Updated Testimony Energy Resource Recovery...

Application No.: A.16-05-001 Exhibit No.: SCE-6 Witnesses: S. DiBernardo S. Liu E. Martinez T. Cameron E. Lavik R. Thomas D. Cox M. Sheriff D. Wong

(U 338-E)

Updated Testimony Energy Resource Recovery Account (ERRA) 2017 Forecast of Operations Public Version

Before the

Public Utilities Commission of the State of California

Rosemead, California

November 10, 2016

SCE-6: ERRA Resource Recovery Account (ERRA) 2017 Forecast of Operations

Table Of Contents

Section Page Witness

-i-

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

II. UPDATED 2017 ERRA FORECAST PROCEEDING REVENUE REQUIREMENT ...............................................................................................3

A. 2017 ERRA Forecast Proceeding Revenue Requirement ......................3

a) ERRA-Related Generation Service Revenue Requirement ...................................................................7

b) ERRA-Related Delivery Service Revenue Requirement ...................................................................8

III. SCE’S BUNDLED ENERGY FORECAST ......................................................9 E. Martinez

A. Retail Sales Forecast Summary .............................................................9

B. Total Retail Sales Forecast by Customer Class ...................................10

C. Customer Forecast ...............................................................................11

D. Annual and Monthly Bundled Energy .................................................11

IV. FORECAST ENERGY PRODUCTION AND COSTS FROM SCE’S PORTFOLIO OF RESOURCES .........................................................13 E. Lavik

A. Introduction ..........................................................................................13

B. Energy Production Forecast Methodology ..........................................13

C. Validation of SCE’s Energy Production Forecast ...............................15

D. 2017 Energy and Cost Forecast Summary ...........................................16

E. SCE’s Utility-Owned Generation and Purchased Power Contracts ..............................................................................................20

1. Hydro Facilities ........................................................................20

2. SCE Solar Photovoltaic Generation .........................................21

3. CHP and Renewables ...............................................................22


Table Of Contents (Continued)


ii

a) Energy Forecast ...........................................................22

b) Payment Forecast .........................................................24

c) Energy and Capacity Prices .........................................24

4. Utility-Owned Natural Gas Facilities ......................................25

a) SCE Peakers .................................................................25

(1) Background and Production .............................25

(2) Costs .................................................................25

b) Mountainview Generating Station ...............................25

5. Interutility Contracts Production ..............................................26 D. Cox

a) WAPA/MWD Agreements ..........................................27

b) Pasadena Corporation Grant Deed ...............................28

c) Interutility Contract Resource Costs ............................29

6. New System Generation Contracts ..........................................29 E. Lavik

a) Production ....................................................................29

b) Costs .............................................................................29

7. 2013 Bilateral Contracts Production ........................................30

a) Production ....................................................................30

b) Costs .............................................................................30

8. Generic and Bilateral Resource Adequacy (RA) Contracts ..................................................................................30

a) Production ....................................................................30

9. Local Capacity Requirements (LCR) Contracts ......................30

a) Production ....................................................................31




iii

b) Costs .............................................................................31

10. Aliso Canyon Contracts ...........................................................31

11. Green Tariff Shared Renewables (GTSR) Program ................33

F. Other SCE Resources and Programs....................................................34 S. DiBernardo

1. Nuclear .....................................................................................34

2. Catalina Fuel Costs ..................................................................34

3. Demand Response ....................................................................34

G. CAISO Costs and Short-Term Market Activity...................................34 E. Lavik

1. CAISO Costs ............................................................................34

2. Short-Term Market Activity Costs ..........................................34

H. Gas Price Sensitivity ............................................................................35

I. Direct GHG Costs ................................................................................36

J. Gas Hedging Costs ...............................................................................36 S. Liu

1. Transaction Fees ......................................................................36

2. Option Premiums .....................................................................36

K. Gas Transportation and Storage ...........................................................36 D. Cox

1. Transportation ..........................................................................37

a) SoCalGas Transportation Agreement for Mountainview Generating Station ...............................37

b) SoCalGas Transportation Agreements for UCSB and CSUSB Fuel Cells .....................................37

c) SoCalGas Transportation Agreements for SCE’s Peakers ..............................................................37

V. FINANCING COSTS ......................................................................................39 T. Cameron




iv

A. Commission Decisions Regarding Financing Costs and Collateral Costs ....................................................................................39

B. SCE’s Current Short-Term Financings ................................................39

1. Credit Facilities ........................................................................39

2. Collateral Requirements ...........................................................41

3. Fixed Rate Bonds Supporting Fuel Inventories .......................41

4. Commercial Paper ....................................................................42

5. Costs of Collateral Issuance .....................................................42

C. Additional Financial Instruments Supporting Collateral .....................42

VI. CARRYING COSTS .......................................................................................44

A. Fuel Inventory Carrying Costs .............................................................44

B. GHG Compliance Carrying Costs .......................................................45

C. Collateral Carrying Costs .....................................................................45

VII. UPDATED GHG FORECAST COSTS AND REVENUES AND RECONCILIATION ........................................................................................47 M. Sheriff

A. Overview ..............................................................................................47

B. Updated 2017 GHG Emissions and Cap-and-Trade Costs ..................48

C. Updated 2017 GHG-related Administrative and Customer Outreach Expenses ...............................................................................51

D. Updated 2017 GHG Allowance Revenue Forecast .............................52

E. Updated 2017 Proposed GHG Revenue Returns .................................53

VIII. UPDATED 2017 FORECAST REVENUE REQUIREMENT AND RATEMAKING PROPOSAL .........................................................................59 S. DiBernardo

A. Introduction ..........................................................................................59




v

B. Updated Estimate of 2017 ERRA-Related Generation Service Revenue Requirement ..........................................................................60

1. Updated Estimate of 2017 Fuel and Purchased Power Revenue Requirement ..............................................................60

a) Fuel Expense ................................................................62

b) Purchased Power Expense ...........................................62

2. Updated December 31, 2016 ERRA Balance ..........................63

3. Updated Energy Settlement Refunds and Litigation Costs .........................................................................................64

C. Updated 2017 ERRA-Related Delivery Service Revenue Requirement .........................................................................................64

1. Updated New System Generation Net Capacity CAM-Related Cost...................................................................65

a) 2017 CAM Eligible Costs ............................................65

2. Updated December 31, 2016 NSGBA Balancing Account ....................................................................................66

3. Estimated 2017 Spent Nuclear Fuel Revenue Requirement .............................................................................66

IX. DIRECT ACCESS, DEPARTING LOAD AND COMMUNITY CHOICE AGGREGATION COST RESPONSIBILITY SURCHARGES ...............................................................................................68 D. Wong

A. Introduction ..........................................................................................68

B. Total Portfolio Costs ............................................................................70

C. 2017 Market Price Benchmark ............................................................71

X. ESTIMATED RATE INFORMATION ..........................................................74 R. Thomas

Appendix A Estimated December 31, 2016 Balancing Account Balances .....................

Appendix B Indifference Rate Calculation ......................................................................




vi

Appendix C Declarations Regarding the Confidentiality of Certain Data


List Of Tables

Table Page

-vii-

Table II-1 Updated and May 2017 ERRA Forecast Revenue Requirement Changes

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

Table II-2 2017 Revenue Requirement vs. Current Rates (October 2016) ..................................................5

Table II-3 Updated and May 2017 ERRA Forecast Proceeding Revenue Requirement

Changes ($000) ......................................................................................................................................7

Table III-4 2017 Bundled Service Customer Load Forecast (GWh) .........................................................10

Table III-5 Annual Retail Sales by Customer Class (GWh) ......................................................................11

Table III-6 Year-End Customers by Customer Class ................................................................................11

Table III-7 Bundled Energy at CAISO (GWh) ..........................................................................................12

Table IV-8 2017 Energy Forecast of the SCE Portfolio (GWh) Confidential ...........................................17

Table IV-9 2017 Forecast of Fuel and Purchased Power Costs ($000) Confidential ................................18

Table IV-10 2017 Forecast of SCE SPVP Production (GWh) ..................................................................21

Table IV-11 New Projects .........................................................................................................................23

Table IV-12 Average Capacity Factors by Technology ............................................................................23

Table IV-13 Forecast of Energy and Payments .........................................................................................24

Table IV-14 Forecast of Posted Energy and Capacity Prices ....................................................................25

Table IV-15 Non-Coincident Contract Capacity Quantities and Expiration Dates for

SCE’s Major Interutility Contracts ......................................................................................................26

