue. 23

34 From time to time, SCE may use commercial paper or borrowings against its credit facility to fund cash

collateral requirements; however, SCE customarily provides collateral through letters of credit supported by the revolving credit agreement.

31

5. Costs of Collateral Issuance 1

For most counterparties, SCE will provide collateral in the form of letters of credit rather than 2

having to borrow cash. The participation fees and additional fees associated with the letters of credit 3

issued under the revolver will be charged to the ERRA. 4

C. Additional Options Supporting Collateral 5

As previously discussed, the revolvers may not be large enough to support all of SCE’s collateral 6

requirements. Therefore, SCE’s current credit facility includes an option to increase its credit facility 7

limit from . If additional collateral support is required, SCE may seek to 8

increase the limits of its credit facility up to 9

32

VI. 1

UPDATED CARRYING COSTS 2

The purpose of this chapter is to set forth SCE’s 2018 estimated fuel inventory carrying costs 3

(nuclear,35 natural gas, propane, and diesel fuel inventories), estimated 2018 GHG compliance carrying 4

costs and collateral carrying costs for inclusion in SCE’s 2018 ERRA revenue requirement. Table VI-12 5

shows SCE’s estimated 2018 fuel inventory, GHG compliance, and collateral carrying ERRA revenue 6

requirement Table VI-12 costs. 7

Table VI-12 Estimate of 2018 Carrying Costs

($000)

A. Fuel Inventory Carrying Costs 8

ERRA fuel inventory includes in-core nuclear fuel, natural gas, diesel, and propane. Total fuel 9

inventory includes the ERRA fuel inventory plus pre-core nuclear fuel. To determine fuel inventory 10

carrying costs rates, the total ERRA and non-ERRA fuel inventory is forecast to arrive at the total fuel 11

inventory. A portfolio of bonds and short term debt is assumed to finance the total fuel inventory. The 12

carrying cost rate is calculated based upon the total fuel inventory and the portfolio of bonds and short 13

term debt. The carrying cost rate is applied to the ERRA fuel inventory to determine the ERRA fuel 14

inventory carrying costs. 15

SCE’s fuel inventory for ERRA consists of in-core nuclear fuel associated with its ownership 16

interest in the Palo Verde Nuclear Generating Station (PVNGS), natural gas storage and imbalance, 17

propane for the micro-turbines on Catalina Island, and diesel fuel for the diesel generators on Catalina 18

35 For the purposes of carrying costs, Nuclear Fuel includes “in-core” nuclear fuel inventories for PVNGS.

Line Description Carrying Cost1. Fuel (Nuclear, Natural Gas, Diesel, Propane)2. Greenhouse Gas3. Collateral

4. Total

33

Island. The calculation of ERRA fuel inventory carrying costs is based on forecast average monthly 1

ERRA inventory balances (PVNGS nuclear in-core, diesel, propane, and natural gas) and the carrying 2

cost rate. The total estimated 2018 ERRA fuel inventory balance and associated financing costs are 3

presented in Table VI-13. 4

Table VI-13 Estimated 2018 Fuel Inventory Carrying Costs

($000)

B. GHG Compliance Carrying Costs 5

This section discusses the forecast of GHG procurement compliance carrying costs in 2018. 6

SCE is authorized to recover the actual interest expense associated with the cash outlays to meet GHG 7

procurement compliance costs.36 To forecast carrying costs, SCE uses the ERRA balancing account 8

interest rates to finance GHG procurement compliance carrying costs. The forecast 2018 GHG 9

procurement compliance inventory and carrying costs are presented in the Table VI-14 below. 10

Table VI-14 Estimated 2018 GHG Compliance Carrying Costs

($000)

C. Collateral Carrying Costs 11

Table VI-15 sets forth the calculation of the carrying costs associated with SCE’s collateral 12

requirements necessary to procure power. This calculation is based on estimated average collateral 13

requirements and the projected terms of SCE’s revolvers, discussed in Chapter V.B. As SCE’s collateral 14

requirements change during 2018, SCE will use actual collateral requirements in determining its 15

carrying costs recorded in the ERRA. 16 36 See D.14-10-033, Attachment B, Section G - GHG Accounting Procedures for Ratesetting Purposes.

Line Description Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Total1. Average ERRA Fuel Inventory Value2. Inventory Carrying Cost

Line Description Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Total1. Average ERRA GHG Inventory2. Inventory Carrying Cost

34

Table VI-15 Estimated 2018 Procurement Collateral Carrying Costs

($000)

Line Description Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Total

1. Average Collateral Value2. Collateral Carrying Cost

35

VII. 1

UPDATED 2018 GHG FORECAST COSTS AND REVENUES AND RECONCILIATION 2

A. Overview 3

This chapter presents SCE’s updated (1) forecast of 2018 GHG allowance revenue (allowance 4

revenue) and revenue returns to eligible customers, (2) reconciliation of prior period “computed” GHG 5

costs to true-up the GHG allowance revenue returns, (3) forecast of 2018 administrative and customer 6

outreach costs, and (4) reconciliation of the prior period activity to account for deviations between actual 7

revenues returned to customers, and actual revenues received from the consignment of allowances to the 8

auction, net of actual administrative and customer outreach costs. 9

In summary, SCE proposes to return a total of $376.087 million in net available GHG revenues 10

to eligible customers in 2018 based on the Commission-adopted methodologies and utilizing GHG 11

revenues and cap-and-trade costs, including administrative and customer outreach costs, as proposed and 12

supported in this Application. Based on SCE’s estimated GHG allowance revenues available for return 13

to eligible customers in 2018 as set forth in this testimony, and after accounting for administrative and 14

customer outreach costs, the amount attributable to Senate Bill (SB) 92 related to the allocation of GHG 15

revenues37 for Multifamily Affordable Housing Solar Roofs Program (as discussed later in this 16

testimony), Emissions-Intensive Trade-Exposed (EITE) revenue returns, and small business customer 17

volumetric returns38 set to offset all or a portion of GHG costs in rates, residential customers can expect 18

a semi-annual, on-bill California Climate Credit of $36.00 in 2018. 19

37 Section 83(c) of SB 92 provides: “The commission shall annually authorize the allocation of one hundred

million dollars ($100,000,000) or 66.67 percent of available funds, whichever is less, from the revenues described in subdivision (c) of Section 748.5 for the Multifamily Affordable Housing Solar Roofs Program, beginning with the fiscal year commencing July 1, 2016, and ending with the fiscal year ending June 30, 2020. The commission shall continue authorizing the allocation of these funds through June 30, 2026, if the commission determines that revenues are available after 2020 and that there is adequate interest and participation in the program.”

38 On October 1, 2017, the 2016 amendments to the Cap-and-Trade Regulation became effective and included a prohibition, effective immediately, of the volumetric return of auction proceeds to customers (for SCE, this applies to the small business customer revenue returns). On October 24, 2017, SCE received direction through email exchanges with the Commission’s Energy Division that the existing rules comply (i.e., as established in

(Continued)

36

B. Updated 2018 GHG Emissions and Cap-and-Trade Costs 1

Table VII-16 provides SCE’s updated forecast of 2018 GHG emissions volumes by GHG 2

obligation and exposure category on an accrual basis, based on the methodologies described in SCE-1. 3

Table VII-16 SCE’s Updated Forecast of 2018 GHG Emissions Volumes

(Metric Tons CO2e)

Table VII-17 provides SCE’s updated forecast of $313.591 million in 2018 GHG costs. The 4

forecast costs shown below are calculated by multiplying the GHG emissions volumes forecasted shown 5

in Table VII-16 above by SCE’s forecast 2018 allowance price of $15.52/MT, which is the 6

Intercontinental Exchange (ICE) settlement price as of September 20, 2017. 7

Table VII-17 SCE’s Updated Forecast of 2018 GHG Costs ($000)

Table VII-18 below presents the updated reconciliation of SCE’s forecast and actual prior period 8

GHG costs based on the methodology adopted in D.14-10-033 (the “Phase 2 Decision”) and provides 9

the information for Template D-2 “Annual GHG Emissions and Associated Costs” consistent with the 10

Continued from the previous page D.12-12-033 and D.14-10-033) until the Commission modifies and adopts new rules to comply with the Cap-and-Trade Regulation revisions.


1. Procurement Contracts2. SCE-Owned Generation3. Out of State Imports4. Market Purchases5. QF and Non QF Renewables

6. Total 20,205,632


1. Procurement Contracts2. SCE-Owned Generation3. Out of State Imports4. Market Purchases5. QF and Non QF Renewables

6. Total 313,591$

37

Phase 2 Decision. The prior period reconciliation reflects 1) amounts recorded in 2016 and 2) amounts 1

recorded through September 30, 2017 and estimated through December 31, 2017, consistent with the 2

methodology established in D.14-10-033. 3

Table VII-18 Updated Annual GHG Emissions and Associated Costs

(Template D-2)

Line Description

ForecastFinal (Recorded

through December 2013)

Forecast

Recorded (Used to Set 2015 GHG

Revenue Returns)

Final (Recorded through

December 2014)Forecast


Revenue Returns)

Final(Recorded through

December 2015)Forecast


Revenue Returns)

Final(Recorded

through December 2016)

Forecast

Recorded Through

September 2017, Forecast Oct. -

Dec. 2017

Forecast Recorded

(1) (2) (3) (4) (5) (6) (7) (8) (9) ( 0) (11) (12) (13) (14) (15)1 Direct GHG Emissions (MTCO2e)2 Utility Owned Generation (UOG)3 Tolling Agreements - Physical 1/4 Energy Imports (Specified)5 Energy Imports (Unspecified) 2/6 Tolling Agreements - Financial7 Subtotal

8 Indirect GHG Emissions (MTCO2e)9 CAISO Market Purchases 10 Qualifying Facility (QF) Contracts 3/

11 Subtotal

12 Total Emissions (MTCO2e) 8 540 635 24 754 614 22 787 127 24 720 902 24 609 528 24 704 713 25 142 610 24 541 264 26 250 022 27 148 085 25 628 392 23 515 963 23 521 820 20 205 632 -

13 Weighted Average Cost of Compliance Instrument 14 Average Price for Financial Toll Settlement ($/MT) 4/15 Proxy GHG Price ($/MT) 5/ 14.62$ 13.56$ 12.48$ 11.97$ 12.04$ 12.65$ 12.76$ 12.79$ 13.14$ 12.81$ 12.84$ 13.19$ 13.60$ 15.52$ -$

16 GHG Costs ($)17 Direct GHG Costs 18 Direct GHG Costs - Tolling Agreements 19 Indirect GHG Costs20 Current Year Total GHG Costs 271 064 082$ 313 850 285$ 284 383 339$ 293 032 374$ 293 315 968$ 312 514 619$ 311 749 078$ 304 588 374$ 344 925 289$ 343 583 069$ 325 541 777$ 310 175 547$ 319 892 396$ 313 591 409$ -$ 21 Previous Year's Forecast Reconciliation (Line 23) -$ -$ 42 786 203$ 42 786 203$ -$ 8 649 035$ 8 649 035$ -$ (481,947)$ (481,947)$ -$ (8,502,925)$ (8,502,925)$ (8,324,443)$ -$ 22 Total Costs ($) 271 064 082$ 313 850 285$ 327 169 542$ 335 818 577$ 293 315 968$ 321 163 654$ 320 398 113$ 304 588 374$ 344 443 342$ 343 01 122$ 325 541 777$ 301 672 623$ 311 389 471$ 305 266 966$ -$

23 Forecast Variance ($) 6/ N/A 42,786,203$ N/A 8,649,035$ 283,594$ N/A (765,54 )$ (7, 60,705)$ N/A (1,342,220)$ (18,041,292)$ N/A 9,7 6,849$ N/A 0

1/ Emiss ons for Tolling Agreement exposure that is settled using in entory. 2/ Electric ty importers may claim certa n adjustments for renewable energy purchases and exported electricity. These adjustments may reduce a compliance entity's cap-and-trade compliance obl gat on and are accounted for in L ne 5. 3/ SCE considers GHG costs assoc ated with QF Contracts as an indirect GHG emissions obligation since the GHG costs are embedded in the energy costs for these resources. / In order to calculate the costs associated with Financial Toll Agreement Settlement consistent with the methodology described in Section 2.1 of the Phase II Dec sion the utilities use the A erage Settlement Price for these resources as calculated in Template C-1. 5/ Recorded Proxy GHG Price = A erage CAISO Daily GHG Allowance Price Index 6/ The Forecast Variance of ($8.502) million shown n Column 12 was pre iously reflected in the GHG cost true-up in the 2017 GHG re enue returns (D.16-12-05 ). The Forecast Variance of ($8 32 ) million shown in Column 1 is the incremental true-up amount for 2016 associated with us ng actual year-end data of ($18 0 1) million plus a forecast ariance of $9.717 million n 2017 (using September recorded).

201820162013 20152014 2017

As shown in Template D-2 (Line 20), SCE’s forecast of 2018 GHG costs is $313.591 million. 4

As presented in Section E of this chapter, SCE will adjust the 2018 allowance revenue returns to eligible 5

small business customers that receive volumetric returns of allowance revenue to account for the 6

($8.324) million deviation between prior period forecasts and recorded costs (Line 21 in Template D-2) 7

for both the 2017 estimated forecast variance of $9.717 million and the 2016 true-up for the forecast 8

variance of ($18.041) million. 9

Table VII-19 below provides the updated information for Template C-1 “Weighted Average Cost 10

of Compliance Instruments Calculation” consistent with the Phase 2 Decision and provides the support 11

for the 2017 recorded weighted average cost of compliance instrument inventory $/MT and the average 12

price for financial toll settlement $/MT used in Template D-2 above. 13

38

Table VII-19 Updated Weighted Average Cost of GHG Compliance Instruments Calculation

(Template C-1)

Month Transaction Type QuantityCost

($/MT)Sales

Price ($)Total Cost ($)

Inventory Balance ($)

Total Qty in Inventory

WAC ($) Monthly AccruedSummary Monthly

True upTotal after

True upMonthly Accrued

Summary Monthly

True upTotal after

True upDec-16Jan-17 Month Jan-17 Month Jan-17Feb-17 End of Month WAC 2016 ICE forward priceMar-17 Physical Settement (629,980.00) 12.41 (7,816,713.64) Monthly Emissions (MT) Monthly Emissions (MT)Mar-17 Purchase 25,000.00 13.45 336,250.00 Balancing Account Entry for Month Balancing Account Entry for MonthApr-17May-17 Purchase 999,000.00 13.80 13,786,200.00 Month Feb-17 Month Feb-17Jun-17 Physical Settement (755,013.00) 12.56 (9,480,508.50) End of Month WAC 2016 ICE forward priceJul-17 Monthly Emissions (MT) Monthly Emissions (MT)

Aug-17 Purchase 1,972,000.00 14.75 29,087,000.00 Balancing Account Entry for Month Balancing Account Entry for MonthAug-17 Purchase 874,309.00 13.74 12,013,005.66 Sep-17 Physical Settement (893,098.00) 13.02 (11,628,135.96) Month Mar-17 Month Mar-17

End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month Apr-17 Month Apr-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month May-17 Month May-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month Jun-17 Month Jun-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month Jul-17 Month Jul-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month Aug-17 Month Aug-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Month Sep-17 Month Sep-17End of Month WAC 2016 ICE forward priceMonthly Emissions (MT) Monthly Emissions (MT)Balancing Account Entry for Month Balancing Account Entry for Month

Total Volume (MT) Total Volume (MT)Total Amount ($) Total Amount ($)

WAC WAC

Physical Inventory Physical Settlement Financial Settlement

39

C. Updated 2018 Administrative and Customer Outreach Expenses 1

As detailed in Table VII-20 below, which provides the information for Template D-3 “Detail of 2

Outreach and Administrative Expenses” as ordered by the Phase 2 Decision, SCE is currently estimating 3

it will record $192,197 in 2017 associated with administrative and internal customer outreach-related 4

costs. The recorded costs primarily include the marketing, education and outreach costs associated with 5

the April and October climate credits. For 2018, SCE’s updated forecast is $200,000, which is $50,000 6

lower than the forecast set forth in SCE’s direct testimony in this proceeding. 7

Table VII-20 Updated Detail of Outreach and Administrative Expenses

(Template D-3)

D. Updated 2018 GHG Allowance Revenue Forecast 8

SCE forecasts each year’s GHG allowance revenue by multiplying the total volume of 9

allowances that the CARB has allocated to SCE for 2018 by a forecast proxy price for these allowances. 10

This is consistent with the Phase 2 Decision adopted methodology for forecasting GHG allowance 11

revenues. Based on SCE’s forecast GHG exposures and planned settlement strategies in 2018, SCE has 12

planned consignment volumes in the 2018 ARB auctions as shown below in Table VII-21 below. 13

Line Description Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded 1/ Forecast Recorded 1 Utility Outreach Expenses ($)2 Customer Call Center -$ -$ -$ -$ 95,000$ -$ 95,000$ -$ 95,000$ -$ -$ -$ 3 Marketing - SCE (incl email, bill inserts) -$ -$ -$ 219,112$ 305,000$ 266,961$ 305,000$ 184,711$ 305,000$ 190,197$ 190,000$ -$ 4 Targetbase 225,000$ -$ -$ 227,045$ -$ -$ -$ -$ -$ -$ -$ -$ 5 Other - Marketing/Advertising Agency -$ -$ -$ -$ 162,500$ -$ 162,500$ -$ 162,500$ -$ -$ -$ 6 Subtotal Outreach 225,000$ -$ -$ 446,157$ 562,500$ 266,961$ 562,500$ 184,711$ 562,500$ 190,197$ 190,000$ -$

7 Utility Administrative Expenses ($)8 IT-related expenses 850,000$ 326,828$ 50,000$ 140,437$ 30,000$ 146,300$ 30,000$ 27,728$ 30,000$ -$ 10,000$ -$

9 Utility Outreach and Administrative Expenses ($) (Line 6 + Line 8) 1,075,000$ 326,828$ 50,000$ 586,594$ 592,500$ 413,261$ 592,500$ 212,439$ 592,500$ 190,197$ 200,000$ -$

10 Additional (Non-Utility) Statewide Outreach ($) 1,400,000$ -$ -$ 1,400,058$ -$ -$ -$ -$ -$ -$ -$ -$

11 Total Outreach and Administrative Expenses ($) (Line 9 + Line 10) 2,475,000$ 326,828$ 50,000$ 1,986,652$ 592,500$ 413,261$ 592,500$ 212,439$ 592,500$ 190,197$ 200,000$ -$

1/ Recorded through September 30, 2017 plus estimated through December 31, 2017

201820172015 201620142013

40

Table VII-21 SCE’s Updated 2018 Forecast Consignment in ARB Auctions

(Metric Tons CO2e

SCE’s updated forecast cap-and-trade auction revenues for 2018, calculated by multiplying the 1

expected consignment volumes by the proxy allowance price of $15.52, are shown below in Table VII-2

22. The forecasted price for allowances used to calculate SCE’s forecast 2018 cap-and-trade revenues 3

of $15.52/MT is the same as the forecast price used to calculate expected 2018 cap-and-trade costs in 4

Chapter IV. 5

Table VII-22 SCE’s Updated Forecast 2018 Allowance Revenue

($000)

SCE now has actual allowance revenue amounts from the February, May and August 2017 6

auctions. SCE’s updated forecast for the November 2017 auction is based on an updated forecast proxy 7

price of $15.19/MT, which is the ICE settlement price for the vintage 2017 allowances with delivery in 8

December 2017. Table VII-23 below presents SCE’s updated 2017 GHG allowance revenue amounts. 9

Line No. Auction Date Metric Tons CO2e1. February 20182. May 20183. August 20184. November 20185. Total 2018 Forecast 25,889,683

Line No. Auction Date ($000)1. February 20182. May 20183. August 20184. November 20185. Total 2018 Forecast 401,808$

41

Table VII-23 SCE’s Updated Recorded/Forecast 2017 Allowance Revenue

E. Updated 2018 GHG Revenue Return 1

Pursuant to Commission Decision 12-12-033, GHG allowance revenue is first set aside to cover 2

forecast annual administration and customer outreach costs. Under Public Utilities Code Section 3

748.5(c), the Commission may allocate up to 15% of allowance revenue for clean energy and EE 4

projects that are not funded by another source and approved by the Commission in relevant proceedings 5

where EE or clean energy programs are comprehensively reviewed.39 AB 693 directed the Commission 6

to authorize the allocation of $100 million or 10% of available funds, whichever is less, for the 7

Multifamily Affordable Housing (MASH) Solar Roofs Program, commencing July 1, 2016 and ending 8

June 30, 2020. On March 18, 2016, in response to AB 693, an ALJ ruling issued in R.14-07-002 9

directed the IOUs in their 2017 ERRA Forecast applications to take steps to estimate funds to be 10

allocated to the MASH Solar Roofs Program, which will result in more accurate calculations of proceeds 11

distribution and minimize true-ups needed in future years. These set-aside amounts were accounted for 12

in the 2017 GHG revenue returns as authorized in D.16-12-054. 13

Effective in 2018, AB 693, as amended by SB 92 (codified in CPUC Section 2870(c)),40 directs 14

the Commission to allocate “one hundred million dollars ($100,000,000) or 66.67 percent of available 15

funds, whichever is less, from the revenues described in subdivision (c) of Section 748.5 for the 16

39 SCE’s Total Allowance Revenue for Clean Energy Programs Amount is $60 million (i.e., 15% of Line 5 on

Table VII-24). 40 Senate Bill (SB) 92 (Stats. 2017, Ch. 26), ratified on June 27, 2017.

Line No. Auction Date ($000)1. February 2017 (Recorded)2. May 2017 (Recorded)3. August 2017 (Recorded)4. November 2017 (Forecast)5. Total 2017 Fcst./Rcrd. 385,767$

42

Multifamily Affordable Housing Solar Roofs Program.” In an email Ruling dated October 18, 2017,41 1

ALJ Miles directed the IOUs in their respective November ERRA Update testimonies to provide: 1) an 2

updated calculation of the allocation of GHG net revenues to the Multifamily Affordable Housing Solar 3

Roofs Program pursuant to PUC Section 2870(c); and 2) a before-and-after comparison of the effect on 4

the residential Climate Credit and an explanation of how the calculations comply with SB92. In 5

addition, ALJ Miles directed SCE to coordinate with the other IOUs “so that a consistent methodology 6

is developed among the three investor owned utilities in California.” The three IOUs discussed via 7

conference call on October 20, 2017, and confirmed via emailed dated October 24, 2017, that $100 8

million is the “lesser amount” ordered by SB92, and that the statewide cost allocation among the three 9

IOUs for this funding amount should follow the cost responsibility in the California Solar Initiative 10

(CSI) proceeding.42 SCE’s allocated funding percentage from that proceeding is 46%. Accordingly, 11

Line 14 of Table VII-24 shows SCE’s 2018 SB92 allocation of GHG revenues for Multifamily 12

Affordable Housing Solar Roofs Program in the amount of $46 million (i.e., 46% of $100 million), 13

which results in SCE’s proposed semi-annual 2018 residential Climate Credit of $36.00. Without the 14

SB92 allocation of revenues for the Multifamily Affordable Housing Solar Roofs Program, SCE’s semi-15

annual 2018 residential Climate Credit would be $41.00.43 This calculation is shown in Appendix C. 16

Next, the amount of revenue owed to EITE customers in 2018 is forecast based on the final 2017 17

EITE return amounts provided by the Energy Division on June 15, 2017, followed by volumetric returns 18

to small business customers (taking into account an Industry Assistance Factor in 2018 of 70%). 19

41 On October 31, 2017, ALJs Simon and Hecht issued a Proposed Decision in R.14-07-002, which clarifies the

method for allocating AB693 funding among the IOUs which differs from the method the IOUs agreed to pursuant to ALJ Miles’ email ruling of October 18, 2017. Given the timing considerations for the submission of the IOUs’ respective November Updates, the fact that there is no final Commission decision on the issue, and because the differences in the two methods are not expected to result in materially-different allocations, in this testimony SCE proposes to use the method agreed to by the IOUs. If the Commission issues a final decision in R.14-07-002 that implements a different methodology, any resulting changes can be trued-up in SCE’s 2019 ERRA Forecast proceeding.

42 SCE’s share of 46% is based on the allocation in “Table 1:MASH/SASH Individual Utility Funding Allocations” on p.27 in D.15-01-027.

43 Please see supporting workpapers which provide the “before-and-after” calculations.

43

Finally, any remaining GHG allowance revenue is distributed as California Climate Credit payments to 1

residential customers. 2

Table VII-24 below provides the information for Template D-1 “Annual Allowance Revenue 3

Receipts and Customer Returns” pursuant to the Phase 2 Decision, and presents an accounting of the 4

recorded GHGRBA activity through September 30, 2017 and estimated activity for October 1 – 5

December 31, 2017. This reconciliation produces an “over-collection” (meaning that the 2017 forecast 6

revenue returns were overstated) due to the difference in forecast and actual auction allowance revenues 7

and allowance revenue returns. This over-collected amount of ($15.816) million is added to the forecast 8

year 2018 auction allowance revenues to determine the net revenue amount available for disbursement 9

to eligible customers in 2018. 10

Based on the updated costs and revenues as set forth in this testimony, SCE’s proposed 2018 11

residential California Climate Credit is $36.00 to be distributed twice (April and October) in 2018 on 12

residential customer bills. 13

Table VII-24 Updated Annual Allowance Revenue Receipts and Customer Returns (Template D-1)

Line Description Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded 1/ Forecast Recorded

1 Proxy GHG Price ($/MT) N/A N/A 12.48$ 12.04$ 12.65$ 12.79$ 13.14$ 12.84$ 13.50$ N/A 15.52$ N/A

2 Allocated Allowances (MT) 32 603 468 32 603 468 31 594 859 31 594 859 31 399 111 31 399 111 29 550 282 29 550 281 26 868 834 26 868 834 25 889 683 25 889 683

3 Revenues ($)4 Prior Balance N/A N/A (389 586 000)$ (384 888 000)$ (160 837 218)$ (167 118 600)$ (346 523)$ (22 378 563)$ 30 396 659$ 29 397 778$ (15 816 954)$ -$ 5 Allowance Revenue (389 232 000)$ (384 638 000)$ (394 304 000)$ (368 730 000)$ (397 199 000)$ (390 808 663)$ (388 290 705)$ (376 175 077)$ (362 460 584)$ (385 767 014)$ (401 808 000)$ -$ 6 Interest (354 000)$ (250 000)$ 177 000$ (299 600)$ -$ -$ -$ -$ -$ -$ -$ -$ 7 Franchise Fees and Uncollectibles -$ -$ (6 620 000)$ (7 641 000)$ (4 463 271)$ (5 606 232)$ (4 363 170)$ (4 227 028)$ (4 207 516)$ (4 478 062)$ (4 664 269)$ -$ 8 Subtotal Revenues (389 586 000)$ (384 888 000)$ (790 333 000)$ (761 558 600)$ (562 499 489)$ (563 533 494)$ (393 000 398)$ (402 780 668)$ (336 271 441)$ (360 847 299)$ (422 289 223)$ -$

9 Expenses ($)10 Outreach and Administrative Expenses (from Template D-3) 2 475 000$ -$ 50 000$ 2 313 000$ 592 500$ 413 261$ 592 500$ 212 439$ 250 000$ 190 197$ 200 000$ -$ 11 Franchise Fees and Uncollectibles -$ -$ -$ -$ 6 658 4 797 6 658 2 466 2 902 2 208$ 2 322$ -$ 12 Interest -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 13 Subtotal Expenses 2 475 000$ -$ 50 000$ 2 313 000$ 599 158$ 418 058$ 599 158$ 214 905$ 252 902$ 192 405$ 202 322$ -$

14 AB693/SB92 Set Aside for Multi Family Solar Rooftops (2018 funds) -$ -$ 46 000 000$ 15 Prior Year Set Aside (2016 and 2017 funds) 8 077 223$ 8 077 223$ -$ -$

16 Net GHG Revenues ($) (Line 8 Line 13 Line 14 Line 15) (387 111 000)$ (384 888 000)$ (790 283 000)$ (759 245 600)$ (561 900 331)$ (563 115 436)$ (392 401 240)$ (402 565 763)$ (327 941 316)$ (352 577 671)$ (376 086 902)$ -$ 17 GHG Revenues to be Distributed in Future Years ($) -$ -$ 194 616 000$ 192 319 000$ -$ -$ -$ -$ -$ -$ -$ -$

18Net GHG Revenues Available for Customers in Forecast Year ($) (Line 16 Line 17)

(387 111 000)$ (384 888 000)$ (595 667 000)$ (566 926 600)$ (561 900 331)$ (563 115 436)$ (392 401 240)$ (402 565 763)$ (327 941 316)$ (352 577 671)$ (376 086 902)$ -$

19 GHG Revenue Returned to Eligible Customers ($)20 EITE Customer Return -$ -$ 30 008 000$ 30 008 000$ 34 673 000$ 34 673 000$ 25 488 811$ 50 591 667$ 26 673 763$ 25 866 502$ 25 948 227$ -$ 21 Small Business Volumetric Return 2/ -$ -$ 30 550 000$ 40 961 000$ 39 496 000$ 52 964 531$ 24 446 633$ 32 179 018$ 21 725 095$ 27 111 903$ 19 941 970$ -$ 22 Residential Volumetric Return -$ -$ 178 425 000$ 169 887 000$ 225 679 000$ 194 522 279$ -$ 11 209 570$ -$ -$ -$ 23 Subtotal EITE Volumetric Returns -$ -$ 238 983 000$ 240 856 000$ 299 848 000$ 282 159 809$ 49 935 444$ 93 980 255$ 48 398 858$ 52 978 405$ 45 890 197$ -$

24 Number of Households Eligible for the California Climate Credit - - 4 447 615 4 380 118 4 487 449 4 427 938 4 493 380 4 434 566 4 522 905 4 522 905 4 566 483 - 25 Per-Household Semi-Annual Climate Credit N/A N/A 40$ 40$ 29$ 29$ 38$ 38$ 31$ 31$ 36$ -$

(0.5 x Line 18 Line 23) / Line 24)

26Revenue Distributed for the Climate Credit ($)(2 x Line 25 x Line 24)

-$ -$ 356 684 000$ 351 271 000$ 262 052 331$ 258 577 064$ 342 465 796$ 337 983 286$ 279 542 458$ 283 782 311$ 330 196 705$ -$

27 Revenue Balance ($)(Line 8 Line 13 Line 23 26) (387 111 000)$ (384 888 000)$ (194 616 000)$ (167 118 600)$ -$ (22 378 563)$ -$ 29 397 778$ (8 077 223)$ (15 816 954)$ (46 000 000)$ -$

1/ Recorded through September 30 2017 plus est mated through December 31 2017.2/ SCE rece ved ema l notice on October 12 2017 that per ARB s 2016 amendments to the Cap-and-Trade Regu ation the Small Bus ness Volumetric is discont nued as of October 1 2017. However SCE s advised by the CPUC Energy Division that no changes to the return of GHG revenues should be made until the Energy Division issues its guidance.

2013 201820162014 2015 2017

44

F. Updated 2018 GHG Cost and Revenue Distribution for EITE and Volumetric Returns by 1

Rate Schedule 2

Table VII-25 below sets forth the updated 2018 amounts of GHG revenue allocated to small 3

business customers (utilizing a 70% small business assistance factor in 2018 per D.13-12-002) on a 4

volumetric return basis necessary to offset the amount of cap-and-trade costs in rates44, based on the 5

cap-and-trade costs described in Chapter IV of this exhibit, and includes a true-up for the deviation 6

between the forecast authorized prior period GHG costs (used to set the 2017 revenue returns) and actual 7

prior period GHG costs as supported in Section B of this chapter. The table below also presents SCE’s 8

updated 2018 forecast EITE revenue returns by rate class and customer group, which is set at the 2017 9

recorded level of EITE revenue returns provided by the Energy Division. 10

In 2018, SCE is proposing recovery of 2018 forecast cap-and-trade costs of $313.591 million, or 11

$317.232 million including FF&U, through all bundled service customers’ generation rates. For the 12

purposes of setting the small business volumetric credits in 2018, this total 2018 GHG cost amount of 13

$317.232 million is decreased to account for the $8.324 million ($8.421 million including FF&U) 14

deviation between the forecast authorized prior period GHG costs and actual prior period GHG 15

computed costs as presented in Template D-2. This results in an amount of $308.811 million to be used 16

to set the 2018 allowance revenue returns (i.e., volumetric ¢/kWh credits) to eligible small business 17

customers as shown in Table VII-25 below. 18

44 On October 1, 2017, the 2016 amendments to the Cap-and-Trade Regulation became effective and included a

prohibition, effectively immediately, of the volumetric return of auction proceeds to ratepayers (for SCE, this applies to the small business customer revenue returns). On October 24, 2017, SCE received direction through email exchanges with the Commission’s Energy Division that the existing rules comply (i.e., as established in D.12-12-033 and D.14-10-033) until the Commission modifies and adopts new rules to comply with the Cap- and-Trade Regulation revisions.