Table IV-16 SCE Entitlement to Hoover Dam Electrical Output for Year 2017 Source:

Bureau of Reclamation - CRSR 3/2016 Most Probable Inflow ...........................................................28

Table VI-17 Estimate of 2017 Carrrying Costs ($000) .............................................................................44

Table VI-18 Estimated 2017 Fuel Inventory Carrying Costs ($000) ........................................................45

Table VI-19 Estimated 2017 GHG Compliance Carrying Costs ($000) ..................................................45


List Of Tables (Continued)

Table Page

viii

Table VI-20 Estimated 2017 Procurement Collateral Carrying Costs ($000) ...........................................46

Table VII-21 SCE’s Updated Forecast of 2017 GHG Emissions Volumes (Metric Tons

CO2e) ...................................................................................................................................................48

Table VII-22 SCE’s Updated Forecast of 2017 GHG Costs ($000) ..........................................................48

Table VII-23 Updated Annual GHG Emissions and Associated Costs (Template D-2) ...........................49

Table VII-24 Updated Weighted Average Cost of GHG Compliance Instruments

Calculation (Template C-1) .................................................................................................................50

Table VII-25 Updated Detail of Outreach and Administrative Expenses (Template D-3) .......................52

Table VII-26 SCE’s Updated 2017 Forecast Consignment in ARB Auctions (Metric Tons

CO2e) ....................................................................................................................................................52

Table VII-27 SCE’s Updated Forecast 2017 Allowance Revenue ($000) ................................................53

Table VII-28 SCE’s Updated Recorded/Forecast 2016 Allowance Revenue ...........................................53

Table VII-29 Updated Annual Allowance Revenue Receipts and Customer Returns

(Template D-1) .....................................................................................................................................56

Table VII-30 Updated GHG Allowance Revenue Allocation by Class ....................................................57

Table VII-31 Updated GHG Costs and Revenues by Rate Schedule (Template D-4) ..............................58

Table VII-32 Updated History of GHG Revenues, Costs, and Emissions Intensity

(Template D-5) .....................................................................................................................................58

Table VIII-33 Updated Estimate of 2017 ERRA Forecast Proceeding Revenue

Requirement ($000) .............................................................................................................................59

Table VIII-34 Updated Estimate of 2017 Fuel and Purchased Power Revenue

Requirement ($000) .............................................................................................................................61

Table VIII-35 Updated Estimate of 2017 Fuel Expense ($000) ................................................................62

Table VIII-36 Updated Estimate of 2017 Purchased Power Expense ($000) ...........................................63


List Of Tables (Continued)

Table Page

ix

Table VIII-37 CAM Applicable Resources ...............................................................................................65

Table VIII-38 Updated Estimate of 2017 CAM-Related Revenue Requirement ($000) ..........................66

Table VIII-39 Estimated 2017 Spent Nuclear Fuel Revenue Requirement ($000) ...................................67

Table IX-40 Comparison of Market Price Benchmarks ............................................................................73

Table X-41 SCE 2017 ERRA Forecast Class Average Rates ....................................................................75

Table X-42 Rate Schedule By Customer Group ........................................................................................76

1

I. 1

INTRODUCTION 2

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

Account (ERRA) 2017 Forecast proceeding revenue requirement, including the kilowatt-hour (kWh) 4

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

31, 2016 balances in applicable balancing accounts; (2) update the 2017 Cost Allocation Methodology 6

(CAM)-related revenue requirement; (3) provide an estimate of the 2017 Cost Responsibility Surcharge 7

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

(CCA) customers; and (4) update the 2017 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 2017 Forecast proceeding revenue 11

requirement in the amount of $4.485 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, 2016 account balances included 13

in this revenue requirement. 14

In this update, SCE also proposes to return a total of $327.941 million in net available GHG 15

allowance revenues (Line 17 of Table VII-29) to eligible customers in 2017 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 2017, residential customers can 19

expect a semi-annual, on-bill California Climate Credit of $31.00 in 2017. 20

A discussion of SCE’s updated estimated 2017 ERRA Forecast proceeding revenue requirement 21

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

address the following: 23

• Chapter III, SCE’s Updated Bundled Energy Forecast 24

• Chapter IV, Updated Forecast Energy Production and Costs from SCE’s Portfolio of 25

Resources 26

• Chapter V, Updated Financing Costs 27

2

• Chapter VI, Updated Carrying Costs 1

• Chapter VII, Updated GHG Forecast Costs and Revenues and Reconciliation 2

• Chapter VIII, Updated 2017 Forecast Revenue Requirement and Ratemaking Issues 3

• Chapter IX, Updated Cost Responsibility Surcharges (Direct Access, Departing Load, and 4

Community Choice Aggregation) 5

• Appendix A, Updated Estimated December 31, 2016 Balancing Account Balances 6

• Appendix B, Updated Indifference Rate Calculation 7

3

II. 1

UPDATED 2017 ERRA FORECAST PROCEEDING REVENUE REQUIREMENT 2

A. 2017 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 2017 ERRA Forecast proceeding revenue requirement in the 5

amount of $4.485 billion beginning January 1, 2017. This updated 2017 ERRA Forecast revenue 6

requirement represents an increase of $336 million from the estimated 2017 ERRA Forecast revenue 7

requirement presented in the May 2, 2016 Application and supporting testimony. 8

As shown in Table II-1, this Update Testimony presents an increase in the estimated 2017 fuel 9

and purchased power costs of approximately $271 million as described in more detail in Chapter IV, an 10

increase of $34 million due to updated estimates of year-end 2016 ERRA and New System Generation 11

(NSG) balancing account balances, and an increase of $30 million attributable to the net impact of 12

updated GHG cap-and-trade costs and GHG allowance revenues. 13

4

Table II-1 Updated and May 2017 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 2017 fuel and purchased power expenses from the amounts included in the May filing are 2

summarized below: 3

1. SCE forecasts a natural gas price of $3.15/MMBtu for 2017, which is $0.58 higher than the 4

average forecast gas price included in the 2017 ERRA May forecast; 5

2. SCE expects its sales to be lower than it did in the 2017 ERRA May forecast; 6

3. SCE expects higher fuel-related costs from its natural gas-fueled utility-owned generation 7

(UOG) and tolling resources due to higher forecast natural gas prices; 8

4. SCE expects higher open market costs due to higher forecast SP-15 forward market power 9

prices; and 10

5. SCE expects higher Short Run Avoided Cost (SRAC) payments due to higher forecast market 11

prices. 12

Line Description

Updated 2017 Revenue

Requirement

(Filed May 2016) 2017 Proposed

Revenue Requirement Change

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

1. Fuel and Purchased Power 1/ 4,584,334$ 4,313,149$ 271,185$

2. ERRA Balancing Account (94,007)$ (110,913)$ 16,906$

3. Energy Settlements Memorandum Account - Net Amount 2/ -$ -$ -$

4. New System Generation Balancing Account 8,896$ (8,569)$ 17,465$

5. SUBTOTAL ERRA-RELATED 4,499,222$ 4,193,667$ 305,555$

6. GHG Cap-and-Trade Costs 313,776$ 308,759$ 5,017$

7. GHG Allowance Revenues (327,941)$ (353,282)$ 25,341$

8. SUBTOTAL GHG-RELATED (14,165)$ (44,523)$ 30,358$

9. TOTAL ERRA PROCEEDING REVENUE REQUIREMENT 4,485,057$ 4,149,144$ 335,913$

1/ Amounts include Spent Nuclear Fuel. 2/ Amount reflects 12/31/16 forecast ESMA refunds less forecast litigation-related costs.

5

As shown in Table II-2 below, the updated 2017 ERRA Forecast revenue requirement of $4.485 1

billion represents an increase of $799.7 million as compared to the revenue requirement used to set the 2

rates in effect today.1 3

Table II-2 2017 Revenue Requirement vs. Current Rates (October 2016)

Pursuant to Section III.B.3 of the adopted 2015 ERRA Forecast Settlement Agreement (D.15-10-4

037), SCE has the option to file a Tier 1 advice letter to implement, effective on or about the date one 5

year after the Primary Implementation Date of November 24, 2015, a rate change to increase rates by an 6

equal amount of the reduction effective November 24, 2015 of $250 million, because SCE will have 7

fully returned the required net refund to customers within this twelve-month period. In the event a 8

Commission decision is not issued by December 15, 2016 (the last Commission conference of 2016) in 9

this 2017 ERRA Forecast application, SCE will implement the $250 million increase in rates on January 10

1 The rates in effect today are based on the revenue requirement approved by D.15-12-033 and also incorporate

disbursements of GHG allowance revenues to Emissions-Intensive Trade-Exposed (EITE) customers in October 2016 as discussed in Chapter VII.