45

Table VII-25 Updated GHG Allowance Revenue Allocation by Class

Finally, Table VII-26 below provides the updated GHG costs and revenues by rate schedule, and 1

Table VII-27 below provides the updated history of GHG revenue, costs and emissions intensity, as 2

required by the Phase 2 Decision (Templates D-4 and D-5 of Attachment D of the Phase 2 Decision). 3

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)Rate Class GHG GHG 2018 Forecasted GHG GHG GHG EITE EITE Non-EITE Non-EITE Total

Line By Bndl Cost Bndl Cost Bundled Unit Cost Bndl Cost w/true up Unit Cost Credit Credit Credit Credit CreditNo. Customer Group Allocator ($000) MWh Rate ($000) w/true up System MWh ($000) System MWh ($000) ($000)

DomesticGroup Total 41.5% $0.00496 $0.00483 -$

Lighting-SM Med PowerGS-1 8.6% $0.00465 $0.00453 19,203$ GS-2 17.9% $0.00498 $0.00484 786$ TC-1 0.1% $0.00375 $0.00365TOU-GS-2 8.4% $0.00441 $0.00429 126$

Large PowerTOU-8-SEC 7.8% $0.00409 $0.00398 1,691$ TOU-8-PRI 4.5% $0.00378 $0.00368 3,156$ TOU-8-SUB 4.2% $0.00357 $0.00348 11,854$

Agricultural & PumpingTOU-PA-2 2.3% $0.00411 $0.00400 849$ TOU-PA-3 1.4% $0.00304 $0.00296 257$

Street & Area LightingLS-1 0.3% $0.00263 $0.00256 -$ LS-2 0.1% $0.00255 $0.00248LS-3 0.2% $0.00303 $0.00295DWL 0.0% $0.00255 $0.00249OL-1 0.0% $0.00262 $0.00255

StandbyTOU-8-SEC 0.2% $0.00404 $0.00394 71$ TOU-8-PRI 0.7% $0.00383 $0.00373 469$ TOU-8-SUB 1.9% $0.00336 $0.00327 7,431$

Total 100% 317,232$ 308,811$ 25,948$ 19,942$ 45,890$

46

Table VII-26 Updated GHG Costs and Revenues by Rate Schedule (Template D-4)

Table VII-27 Updated History of GHG Revenues, Costs, and Emissions Intensity (Template D-5)

Rate Class By Customer GroupForecast MWh Sales

(MWh)Forecast GHG

Revenue Req ($) Rate Impact ($/kWh)Forecast GHG

Revenue ($)Forecast MWh Sales (MWh)

Forecast GHG Revenue Req ($)

Rate Impact ($/kWh)

Forecast GHG Revenue ($)

DomesticGroup Total 0.00496 $0 0.00000 (3,670,249)

Lighting-SM Med PowerGS-1 0.00465 $0 0.00000 (590,820)GS-2 0.00498 $0 0.00000 (636,591)TC-1 0.00375 $0 0.00000 0TOU-GS3 0.00441 $0 0.00000 (17,424)

Large PowerTOU-8-SEC 0.00409 $0 0.00000 (784,241)TOU-8-PRI 0.00378 $0 0.00000 (1,662,669)TOU-8-SUB 0.00357 $0 0.00000 (4,770,303)

Agricultural & PumpingTOU-PA-2 0.00411 $0 0.00000 (23,497)TOU-PA-3 0.00304 $0 0.00000 0

Street & Area LightingLS-1 0.00263 $0 0.00000 0LS-2 0.00255 $0 0.00000 0LS-3 0.00303 $0 0.00000 0DWL 0.00255 $0 0.00000 0OL-1 0.00262 $0 0.00000 0

StandbyTOU-8-SEC 0.00404 $0 0.00000 (62,982)TOU-8-PRI 0.00383 $0 0.00000 (234,569)TOU-8-SUB 0.00336 $0 0.00000 (1,271,195)

Total $317,231,642 (362,362,363) $0 0.00000 (13,724,539)

Notes: Rate impact for domestic customer is different than unit cost in Table VII-25 because it is calculated using total residential sales instead of only upper tiered sales. GHG cost will be applied to upper tier sales only when rates are implemented

Bundled Customers DA Customers

Recorded Recorded Recorded Recorded Forecast 1/ ForecastLine Description 2013 2014 2015 2016 2017 2018

1 Total GHG Revenues (Net available for customers) 384,888,000$ 370,569,587$ 396,414,894$ 380,402,105$ 390,245,077$ 406,472,269$ 2 Total GHG Costs 313,850,286$ 293,315,968$ 304,588,374$ 325,541,777$ 319,892,396$ 313,591,409$ 3 Emissions Intensity (MTCO2e/MWH) 0.33 0.33 0.33 0.35

1/ Recorded through September 2017 plus estimated through December 2017

47

VIII. 1

UPDATED 2018 FORECAST REVENUE REQUIREMENT AND RATEMAKING PROPOSAL 2

A. Introduction 3

The purpose of this chapter is to present SCE’s updated 2018 ERRA Forecast Proceeding 4

revenue requirement of $4.556 billion, as shown on Line No. 14 in Table VIII-28. This 2018 ERRA 5

Forecast revenue requirement includes 2018 GHG cap-and-trade costs and allowance revenues to be 6

returned to eligible customers in 2018 as supported in Chapter VII of this exhibit. 7

SCE will include the actual December 31, 2017 year-end recorded balancing account balances in 8

the ERRA revenue requirement rate change and advice letter filed in compliance with a Commission 9

decision in this proceeding, if available. 10

Table VIII-28 Updated Estimate of 2018 ERRA Forecast Proceeding Revenue Requirement

($000)

Line Description Updated Estimated 2018 Revenue Requirement

1. Generation Service

2. Generation Fuel and Purchased Power Revenue Requirement 3,874,918$ 3. Estimated December 31, 2017 ERRA Balance 360,872$ 4. Estimated Generator Refunds as of December 31, 2017 1/ (7,060)$ 5. GHG Cap-and-Trade Costs 317,232$ 6. TOTAL ERRA PROCEEDING GENERATION SERVICE 4,545,962$

7. Delivery Service

8. New System Generation Revenue Requirement 505,700$ 9. Estimated December 31, 2017 NSGBA Balance (151,822)$

10. LCR F&PP Revenue Requirement 27,533$ 11. Spent Nuclear Fuel Storage Revenue Requirement 4,361$ 12. GHG Allowance Revenues (376,087)$ 13. TOTAL ERRA PROCEEDING DELIVERY SERVICE 9,686$

14. TOTAL ERRA PROCEEDING REVENUE REQUIREMENT 4,555,648$ 1/ Estimated Generator Refunds are net of litigation costs.

48

B. Updated Estimate of 2018 ERRA-Related Generation Service Revenue Requirement 1

As shown above on Line No. 6 of Table VIII-28, SCE requests a 2018 ERRA generation service 2

revenue requirement of $4.546 billion. This revenue requirement is a consolidation of estimated fuel 3

and purchased power expenses, GHG cap-and-trade costs, the estimated December 31, 2017 balance in 4

the ERRA balancing account and estimated net45 generator refunds stemming from electricity 5

overcharges to SCE during the 2000-2001 California Energy Crisis. 6

1. Updated Estimate 2018 Fuel and Purchased Power Revenue Requirement 7

As shown below on Line No. 36 in Table VIII-29, SCE’s requested 2018 fuel and purchased 8

power cost revenue requirement is $4.725 billion. This amount includes $58.0 million for franchise fees 9

and uncollectible (FF&U) expense and municipal surcharges.46 10

45 The forecast estimated net generator refunds are net of forecast associated litigation costs, which are recorded

in the LCTA. 46 The FF&U amount is determined using the current FF&U factor adopted by the Commission in D.15-11-021.

The municipal surcharge amount as shown on Line 23 is the amount of the municipal surcharges (franchise fees) that SCE estimates it will pay associated with the DWR revenue requirement in 2018.

49

Table VIII-29 Updated Estimate of 2018 Fuel and Purchased Power Revenue Requirement

($000)

Line


Requirement1. Fuel2. Palo Verde - Nuclear3. Catalina - Diesel and Propane 5,175$ 4. Peakers - Gas5. Mountainview - Gas6. Fuel Inventory Carrying Cost7. GHG Carrying Cost8. Subtotal Fuel 160,975$

9. Purchased Power10. CHP and Renewables 11. Removal of A.16-11-005 Forecast Costs12. 2013 Bilateral 13. Demand Response -$ 14. Direct and Tolling Contract GHG Costs15. Gas Hedging16. Gas Transportation and Storage17. Generic & Bilateral RA18. Green Rate Program 925$ 19. Interutility20. ISO & S/T Market Activities 1/21. Collateral22. Subtotal Purchased Power 3,979,270$

23. Total - Generation Service 4,140,245$ 24. FF&U 48,061$ 25. Municipal Surcharge (Franchise Fees) 3,845$ 26. Subtotal FF&U and Municipal Surcharge 51,905$ 27. Total - Generation Service 4,192,150$ 28. Delivery Service29. New Gen CAM Capacity 30. CHP Settlement31. CAM-related Peakers32. LCR Contracts33. PRP Solicitation34. FF&U35. Total - Delivery Service 533,233$ 36. TOTAL F&PP Revenue Requirement 4,725,383$

Component

1/ Includes bundled service share of CAM energy and ancillary services per D.14-02-040.

50

a) Fuel Expense 1

As shown below on Line No. 12 in Table VIII-30, SCE has estimated its total 2018 fuel costs to 2

be $160.975 million. 3

Table VIII-30 Updated Estimate of 2018 Estimated Fuel Expense

($000)

The estimated 2018 PVNGS, Mountainview, Peakers, and Catalina fuel costs are supported in 4

Chapter IV. The forecast of fuel inventory carrying costs associated with nuclear, natural gas, and diesel 5

fuel inventories are supported in Chapter VI. 6

b) Purchased Power Expense 7

As shown below on Line No. 25 in Table VIII-31, SCE has estimated its total 2018 purchased 8

power costs to be $4.564 billion as supported in Chapter IV. Collateral costs, as shown on Line No. 24, 9

are supported in Chapter VI. 10

Line Amount

1. Nuclear - Palo Verde

2. Gas3. Peakers4. Mountainview5. Gas Subtotal 115,477$

6. Catalina7. Diesel 5,040$ 8. Propane 135$ 9. Catalina Subtotal 5,175$

10. Fuel Inventory Carrying Cost11. GHG Carrying Cost

12. TOTAL 160,975$

Component

51

Table VIII-31 Updated Estimate of 2018 Purchased Power Expense

($000)

2. Updated December 31, 2017 ERRA Balance 1

The ERRA was established in D.02-10-062, effective January 1, 2003. The purpose of the 2

ERRA is to record the difference between ERRA-related revenue and SCE’s fuel and purchased power 3

expenses. 4

As set forth on Line No. 14 of Table 1 in Appendix A and as shown on Line 3 of Table VIII-28 5

(includes FF&U), SCE estimates that the balance in the ERRA balancing account as of December 31, 6

Line Amount1. CHP & Renewables2. Capacity3. Energy4. Other5. Subtotal

6. 2013 Bilateral7. Capacity8. Energy9. Subtotal

10. LCR Contracts11. Capacity12. Energy13. Subtotal

14. PRP Solicitation

15. Demand Response (Energy) -$

16. Direct and Tolling Contract GHG Costs

17. Gas Hedging

18. Gas Transportation and Storage

19. Generic & Bilateral RA

20. Green Rate Program 925$

21. Interutility

22. ISO & S/T Market Activities 1/

23. New Gen CAM Capacity

24. Collateral25. TOTAL 4,563,621$

Component

1/ Includes bundled service share of CAM energy and ancillary services per D.14-02-040.

52

2017 will be an under-collection of $356.7 million. In order to estimate the year-end ERRA balancing 1

account balance, SCE has used recorded amounts through October 31, 2017, plus a forecast of the 2

activity SCE expects to be recorded in the ERRA during November through December 2017. Including 3

FF&U of $4.1 million, the total estimated ERRA year-end under-collection is $360.8 million. SCE will 4

include the recorded operation of the ERRA balancing account for the 2017 Record Period in its April 1, 5

2018 ERRA Review application. 6

3. Updated Energy Settlement Refunds and Litigation Costs 7

SCE is pursuing refunds from generators who overcharged SCE (and the other California IOUs) 8

for electricity during the 2000-2001 California Energy Crisis. As shown on Line No. 13 of Table 3 in 9

Appendix A, SCE is estimating a December 31, 2017 over-collected balance of $10.3 million (including 10

FF&U) in the ESMA. SCE will include the recorded operation of the ESMA for the 2017 Record 11

Period in its April 1, 2018 ERRA Review application. 12

Also included in Table 3 in Appendix A is the Litigation Costs Tracking Account (LCTA). In 13

accordance with Resolution E-3894, SCE shall maintain a LCTA within the ESMA to track: 1) 14

litigation costs that are “set-aside” in the FERC investigation settlement agreements; and 2) actual 15

litigation costs incurred by SCE. As shown on Line No. 30 of Table 3 in Appendix A, SCE is 16

estimating a December 31, 2017 under-collected balance of $3.2 million (including FF&U) in the 17

LCTA. SCE will include the recorded operation of the LCTA for the 2017 Record Period in its April 1, 18

2018 ERRA Review application. Combining the ESMA and LCTA estimated December 31, 2017 19

ending balances results in an overcollection of $7.1 million, as shown on Line 4 of Table VIII-28. 20

C. Updated 2018 ERRA-Related Delivery Service Revenue Requirement 21

As shown on Line No. 13 of Table VIII-28 above, SCE requests a 2018 ERRA Forecast 22

Proceeding delivery service revenue requirement of $9.7 million. This amount is a consolidation of 23

New System Generation costs, the estimated December 31, 2017 balance in the NSGBA, the estimated 24

spent nuclear fuel storage revenue requirement, the estimated LCR contracts revenue requirement, and 25

estimated GHG allowance revenues to be returned to eligible customers in 2018. GHG allowance 26

revenue returns are discussed in Chapter VII. 27

53

1. Updated New System Generation Net Capacity CAM-Related Cost 1

SCE is updating its estimate for the portion of its procurement costs for which the Commission 2

has required CAM treatment. As discussed in more detail in the May Application, CAM-related costs 3

are net capacity costs of a portion of SCE’s procurement costs that the Commission has required to be 4

recovered from all benefiting customers rather than just SCE’s bundled service customers. In SCE’s 5

May Application, the CAM-related revenue requirement was estimated to be $574.9 million. In this 6

update, SCE is estimating the CAM-related revenue requirement to be $505.7 million. Table VIII-32 7

below shows the updated CAM-related revenue requirement estimate. 8

Table VIII-32 Updated Estimate of 2018 CAM-Related Revenue Requirement

($000)

2. Updated December 31, 2017 NSGBA Balancing Account47 9

As set forth on Line No. 17 of Table 2 in Appendix A, SCE estimates that the balance in the 10

NSGBA as of December 31, 2017 will be an over-collection of $150.1 million. In order to estimate the 11

year-end NSGBA balance, SCE has used recorded amounts through October 31, 2017, plus a forecast of 12

the activity SCE expects to be recorded in the NSGBA during November through December 2017. SCE 13

has included in the 2018 ERRA Forecast Proceeding delivery service revenue requirement the estimated 14

year-end over-collection in the NSGBA, plus $1.7 million for FF&U, for a total over-collection of 15

47 Pursuant to D.14-02-040, “energy auctions shall no longer be used net capacity costs [of energy and ancillary

services value] for facilities subject to CAM. Instead, the IOUs shall use the mechanism adopted in D.07-09-044, known as the “Joint Parties Proposal.” SCE will modify the ERRA and NSGBA preliminary statements to reflect this change in the advice letter implementing a final decision in this proceeding.

Line Description Total Est. Payment Less: Energy/AS Value CAM Net Cost1. New Generation PPAs2. Combined Heat and Power3. Peakers4. Subtotal 499,897$ 5. FF&U 5,803$ 6. Total CAM-Related Purchased Power Revenue Requirement 505,700$

54

$151.8 million. SCE will include the recorded operation of the NSGBA for the 2017 Record Period in 1

its April 1, 2018 ERRA Review application. 2

55

IX. 1

UPDATED COST RESPONSIBILITY SURCHARGES (DIRECT ACCESS, DEPARTING 2

LOAD, AND COMMUNITY CHOICE AGGREGATION) 3

The purpose of this chapter is to describe the methodology used to determine the 2018 Cost 4

Responsibility Surcharge (CRS)48 for Direct Access (DA), Departing Load (DL), and Community 5

Choice Aggregation (CCA) customers, collectively CRS. Calculations for the estimated Competition 6

Transition Charge (CTC) and Power Charge Indifference Adjustment (PCIA), which together constitute 7

the CRS Indifference Charge, are included in Appendix B.49 8

As described in the Background section of Chapter IX of SCE’s Opening Testimony, the CRS 9

Indifference Charge is designed to maintain bundled service customer indifference to departing load by 10

ensuring that departing load customers remain responsible for their pro rata share of the above-market 11

costs of generation resources procured on their behalf prior to their departure from bundled service.50 12

To derive this “Indifference Amount,” SCE quantifies the difference between the forecast annual cost of 13

the generation portfolio procured by SCE (“Total Portfolio Cost”), and the forecast market value of that 14

portfolio (defined as the forecast output of the resources in the generation portfolio multiplied by the 15

total market price benchmark). 16

The forecasts of the Total Portfolio Cost and generation of the CRS-eligible portfolio are within 17

1% of the forecast included in SCE’s Opening Testimony, and the individual MPB components are 18

within 5% of the estimates provided in SCE’s Opening Testimony. As such, the changes to the 19

Indifference Charge, relative to the estimates filed in SCE’s Opening Testimony, are primarily 20

attributable to the following factors: 1) Implementation of SCE’s proposal in Phase 2 of A.17-05-001, 21

48 The CRS also includes the Department of Water Resources (DWR) Bond Charge, which is determined in the

annual DWR Revenue Requirement proceeding. The DWR Bond Charge listed in the illustrative CRS rates in Appendix B is the 2017 DWR Bond Charge.