Line Description


Requirement In Rates Change

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

1. Fuel and Purchased Power 1/ 4,584,334$ 4,336,804$ 247,530$

2. ERRA Balancing Account (94,007)$ (358,553)$ 264,546$

3. Energy Settlements Memorandum Account - Net Amount 2/ 0$ (1,149)$ 1,149$

4. New System Generation Balancing Account 3/ 8,896$ (157,870)$ 166,766$

5. SUBTOTAL ERRA-RELATED 4,499,222$ 3,819,232$ 679,990$

6. GHG Cap-and-Trade Costs 313,776$ 348,801$ (35,025)$

7. GHG Allowance Revenues 4/ (327,941)$ (482,704)$ 154,763$

8. SUBTOTAL GHG-RELATED (14,165)$ (133,903)$ 119,738$


1/ Amounts include Spent Nuclear Fuel. 2/ Amount reflects 12/31/16 forecast ESMA refunds less forecast litigation-related costs. 3/ Amount in rates decreased by a $7.771 million credit as compared to May filing to correct an inadvertent error. 4/ Amount in rates includes EITE disbursement of GHG revenues in October 2016.

6

1, 2017 in accordance with the provisions of the 2015 ERRA Settlement Agreement. This increase 1

would remain in effect until implementation of a final decision in this proceeding.2 2

Table II-3 below compares the Update Testimony and May 2016 Application revenue 3

requirements in more detail, and includes the functionalization between the generation service and the 4

delivery service revenue requirements. The change in SCE’s updated forecast 2017 fuel and purchased 5

power cost estimate compared to the May Application is an increase of $276.2 million, as discussed in 6

Chapter IV.3 7

Table II-3 also shows the change in the 2017 ERRA Forecast proceeding revenue requirement 8

resulting from changes in the December 31, 2016 estimated balances in the ERRA balancing account, 9

the Energy Settlements Memorandum Account (ESMA), and the NSG Balancing Account (NSGBA), 10

using recorded data through October 31, 2016, and estimated November through December 2016 11

activity. As indicated in Table II-3 the updated cumulative balances in these three accounts results in a 12

$34.4 million increase from the estimated December 31, 2016 balances included in the May Application. 13

Appendix A, attached hereto, includes the updated balancing account tables supporting the amounts 14

included in SCE’s updated 2017 ERRA Forecast revenue requirement request. 15

2 This increase is embedded in the December 31, 2016 estimated ERRA balancing account balance.

3 Includes GHG Cap and Trade costs.

7

Table II-3 Updated and May 2017 ERRA Forecast Proceeding Revenue Requirement Changes

($000)

a) ERRA-Related Generation Service Revenue Requirement 1

As shown on Line No. 6 in Table II-3 above, the increase of $223.2 million in SCE’s 2017 2

ERRA forecast generation service revenue requirement is primarily due to a $206.3 million increase in 3

the fuel and purchased power cost estimates, including GHG Cap-and-Trade costs, as shown on Lines 4

Nos. 2 and 5 of Table II-3, netted with an increase of $16.9 million in the generation service revenue 5

Line Description


Requirement

(Filed May 2016) 2017 Proposed

Revenue Requirement Change

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

1. Generation Service

2. Fuel and Purchased Power 3,899,757$ 3,698,503$ 201,254$ 3. ERRA Balancing Account (94,007)$ (110,913)$ 16,906$ 4. Net Generator Refunds 0$ 0 0$ 5. GHG Cap-and-Trade Costs 313,776$ 308,759$ 5,017$ $ 6. TOTAL ERRA PROCEEDING GENERATION SERVICE 4,119,526$ 3,896,350$ 223,177$

7. Delivery Service

8. New System Generation Rate Component:9. F&PP New System Generation 659,167$ 589,873$ 69,295$ 10. NSG Balancing Account 8,896$ (8,569)$ 17,464$ 11. Total New System Generation 668,063$ 581,304$ 86,759$

12. Nuclear Decommissioning Rate Component:13. Spent Nuclear Fuel 4,157$ 4,157$ (1)$ 14. Total Nuclear Decommissioning 4,157$ 4,157$ (1)$

15. Distribution Rate Component16. LCR F&PP Distribution 4,932$ 4,932$ (0)$ 17. GHG Allowance Revenues (327,941)$ (353,282)$ 25,341$ 18. Total Distribution (323,009)$ (348,350)$ 25,341$

19. Public Purpose Programs Charge (PPPC)20. LCR F&PP PPPC 16,321$ 15,684$ 637$ 21. Total Distribution 16,321$ 15,684$ 637$

22. TOTAL ERRA PROCEEDING DELIVERY SERVICE 365,531$ 252,795$ 112,736$


8

requirement as shown on Line No. 3 of Table II-3 associated with the estimated year-end 2016 ERRA 1

balance, and $0 million associated with net Generator refunds related to the 2000-2001 California 2

Energy Crisis settlements approved by the Federal Energy Regulatory Commission (FERC). SCE’s 3

forecast year-end 2016 ERRA over-collected balance of $94.0 million primarily reflects the remaining 4

amount to be amortized in rates related to the two-year amortization of the year-end 2015 ERRA over-5

collected balance, as adopted in D.15-12-033. 6

b) ERRA-Related Delivery Service Revenue Requirement 7

In addition to the bundled service generation revenue requirement identified in Table II-3 above, 8

SCE’s estimated 2017 ERRA Forecast revenue requirement also includes delivery service amounts. As 9

shown on Line No. 22 in Table II-3 above, the increase of $112.7 million in SCE’s 2017 ERRA forecast 10

delivery service revenue requirement is due to an increase in the New System Generation (i.e., CAM-11

related) revenue requirement of $69.3 million, an increase of $17.5 million associated with SCE’s year-12

end 2016 NSGBA balance, a decrease of $0.001 million associated with spent nuclear fuel costs, an 13

increase of $0.6 million associated with Local Capacity Requirement (LCR) contracts4 and an increase 14

of $25.3 million associated with lower GHG allowance revenues to be returned to eligible customers. 15

As supported in Chapter IV, the increase in the New System Generation revenue requirement of $69.3 16

million is primarily driven by SCE holding the dispatch rights for all new generation contracts in 2017. 17

SCE discusses the background for recovering these costs through CAM in more detail in Chapter VIII. 18

The GHG allowance revenue forecast is discussed in Chapter VII.19

4 The 2017 LCR contracts include BTM – Energy Storage to be collected in distribution rates, and ES BTM

PLS, EE, and BTM Solar to be collected in the Public Purpose Programs Charge.

9

III. 1

SCE’S BUNDLED ENERGY FORECAST 2

This chapter presents a summary of SCE’s forecast of 2017 bundled customer energy load in its 3

service area and a brief description of the methodology used to produce the forecast. A brief discussion 4

of the major factors and assumptions that influence the forecast is also presented. 5

A. Retail Sales Forecast Summary 6

SCE developed its bundled service customer energy forecast for this Update Testimony based on 7

a retail customer sales forecast that was completed in February 2016. The sales forecast used in this 8

Update Testimony also reflects SCE’s most recent estimate of the total number of customers for the City 9

of Apple Valley’s proposed Community Choice Aggregation (CCA) program, known as Apple Valley 10

Choice Energy (AVCE).5 The retail sales forecast consists of sales to bundled service, DA, and CCA 11

customers measured at the customer meter. Total retail electricity sales in the SCE service area totaled 12

86,856 GWh in 2015. For 2016 and 2017, SCE is predicting sales of 85,155 GWh and 84,253 GWh, 13

respectively. The predicted decrease in sales between 2015 and 2016 is about negative 2.0 percent. The 14

primary drivers of the lower forecast are weather and the behind-the-meter solar photovoltaic (PV) 15

generation. Temperatures as measured by Cooling Degree Days were warmer than normal in 2015. 16

Therefore, the transition from an above-normal weather year to a normal weather year assumed in the 17

forecast has a downward impact on predicted sales in 2016 relative to recorded sales in 2015. In 18

addition, the significant increase (35% from 2015 to 2016) in SCE’s solar PV generation outlook also 19

contributed to the projected decline in sales from 2015 to 2016. 20

For the ERRA Forecast proceeding, the forecast of retail sales is converted to a forecast of 21

bundled service customer sales, and then converted to a forecast of bundled service customer energy at 22

the California Independent System Operator (CAISO) interface (i.e., distribution line losses are 23

accounted for). 24

5 SCE incorporated its estimate AVCE departing load based on notification from the City of Apple Valley of

the start of its CCA beginning on May 1, 2017.

10

Table III-4 summarizes the steps in converting retail sales to bundled service customer energy at 1

the CAISO interface. For 2017, the retail sales forecast of 84,253 GWh less of DA sales 2

and of CCA sales yields a forecast of bundled service customer sales of . The 3

bundled service customer sales forecast is then multiplied by one plus an average annual distribution 4

loss factor (expressed as a percentage). This procedure produces a bundled service customer energy 5

forecast at the CAISO interface of in 2017. It is the bundled service customer energy at 6

the CAISO interface for which SCE must obtain supply, and this is the forecast that SCE is submitting 7

for the purposes of this proceeding. 8

Table III-4 2017 Bundled Service Customer Load Forecast

(GWh)

B. Total Retail Sales Forecast by Customer Class 9

Table III-5 below presents SCE’s forecast of total electricity sales by customer class. The table 10

shows actual recorded sales in 2015 and forecast numbers for 2016 and 2017. The projected average 11

annual growth in total retail sales is negative 2.0 percent in 2016 and negative 3.0 percent in 2017 12

relative to recorded retail sales in 2015. 13

Line Description 2015 2016* 2017*1. Total Retail Sales (@meter) 86,856 85,155 84,2532. Direct Access Sales (@meter) 11,418 3. CCA Sales (@meter) 135 4. Bundled Service Sales (@meter) 75,3035. Bundled Energy at ISO 79,596

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

11

Table III-5 Annual Retail Sales by Customer Class

(GWh)

C. Customer Forecast 1

Table III-6 shows SCE’s forecast of total electricity customers. SCE expects the number of 2

customers to increase 0.6 percent in 2016 and 0.7 percent in 2017. 3

Table III-6 Year-End Customers by Customer Class

D. Annual and Monthly Bundled Energy 4

SCE had its first departing CCA load starting in May 2015 in the form of Lancaster Choice 5

Energy (LCE). CCA departing load will be larger in 2016 and 2017 than the partial-year departure of 6

load in 2015. SCE has incorporated its best estimate of the migrating CCA load in this application 7

based on information SCE has received including the start of Apple Valley Clean Energy (AVCE) in 8

May 2017.6 As a result, SCE’s bundled sales growth has been reduced relative to retail sales growth. 9

6 SCE assumed a 10% opt-out rate for non-municipal AVCE accounts. This is the same opt-rate agreed to

between SCE and Lancaster Clean Energy (LCE), the only CCA in the SCE service territory to-date.

Line Customer Class 2015 2016* 2017*1. Residential 30,093 29,100 28,5272. Commercial 42,396 41,039 41,5673. Industrial 7,623 8,054 8,0594. Other** 6,744 6,118 6,1005. Total Retail Sales 86,856 84,312 84,253

*Forecast

**Includes Public Authorities, Agriculture, and Street Lighting Sales

Line Customer Class 2015 2016 2017*

1. Residential 4,393,150 4,420,391 4,451,2532. Commercial 561,475 568,091 575,3243. Industrial 10,811 10,766 10,7184. Other** 67,894 67,728 67,6165. Total Customers 5,033,330 5,066,976 5,104,911

* Forecast** Includes Public Authorities, Agriculture, and Street Lighting Sales

12

Table III-7 presents actual recorded bundled monthly energy at CAISO in 2015 and the forecast 1

of monthly bundled energy at CAISO in 2016 and 2017. 2

Table III-7 Bundled Energy at CAISO

(GWh)

Line Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total1. 2015 5,982 5,365 6,189 5,860 5,998 7,104 7,701 8,468 8,007 7,098 5,673 6,150 79,5962. 2016* 5,960 5,512 5,750 5,704 5,976 7,2823. 2017*

*ForecastShaded Areas are Confidential per D.06-06-066 Matrix Section V.(C).

13

IV. 1

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

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 UOG, 6

which includes nuclear, natural gas, hydroelectric, fuel cells, and renewable generation resources; SCE’s 7

purchased power resources, including CHP and renewable resources, interutility contracts, and bilateral 8

contracts; and proxy7 (i.e., generic) costs from anticipated future solicitations and market purchases. 9

SCE’s 2017 forecast also includes executed contracts from SCE’s Local Capacity Requirements (LCR) 10

solicitations for the Western Los Angeles (LA) Basin and Moorpark regions, as approved in D.15-11-11

041 and proposed in A.14-11-016, respectively. 12

The increase in SCE’s 2017 fuel and purchased power cost forecast can be generally attributed to 13

three major factors. First, SCE expects higher fuel-related costs from its natural gas-fueled UOG and 14

tolling resources due to an increase in forecasted natural gas prices. Second, SCE expects higher open 15

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

SRAC payments due to higher forecast market prices. SCE used $58.27/kW-year as the proxy price to 17

meet Generic Capacity need as outlined in the 2015 “Estimated Cost of New Renewable and Fossil 18

Generation in California Final Staff Report” study issued by the CEC. 19

B. Energy Production Forecast Methodology 20

In this ERRA Forecast application, as in its past forecast applications, SCE forecasts energy 21

production from its portfolio primarily using the Ventyx Planning and Risk (PROSYM) software.8 The 22

Ventyx models are used to: (1) forecast the least-cost dispatch (LCD) of dispatchable resources in 23

7 The proxy capacity costs are further discussed in Section IV.E.

8 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.

14

SCE’s portfolio; (2) optimize hydro dispatch; and (3) perform Monte Carlo simulations of forced outage 1

rates of individual units. 2

The simulated dispatch is based on a forecast of power, gas, and GHG prices,9 physical 3

constraints of each generating unit, and contractual limitations. SCE’s forecast methodology 4

economically dispatches resources in a least-cost manner as directed by the Commission, rather than 5

force-dispatching resources to meet SCE’s forecast of bundled customer demand. Under the LCD 6

principle, a generating resource or contract is simulated to dispatch if its marginal operating cost is less 7

than the market price of power, while simultaneously observing all operating constraints.10 For a given 8

hour, the difference between the forecast bundled load and the total forecast economic dispatch of SCE’s 9

resource portfolio constitutes SCE’s projected open position for the hour. 10

SCE based its 2017 power price forecast on the forward power broker quotes for 2017 in effect 11

as of August 26, 2016. The 24-hour flat price as of August 26, 2016, was $33.98/MWh for 2017.11 SCE 12

derived its hourly price forecast by applying on-peak and off-peak hourly price profiles to the respective 13

monthly on-peak and off-peak forward quotes for 2017 in effect as of August 26, 2016,12 such that the 14

simple averages of the hourly on-peak and off-peak forecast prices for a particular month match the 15

forward on-peak and off-peak power prices for that month. SCE updated its existing MRTU-based 16

statistical models to generate hourly price profiles for the SP-15 and NP-15 zones.13 17

9 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.

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

11 SCE has contracts in NP-15. SCE used relevant prices to forecast the cost of those contracts.

12 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.

13 The statistical models incorporated historical MRTU data from the CAISO’s Integrated Forward Market (IFM).

15

SCE used the Intercontinental Exchange’s (ICE) settlement price of a 2017-vintage GHG 1

allowance as the basis for its 2017 GHG price forecast. The ICE settlement price as of August 26, 2016, 2

was $13.19 /MT for 2017. This price is assumed to be constant for any GHG emissions produced in 3

2017.14 Lastly, SCE based its daily natural gas price forecast on monthly NYMEX forward prices at the 4

SoCal Border in effect as of August 26, 2016 plus intrastate transportation charges from Southern 5

California Gas Company (SoCalGas), as applicable.15 The 12-month average NYMEX forward gas 6

price as of August 26, 2016 was $3.15 /MMBtu for 2017. Within a given month, SCE assumed that the 7

daily gas price forecast is equal to the monthly forward price. 8

C. Validation of SCE’s Energy Production Forecast 9

SCE follows a consistent process to forecast its energy production and costs for the subsequent 10

calendar year, supported by a robust internal validation process. SCE’s forecast process is discussed 11

below. 12

The first stage of SCE’s forecast process involves developing all forecast inputs. These inputs 13

include, but are not limited to, SCE’s forecast of power, gas, and GHG prices; production from UOG 14

resources (nuclear, hydro, gas, fuel cells and renewable facilities); CHP and renewable energy 15

production and costs; gas hedging costs; CAISO costs, etc. These inputs are developed and vetted by 16

various business groups or divisions responsible for each input and then submitted to senior managers in 17

SCE’s Energy Procurement & Management Organizational Unit for further review and approval. 18

Once approved, the forecast inputs are utilized in PROSYM, which is an industry-standard 19

production cost model capable of modeling various types of resources with differing constraints. SCE 20

uses PROSYM to forecast its LCD activities. Once the dispatch results are produced, SCE conducts a 21

14 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 will now be reviewed in this proceeding, and are discussed in further detail in Chapter VII.