49 The format of Appendix B aligns directly with the common workpapers agreed to by participants in the PCIA Working Group. Formal Commission approval of this new format change is pending in the Joint Utilities’ and Community Choice Aggregators’ Joint Petition for Modification of D.06-07-030, filed on April 5, 2017.

50 See generally Resolution E-4475 at p. 2.

56

which removes the utility-owned generation resources built prior to 1996 (Legacy UOG) from the 2001 1

and 2004 vintage Indifference Charges, effective January 1, 2017 (Pre-2009 Vintage UOG Proposal); 2

and 2) the Commission’s implementation of an Effective Load Carrying Capacity (ELCC) approach to 3

establishing Resource Adequacy (RA) values. Each of these factors is described in additional detail 4

below. 5

A. Finalization of the 2018 MPB 6

As described in SCE’s Opening Testimony, the MPB is set pursuant to the methodology 7

established in D.11-12-018 and Resolution E-4475 and is finalized based on several inputs that are not 8

available until November. The MPB has three components: an energy component (Brown MPB) that is 9

set using forward prices derived from an index obtained from Platt’s and weighted based on SCE’s 10

historical recorded load; a renewable component (Green MPB) that is set using a combination of data on 11

newly-delivering investor-owned utility (IOU) renewable contracts and the average price of voluntary 12

renewable programs throughout the Western Electric Coordinating Council (Department of Energy, or 13

DOE, Green Adder); and a capacity component (Capacity MPB) that is set using the results from a 14

California Energy Commission report. Each of these three components have been updated and are 15

shown in Table IX-33 below. 16

Table IX-33 Comparison of MPBs Over Time

California Choice Energy Authority and the Public Agency Coalition (referred to as the Joint 17

Parties) submitted testimony and briefs in this proceeding requesting that the Commission eliminate the 18

use of the DOE Green Adder in the renewable component of the MPB, and protested SCE’s Advice 19

Market Price Benchmarks Pursuant to Resolution E-4475

2018 ERRA Forecast - Nov.

2018 ERRA Forecast - May

2017 ERRA Forecast

2016 ERRA Forecast

2015 ERRA Forecast

2014 ERRA Forecast

Weighted On/Off Peak Platts Price: "Brown MPB"

$32.37/MWh $31.06/MWh $33.73/MWh $31.79/MWh $41.55/MWh $40.72/MWh

IOU Green Benchmark October 1 Advice Letter Data


Renewable Green Benchmark: "Green MPB"


CEC Estimate of the Going Forward Costs of a Combustion Turbine: "Capacity MPB"

$58.26/kW-Year $58.26/kW-Year $58.26/kW-Year $58.26/kW-Year $50.17/kW-Year $50.17/kW-Year

57

3667-E,51 the annual Tier 1 Advice Letter that submits the relevant data used to set the MPB. In those 1

filings, the Joint Parties assert that the data used to set the DOE Green Adder includes numerous errors 2

and is unavailable.52 The Joint Parties’ protest was correctly rejected on November 1 by Energy 3

Division, who issued a disposition letter approving SCE’s Advice 3667-E and directing SCE to use the 4

most recently published DOE Green Adder of $16.64/MWh. That value has been used in SCE’s 5

Appendix B workpapers.53 6

B. Implementation of SCE’s Pre-2009 Vintage UOG Proposal 7

Phase 2 of A.16-05-001, which is a consolidation of all three IOUs’ 2017 ERRA Forecast 8

proceedings, was initiated to address the applicability of the PCIA to pre-2009 vintage Departing Load 9

customers in light of the expiration of the Department of Water Resources (DWR) power contracts. 10

SCE submitted supplemental testimony on August 21, 2017 in Phase 2 of that proceeding revising its 11

original position, and proposed that pre-2009 vintage departing load customers’ pay PCIA rates that 12

only recover their equitable share of legacy San Onofre Generation Station (SONGS) costs, and which 13

exclude all other above-market costs of SCE’s other Legacy UOG. Additionally, SCE clarified in 14

discovery responses to the Joint Parties and the Direct Access Customer Coalition and Alliance for 15

Retail Energy Markets (DACC/AReM) and in SCE counsel statements on the record at a Pre-Hearing 16

51 The protest of SCE’s Advice 3667-E and PG&E Advice 5151-E was filed by California Choice Energy

Authority, Sonoma Clean Power Authority, Peninsula Clean Energy Authority, and Silicon Valley Clean Energy Authority (Joint CCA Parties).

52 See generally Joint Parties Opening Brief at pp. 10-12, Joint Parties Reply Brief at pp. 3-4, Joint Parties Opening Testimony at pp. 9-12, and the Joint CCA Parties’ protest of SCE Advice 3667-E and PG&E Advice 5151-E.

53 As described at length in SCE’s Opening and Reply Briefs, the Joint Parties’ proposal to eliminate the use of the DOE Green Adder is procedurally inappropriate and should be rejected. Moreover, SCE addressed the factual concerns raised by the Joint Parties in Advice 3667-E by independently validating, and updating if necessary, each of the values previously published on the National Renewable Energy Laboratory (NREL) website and used to set the 2017 DOE Green Adder (independently validated 2018 DOE Green Adder). SCE explained in Advice 3667-E and its response to the Joint CCA Parties’ protest that it provided the 2018 DOE Green Adder as an option to the Commission if it wished to address the Joint Parties’ previously identified factual concerns and observed that the 2018 DOE Green Adder is within 5% of the 2013-2017 DOE Green Adders, but also noted that it did not object to using the 2017 data that was officially published on the NREL website. SCE has used the latter in its Appendix B workpapers.

58

Conference in A.16-05-001, that, pursuant to D.16-12-054, it proposed to implement its proposal 1

retroactive to January 1, 2017 and refund to pre-2009 vintage Departing Load customers any amounts 2

over-collected in 2017. 3

SCE is optimistic that the Commission will approve SCE’s revised proposal; no parties have 4

objected to SCE’s revised proposal. As such, SCE has reflected its revised proposal in the Appendix B 5

workpapers by removing non-SONGS-related Legacy UOG from the 2001 and 2004 vintage departing 6

load customers’ portfolios, and has applied a one-time negative adjustment of $250M to the 2001 and 7

2004 vintage departing load customers’ indifference calculation to effectuate the January 1, 2017 8

retroactive implementation of the proposal. 9

C. Commission’s Implementation of RA Program Changes 10

D.17-06-027 adopted refinements to the 2018 RA program pursuant to Public Utilities Code 11

Section 399.26(d), which requires that the Commission use ELCC values to establish the contribution of 12

wind and solar energy resources toward meeting RA requirements. The Commission describes the 13

ELCC in the following manner: 14

ELCC is a statistical modeling approach to determine the capacity value of different 15 resources relative to “perfect capacity.” For example, if removing 100 MW of solar 16 resources from the grid and replacing it with 50 MW of perfect capacity results in no change 17 in the Loss of Load Expectation, then the ELCC of the solar resources would be 50%.54 18

As noted explicitly in D.17-06-027, the use of ELCC values result in a “notable decrease in RA capacity 19

credit given to solar generators.” Indeed, the average NQC of SCE’s CRS-eligible solar resources, as 20

established in the CAISO’s published NQC list, was reduced by over 50% as compared to the average 21

NQC included in SCE’s Opening Testimony (approximately 730 MW compared to 1,300 MW). On the 22

other hand, the use of ELCC values result in an increase in the RA capacity credit given to wind 23

generators, and the average NQC of SCE’s CRS-eligible wind resources was increased by over 60% 24

(approximately 570 MW compared to 350 MW). Overall, the implementation of these changes resulted 25

54 D.16-06-045 at p. 17. See also D.17-06-026 at pp. 19-21.

59

in a decrease to the NQC of SCE’s CRS-eligible portfolio, which, all else being equal, will reduce the 1

market value of the portfolio and increase the Indifference Charge. 2

D. Implementation of Minor Changes to Common PCIA Template Approved in D.17-08-026 3

Since the finalization of the Common PCIA Template in April,55 SCE has identified a few minor 4

improvements that do not change the overall framework agreed to in the PCIA Working Group. 5

Specifically, following a discussion with Energy Division, SCE has proposed changes to the labels of 6

three of the line items to ensure consistent naming convention throughout the Template, and has added a 7

Franchise Fees and Uncollectibles (FF&U) factor to the final Indifference Amount. Additionally, at the 8

request of the Joint Parties and DACC/AReM, SCE is proposing to separate the SONGS costs from the 9

other Legacy UOG resources, to delete the 2003 and 2004 vintage columns because there are no 10

incremental CRS-eligible resources in those years,56 and to consolidate the 2005-2008 vintage columns 11

with the 2009 vintage column because there are no 2005-2008 vintage departing load customers.57 This 12

change is purely a presentation change that is consistent with the vintage columns presented by PG&E 13

and is consistent with the final PCIA rates in the later Common PCIA Template tabs. A redline copy of 14

the changes was circulated to the parties who submitted the Petition for Modification prior to the 15

submittal of this update testimony, and no party objected to SCE simply utilizing the improved template. 16

55 The Common PCIA Template was jointly developed by parties in the PCIA Working Group. SCE, Pacific

Gas and Electric Company, San Diego Gas & Electric Company, Sonoma Clean Power Authority, Peninsula Clean Energy, Silicon Valley Clean Energy, and Marin Clean Energy filed a Petition for Modification of D.06-07-030 requesting that the Commission adopt the Common PCIA Template for use in future ERRA Forecast proceedings. The Commission approved the Petition for Modification in D.17-08-026.

56 The only SCE resource that was built/procured in 2003-2004 is Mountainview, which is no longer PCIA-eligible.

57 Direct Access was closed to new customers between 2001 and 2009, and no communities departed bundled service for Community Choice Aggregation during that period. The 2005-2008 vintage portfolios were simply shown in SCE’s workpapers to quantify the forecast costs and generation of the resources signed or built in those years. However, because no customers departed SCE's bundled service between the years of 2005-2008, there are no 2005-2008 vintage PCIA rates based on those 2005-2008 vintage portfolio indifference amounts.

60

X. 1

UPDATED PRESENT RATE REVENUE 2

The average rates contained herein reflect SCE’s updated estimated 2018 ERRA rate forecast by 3

class and functional rate component. The average rates are estimated by applying the current revenue 4

requirement in addition to 2018 ERRA-related revenue changes, as proposed in SCE’s 2018 ERRA 5

Forecast Application, to the preliminary forecasted sales by class. The rate information is limited to the 6

proposed revenue changes in the ERRA Application and does not reflect the consolidated revenue 7

requirement changes SCE expects to implement on January 1, 2018. 8

Table X-34 SCE 2018 ERRA Forecast Class Average Rates

RaTe Schedule Transmission Distribution NSGC NDC PPPC DWRBC PURCF UG DWREC Total Total TotalLine By Delivery GenerationNo. CusTomer Group ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)1 DomesTic2 D 0.01523 0.08242 0.00590 0.00001 0.00980 0.00549 0.00043 0.08311 - 0.11928 0.08311 0.20239 3 D-CARE 0.01523 0.00754 0.00590 0.00001 0.00994 - 0.00043 0.08308 - 0.03905 0.08308 0.12213 4 D-APS 0.01523 0.05033 0.00590 0.00001 0.00980 0.00549 0.00043 0.08254 - 0.08719 0.08254 0.16973

DE 0.01523 0.02669 0.00590 0.00001 0.00980 0.00549 0.00043 0.08283 - 0.06355 0.08283 0.14638 6 DM 0.01523 0.09986 0.00590 0.00001 0.00980 0.00549 0.00043 0.08325 - 0.13672 0.08325 0.21997 7 DMS-1 0.01523 0.08939 0.00590 0.00001 0.00980 0.00549 0.00043 0.08325 - 0.12625 0.08325 0.20950 8 DMS-2 0.01523 0.06903 0.00590 0.00001 0.00980 0.00549 0.00043 0.08324 - 0.10589 0.08324 0.18913 9 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------10 Group Total 0.01523 0.06193 0.00590 0.00001 0.00983 0.00412 0.00043 0.08308 - 0.09746 0.08308 0.18053 1112 Lighting-SM Med PoTer13 GS-1 0.01332 0.06366 0.00563 0.00001 0.00716 0.00549 0.00043 0.08440 - 0.09570 0.08440 0.18010 14 GS-2 0.01301 0.06871 0.00528 0.00001 0.00662 0.00549 0.00043 0.07866 - 0.09954 0.07866 0.17821 16 TC-1 0.00772 0.09933 0.00375 0.00001 0.00797 0.00549 0.00043 0.06363 - 0.12470 0.06363 0.18833 17 TOU-GS 0.01239 0.05507 0.00502 0.00001 0.00601 0.00549 0.00043 0.07411 - 0.08441 0.07411 0.15853 18 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------19 Group Total 0.01291 0.06401 0.00530 0.00001 0.00660 0.00549 0.00043 0.07889 - 0.09475 0.07889 0.17364 2021 Large PoTer22 TOU-8-S 0.01075 0.04474 0.00459 0.00001 0.00554 0.00549 0.00043 0.06930 - 0.07156 0.06930 0.14086 23 TOU-8-P 0.00946 0.03844 0.00412 0.00001 0.00499 0.00549 0.00043 0.06516 - 0.06294 0.06516 0.12810 24 TOU-8-T 0.00732 0.00718 0.00342 0.00001 0.00337 0.00549 0.00043 0.05876 - 0.02722 0.05876 0.08598 25 TOU-8-S-S 0.01128 0.04521 0.00451 0.00001 0.00548 0.00549 0.00043 0.07014 - 0.07242 0.07014 0.14256 26 TOU-8-S-P 0.00937 0.04502 0.00395 0.00001 0.00537 0.00549 0.00043 0.06654 - 0.06963 0.06654 0.13617 27 TOU-8-S-T 0.00668 0.00697 0.00299 0.00001 0.00343 0.00549 0.00043 0.05814 - 0.02600 0.05814 0.08414 28 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------29 Group Total 0.00915 0.03025 0.00400 0.00001 0.00466 0.00549 0.00043 0.06453 - 0.05400 0.06453 0.11852 3031 Agricultural & Pumping34 TOU-PA-2 0.00903 0.05208 0.00353 0.00001 0.00540 0.00549 0.00043 0.07135 - 0.07597 0.07135 0.14732 35 TOU-PA-3 0.00753 0.04205 0.00316 0.00001 0.00450 0.00549 0.00043 0.05696 - 0.06317 0.05696 0.12013 36 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------37 Group Total 0.00837 0.04767 0.00337 0.00001 0.00500 0.00549 0.00043 0.06503 - 0.07035 0.06503 0.13538 3839 Street & Area Lighting40 LS-1 0.00632 0.21713 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.24038 0.04422 0.28460 41 LS-2 0.00632 0.03756 0.00295 0.00001 0.00805 0.00549 0.00043 0.04410 - 0.06081 0.04410 0.10491 42 LS-3 0.00632 0.01392 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.03717 0.04422 0.08139 43 DTL 0.00632 0.19317 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.21642 0.04422 0.26064 44 OL-1 0.00632 0.18124 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.20449 0.04422 0.24871 45 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------46 Group Total 0.00632 0.12356 0.00295 0.00001 0.00805 0.00549 0.00043 0.04420 - 0.14681 0.04420 0.19101 474849 Total 5 Cust Gps. 0.01265 0.05525 0.00512 0.00001 0.00732 0.00497 0.00043 0.07621 - 0.08575 0.07621 0.16196

61

Table X-35 Average Generation Rates

Rate Schedule Current ProposedBy Generation Generation

Customer Group (¢ / kWh) (¢ / kWh)

DomesticNon-CARE 7.46 8.31D-CARE 7.46 8.31

---------- ----------Group Total 7.46 8.31

Lighting-SM Med PowerGS-1 7.58 8.44GS-2 7.07 7.87TC-1 5.72 6.36TOU-GS-3 6.65 7.41

---------- ----------Group Total 7.08 7.89

Large PowerTOU-8-SEC 6.22 6.93TOU-8-PRI 5.85 6.52TOU-8-SUB 5.27 5.88TOU-8-SEC-S 6.30 7.01TOU-8-PRI-S 5.98 6.65TOU-8-SUB-S 5.22 5.81

---------- ----------Group Total 5.79 6.45

Agricultural & PumpingTOU-AG 6.41 7.14TOU-PA-5 5.11 5.70

---------- ----------Group Total 5.84 6.50

Street & Area LightingLS-1 3.97 4.42LS-2 3.96 4.41LS-3 3.97 4.42DWL 3.97 4.42OL-1 3.97 4.42

---------- ----------Group Total 3.97 4.42

---------- ----------Grand Total 6.84 7.62

Appendix A

Estimated December 31, 2017 Balancing Account Balances

TABLE 1

Line Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Forecast Forecast AnnualNo. Description January February March April May June July August September October November December Summary

1. Beginning Balance (20,311) 3,818 30,385 29,747 103,402 184,015 228,375 239,006 227,531 190,140 292,365 332,313 (20,311) 2. Transfer From Energy Settlements Memo Account (ESMA) (48) (48) 3. Transfer from Litigation Costs Tracking Account (LCTA) 3,217 3,217 4. Adjusted Beginning Balance (17,142) 3,818 30,385 29,747 103,402 184,015 228,375 239,006 227,531 190,140 292,365 332,313 (17,142)

5. ERRA Revenue (252,674) (211,572) (243,276) (230,329) (253,958) (430,521) (525,838) (556,878) (473,787) (319,088) (247,449) (258,745) (4,004,115)

6. Expenses:7. Fuel 18,060 15,097 14,386 7,279 13,664 16,246 17,989 18,956 18,850 5,992 21,897 16,677 185,093

8. Purchased Power9. Cogen and Renewables 109,792 123,682 128,105 198,968 214,637 327,227 299,575 278,855 219,563 199,970 142,326 129,085 2,080,054

10. Other Purchased Power 145,786 99,349 100,127 97,689 106,160 131,245 218,691 247,364 197,778 215,113 122,806 136,994 1,819,10211. Subtotal Purchased Power 273,638 238,128 242,618 303,936 334,461 474,717 536,255 545,175 436,191 421,075 287,029 282,757 4,375,981

12. Monthly (Over)/Under Collection 20,964 26,556 (658) 73,607 80,503 44,196 10,417 (11,702) (37,596) 101,988 39,580 24,012 371,866

13. Total Interest: (4) 11 19 48 110 163 214 227 205 237 368 406 2,006

14. Total ERRA Ending Balance 3,818 30,385 29,747 103,402 184,015 228,375 239,006 227,531 190,140 292,365 332,313 356,731 356,731

15. Interest Rates 0.74% 0.80% 0.77% 0.87% 0.92% 0.95% 1.10% 1.17% 1.18% 1.18% 1.42% 1.42%

Estimated ERRA Ending Balance 356,731 FF&U 4,141

Total ERRA w/ FF&U 360,872

2017

Energy Resource Recovery Account($000)

ERRAA 1

TABLE 2


1. Beginning Balance (5,992) (31,829) (61,221) (96,574) (128,868) (154,889) (175,009) (142,868) (111,713) (98,911) (122,117) (139,141) (5,992) 2. Adjustment/Transfer 3. Associated Interest 4. Adjusted Beginning Balance (5,992) (31,829) (61,221) (96,574) (128,868) (154,889) (175,009) (142,868) (111,713) (98,911) (122,117) (139,141) (5,992)

5. Revenue:6. Billed (40,625) (49,959) (58,165) (48,346) (57,018) (63,621) (70,563) (81,063) (71,728) (63,339) (47,662) (59,236) (711,324)

7. Change in Unbilled8. Current Month Accrual (23,465) (20,711) (16,551) (20,037) (19,584) (20,276) (27,446) (24,682) (18,826) (16,618) (25,331) (25,013) (258,541) 9. Last Month Reversal 12,322 23,465 20,711 16,551 20,037 19,584 20,276 27,446 24,682 18,826 16,618 25,331 245,849 10. Change in Unbilled (11,143) 2,754 4,160 (3,486) 453 (692) (7,170) 2,764 5,856 2,208 (8,713) 318 (12,691)

11. Less: FF&U (Rate 0.988525) (594) (542) (620) (595) (649) (738) (892) (898) (756) (701) (647) (676) (8,308)

12. NSGBA Revenue (51,173) (46,663) (53,385) (51,237) (55,916) (63,575) (76,841) (77,401) (65,116) (60,429) (55,728) (58,242) (715,707)

13. Authorized Peaker Rev. Rqm't 4,610 4,168 4,437 4,140 4,207 4,627 5,107 5,392 5,386 4,939 4,342 4,520 55,876

14. Expenses 20,739 13,133 13,646 14,884 25,797 38,959 104,021 103,288 72,636 32,392 34,517 42,955 516,966

15. Monthly (Over)/Under Collection (25,825) (29,361) (35,302) (32,212) (25,912) (19,990) 32,287 31,279 12,906 (23,098) (16,870) (10,767) (142,866)

16. Total Interest: (12) (31) (51) (82) (109) (131) (146) (124) (104) (109) (154) (170) (1,220)

17. Ending Balance (31,829) (61,221) (96,574) (128,868) (154,889) (175,009) (142,868) (111,713) (98,911) (122,117) (139,141) (150,079) (150,079)

18. Interest Rates 0.74% 0.80% 0.77% 0.87% 0.92% 0.95% 1.10% 1.17% 1.18% 1.18% 1.42% 1.42%

Estimated NSGBA Ending Balance (150,079) FF&U (1,742)

Total NSGBA w/ FF&U (151,822)

2017

New System Generation Balancing Account(Thousands of Dollars)

NSGBA A 2

TABLE 3


1. Beginning Balance (48) - - (2,019) (2,020) (2,022) (2,024) (2,025) (2,027) (2,029) (10,105) (10,117) (48) 2. Transfer to ERRA 48 - - - - - - - - - - - 48 3. Associated interest 0 - - - - - - - - - - - 0 4. Adjusted Beginning Balance - - - (2,019) (2,020) (2,022) (2,024) (2,025) (2,027) (2,029) (10,105) (10,117) -

5. Monthly (Over)/Under Collection

6. Total Refund Received (Cr) 7. Litigation Reimbursement Received - - (2,243) - - - - - - (8,190) - - (10,432) 8. Other Market Participant Amounts Paid - - - - - - - - - - - - - 9. Subtotal - - (2,243) - - - - - - (8,190) - - (10,432)

10. Less: Shareholder Incentive Amount - - 224 - - - - - - 120 - - 344

11. Total Amount to be Refunded to Customers - - (2,018) - - - - - - (8,070) - - (10,088)

12. Interest: - - (1) (1) (2) (2) (2) (2) (2) (6) (12) (12) (41)

13. Ending Balance - - (2,019) (2,020) (2,022) (2,024) (2,025) (2,027) (2,029) (10,105) (10,117) (10,129) (10,129)

14. Interest Rates 0.74% 0.80% 0.77% 0.87% 0.92% 0.95% 1.10% 1.17% 1.18% 1.18% 1.42% 1.42%

Estimated ESMA Ending Balance (10,129) FF&U (118)

Total ESMA w/ FF&U (10,247)

Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Forecast Forecast Annual15. LITIGATION COST TRACKING ACCOUNT January February March April May June July August September October November December Summary

16. Beginning Balance 3,217 2 147 407 779 1,095 1,399 1,609 1,775 2,047 2,276 2,533 3,217 17. Transfer to ERRA (3,217) - - - - - - - - - - - (3,217) 18. Adjusted Beginning Balance - 2 147 407 779 1,095 1,399 1,609 1,775 2,047 2,276 2,533 -

19. Monthly (Over)/Under Collection

20. Litigation Reimbursement Received (Non-provision) - - - - - - - - - - - - -

21. Incurred Litigation Expense:22. Law 2 1 432 216 366 297 6 636 - 326 254 614 3,151 23. Mirant's Audit Costs - - - - - - - - - - - - - 24. Cal Muni Costs - 1 6 5 18 15 11 7 1 10 - - 74 25. ES&M - - - - - - - - - - - - - 26. Accrual - 143 (177) 150 (69) (9) 190 (479) 269 (109) - - (91) 27. Subtotal 2 145 261 371 315 304 208 165 270 227 254 614 3,135

28. Total Amount to be Recovered from Customers 2 145 261 371 315 304 208 165 270 227 254 614 3,135

29. Interest: 0 0 0 0 1 1 1 2 2 2 3 3 16

30. Ending Balance 2 147 407 779 1,095 1,399 1,609 1,775 2,047 2,276 2,533 3,151 3,151

31. Interest Rates 0.74% 0.80% 0.77% 0.87% 0.92% 0.95% 1.10% 1.17% 1.18% 1.18% 1.42% 1.42%

Estimated LCTA Ending Balance 3,151 FF&U 37

Total LCTA w/ FF&U 3,187

2017

Energy Settlement Memorandum Account/Litigation Cost Tracking Account (Thousands of Dollars)

ESMA & LCTAA 3

Appendix B

Indifference Rate Calculation

Line�No. Description Source�of�Data Value1. On�Peak�SP�15�Price�($/MWh) Platt's2. Off�Peak�SP�15�Price�($/MWh) Platt's3. On�Peak�Load�Weight�(%) 2016�Recorded�Load��On�Peak�Hours 62%4. Off�Peak�Load�Weight�(%) 2016�Recorded�Load��Off�Peak�Hours 38%5. Load�Weighted�Average�Price�($/MWh) Line�1�x�Line�3�+�Line�2�x�Line�4 $32.37

6. IOU�Green�Benchmark�($/MWh) Line�18 $61.477. IOU�RPS�Premium�($/MWh) Line�6��Line�5 $29.108. DOE�Renewable�Adder�($/MWh) ED�Disposition�of�Advice�3667�E $16.649. Weighted�Average�Renewable�Premium�($/MWh) 68%�x�Line�7�+�32%�x�Line�8 $25.11

10. Weighted�Average�Renewable�Benchmark�($/MWh) Line�9�+�Line�5 $57.48

11. Capacity�Benchmark�($/kW�Year) 2015�CEC�Report��Advice�3667�E $58.26

12. Line�Loss�Adjustment�Factor Resolution�E�4475 1.053

13. Franchise�Fees�and�Uncollectibles�Factor D.15�11�021 0.98853

14. Total�IOU�Renewable�Resource�Cost�($000) ED�Info�Received�10/24/17 $417,11315. Total�IOU�Renewable�Resource�Capacity�(MW) ED�Info�Received�10/24/17 49316. Total�IOU�Renewable�Resource�Capacity�Value�($000) Line�15�x�$58.26 $28,72217. Revised�IOU�Renewable�Resource�Cost Line�14��Line�16 $388,391

18. Total�IOU�Renewable�Energy�(MWh) ED�Info�Received�10/24/17 6,318,25619. IOU�Green�Benchmark Line�17�x�1000�/�Line�18 $61.47

IOU�Green�Benchmark��2018�ERRA�Forecast�Data

Indifference�Calculation�Inputs�and�Sources2018�ERRA�Forecast��November�Filing

B-1

CONFIDENTIAL�INFORMATION�DISCLOSED�PURSUANT�TO�PUBLIC�UTILITIES�CODE�SECTION�583�AND�GENERALORDER�66�C.��PUBLIC�DISCLOSURE�IS�RESTRICTED

Pre�2002CTC�Eligible SONGS�Settlement Legacy�UOG 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total

1. CRS�Eligible�Portfolio�Costs�($000)��Excludes�CAM�eligible2. UOG�Capital�and�O&M�(2015�GRC�Phase�1)��No�FF&U 574,016�� 63,112�� 637,128��3. SONGS�Settlement�Revenue�Requirement��No�FF&U 189,852�� 189,852��4. UOG�Fuel5. QF�Eligible�CHP6. Renewable�QF�and�RPS�Contracts7. Conventional�Contracts�(Bilateral/RFO/IU)8. Common9. Total�(Incremental) 317,440�� 189,852�� 619,220�� 948,133�� 283,379�� 328,166�� 66,258�� 122,959�� 219,134�� 251,019�� 72,081�� 1,142�� 3,418,784��

10. Total�Vintaged�Costs 317,440�� 507,292�� 1,126,512�� 2,074,645�� 2,358,024�� 2,686,190�� 2,752,448�� 2,875,407�� 3,094,542�� 3,345,561�� 3,417,642�� 3,418,784�� 3,418,784��

11. CRS�Eligible�Supply�(GWhs)��Excludes�CAM�eligible12. UOG13. QF�Eligible�CHP14. Renewable�QF15. Conventional�Contracts�(Bilateral/RFO/IU)16. Total�(Incremental)

17. TOTAL�Vintaged�GWh�@�Generator

18. Vintaged�GWhs�@�Meter 4,097�� 4,097�� 12,799�� 19,694�� 21,880�� 24,562�� 25,179�� 25,732�� 28,229�� 32,066�� 32,312�� 32,325�� 32,325��

19. CRS�Eligible�Net�Qualifying�Capacity��Excludes�CAM�eligible20. UOG �� 1,645�� 13�� 1,658��21. QF�Eligible�CHP 124�� 0�� 124��22. Renewable�QF 567�� 518�� 236�� 256�� 13�� 36�� 258�� 248�� 2,132��23. Conventional�Contracts�(Bilateral/RFO/IU) �� 1,591�� 1,269�� 660�� 1,616�� 5,135��24. Total�(Incremental) 691�� 1,645�� 531�� 236�� 256�� 13�� 1,626�� 1,527�� 907�� 1,616�� 9,049��

25. TOTAL�Vintaged�Net�Qualifying�Capacity 691�� 691�� 2,336�� 2,867�� 3,103�� 3,358�� 3,372�� 4,998�� 6,526�� 7,433�� 9,049�� 9,049�� 9,049��

CRS�Ineligible�Portfolio Costs Energy26. Green�Rate27. Mountainview28. DR,�LCR,�PRP29. <�1�Year�Contracts�(Generic�RA,�ISO,�ST�Purchases)30. CAM�Eligible�Costs31. Common�Costs

IOU�Portfolio�by�Resource�Type2018�ERRA�Forecast��November�Filing

Vintage�Portfolios

B-2

Pre�2002 SONGSCTC�Eligible Settlement 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

1. Cost�of�Portfolio2. CRS�Eligible�Portfolio�Costs�($000) 317,440�� 189,852�� 619,220�� 948,133�� 283,379�� 328,166�� 66,258�� 122,959�� 219,134�� 251,019�� 72,081�� 1,142�� 3. CRS�Eligible�Cumulative�Portfolio�Costs 317,440�� 507,292�� 1,126,512�� 2,074,645�� 2,358,024�� 2,686,190�� 2,752,448�� 2,875,407�� 3,094,542�� 3,345,561�� 3,417,642�� 3,418,784�� 3,418,784��

4. CRS�Eligible�Supply5. CRS�Eligible�Supply�at�Meter�(GWh) 4,097�� 8,701�� 6,895�� 2,187�� 2,681�� 617�� 553�� 2,497�� 3,837�� 246�� 13�� 6. CRS�Eligible�Cumulative�GWh�at�Meter 4,097�� 4,097�� 12,799�� 19,694�� 21,880�� 24,562�� 25,179�� 25,732�� 28,229�� 32,066�� 32,312�� 32,325�� 32,325��

7. CRS�Eligible�Net�Qualifying�Capacity8. CRS�Eligible�Net�Qualifying�Capacity�(MW) 691�� 1,645�� 531�� 236�� 256�� 13�� 1,626�� 1,527�� 907�� 1,616�� 9. CRS�Eligible�Cumulative�Net�Qualifying�Capacity� 691�� 691�� 2,336�� 2,867�� 3,103�� 3,358�� 3,372�� 4,998�� 6,526�� 7,433�� 9,049�� 9,049�� 9,049��

IOU�Total�Portfolio�Summary2018�ERRA�Forecast��November�Filing

Legacy�UOGVintage

B-3

Line No. Description Equation Unit CTC-Eligible SONGS Settlement Legacy UOG 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Cost of Portfolio

1. CRS Eligible Portfolio Costs Portfolio Summary Line 2 $000 317,440 507,292 1,126,512 2,074,645 2,358,024 2,686,190 2,752,448 2,875,407 3,094,542 3,345,561 3,417,642 3,418,784 3,418,784

2. CRS Eligible Supply at Customer Meter Portfolio Summary Line 6 GWh 4,097 4,097 12,799 19,694 21,880 24,562 25,179 25,732 28,229 32,066 32,312 32,325 32,3253. CRS Eligible Renewable Supply at Customer Meter GWh 3,359 3,359 3,359 10,254 12,441 15,122 15,739 16,282 18,779 22,616 22,637 22,650 22,6504. CRS Eligible Net Qualifying Capacity Portfolio Summary Line 9 MW 691 691 2,336 2,867 3,103 3,358 3,372 4,998 6,526 7,433 9,049 9,049 9,049

5. Portfolio Unit Cost Line 1 / Line 2 $/MWh $77.48 123.81$ $88.02 $105.35 $107.77 $109.37 $109.32 $111.75 $109.62 $104.33 $105.77 $105.76 $105.76

6. Market Value of Portfolio

7. Market Value of Brown Portfolio8. Non-Renewable Energy Line 2 - Line 3 GWh 738 738 9,440 9,440 9,440 9,440 9,440 9,450 9,450 9,450 9,675 9,675 9,6759. Platt's Weighted Price (Brown Benchmark) Input Line 5 $/MWh 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$ 32.37$

10. Market Value of Brown Portfolio Line 8 x Line 9 $000 23,897$ 23,897$ 305,580$ 305,581$ 305,581$ 305,581$ 305,581$ 305,913$ 305,913$ 305,913$ 313,205$ 313,205$ 313,205$

11. Market Value of Green Portfolio12. Renewable Energy Line 3 GWh 3,359 3,359 3,359 10,254 12,441 15,122 15,739 16,282 18,779 22,616 22,637 22,650 22,65013. Weighted Average Green Benchmark Input Line 10 $/MWh 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$ 57.48$14. Market Value of Green Portfolio Line 12 x Line 13 $000 193,096$ 193,096$ 193,096$ 589,454$ 715,156$ 869,282$ 904,745$ 935,954$ 1,079,519$ 1,300,085$ 1,301,250$ 1,301,998$ 1,301,998$