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

16

thorough validation of the dispatch outcomes by resource.16 If necessary, SCE will rerun the previous 1

forecast steps if it believes more accurate dispatch results can be realized. 2

Once dispatch results are validated, all energy and cost forecasts are input into SCE’s ERRA 3

forecasting tool, an internally-developed, automated software program that aggregates the hourly energy 4

production and cost forecast data. The ERRA forecasting tool produces the ERRA forecast tables 5

included in the following section(s). Prior to inclusion in SCE’s ERRA Forecast filing, the forecast 6

tables are reviewed and approved by SCE’s senior management. 7

D. 2017 Energy and Cost Forecast Summary 8

Because this ERRA application is designed to forecast SCE’s energy-related costs that will 9

ultimately be used to establish retail generation rates in 2017, a single expected scenario forecast is 10

utilized. All production and residual open position forecasts provided in this section are reflected at the 11

CAISO system interface. To accomplish this, SCE reduced generation production forecasts by the 12

forecast transmission losses and grossed up the forecast retail load by the forecast distribution losses. 13

Table IV-8 summarizes the monthly forecast production from SCE’s portfolio and SCE’s open energy 14

positions. Table IV-9 summarizes the monthly forecast cost of SCE’s purchased power resources 15

accounted for in the ERRA balancing account. The remainder of this chapter provides detailed 16

descriptions of the resources and the underlying forecast assumptions.17

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

discrepancies to ensure that its results are reasonably justified.

17

Table IV-8 2017 Energy Forecast of the SCE Portfolio

(GWh) Confidential

1

18

Table IV-9 2017 Forecast of Fuel and Purchased Power Costs

($000) Confidential

19

Table IV-9 (Continued) 2017 Forecast of Fuel and Purchased Power Costs

($000) Confidential

20

E. 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

21

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 2017, SCE’s forecast of its UOG Hydro production, inclusive of pumpback operations, is 4

shown in Table IV-8. This forecast assumes a normal hydrological year for 2017, and also incorporates 5

SCE’s best estimate of upcoming major planned outages of Big Creek and Eastern Hydro units in 2017. 6

2. SCE Solar Photovoltaic Generation 7

SCE’s Solar Photovoltaic Program (SPVP) is a Commission-approved initiative to install, own, 8

and operate up to 91 MW Direct Current (DC) of utility-owned solar photovoltaic projects on 9

commercial rooftop space and ground-mounts in SCE’s service area.17 SCE estimates that in 2017 that 10

its UOG SPVP solar projects will provide a total of approximately 91 MW DC of capacity, primarily 11

(although not exclusively) located in San Bernardino County. These photovoltaic projects generally 12

provide energy during peak usage times. For 2017, SCE’s forecast of SPVP production, based on the 13

previous year’s project capacity factors, is shown in Table IV-10. 14

Table IV-10 2017 Forecast of SCE SPVP Production

(GWh)

17 The Commission originally approved a 500 MW SPVP program, with 250 MW of projects to be UOG and

250 MW to be owned by independent power producers. See D.09-06-049. SCE’s February 2011 Petition for Modification requested the program be modified to include, among other things, a reduction of both the UOG and the Independent Power Producer portions from 250 MW to 125 MW, and the petition was approved on February 16, 2012. On July 27, 2012, SCE filed a second Petition for Modification to further reduce the UOG portion of the SPVP from 125 MW to 91 MW, given that 18 MW of ground sites were at risk due to interconnection cost and schedule, and 16 MW of formerly-committed rooftops were no longer viable. SCE proposed that the 34 MW reduction from the UOG SPVP Program be transferred to the Renewable RAM Procurement Program. The Commission approved SCE’s petition in D.13-05-033, capping the UOG portion of SPVP at 91 MW. The independent power producer portion of the program maintains its 125 MW program goal.

Line Description Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Total1. SCE-Owned SPVP Production

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3. CHP and Renewables 1

a) Energy Forecast 2

For the 2017 Forecast Period, SCE expects to pay for from contracted CHP 3

(combined heat and power) and renewable projects. These energy deliveries from CHP and renewable 4

projects are effectively “must take” energy. 5

There will be 343 projects delivering energy having approximately 9,920 MW of contract 6

capacity allocated as follows: 7

• 1,318 MW of CHP 8

• 8,602 MW of renewable.19 9

In addition and not included in the above capacity is 148 MW of dispatch capacity contracted 10

through the CHP Program Settlement requests for offers. 11

In general, SCE uses the historical performance of each project to forecast monthly deliveries. 12

However, for new projects there is no historical performance data. As a result, forecast energy 13

deliveries are based on contractual expectations discounted by their expected probabilities of successful 14

development. 15

From September 2016 through 2017, SCE expects 59 projects with new contracts will begin 16

delivering energy. The number of new projects and their capacity by technology is as follows in Table 17

IV-11. 18

18 At the CAISO virtual network, SCE expects that includes dispatch energy from some CHP

contracts, electric line losses, the , and excludes 20 GWh allocated to serve Green Tariff customers as a part of the GTSR Program described in Section E.10. The net energy deliveries and payments after all the adjustments are listed in Table IV-8.

19 The contract capacity for a project that is undeveloped is weighted by the project’s expected success rate.

23

Table IV-11 New Projects

The energy and capacity of the new renewable projects under development are adjusted by their 1

probability of successful development. The amount of expected capacity from new renewable contracts 2

is approximately 1,240 MW. In Table IV-12, the average annual capacity factors aggregated for each of 3

the six technologies are listed. These average annual capacity factor for each project is based on 4

expected annual energy, contract capacity, and success rate for a new, undeveloped project. In addition, 5

the number of hours each project is expected to operate during the forecast period is taken into account 6

when calculating the energy-weighted annual capacity factors for each technology. 7

Table IV-12 Average Capacity Factors by Technology

The energy forecast also includes energy from projects whose contracts are scheduled to expire 8

during, or immediately before, the 2017 Forecast Period. SCE assumes that it will re-contract with 100 9

percent of expired CHP and non-RPS eligible renewable projects that are 20 MW or less. The total 10

amount of re-contracted energy for the forecast period is 74 GWH. 11

Line Technology NumberCapacity

MW1. Biomass 1 5 2. Cogeneration 1 31 3. Geothermal 1 225 4. Small Hydro 0 0 5. Solar 51 397 6. Wind 5 613 7. Total 59 1,271

Line TechnologyCapacity

Factor1. Biomass 76.8%2. Cogeneration 82.4%3. Geothermal 87.5%4. Small Hydro 40.1%5. Solar 29.4%6. Wind 27.0%

24

b) Payment Forecast 1

The forecasted payments to CHP and renewable projects delivering energy during 2017 are 2

approximately 20: The expected monthly energy, energy payments, and capacity payments 3

including re-contracted projects are shown in the Table IV-13. Total expected payments include $3.4 4

million for the re-contracted projects based on posted avoided costs of energy and capacity. 5

Table IV-13 Forecast of Energy and Payments

c) Energy and Capacity Prices 6

Energy and capacity prices for each of the CHP and renewable projects are based on the 7

individual project’s contract. Many of these projects have contract-specific energy prices and capacity 8

prices. A number of QF projects are paid at the posted avoided cost of energy price. For QF projects 9

with the Standard Offer Contract, the project’s capacity price is either the firm or as-available avoided 10

capacity price depending on the project’s specified dedicated capacity. For the older QF and new CHP 11

contracts, capacity prices are contract-specific. 12

Most QF projects are paid at the posted avoided cost of energy. The monthly posted energy 13

prices are calculated using the average 12-month forward SP15 prices, forward southern California 14

border gas prices, expected intrastate gas transportation rates, and the commission-approved O&M. The 15

monthly SRAC energy prices for the forecast period is included in Table IV-14 as follows: 16

20 SCE estimates a net revenue of from agreement, other out-of-state renewable

management costs, and CHP dispatch costs. See Table IV-9.

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

Energy GWh

Energy Payments $000Capacity Payments $000Total Payments $000

25

Table IV-14

Forecast of Posted Energy and Capacity Prices

4. Utility-Owned Natural Gas Facilities 1

a) SCE Peakers 2

(1) Background and Production 3

In the Assigned Commissioner’s Ruling (ACR) dated August 15, 2006, addressing electric 4

reliability needs in southern California (Rulemaking (R.) 05-12-013 and R.06-02-013), Commission 5

President Peevey ordered SCE to build up to 250 MW of black-start capable, dispatchable generation 6

capacity within its service territory. Four Peaker units with a total capacity of 196 MW began 7

operations in August 2007, and the fifth Peaker with a capacity of 49 MW began operation in November 8

2012. SCE included its forecast of UOG peaking unit generation in Table IV-8. 9

(2) Costs 10

Effective with the 2009 GRC decision, SCE transitioned to GRC-based rate recovery for all 11

capacity and non-fuel variable costs associated with its UOG Peakers. The natural gas cost forecast for 12

these peaking units is included in Table IV-9. 13

b) Mountainview Generating Station 14

On July 1, 2009, Mountainview Power Company, LLC (MVL), a wholly-owned subsidiary of 15

SCE, transferred ownership of the Mountainview Generating Station (Mountainview) to SCE. The 16

Commission approved the transfer as part of SCE’s 2009 GRC, in D.09-03-025. As a result, 17

Mountainview’s capital costs are no longer recovered as purchased power costs through the ERRA, but 18

instead are recovered in SCE’s authorized base generation revenue requirement and through base rates. 19

However, Mountainview fuel costs and availability and heat rate incentive payments continue to be 20

Avoided Cost Prices Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17

Energy ¢/kWhFirm 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 91.97As-Available Capacity $/kW-yea 53.16 53.16 53.16 53.16 53.16 53.16 53.16 53.16 53.16 53.16 53.16 53.16

26

recorded in the ERRA balancing account.21 SCE included its Mountainview generation forecast in 1

Table IV-8. The natural gas forecast for Mountainview is included in Table IV-9. 2

5. Interutility Contracts Production 3

SCE is a party to three22 major interutility contracts under which it is expected to purchase and/or 4

exchange capacity and associated energy for various periods from January 2017 to September 2017, 5

except for the City of Pasadena which has no expiration date. These interutility contracts were executed 6

prior to industry restructuring and contain complex terms and conditions that were designed to satisfy 7

the unique needs of SCE and each of the counterparties. The current contracts with Western Area Power 8

Administration (WAPA) and The Metropolitan Water District of Southern California (MWD) expire at 9

the end of September 2017. SCE has entered into a new contract with WAPA that has a term start date 10

of October 1, 2017, and expires on September 30, 2067. This new WAPA contract replaces the current 11

contract that expires on September 30, 2017. Table IV-15 summarizes these major interutility contracts. 12

Table IV-15 Non-Coincident Contract Capacity Quantities and

Expiration Dates for SCE’s Major Interutility Contracts

21 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.

22 Excluded from this total are SCE’s so-called “Fringe Service” agreements, which provide for small amounts of energy exchanges among neighboring utilities. These include two contracts with the Department of Defense for the Air Force that SCE presented to the Commission in Advice Letters 2686-E and 1777-E and contracts associated with retail tariffs.

27

The process of forecasting the level of energy deliveries and receipts for interutility contracts 1

with dispatchability (i.e., with WAPA and MWD) is an inherently complex task. SCE is forecasting net 2

interutility contract purchases of 196 GWh in 2017. 3

a) WAPA/MWD Agreements 4

SCE has a current annual (October through September) entitlement of 277.5 MW of contingent 5

capacity and 251 GWh of firm energy23 from the Boulder Canyon Project (Hoover), marketed by 6

WAPA, SCE has a new annual (October through September) entitlement of 280.245 MW of contingent 7

capacity and 238 GWh of firm energy from the Boulder Canyon Project (Hoover), marketed by WAPA 8

from October 1, 2007 through December 30, 2017. In addition, SCE’s exchange agreement with MWD 9

is projected to allow SCE to integrate MWD’s current annual (October through September) entitlement 10

at Hoover (247.5 MW of contingent capacity and 1,292 GWh of firm energy) with SCE’s own 11

entitlement from Hoover through September 30, 2017. The combination of SCE’s and MWD’s current 12

annual (October through September) entitlements to Hoover provides a total of 525 MW of contingent 13

capacity and 1,543 GWh of firm energy available to SCE. In addition, SCE receives MWD’s 14

entitlement to Parker Dam (60 MW of contingent capacity and 50% of the energy output). In return, 15

SCE provides MWD with (1) exchange energy, at no net cost to SCE, within a twelve-month contract 16

year, (2) 400 to 500 GWh per year of benefit energy during off-peak hours, and (3) interchange energy 17

within a month equal to MWD’s energy entitlement to Hoover and Parker. MWD must acquire 18

additional energy to meet its pumping requirements along the Colorado River Aqueduct that exceed the 19

energy that SCE provides. 20

Due to the lowering of the surface elevation of Lake Mead, which is the forebay to the Hoover 21

power plant, the amount of capacity and firm energy available to SCE and MWD will be reduced from 22

the amounts described in the previous paragraph. For the year 2017, the monthly capacity and firm 23

23 Firm energy is energy obligated from Hoover under the Hoover Power Plant Act. During periods when

Hoover is unable to provide energy in amounts equal to the firm energy, WAPA is obligated to provide any deficit, if requested by the purchaser, at a rate equal to WAPA’s cost to acquire.

28

energy available to SCE could range as low as 144 MW and 9 GWh, respectively.24 The forecast 1

amount of capacity and energy available to SCE out of Hoover is shown in Table IV-16. 2

Table IV-16 SCE Entitlement to Hoover Dam Electrical Output for Year 2017

Source: Bureau of Reclamation - CRSR 3/2016 Most Probable Inflow

b) Pasadena Corporation Grant Deed 3

On June 20, 1933, SCE and the City of Pasadena (Pasadena) entered into the Corporation Grant 4

Deed that transferred ownership of a hydroelectric powerhouse and accompanying parcels of land in 5

24 The Bureau of Reclamation, the owner and operator of Hoover Dam, anticipates a low reservoir elevation

through 2017. The reason for the low elevation is due to two major factors: (1) low precipitation since 2000 and (2) surplus water deliveries to California. Historically, California has taken more water from the Colorado River than it is entitled to. In recognition of California agreeing to reduce its excess take from the Colorado River, the Bureau of Reclamation has agreed to declare interim surplus water releases until California can find a substitute for the excess take.

29

Azusa Canyon to Pasadena. In accordance with the exchange provisions of the Corporation Grant Deed, 1

Pasadena delivers to SCE the entire electrical output of the Azusa Powerhouse (nameplate rated at 3 2

MW). Pasadena then has twelve months from the time of delivery to SCE to request that SCE return a 3

like amount of energy. SCE charges Pasadena for transmission service on the returned energy. If 4

Pasadena does not request the like amount of energy, or any portion thereof, to be returned within this 5

twelve-month period, Pasadena forfeits any subsequent right to the non-returned energy, and the energy 6

is purchased by SCE at a rate of $2.50/MWh. 7

c) Interutility Contract Resource Costs 8

During the 2017 Forecast Period, SCE will purchase or exchange capacity and associated energy 9

with (1) WAPA, (2) MWD, and (3) the City of Pasadena. Table IV-15 and Table IV-16 summarize the 10

estimated amounts of capacity and energy attributable to SCE’s major interutility agreements. 11

6. New System Generation Contracts 12

a) Production 13

Pursuant to D.07-09-044 and the Joint Party Proposal (JPP) adopted in that decision, SCE will 14

hold the dispatch rights for all New Gen contracts in 2017. SCE included its bundled customer share of 15

energy in the portfolio position forecast. 16

b) Costs 17

Consistent with the New Generation cost allocation decisions,25 SCE accounted for the forecast 18

of total net capacity costs for all the New Generation contracts that are expected to operate in 2017. The 19

total forecasted New Generation CAM costs, found in Table IV-9, reflect the total of the capacity costs 20

net of estimated expected revenue and production cost. SCE’s bundled service customers are 21

responsible for their assessed load-share responsibility. 22

25 In D.06-07-029, the Commission adopted a CAM that allows the benefits and costs of new generation to be

shared by 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.