15. Capacity Adder16. Average Monthly NQC Line 4 MW 691 691 2,336 2,867 3,103 3,358 3,372 4,998 6,526 7,433 9,049 9,049 9,04917. Capacity Value per Resolution E-4475 Input Line 11 $/kW-Year 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$ 58.26$18. Market Value of Capacity Line 16 x Line 17 $000 40,248$ 40,248$ 136,067$ 167,011$ 180,778$ 195,664$ 196,450$ 291,208$ 380,190$ 433,050$ 527,191$ 527,191$ 527,191$

19. Portfolio Market Value Line 10 + Line 14 + Line 18 $000 257,241$ 257,241$ 634,743$ 1,062,045$ 1,201,515$ 1,370,527$ 1,406,775$ 1,533,076$ 1,765,623$ 2,039,049$ 2,141,647$ 2,142,394$ 2,142,394$20. Line Loss Adjusted Portfolio Market value Line 19 x Input Line 12 $000 270,875$ 270,875$ 668,385$ 1,118,334$ 1,265,195$ 1,443,165$ 1,481,334$ 1,614,329$ 1,859,201$ 2,147,118$ 2,255,154$ 2,255,941$ 2,255,941$

21. Indifference Amount22. Portfolio Total Cost Line 1 $000 317,440$ 507,292$ 1,126,512$ 2,074,645$ 2,358,024$ 2,686,190$ 2,752,448$ 2,875,407$ 3,094,542$ 3,345,561$ 3,417,642$ 3,418,784$ 3,418,784$23. Portfolio Market Value Line 22 $000 270,875$ 270,875$ 668,385$ 1,118,334$ 1,265,195$ 1,443,165$ 1,481,334$ 1,614,329$ 1,859,201$ 2,147,118$ 2,255,154$ 2,255,941$ 2,255,941$24. Total Indifference Amount (Unadjusted) Line 22 - Line 23 $000 46,565$ 236,417$ 458,128$ 956,311$ 1,092,829$ 1,243,025$ 1,271,114$ 1,261,078$ 1,235,341$ 1,198,442$ 1,162,488$ 1,162,843$ 1,162,843$

25. DWR Revenue Requirement $000 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$26. One-Time Adjustments (if applicable) $000 (251,429)$ -$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$ (1,212)$27. Carry Over Negative Indifference (if applicable) $000 -$ -$ -$ -$ -$ -$ -$ -$ -$28. Adjusted Indifference Amounts Sum (Lines 24:27) $000 46,565$ (15,012)$ 458,128$ 955,099$ 1,091,617$ 1,241,813$ 1,269,902$ 1,259,866$ 1,234,129$ 1,197,230$ 1,161,276$ 1,161,631$ 1,161,631$29. Adjusted Indifference Amounts with FF&U Line 28/Input Line 13 47,106$ (15,186)$ 463,446$ 966,186$ 1,104,289$ 1,256,228$ 1,284,643$ 1,274,491$ 1,248,455$ 1,211,128$ 1,174,756$ 1,175,115$ 1,175,115$

Indifference�Amount�Calculation2018�ERRA�Forecast��November�Filing

B-4

Rate GroupSystem Retail Sales (GWh)

Top 100 HoursAllocation

CTCIndifference 2001 2004 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

47,106$ (15,186)$ (15,186)$ 966,186$ 1,104,289$ 1,256,228$ 1,284,643$ 1,274,491$ 1,248,455$ 1,211,128$ 1,174,756$ 1,175,115$ 1,175,115$ Domestic 28,329 45.34% 21,356$ (6,885)$ (6,885)$ 438,024$ 500,633$ 569,516$ 582,398$ 577,795$ 565,992$ 549,069$ 532,580$ 532,743$ 532,743$ GS-1 6,043 6.20% 2,923$ (942)$ (942)$ 59,945$ 68,513$ 77,940$ 79,703$ 79,073$ 77,458$ 75,142$ 72,885$ 72,908$ 72,908$ TC-1 58 0.04% 20$ (6)$ (6)$ 410$ 468$ 533$ 545$ 541$ 530$ 514$ 498$ 498$ 498$ GS-2 13,472 17.98% 8,467$ (2,730)$ (2,730)$ 173,674$ 198,498$ 225,809$ 230,917$ 229,092$ 224,412$ 217,702$ 211,164$ 211,229$ 211,229$ TOU-GS-3 8,115 8.97% 4,224$ (1,362)$ (1,362)$ 86,649$ 99,034$ 112,660$ 115,208$ 114,298$ 111,963$ 108,615$ 105,353$ 105,386$ 105,386$ TOU-8-Sec 8,272 7.98% 3,760$ (1,212)$ (1,212)$ 77,114$ 88,137$ 100,264$ 102,531$ 101,721$ 99,643$ 96,664$ 93,761$ 93,790$ 93,790$ TOU-8-Pri 5,655 5.06% 2,382$ (768)$ (768)$ 48,863$ 55,847$ 63,531$ 64,968$ 64,455$ 63,138$ 61,250$ 59,411$ 59,429$ 59,429$ TOU-8-Sub 6,053 5.16% 2,430$ (784)$ (784)$ 49,850$ 56,975$ 64,814$ 66,280$ 65,756$ 64,413$ 62,487$ 60,611$ 60,629$ 60,629$ TOU-PA-2 1,870 1.86% 875$ (282)$ (282)$ 17,947$ 20,512$ 23,334$ 23,862$ 23,673$ 23,190$ 22,497$ 21,821$ 21,828$ 21,828$ TOU-PA-3 1,469 0.95% 447$ (144)$ (144)$ 9,160$ 10,469$ 11,910$ 12,179$ 12,083$ 11,836$ 11,482$ 11,138$ 11,141$ 11,141$ St. Lighting 700 0.00% 0$ (0)$ (0)$ 10$ 12$ 13$ 14$ 13$ 13$ 13$ 12$ 12$ 12$ Standby - Sec 228 0.05% 21$ (7)$ (7)$ 435$ 497$ 565$ 578$ 574$ 562$ 545$ 529$ 529$ 529$ Standby - Pri 784 0.16% 76$ (24)$ (24)$ 1,551$ 1,773$ 2,017$ 2,063$ 2,046$ 2,005$ 1,945$ 1,886$ 1,887$ 1,887$ Standby - Sub 2,179 0.26% 125$ (40)$ (40)$ 2,555$ 2,920$ 3,322$ 3,397$ 3,370$ 3,301$ 3,203$ 3,107$ 3,107$ 3,107$

Rate GroupCTC Rate 2001 2004 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Domestic 28,329 45.34% 0.00075$ (0.00024)$ (0.00024)$ 0.01546$ 0.01767$ 0.02010$ 0.02056$ 0.02040$ 0.01998$ 0.01938$ 0.01880$ 0.01881$ 0.01881$ GS-1 6,043 6.20% 0.00048$ (0.00016)$ (0.00016)$ 0.00992$ 0.01134$ 0.01290$ 0.01319$ 0.01309$ 0.01282$ 0.01244$ 0.01206$ 0.01207$ 0.01207$ TC-1 58 0.04% 0.00034$ (0.00011)$ (0.00011)$ 0.00702$ 0.00803$ 0.00913$ 0.00934$ 0.00926$ 0.00907$ 0.00880$ 0.00854$ 0.00854$ 0.00854$ GS-2 13,472 17.98% 0.00063$ (0.00020)$ (0.00020)$ 0.01289$ 0.01473$ 0.01676$ 0.01714$ 0.01700$ 0.01666$ 0.01616$ 0.01567$ 0.01568$ 0.01568$ TOU-GS-3 8,115 8.97% 0.00052$ (0.00017)$ (0.00017)$ 0.01068$ 0.01220$ 0.01388$ 0.01420$ 0.01408$ 0.01380$ 0.01338$ 0.01298$ 0.01299$ 0.01299$ TOU-8-Sec 8,272 7.98% 0.00045$ (0.00015)$ (0.00015)$ 0.00932$ 0.01065$ 0.01212$ 0.01239$ 0.01230$ 0.01205$ 0.01169$ 0.01133$ 0.01134$ 0.01134$ TOU-8-Pri 5,655 5.06% 0.00042$ (0.00014)$ (0.00014)$ 0.00864$ 0.00988$ 0.01123$ 0.01149$ 0.01140$ 0.01117$ 0.01083$ 0.01051$ 0.01051$ 0.01051$ TOU-8-Sub 6,053 5.16% 0.00040$ (0.00013)$ (0.00013)$ 0.00824$ 0.00941$ 0.01071$ 0.01095$ 0.01086$ 0.01064$ 0.01032$ 0.01001$ 0.01002$ 0.01002$ TOU-PA-2 1,870 1.86% 0.00047$ (0.00015)$ (0.00015)$ 0.00960$ 0.01097$ 0.01248$ 0.01276$ 0.01266$ 0.01240$ 0.01203$ 0.01167$ 0.01167$ 0.01167$ TOU-PA-3 1,469 0.95% 0.00030$ (0.00010)$ (0.00010)$ 0.00624$ 0.00713$ 0.00811$ 0.00829$ 0.00823$ 0.00806$ 0.00782$ 0.00758$ 0.00758$ 0.00758$ St. Lighting 700 0.00% 0.00000$ (0.00000)$ (0.00000)$ 0.00001$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ Standby - Sec 228 0.05% 0.00009$ (0.00003)$ (0.00003)$ 0.00191$ 0.00218$ 0.00248$ 0.00254$ 0.00252$ 0.00247$ 0.00239$ 0.00232$ 0.00232$ 0.00232$ Standby - Pri 784 0.16% 0.00010$ (0.00003)$ (0.00003)$ 0.00198$ 0.00226$ 0.00257$ 0.00263$ 0.00261$ 0.00256$ 0.00248$ 0.00241$ 0.00241$ 0.00241$ Standby - Sub 2,179 0.26% 0.00006$ (0.00002)$ (0.00002)$ 0.00117$ 0.00134$ 0.00152$ 0.00156$ 0.00155$ 0.00152$ 0.00147$ 0.00143$ 0.00143$ 0.00143$

CTC

Rate Group CTC PCIA 2001 Vintage PCIA 2004 Vintage PCIA 2009 Vintage PCIA 2010 Vintage PCIA 2011 Vintage PCIA 2012 Vintage PCIA 2013 Vintage PCIA 2014 Vintage PCIA 2015 Vintage PCIA 2016 Vintage PCIA 2017 Vintage PCIA 2018 Vintage

Domestic 28,329 45.34% 0.00075$ (0.00100)$ (0.00100)$ 0.01471$ 0.01692$ 0.01935$ 0.01980$ 0.01964$ 0.01923$ 0.01863$ 0.01805$ 0.01805$ 0.01805$ GS-1 6,043 6.20% 0.00048$ (0.00064)$ (0.00064)$ 0.00944$ 0.01085$ 0.01241$ 0.01271$ 0.01260$ 0.01233$ 0.01195$ 0.01158$ 0.01158$ 0.01158$ TC-1 58 0.04% 0.00034$ (0.00045)$ (0.00045)$ 0.00668$ 0.00768$ 0.00879$ 0.00899$ 0.00892$ 0.00873$ 0.00846$ 0.00820$ 0.00820$ 0.00820$ GS-2 13,472 17.98% 0.00063$ (0.00083)$ (0.00083)$ 0.01226$ 0.01411$ 0.01613$ 0.01651$ 0.01638$ 0.01603$ 0.01553$ 0.01505$ 0.01505$ 0.01505$ TOU-GS-3 8,115 8.97% 0.00052$ (0.00069)$ (0.00069)$ 0.01016$ 0.01168$ 0.01336$ 0.01368$ 0.01356$ 0.01328$ 0.01286$ 0.01246$ 0.01247$ 0.01247$ TOU-8-Sec 8,272 7.98% 0.00045$ (0.00060)$ (0.00060)$ 0.00887$ 0.01020$ 0.01167$ 0.01194$ 0.01184$ 0.01159$ 0.01123$ 0.01088$ 0.01088$ 0.01088$ TOU-8-Pri 5,655 5.06% 0.00042$ (0.00056)$ (0.00056)$ 0.00822$ 0.00945$ 0.01081$ 0.01107$ 0.01098$ 0.01074$ 0.01041$ 0.01008$ 0.01009$ 0.01009$ TOU-8-Sub 6,053 5.16% 0.00040$ (0.00053)$ (0.00053)$ 0.00783$ 0.00901$ 0.01031$ 0.01055$ 0.01046$ 0.01024$ 0.00992$ 0.00961$ 0.00961$ 0.00961$ TOU-PA-2 1,870 1.86% 0.00047$ (0.00062)$ (0.00062)$ 0.00913$ 0.01050$ 0.01201$ 0.01229$ 0.01219$ 0.01193$ 0.01156$ 0.01120$ 0.01121$ 0.01121$ TOU-PA-3 1,469 0.95% 0.00030$ (0.00040)$ (0.00040)$ 0.00593$ 0.00682$ 0.00780$ 0.00799$ 0.00792$ 0.00775$ 0.00751$ 0.00728$ 0.00728$ 0.00728$ St. Lighting 700 0.00% -$ -$ -$ 0.00001$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ 0.00002$ Standby - Sec 228 0.05% 0.00009$ (0.00012)$ (0.00012)$ 0.00182$ 0.00209$ 0.00239$ 0.00245$ 0.00243$ 0.00237$ 0.00230$ 0.00223$ 0.00223$ 0.00223$ Standby - Pri 784 0.16% 0.00010$ (0.00013)$ (0.00013)$ 0.00188$ 0.00217$ 0.00248$ 0.00254$ 0.00251$ 0.00246$ 0.00238$ 0.00231$ 0.00231$ 0.00231$ Standby - Sub 2,179 0.26% 0.00006$ (0.00008)$ (0.00008)$ 0.00112$ 0.00128$ 0.00147$ 0.00150$ 0.00149$ 0.00146$ 0.00141$ 0.00137$ 0.00137$ 0.00137$ System Average 0.00062$ (0.00082)$ (0.00082)$ 0.01213$ 0.01396$ 0.01596$ 0.01633$ 0.01620$ 0.01586$ 0.01536$ 0.01489$ 0.01489$ 0.01489$

Indifference�Rate�Calculation�(Final)2018�ERRA�Forecast��November�Filing

Indifference Amount Allocation to Rate Groups -- Final Indifference Amount by Vintage x Column C

Total Indifference Rate (i.e. CTC + PCIA) -- Indifference Amount by Rate Group / Column B

PCIA -- Total Indifference Rate - CTC Rate (Column D)

B 5

Rate GroupDWRBC (All

Vintages)CTC (For All

Vintages)PCIA 2001

VintagePCIA 2004

VintagePCIA 2009

VintagePCIA 2010

VintagePCIA 2011

VintagePCIA 2012

VintagePCIA 2013

VintagePCIA 2014

VintagePCIA 2015

VintagePCIA 2016

VintagePCIA 2017

VintagePCIA 2018

Vintage

Proposed Class Average Bundled

Generation

Domestic 0.00549 0.00075 (0.00100) (0.00100) 0.01471 0.01692 0.01935 0.01980 0.01964 0.01923 0.01863 0.01805 0.01805 0.01805 0.08311

GS-1 0.00549 0.00048 (0.00064) (0.00064) 0.00944 0.01085 0.01241 0.01271 0.01260 0.01233 0.01195 0.01158 0.01158 0.01158 0.08440

TC-1 0.00549 0.00034 (0.00045) (0.00045) 0.00668 0.00768 0.00879 0.00899 0.00892 0.00873 0.00846 0.00820 0.00820 0.00820 0.06363

GS-2 0.00549 0.00063 (0.00083) (0.00083) 0.01226 0.01411 0.01613 0.01651 0.01638 0.01603 0.01553 0.01505 0.01505 0.01505 0.07866

TOU-GS-3 0.00549 0.00052 (0.00069) (0.00069) 0.01016 0.01168 0.01336 0.01368 0.01356 0.01328 0.01286 0.01246 0.01247 0.01247 0.07411

TOU-8-Sec 0.00549 0.00045 (0.00060) (0.00060) 0.00887 0.01020 0.01167 0.01194 0.01184 0.01159 0.01123 0.01088 0.01088 0.01088 0.06930

TOU-8-Pri 0.00549 0.00042 (0.00056) (0.00056) 0.00822 0.00945 0.01081 0.01107 0.01098 0.01074 0.01041 0.01008 0.01009 0.01009 0.06516

TOU-8-Sub 0.00549 0.00040 (0.00053) (0.00053) 0.00783 0.00901 0.01031 0.01055 0.01046 0.01024 0.00992 0.00961 0.00961 0.00961 0.05876

Small AG 0.00549 0.00047 (0.00062) (0.00062) 0.00913 0.01050 0.01201 0.01229 0.01219 0.01193 0.01156 0.01120 0.01121 0.01121 0.07135

Large AG 0.00549 0.00030 (0.00040) (0.00040) 0.00593 0.00682 0.00780 0.00799 0.00792 0.00775 0.00751 0.00728 0.00728 0.00728 0.05696

St. Lighting 0.00549 - - - 0.00001 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.04420