30

7. 2013 Bilateral Contracts Production 1

a) Production 2

In July 2012, SCE and JPMorgan, on behalf of BE CA LLC, began bilateral negotiations. On 3

February 15, 2013, SCE filed Advice Letter 2853-E to seek CPUC approval of this bilaterally-negotiated 4

capacity and tolling agreement between SCE and BE CA LLC. This agreement was approved by the 5

CPUC on May 9, 2013. The projected total production in 2017 from this contract is shown in Table IV-6

8. 7

b) Costs 8

The four general cost categories for SCE’s 2013 Bilateral Contracts are (1) natural gas fuel costs; 9

(2) GHG costs; (3) variable charges; and (4) capacity payments. Table IV-9 provides the forecast 10

monthly costs for these contracts. 11

8. Generic and Bilateral Resource Adequacy (RA) Contracts 12

a) Production 13

For 2017, SCE estimates a system capacity need and a local area capacity need that varies by 14

month. Within this calculation, SCE forecasts the RA requirement it will need to meet in 2017. This 15

requirement, less RA contracts already procured, then determines SCE’s forecast remaining 2017 RA 16

need. SCE further assumed that RA contracts will be procured at a forecast generic cost to meet this 17

projected RA need for 2017.26 Table IV-9 provides the forecasted monthly capacity costs for both the 18

generic and bilateral RA contracts. 19

9. Local Capacity Requirements (LCR) Contracts 20

On September 12, 2013, SCE launched its LCR RFO to procure specified amounts of Preferred 21

Resources27, Energy Storage, and Gas Fired Generation (GFG) in the Western LA Basin and Moorpark 22

26 SCE applied the capacity price of $58.26/kW-year, based on the CEC’s “Estimated Cost of New Renewable

and Fossil Generation in California Final Staff Report” study.

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

31

local reliability areas to meet long-term local capacity requirements. SCE filed A.14-11-01228 and 1

A.14-11-01629 (LCR RFO Applications) for approval of all contracts entered into as a result of the 2

procurement. Pursuant to the Long Term Procurement Plan (LTPP) Track 1 and 4 decisions30 and as 3

proposed in the LCR RFO Applications, the net cost of the capacity31 is allocated to all benefitting 4

customers. 5

a) Production 6

The LCR contracts included in the forecast are all behind-the-meter resources, and as such, the 7

dispatch of these contracts reduces the overall bundled load requirement. 8

b) Costs 9

Because the LCR contracts scheduled to be on-line in 2017 are all behind-the-meter resources, 10

there are no associated energy costs or market revenues. The capacity costs are forecasted in the LCR 11

RFO Fixed Costs line item in Table IV-9. 12

10. Aliso Canyon Contracts 13

On October 25, 2015, the Commission was notified of a natural gas leak at the Aliso Canyon 14

storage facility located in Northern Los Angeles County. On January 6, 2016, Governor Brown 15

proclaimed a state of emergency at Aliso Canyon. The leak was sealed on February 17, 2016. 16

However, reliability concerns remain because of concerns about the sufficiency of natural gas resources 17

in the area served by Aliso Canyon. 18

On May 10, 2016, SCE sent a letter to the CPUC Executive Director informing him that SCE has 19

activated its Catastrophic Event Memorandum Account (CEMA) to record its costs incurred to mitigate 20

electric reliability issues that could occur in summer and winter months stemming from natural gas 21

28 Application for Approval of the Results of its 2013 LCR RFO for the Western LA Basin Sub-Area.

29 Application for Approval of the Results of its 2013 LCR RFO for the Moorpark Sub-Area.

30 D.13-02-015 (Track 1 decision) OP 15 and D.14-03-004 OP 13.

31 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 contract.

32

curtailments caused by the Moratorium on Injections into the Aliso Canyon Natural Gas Storage 1

Facility. Although the Commission had already directed SCE to spend monies on additional Demand 2

Response and Energy Savings Assistance (ESA) programs, as well as to accelerate the procurement of 3

power as the result of the Moratorium,32 SCE is using the Aliso Canyon CEMA to capture other 4

unforeseen costs incurred as a result of the Moratorium, including utility-owned energy storage projects. 5

On May 26, 2016, the Commission issued Resolution E-4791 authorizing expedited procurement 6

of storage resources to ensure electric reliability in the Los Angeles Basin due to limited operations of 7

the Aliso Canyon Gas Storage Facility. The Resolution specifically ordered SCE to hold competitive 8

solicitation for storage contracts to address electrical reliability risks in the Los Angeles Basin due to the 9

moratorium on injections into the Aliso Canyon Natural Gas Storage Facility. 10

Pursuant to Resolution E-4791, SCE launched the 2016 Aliso Canyon Energy Storage Request 11

for Offers ("2016 ACES RFO") and the 2016 Aliso Canyon Design, Build, and Transfer Request for 12

Proposals ("2016 DBT RFP"). As a result of that solicitation, SCE executed contracts to purchase and 13

build energy storage plants to manage system reliability. SCE has excluded all costs from any Utility 14

Owned Storage (UOS), including the DBT projects in this ERRA Forecast update. As ordered in 15

Resolution E-4791, within 90 days from the operational start date of any Utility Owned Storage projects, 16

including the DBT projects, SCE will file an application to address the reasonableness of these projects. 17

In that application, SCE will also propose the disposition of the CEMA-recorded amounts related to the 18

UOS and DBT projects and propose on-going cost recovery for these costs. 19

The capacity costs from all other third-party-owned procurement contracts are forecasted in the 20

Bilateral and Generic RA line item in Table IV-8. 21

32 Cost recovery for these activities is addressed in D.16-04-040 (ESA Program), D.16-06-029 (Demand

Response Programs) and in the Executive Director’s letter to Colin Cushnie dated letter dated May 6, 2016 (addressing accelerated procurement).

33

11. Green Tariff Shared Renewables (GTSR) Program 1

In D.15-01-051, the Commission approved with modifications SCE’s proposal to implement a 2

GTSR program to comply with Senate Bill 43. The GTSR program provides two options for customers: 3

a green tariff option (Green Tariff) that allows customers to allocate either 50% or 100% of their 4

electricity bill to renewable energy, and an enhanced community renewables (ECR) option that allows 5

customers to support renewable energy in their local community via agreements with third-party 6

renewable energy developers. In 2017, SCE has forecasted Green Tariff participation to be 19,804,897 7

kWh. Because SCE anticipates that new Green Tariff-specific projects will not have reached 8

commercial operation by 2017, SCE will initially use existing RPS resources that are eligible for the 9

Green Tariff program (Interim GTSR Pool) to serve Green Tariff customers.33 As described in D.15-01-10

051,34 SCE will use a cost-sharing mechanism to allocate the costs from the Interim GTSR Pool to 11

Green Tariff customers by estimating the amount of energy required to serve participating Green Tariff 12

customers and removing that “slice” of the Interim GTSR Pool from the bundled portfolio.35 SCE’s 13

RPS compliance requirements will be described in SCE’s RPS Procurement Plan filed in R.15-02-020. 14

To account for this program in SCE’s 2017 energy and cost forecast, SCE has included Green 15

Tariff line items in Table IV-8 and Table IV-9, and adjusted the CHP and Renewables energy and cost 16

forecast accordingly. The forecasted kWh required to serve Green Tariff customers are removed from 17

the CHP and Renewables energy and shown separately. Similarly, procurement costs for the Green 18

Tariff are estimated by multiplying the forecasted energy by the forecasted 2017 Green Rate Portfolio 19

Charge presented in Advice 3347-E,36 and are removed from the CHP and Renewables costs and 20

allocated directly to Green Tariff customers. 21

33 SCE will not begin serving ECR customers until ECR-specific projects reach commercial operation.

34 D.15-01-051 at page 40.

35 The remaining Interim GTSR Pool energy and costs will stay in the CHP and Renewables line items of Table IV-8 and Table IV-9.