Standby - Sec 0.00549 0.00009 (0.00012) (0.00012) 0.00182 0.00209 0.00239 0.00245 0.00243 0.00237 0.00230 0.00223 0.00223 0.00223 0.07014

Standby - Pri 0.00549 0.00010 (0.00013) (0.00013) 0.00188 0.00217 0.00248 0.00254 0.00251 0.00246 0.00238 0.00231 0.00231 0.00231 0.06654

Standby - Sub 0.00549 0.00006 (0.00008) (0.00008) 0.00112 0.00128 0.00147 0.00150 0.00149 0.00146 0.00141 0.00137 0.00137 0.00137 0.05814

DWRBC Per 10/30/2017 PD

ERRA�CRS�Rates�(Final)2018�ERRA�Forecast��November�filing

B 6

Rate Schedule Transmission Distribution NSGC NDC PPPC DWRBC PURCF UG DWREC Total Total TotalLine By Delivery GenerationNo. Customer Group ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)1 Domestic2 D 0.01523 0.08242 0.00590 0.00001 0.00980 0.00549 0.00043 0.08311 - 0.11928 0.08311 0.20239 3 D-CARE 0.01523 0.00754 0.00590 0.00001 0.00994 - 0.00043 0.08308 - 0.03905 0.08308 0.12213 4 D-APS 0.01523 0.05033 0.00590 0.00001 0.00980 0.00549 0.00043 0.08254 - 0.08719 0.08254 0.16973

DE 0.01523 0.02669 0.00590 0.00001 0.00980 0.00549 0.00043 0.08283 - 0.06355 0.08283 0.14638 6 DM 0.01523 0.09986 0.00590 0.00001 0.00980 0.00549 0.00043 0.08325 - 0.13672 0.08325 0.21997 7 DMS-1 0.01523 0.08939 0.00590 0.00001 0.00980 0.00549 0.00043 0.08325 - 0.12625 0.08325 0.20950 8 DMS-2 0.01523 0.06903 0.00590 0.00001 0.00980 0.00549 0.00043 0.08324 - 0.10589 0.08324 0.18913 9 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------10 Group Total 0.01523 0.06193 0.00590 0.00001 0.00983 0.00412 0.00043 0.08308 - 0.09746 0.08308 0.18053 1112 Lighting-SM Med Power13 GS-1 0.01332 0.06366 0.00563 0.00001 0.00716 0.00549 0.00043 0.08440 - 0.09570 0.08440 0.18010 14 GS-2 0.01301 0.06871 0.00528 0.00001 0.00662 0.00549 0.00043 0.07866 - 0.09954 0.07866 0.17821 16 TC-1 0.00772 0.09933 0.00375 0.00001 0.00797 0.00549 0.00043 0.06363 - 0.12470 0.06363 0.18833 17 TOU�GS 0.01239 0.05507 0.00502 0.00001 0.00601 0.00549 0.00043 0.07411 - 0.08441 0.07411 0.15853 18 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------19 Group Total 0.01291 0.06401 0.00530 0.00001 0.00660 0.00549 0.00043 0.07889 - 0.09475 0.07889 0.17364 2021 Large Power22 TOU-8-S 0.01075 0.04474 0.00459 0.00001 0.00554 0.00549 0.00043 0.06930 - 0.07156 0.06930 0.14086 23 TOU-8-P 0.00946 0.03844 0.00412 0.00001 0.00499 0.00549 0.00043 0.06516 - 0.06294 0.06516 0.12810 24 TOU-8-T 0.00732 0.00718 0.00342 0.00001 0.00337 0.00549 0.00043 0.05876 - 0.02722 0.05876 0.08598 25 TOU-8-S-S 0.01128 0.04521 0.00451 0.00001 0.00548 0.00549 0.00043 0.07014 - 0.07242 0.07014 0.14256 26 TOU-8-S-P 0.00937 0.04502 0.00395 0.00001 0.00537 0.00549 0.00043 0.06654 - 0.06963 0.06654 0.13617 27 TOU-8-S-T 0.00668 0.00697 0.00299 0.00001 0.00343 0.00549 0.00043 0.05814 - 0.02600 0.05814 0.08414 28 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------29 Group Total 0.00915 0.03025 0.00400 0.00001 0.00466 0.00549 0.00043 0.06453 - 0.05400 0.06453 0.11852 3031 Agricultural & Pumping34 TOU-PA-2 0.00903 0.05208 0.00353 0.00001 0.00540 0.00549 0.00043 0.07135 - 0.07597 0.07135 0.14732 35 TOU-PA-3 0.00753 0.04205 0.00316 0.00001 0.00450 0.00549 0.00043 0.05696 - 0.06317 0.05696 0.12013 36 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------37 Group Total 0.00837 0.04767 0.00337 0.00001 0.00500 0.00549 0.00043 0.06503 - 0.07035 0.06503 0.13538 3839 Street & Area Lighting40 LS-1 0.00632 0.21713 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.24038 0.04422 0.28460 41 LS-2 0.00632 0.03756 0.00295 0.00001 0.00805 0.00549 0.00043 0.04410 - 0.06081 0.04410 0.10491 42 LS-3 0.00632 0.01392 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.03717 0.04422 0.08139 43 DTL 0.00632 0.19317 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.21642 0.04422 0.26064 44 OL-1 0.00632 0.18124 0.00295 0.00001 0.00805 0.00549 0.00043 0.04422 - 0.20449 0.04422 0.24871 45 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------46 Group Total 0.00632 0.12356 0.00295 0.00001 0.00805 0.00549 0.00043 0.04420 - 0.14681 0.04420 0.19101 474849 Total 5 Cust Gp 0.01265 0.05525 0.00512 0.00001 0.00732 0.00497 0.00043 0.07621 - 0.08575 0.07621 0.16196

Unbundled�Rate�Components2018�ERRA�Forecast��November�Filing

B-7

Appendix C

Calculation of Climate Credit Prior to Inclusion of SB92 Methodology

Template D-1: Annual Allowance Revenue Receipts and Customer Returns w/o SB92 Set Aside in 2018

Line Description Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded 1/ Forecast Recorded

1 Proxy GHG Price ($/MT) N/A N/A 12.48$ 12.04$ 12.65$ 12.79$ 13.14$ 12.84$ 13.50$ N/A 15.52$ N/A

2 Allocated Allowances (MT) 32,603,468 32,603,468 31,594,859 31,594,859 31,399,111 31,399,111 29,550,282 29,550,281 26,868,834 26,868,834 25,889,683 25,889,683

3 Revenues ($)4 Prior Balance N/A N/A (389,586,000)$ (384,888,000)$ (160,837,218)$ (167,118,600)$ (346,523)$ (22,378,563)$ 30,396,659$ 29,397,778$ (15,816,954)$ -$ 5 Allowance Revenue (389,232,000)$ (384,638,000)$ (394,304,000)$ (368,730,000)$ (397,199,000)$ (390,808,663)$ (388,290,705)$ (376,175,077)$ (362,460,584)$ (385,767,014)$ (401,808,000)$ -$ 6 Interest (354,000)$ (250,000)$ 177,000$ (299,600)$ -$ -$ -$ -$ -$ -$ -$ -$ 7 Franchise Fees and Uncollectibles -$ -$ (6,620,000)$ (7,641,000)$ (4,463,271)$ (5,606,232)$ (4,363,170)$ (4,227,028)$ (4,207,516)$ (4,478,062)$ (4,664,269)$ -$ 8 Subtotal Revenues (389,586,000)$ (384,888,000)$ (790,333,000)$ (761,558,600)$ (562,499,489)$ (563,533,494)$ (393,000,398)$ (402,780,668)$ (336,271,441)$ (360,847,299)$ (422,289,223)$ -$

9 Expenses ($)10 Outreach and Administrative Expenses (from Template D-3) 2,475,000$ -$ 50,000$ 2,313,000$ 592,500$ 413,261$ 592,500$ 212,439$ 250,000$ 190,197$ 200,000$ -$ 11 Franchise Fees and Uncollectibles -$ -$ -$ -$ 6,658 4,797 6,658 2,466 2,902 2,208$ 2,322$ -$ 12 Interest -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 13 Subtotal Expenses 2,475,000$ -$ 50,000$ 2,313,000$ 599,158$ 418,058$ 599,158$ 214,905$ 252,902$ 192,405$ 202,322$ -$

14 AB693/SB92 Set Aside for Multi Family Solar Rooftops (2018 funds) -$ -$ -$ 15 Prior Year Set Aside (2016 and 2017 funds) 8,077,223$ 8,077,223$ -$ -$

16 Net GHG Revenues ($) (Line 8 + Line 13 + Line 14 + Line 15) (387,111,000)$ (384,888,000)$ (790,283,000)$ (759,245,600)$ (561,900,331)$ (563,115,436)$ (392,401,240)$ (402,565,763)$ (327,941,316)$ (352,577,671)$ (422,086,902)$ -$ 17 GHG Revenues to be Distributed in Future Years ($) -$ -$ 194,616,000$ 192,319,000$ -$ -$ -$ -$ -$ -$ -$ -$

18Net GHG Revenues Available for Customers in Forecast Year ($) (Line 16 + Line 17)

(387,111,000)$ (384,888,000)$ (595,667,000)$ (566,926,600)$ (561,900,331)$ (563,115,436)$ (392,401,240)$ (402,565,763)$ (327,941,316)$ (352,577,671)$ (422,086,902)$ -$

19 GHG Revenue Returned to Eligible Customers ($)20 EITE Customer Return -$ -$ 30,008,000$ 30,008,000$ 34,673,000$ 34,673,000$ 25,488,811$ 50,591,667$ 26,673,763$ 25,866,502$ 25,948,227$ -$ 21 Small Business Volumetric Return 2/ -$ -$ 30,550,000$ 40,961,000$ 39,496,000$ 52,964,531$ 24,446,633$ 32,179,018$ 21,725,095$ 27,111,903$ 19,941,970$ -$ 22 Residential Volumetric Return -$ -$ 178,425,000$ 169,887,000$ 225,679,000$ 194,522,279$ -$ 11,209,570$ -$ -$ -$ 23 Subtotal EITE + Volumetric Returns -$ -$ 238,983,000$ 240,856,000$ 299,848,000$ 282,159,809$ 49,935,444$ 93,980,255$ 48,398,858$ 52,978,405$ 45,890,197$ -$

24 Number of Households Eligible for the California Climate Credit - - 4,447,615 4,380,118 4,487,449 4,427,938 4,493,380 4,434,566 4,522,905 4,522,905 4,566,483 - 25 Per-Household Semi-Annual Climate Credit N/A N/A 40$ 40$ 29$ 29$ 38$ 38$ 31$ 31$ 41$ -$

(0.5 x Line 18 + Line 23) / Line 24)

26Revenue Distributed for the Climate Credit ($)(2 x Line 25 x Line 24)

-$ -$ 356,684,000$ 351,271,000$ 262,052,331$ 258,577,064$ 342,465,796$ 337,983,286$ 279,542,458$ 283,782,311$ 376,196,705$ -$

27 Revenue Balance ($)(Line 8 + Line 13 + Line 23 + 26) (387,111,000)$ (384,888,000)$ (194,616,000)$ (167,118,600)$ -$ (22,378,563)$ -$ 29,397,778$ (8,077,223)$ (15,816,954)$ -$ -$

1/ Recorded through September 30, 2017 plus estimated through December 31, 2017.2/ SCE received email notice on October 12, 2017 that per ARB's 2016 amendments to the Cap-and-Trade Regulation, the Small Business Volumetric is discontinued as of October 1, 2017. However SCE is advised by the CPUC Energy Division that no changes to the return of GHG revenues should be made until the Energy Division issues its guidance.

20182013 2014 2015 2016 2017

C 1

Appendix D

Witness Qualifications and Confidentiality Declarations

D-1

DECLARATION OF TODD CAMERON REGARDING THE CONFIDENTIALITY OF 1

CERTAIN MATERIAL IN SCE’S WORKPAPERS 2

I, TODD CAMERON, declare and state: 3

1. I am a Project Manager in the Regulatory Finance and Economics Group, Treasurer’s 4

Department at Southern California Edison Company (SCE). As such, I have responsibility for preparing 5

the financing and carrying cost sections of the 2018 ERRA Forecast of Operations testimony. This 6

portion of the forecast is presented in Exhibit No. SCE-1 Chapter VI of SCE’s 2018 ERRA forecast 7

application. I also have responsibility for preparing and submitting workpapers in support of my 8

testimony. I make this declaration in accordance with the Administrative Law Judge’s Ruling 9

Clarifying Interim Procedures for Complying with Decision 06-06-066, issued on August 22, 2006 in 10

Rulemaking 05-06-040. I have personal knowledge of the facts and representations herein and, if called 11

upon to testify, I could and would do so, except for those facts expressly stated to be based upon 12

information and belief, and as to those matters, I believe them to be true. 13

2. I have reviewed the workpaper information that supports my testimony, and the material 14

therein that SCE seeks to protect as confidential. I am informed and believe that the material listed in 15

the table below should not be made publicly available in compliance with the limits on confidentiality 16

found in the Matrix of Allowed Treatment, Investor Owned Utility (IOU) Data (Matrix) to which this 17

material corresponds. Also set forth is an explanation of why the data cannot be aggregated, redacted, 18

summarized, masked or otherwise protected in a way that allows partial disclosure: 19

Description of the Data

Location of the Data

Line or Table

Matrix Category Reason why data cannot be aggregated, etc.

2018 Average Fuel Inventory By Month ($000)

Workpapers, Chapter VI, p2

Columns B:D Lines 2 – 13

II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (1) Utility Retained Generation (URG)

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in this proceeding.

2018 Fuel Inventory Carrying Cost Rate


Columns C, E & G:D Lines 2 – 14

II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (1)

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden

D-2



Line or Table


Utility Retained Generation (URG)

of proof in this proceeding.

Global Insight Projection of LIBOR Rates - March, 2017


Columns B:D Lines 2 – 13

Section 583 of the Public Utilities Code and General Order 66(c).

SCE must protect the IHS information. Pursuant to Section 5.4 of the IHS Service Agreement, SCE is permitted to provide the information to a regulatory agency (such as the CPUC) so long as SCE takes reasonable steps to seek confidential treatment of the information

Fuel Inventory Carrying Cost Rate 2018


Columns, B, D, F, Lines 2-13



Collateral Calculations; 2018 forecast period


Cells C5:Q43



GHG Inventory; 2018 forecast period


Cells C2:D13



Global Insight Projection of 90 Commercial Paper Rate - March, 2017


Column B Lines 2 – 13

Section 583 of the Public Utilities Code and General Order 66(c).

SCE must protect the IHS information. Pursuant to Section 5.4 of the IHS Service Agreement, SCE is permitted to provide the information to a regulatory agency (such as the CPUC) so long as SCE takes reasonable steps to seek confidential treatment of the information

3. I am informed and believe that SCE is complying with the limitations on confidentiality 1

specified in the Matrix that pertain to the data listed in the table above. 2

D-3

4. I am informed and believe and thereon allege that the data in the table above cannot be 1

aggregated, redacted, summarized masked or otherwise protected in a manner that would allow partial 2

disclosure of the data while still protecting confidential information. 3

5. I am not aware of any instances where the data in the table in paragraph 2 above has ever 4

been made publicly available. 5

I declare under penalty of perjury under the laws of the State of California that the foregoing is 6

true and correct. 7

Executed on November 8, 2017, at Rosemead, California. 8

__/s/ Todd Cameron_____ 9

TODD CAMERON 10

D-4

DECLARATION OF SUSAN P. DIBERNARDO REGARDING THE 1

CONFIDENTIALITY OF CERTAIN DATA 2

I, Susan P. DiBernardo, declare and state: 3

1. I am the Manager of Revenue Requirements & Forecast group in the State Regulatory 4

Operations (SRO) Department at Southern California Edison (SCE). As such, I had 5

responsibility for preparing portions of testimony and workpapers in the 2018 Forecast of 6

Operations November Update testimony (SCE-5C). I make this declaration in accordance with 7

the Administrative Law Judge’s Ruling Clarifying Interim Procedures for Complying with 8

Decision 06-06-066, issued on August 22, 2006 in Rulemaking 05-06-040. I have personal 9

knowledge of the facts and representations herein and, if called upon to testify, could and would 10

do so, except for those facts expressly stated to be based upon information and belief, and as to 11

those matters, I believe them to be true. 12

2. I have reviewed those sections of Exhibit No. SCE-5C that I am sponsoring. Listed 13

below are the data in those portions of Exhibit No. SCE-5C for which SCE is seeking 14

confidential protection and the categories on the Matrix of Allowed Confidential Treatment 15

Investor Owned Utility (IOU) Data (Matrix) to which these data correspond. Also set forth is an 16

explanation of why the data cannot be aggregated, redacted, summarized, masked or otherwise 17

protected in a way that allows partial disclosure: 18



Line or Table

Matrix Category

Reason why data cannot be aggregated, etc.

SCE’s 2018 Annual Fuel - Peakers and Mountainview

SCE-5C, p. 50 & p. 51

Table VIII-29, Table VIII-30

II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR


SCE’s 2018 Fuel Inventory

SCE-5C, p. 50 & p. 51


II.A.2. Component of Utility Electric

Further aggregation, redaction, summarization or omission of this data would compromise

D-5



Line or Table

Matrix Category


Carrying Costs

Price Forecast Confidential for three years.

SCE’s ability to meet its burden of proof in this proceeding.

SCE’s 2018 Annual CHP and Renewable (QF) Costs

SCE-5C, p. 50 & p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. 3. QF Contracts


SCE’s 2018 Annual Forecast of Other Purchased Power Contract Costs -Existing Interutility Contracts

SCE-5C, p. 50 & p. 52

Table VIII-29 Table VIII-31

II. Cost forecast data-Electric. B. Generation Cost Forecasts. (4) Non-QF bilateral contracts.


SCE’s New Gen Auction

SCE-5C, p. 50 & p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG).


SCE’s 2013 Bilateral

SCE-5C, p. 50& p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR IV. Resource Planning Information-Electric. (f) Forecast of Post 1/1/03 (New World) contracts


D-6



Line or Table

Matrix Category


SCE’s Annual Bilateral Contracts (Capacity) & Generic RA

SCE-5C, p. 50 & p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR IV. Resource Planning Information-Electric. (f) Forecast of Post 1/1/03 (New World) contracts


SCE’s 2018 Forecast of Annual Gas Hedging Costs

SCE-5C, p. 50 & p. 52


I. Natural Gas Information. (A) Forecasts (gas) (4) Long-term fuel (gas) buying and hedging plans.


SCE’s 2018 Forecast of Gas Transportation and Storage Costs

SCE-5C, p. 50 & p. 52


I. Natural Gas Information. (A) Forecasts (gas) (4) Long-term fuel (gas) buying and hedging plans.


SCE’s Direct and Tolling Contract GHG Costs

SCE-5C, p. 50 & p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR


SCE’s Least Capacity Requirements (LCR) Contracts

SCE-5C, p. 50 & p. 52


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained


D-7



Line or Table

Matrix Category


Generation (URG) OR IV. Resource Planning Information-Electric. (f) Forecast of Post 1/1/03 (New World) contracts

3. I am informed and believe that SCE is complying with the limitations on 1

confidentiality specified in the matrix that pertain to the data listed in the table above. 2

4. Additionally, SCE is seeking confidential treatment of certain data that is market-3

sensitive, but does not fall into a category on the matrix. That data is listed below: 4



Line or Table

Basis for Assertion of Confidentiality

SCE’s 2018 Collateral Costs

SCE-5C, p. 50 & p. 52


This number represents the forecast negative mark-to-market of SCE’s contracts (current & future) under a very low price scenario. With this forecast information, one can derive SCE’s net short (MW) position (which is confidential under Matrix, Sec. VI.A.)

New Gen CAM (Capacity), Combined Heat and Power, and CAM-related Peakers (Estimated CAM-Related Revenue Requirement)

SCE-5C, p. 50, p. 52 & p. 54

Table VIII-29, Table VIII – 31, and Table VIII – 32 (Lines 1-4)

These numbers represents load and energy cost forecasts that are market sensitive and confidential under matrix Sec. VI.

5. I am informed and believe and thereon allege that the data in the table above cannot 5

be aggregated, redacted, summarized, masked or otherwise protected in a manner that would 6

D-8

allow partial disclosure of the data while still protecting confidential information without 1

jeopardizing SCE’s ability to provide sufficient evidence to support SCE’s Application. 2

6. I am informed and believe and thereon allege that the data in the tables in paragraphs 3

2 and 4 above have never been made publicly available. 4

I declare under penalty of perjury under the laws of the State of California that the 5

foregoing is true and correct. 6


/s/ Susan P. DiBernardo 8

Susan P. DiBernardo 9

D-9

SOUTHERN CALIFORNIA EDISON COMPANY 1

WITNESS QUALIFICATIONS AND CONFIDENTIALITY DECLARATION 2

OF TRACY KIMURA 3

Q. Please state your name and business address for the record. 4

A. My name is Tracy Kimura, and my business address is 2244 Walnut Grove Ave, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company 7

(“SCE”). 8

A. I am an Emissions Trader in the Energy Procurement and Management organization. In 9

this capacity I am responsible for SCE’s implementation of the California greenhouse gas 10

cap-and-trade program and participation in the greenhouse gas emissions markets. 11

Q. Briefly describe your educational and professional background. 12

A. I graduated from the University of California, Los Angeles with a Bachelor’s degree in 13

Applied Mathematics. I have been employed by SCE since 2007 where I’ve previously 14

held roles as a Power Trader and Power Trading Analyst. 15

Q. What is the purpose of your testimony in this proceeding? 16

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-5C, titled 17

Energy Resource Recovery Account (ERRA) 2018 Forecast of Operations, as identified 18

in the Table of Contents thereto. 19

Q. Was this material prepared by you or under your supervision? 20

A. Yes, it was. 21

Q. Insofar as this material is factual in nature, do you believe it to be correct? 22

A. Yes, I do. 23

D-10

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 1

judgment? 2

A. Yes, it does. 3

Q. Does this conclude your qualifications and prepared testimony? 4

A. Yes, it does. 5

D-11

DECLARATION OF TRACY KIMURA IN SUPPORT OF PREPARED TESTIMONY 1

AND REGARDING THE CONFIDENTIALITY OF CERTAIN DATA 2

I, Tracy Kimura, do hereby declare and affirm as follows: 3

1. I am an Emissions Trader in the Energy Procurement and Management Organization 4

at Southern California Edison (SCE). As such, I had responsibility for preparing portions of the 5

testimony, update testimony, and workpapers in SCE’s 2018 Energy Resource Recovery 6

Account (ERRA) Forecast Application. 7

2. I sponsor the portions of Exhibit SCE-5C, titled “Energy Resource Recovery Account 8

(ERRA) 2018 Forecast of Operations,” Chapter VII.B. and Chapter VII.D, as indicated in the 9

table of contents thereto. 10

3. That the facts stated within the material I sponsor in Exhibit SCE-5C are true and 11

correct to the best of my knowledge and belief, and that insofar as said material is in the nature 12

of opinion or judgment, it represents my best judgment. 13

4. I am the same Tracy Kimura whose witness qualifications are set forth in Exhibit 14

SCE-5C in this proceeding. My qualifications to offer this testimony are set forth in that exhibit. 15

5. I make this declaration, in part, in accordance with Decisions 06-06-066 and 08-04-16

023 issued in Rulemaking 05-06-040. I have personal knowledge of the facts and 17

representations herein and, if called upon to testify, could and would do so, except for those facts 18

expressly stated to be based upon information and belief, and as to those matters, I believe them 19

to be true. 20

6. I have reviewed those sections of Exhibit SCE-5C that I am sponsoring. Listed below 21

are the Greenhouse Gas (GHG) data for which SCE is seeking confidential protection and the 22

confidentiality protocols adopted in D.14-10-033 (Attachment A) to which these data 23

correspond. 24

D-12



Line or Table Attachment A Confidentiality Protocol

GHG Allowance Volume and Revenue Forecast

Exhibit SCE-5C

Tables: VII-18; VII-21; VII-22; and VII-23

1. Pursuant to the ARB GHG non-disclosure regulations Public Utilities Code Section 454(g) and CPUC D.06-06-066 as modified by D.08-04-023, the following current or forecast confidential GHG information will not be disclosed to the public:

a. Utility AB 32 GHG auction participation, including but not limited to:

• Qualification status (ability to participate) • Intent to participate in an auction, auction approval

status, maintenance of continued auction approval • Participation in an auction • Auction bidding strategy • Bid price or bid quantity information • Bid guarantee information

b. Utility AB 32 GHG allowance procurement or revenue return positions. Specifically:

• Utility GHG price forecasts internally derived for utility procurement planning purposes

• Utility GHG compliance instrument inventories or quantities that can be used to derive GHG compliance instrument holdings

d. Other utility procurement related information subject to confidentiality protection pursuant to the terms of D.06-06-066 as modified by D.08-04-023, that pertains to GHG compliance. Specifically:

i. ARB allowance or offset procurement quantity targets; ii. CPUC-approved procurement limits for compliance exposure and financial exposure; and iii. detailed forecasted GHG financial exposure by type (direct and indirect) or resource category, including utility forecasts of payments to tolling counterparties, qualifying facilities for GHG, and increased power market costs.

Further, this data must be kept confidential, per the California Air Resources Board (ARB) California Cap-and-Trade Regulation, Title 17, California Code of Regulations, Article 5, Section 95914(c).

7. I am informed and believe, and thereon allege, that the data in the table in paragraph 6 1

above cannot be aggregated, redacted, summarized, masked, or otherwise protected in a manner 2

D-13

that would allow partial disclosure of the data while still protecting confidential information 1

without jeopardizing SCE’s ability to provide sufficient evidence to support SCE’s Application. 2

8. I am informed and believe, and thereon allege, that the data in the table in paragraph 6 3

above has never been made publicly available. 4




/s/ Tracy Kimura

Tracy Kimura

D-14

DECLARATION OF ERIC LAVIK REGARDING THE CONFIDENTIALITY OF 1

CERTAIN MATERIAL IN SCE’S WORKPAPERS 2

I, Eric Lavik, declare and state: 3

1. I am a Manager within the Portfolio Planning and Analysis group in the Power 4

Supply Department at Southern California Edison (SCE). As such, I have responsibility for the 5

preparation of the forecast of energy and payments to CHP and renewable projects that have 6

contracts with SCE. This forecast is presented in Exhibit No. SCE-1C Section IV-E-3 of SCE’s 7

Energy Resource Recovery Account (ERRA), 2018 Forecast of Operations testimony. I also 8

have responsibility for preparing and submitting workpapers in support of my testimony. I make 9

this declaration in accordance with the Administrative Law Judge’s Ruling Clarifying Interim 10

Procedures for Complying with Decision 06-06-066, issued on August 22, 2006 in Rulemaking 11

05-06-040. I have personal knowledge of the facts and representations herein and, if called upon 12

to testify, could and would do so, except for those facts expressly stated to be based upon 13


2. I have reviewed the workpaper information that supports my testimony, and the 15

material therein that SCE seeks to protect as confidential. I am informed and believe that the 16

material listed in the table below should not be made publicly available in compliance with the 17

limits on confidentiality found in the Matrix of Allowed Treatment, Investor Owned Utility 18

(IOU) Data (Matrix) to which this material corresponds. Also set forth is an explanation of why 19

the material cannot be aggregated, redacted, summarized, masked or otherwise protected in a 20

way that allows partial disclosure: 21

Description of Material and Relation to Testimony

Location and Page

Matrix Category or reason for confidentiality


SCE forecast of generation and costs from CHP and Renewable contracts

Workpapers IV.B. Forecast of Qualifying Facility Generation; Confidential for three years; and II.B.3. Forecast of QF Contract Costs; Confidential for three years

Actual number is needed for SCE to carry its burden of proof.

D-15


confidentiality specified in the Matrix that pertain to the data listed in the table above. 2



allow partial disclosure of the data while still protecting confidential information. 5

5. I am not aware of any instances where the data in the table in paragraph 2 above has 6

ever been made publicly available. 7




/s/ Eric Lavik 11 Eric Lavik 12

D-16

DECLARATION OF EDUARDO MARTINEZ REGARDING THE CONFIDENTIALITY 1

OF CERTAIN DATA 2

I, Eduardo Martinez, declare and state: 3

1. I am a Senior Long Term Demand Forecast Planner in the Demand and Distributed 4

Energy Resources Group within the Planning Analysis & Forecasting Department at Southern 5

California Edison (SCE). As such, I had responsibility for preparing the bundled sales and 6

energy forecasts for the Energy Resource Recovery Account (ERRA) 2018 Forecast of 7

Operations. I make this declaration in accordance with the Administrative Law Judge’s Ruling 8

Clarifying Interim Procedures for Complying with Decision 06-06-066, issued on August 22, 9

2006 in Rulemaking 05-06-040. I have personal knowledge of the facts and representations 10

herein and, if called upon to testify, could and would do so, except for those facts expressly 11

stated to be based upon information and belief, and as to those matters, I believe them to be true. 12

2. I have reviewed the bundled sales and energy forecasts for which SCE is seeking 13







Line or Table


SCE’s Direct Access Sales Forecast

Page 8 of “SCE’s Bundled Energy Forecast”

Grey shaded area on line 14

V) C) LSE Total Energy Forecast – Direct Access Customer (MWh)

SCE must provide full disclosure to support ERRA testimony.

SCE’s CCA Sales Forecast



V) C) LSE Total Energy Forecast – CCA Customer (MWh)


SCE’s Bundled Sales Forecast



V) C) LSE Total Energy Forecast – Bundled Customer (MWh)


D-17



Line or Table



Page 8 of “SCE’s Bundled Energy Forecast”.

Grey shaded area in Table III-4



SCE’s Direct Access Sales Forecast



V) C) LSE Total Energy Forecast – Direct Access Customer (MWh)


SCE’s Bundled Energy Forecast





SCE’s Bundled Energy at CAISO Forecast






confidentiality specified in the Matrix that pertain to the data listed in the table above. 2





5. I am informed and believe and thereon allege that the data in the tables in paragraph 2 7

above has never been made publicly available. 8



Executed on November 9, 2017 at Rosemead, California. 11

/s/Eduardo Martinez 12 Eduardo Martinez13

D-18

DECLARATION OF ROBERT THOMAS REGARDING THE CONFIDENTIALITY OF 1

CERTAIN DATA 2

I, ROBERT THOMAS, declare and state: 3

1. I am Manager of Rate Design in Regulatory Operations at Southern California Edison 4

(SCE). As such, I had responsibility for preparing portions of testimony and workpapers in the 5

2018 Forecast of Operations Exhibit (SCE-1) in SCE’s Energy Resource Recovery Account 6

(ERRA) Application. I make this declaration in accordance with the Administrative Law 7

Judge’s Ruling Clarifying Interim Procedures for Complying with Decision 06-06-066, issued on 8

August 22, 2006 in Rulemaking 05-06-040. I have personal knowledge of the facts and 9

representations herein and, if called upon to testify, could and would do so, except for those facts 10

expressly stated to be based upon information and belief, and as to those matters, I believe them 11

to be true. 12

2. I have reviewed those sections of Exhibit No. SCE-1 that I am sponsoring. Listed 13

below are the data in those portions of Exhibit No. SCE-1 for which SCE is seeking confidential 14

protection and the categories on the Matrix of Allowed Confidential Treatment Investor Owned 15

Utility (IOU) Data (Matrix) to which these data correspond. Also set forth is an explanation of 16

why the data cannot be aggregated, redacted, summarized, masked or otherwise protected in a 17

way that allows partial disclosure: 18







Line or Table

Matrix Category

Basis for Assertion of Confidentiality


Page 45 of “Table VII-25”

Grey shaded area of Table VII-25



D-19

Forecast MWh Sales and GHG Revenues





Emission Intensity (MTCO2e/MWH)









6. I am informed and believe and thereon allege that the data in the tables in paragraphs 5

2 and 4 above have never been made publicly available. 6




/s/ Robert Thomas 10 Robert Thomas 11

D-20

DECLARATION OF DESIREE WONG REGARDING THE CONFIDENTIALITY OF 1

CERTAIN DATA 2

I, Desiree Wong, declare and state: 3

1. I am a Project Manager in the Revenue Requirements department in the Regulatory 4

Affairs Organization at Southern California Edison Company. As such, I had responsibility for 5

preparing portions of testimony and workpapers in the 2018 Forecast of Operations Exhibit 6

(SCE-5C) in SCE’s Energy Resource Recovery Account (ERRA) Application. I make this 7

declaration in accordance with the Administrative Law Judge’s Ruling Clarifying Interim 8

Procedures for Complying with Decision 06-06-066, issued on August 22, 2006 in Rulemaking 9

05-06-040. I have personal knowledge of the facts and representations herein and, if called upon 10

to testify, could and would do so, except for those facts expressly stated to be based upon 11


2. I have reviewed those sections of Exhibit No. SCE-5C that I am sponsoring. Listed 13

below are the data in those portions of Exhibit No. SCE-5C for which SCE is seeking 14











Line or Table Matrix Category Basis for Assertion of Confidentiality

Platts On- and Off-Peak forward strip prices

Appendix B – Indifference Calculation Inputs and Sources

Lines 1 and 2 N/A Proprietary, subscription-based data

D-21



Line or Table Matrix Category Basis for Assertion of Confidentiality

Forecast costs by resource type and vintage

Appendix B –IOU Portfolio by Resource Type; F&PP Eligible and Ineligible Workpapers; Cost Summary Workpapers

Lines 4-9, 27-32 of Appendix B; Columns D of Workpapers

II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts.


Forecast energy by resource type and vintage

Appendix B –IOU Portfolio by Resource Type; F&PP Eligible and Ineligible Workpapers Energy Summary Workpapers

Lines 13-18, 27-32; Column E of Workpapers

IV. Resource Planning Information – Electric. (A,B,C,E,F)






6. I am informed and believe and thereon allege that the data in the table in paragraph 4 5

above have never been made publicly available. 6




/s/ Desiree Wong 10 Desiree Wong 11

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