36 Advice 3347-E at page Appendix B-3.

34

F. Other SCE Resources and Programs 1

1. Nuclear 2

There are no updates to this section. 3

2. Catalina Fuel Costs 4


3. Demand Response 6


G. CAISO Costs and Short-Term Market Activity 8

CAISO implemented a new market design, known as MRTU, on April 1, 2009. The new market 9

design includes elements such as the IFM, locational marginal pricing (LMP), and congestion revenue 10

rights (CRRs), and operates in a dramatically different manner than the previous zonal market. Due to 11

the complexity of the CAISO market, SCE separated the total costs from the CAISO market into (1) the 12

non-energy-related CAISO costs (CAISO costs); and (2) energy-related short-term market activity cost 13

(short-term market activity cost). SCE forecast the CAISO costs and the short-term market activity 14

costs separately, applying different forecasting methodologies as described below. 15

1. CAISO Costs 16

SCE’s 2017 ERRA forecast of CAISO costs is comprised of the net cost of: grid management 17

charges (GMC); FERC fees; CRR auction-related costs; ancillary services; CAISO uplift costs; Standard 18

Capacity Product (SCP) costs; and other non-energy-related CAISO costs. SCE considers these costs as 19

the non-energy-related CAISO costs as they are not sensitive to short-term energy market prices. 20

Therefore, SCE assumed that its 2017 CAISO costs, described above, would be equal to its historical 21

costs for the most recent 12-month period (i.e., from January 2015 through December 2015). SCE’s 22

2017 forecast CAISO costs are presented in Table IV-8. 23

2. Short-Term Market Activity Costs 24

SCE estimates its hourly open energy positions by netting its projected production from its 25

supply portfolio against its forecasted bundled load for each hour. SCE covers a major portion of its 26

35

open positions through the IFM,37 with bilateral transactions comprising a smaller portion. SCE also 1

covers a very small portion of its open positions in the CAISO hour-ahead and real-time (RT) markets. 2

For the purpose of this ERRA forecast application, SCE separated the forecast energy costs associated 3

with covering its open positions from the forecast CAISO costs discussed in the preceding section. All 4

forecast short-term market activity costs are reported separately in Table IV-9. 5

H. Gas Price Sensitivity 6

Pursuant to an agreement with ORA reached in A.10-08-001, SCE agreed to perform a two-7

standard-deviation gas price sensitivity analysis for ORA in support of its future ERRA forecasts for up 8

to five years. SCE performed the subject gas price sensitivity analysis and included the results in its 9

2011 ERRA Application (A.11-08-002) for the 2012 forecast calendar year.38 SCE conducted a similar 10

sensitivity analysis for this 2017 ERRA forecast. 11

Using this sensitivity analysis, SCE’s forecasted 2017 ERRA costs are projected to increase or 12

decrease by similar amounts, approximately , with an approximate $0.10/MMBtu upward or 13

downward gas price movement from the base case forecast SoCal Border gas price of $3.15/MMBtu for 14

the 2017 12-month strip. 15

As SCE has stated in previous ERRA forecast proceedings, the gas price sensitivity analysis can 16

only serve as a “rough check” on the updated ERRA forecasts and cannot be used to determine forecast 17

accuracy. One cannot simply apply the gas price sensitivity analysis to assess the accuracy of ERRA 18

forecast updates due to the multiple changes of the major input drivers (e.g., SCE’s portfolio changes) 19

that occur. 20

37 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 benefit from future CRR holdings.

38 SCE provided the detailed description of the methodology SCE applied to its gas price sensitivity analysis in A.11-08-022.

36

I. Direct GHG Costs 1

Direct GHG costs are shown separately in Table IV-9. Indirect GHG costs are embedded in the 2

purchased power contracts and utility-owned generation forecasts, and are identified and discussed in 3

further detail in Chapter VII. 4

J. Gas Hedging Costs 5

The total forecast cost to hedge the natural gas price risk for SCE’s UOG, purchased power 6

contracts, and QF contracts in 2017 is . This amount includes the mark-to-market (MTM) 7

gains/losses on existing hedges for 2017 gas risk as of August 26, 2016, expected transaction fees for 8

gas to be procured and hedged for 2017, and costs for expected future option premiums related to 2017 9

gas risk. The MTM for gas risk hedged for the 2017 forecast year as calculated by SCE Risk Operations 10

as of August 26, 2016 is . Additional forecasted costs are made up of: (1) forecasted 11

transaction fees of and (2) forecasted option premiums of . Each of these items is discussed further 12

below. 13

14

15

1. Transaction Fees 16

Transaction fees consist of clearing and exchange fees charged by the NYMEX and 17

Intercontinental Exchange (ICE), as well as brokerage fees from over-the-counter brokered financial 18

transactions. 19

2. Option Premiums 20

The price of an option is reflected as a cost in addition to the forecast cost of gas. The option 21

premium is the cost of removing the risk of increased gas prices. 22

K. Gas Transportation and Storage 23

For 2017, SCE expects to maintain firm transportation agreements with an estimated annual cost 24

of $1,200. This estimated cost is for reliable delivery of natural gas to both SCE-owned and -contracted 25

natural gas-fired resources. SCE does not expect to purchase storage on the Southern California Gas 26

Company (SoCalGas) system in 2017. Due to operational problems at SoCalGas’ Aliso Canyon storage 27

37

facility, SoCalGas does not have a clear picture of how much injection, withdrawal, and inventory 1

capacity it will be able to provide for this next storage year. As a result, until further notice SoCalGas 2

will not be offering sales of unbundled storage services to noncore customers. 3

1. Transportation 4

a) SoCalGas Transportation Agreement for Mountainview Generating Station 5

Effective February 1, 2016, SCE renewed a three-year contract with SoCalGas under Rate 6

Schedule GT-TLS, under a volumetric rate. There is no fixed component for the term of the contract. 7

Effective November 1, 2016, the contract term was changed to month-to month in accordance with the 8

July 14, 2016, CPUC approval of a curtailment procedures settlement agreement.39 9

b) SoCalGas Transportation Agreements for UCSB and CSUSB Fuel Cells 10

Effective March 1, 2016, SCE renewed its existing two-year contract with SoCalGas for 11

transportation capacity on the SoCalGas system to SCE’s fuel cell at U.C. Santa Barbara (UCSB). 12

Effective October 1, 2016, SCE renewed its existing contract for another two years with SoCalGas for 13

transportation to SCE’s fuel cell at California State University San Bernardino (CSUSB). Effective 14

November 1, 2016, both contract terms were changed to month-to-month in accordance with the July 14, 15

2016, CPUC approval of a curtailment procedures settlement agreement. Both agreements are under 16

Rate Schedule GT-NC. The fixed component is a $50 monthly customer charge for each agreement. 17

The total expected fixed cost for both agreements in 2017 is $1,200. 18

c) SoCalGas Transportation Agreements for SCE’s Peakers 19

Effective February 1, 2016, SCE permitted the auto-renewal of its existing three-year contract 20

with SoCalGas under Rate Schedule GT-TLS, a volumetric rate schedule, for an additional three-year 21

term for SCE’s Barre, Center, Grapeland, and Mira Loma Peakers. Effective June 1, 2015, SCE 22

39 On June 26, 2015, SoCalGas and San Diego Gas & Electric Company (SDG&E) filed A.15-06-020,

requesting authority to revise their curtailment procedures. On April 28, 2016, SoCalGas, SDG&E, and five other parties filed a Motion for Adoption of Curtailment Procedures Settlement Agreement. The Commission adopted D.16-07-008 on July 14, 2016, which granted the motion and adopted the Settlement Agreement in entirety and without modification.

38

renewed a three-year contract with SoCalGas under Rate Schedule GT-TLS, a volumetric rate, for 1

SCE’s McGrath Peaker. There is no fixed component associated with these transportation contracts. 2

Effective November 1, 2016, these contract terms were changed to month-to-month in 3

accordance with the July 14, 2016, CPUC approval of a curtailment procedures settlement agreement.4

39

V. 1

FINANCING COSTS 2

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

procurement during 2017 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.40 D.02-10-062, which established the ERRA, provides for recovery of fuel and credit costs, 8

including collateral costs.41 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.42 13

B. SCE’s Current Short-Term Financings 14

1. Credit Facilities 15

In May 2012, SCE replaced its five-year, $2.4 billion revolving credit line and its three-year 16

$500 million revolving credit line with a five-year, $2.75 billion revolving credit facility. Annually, 17

SCE extends its five-year, $2.75 billion revolving credit facility for an additional year, and expects to do 18

so in 2017. Currently, the new termination date of the facility is July 20, 2020. SCE plans to allocate 19

of the $2.75 billion revolver to procurement and balancing account undercollection 20

allocation in 2017. 21

40 D.93-01-027, Findings of Fact 23-26, 28, 30-32, Conclusion of Law 14, 47 CPUC 2d 682, 696-698.

41 D.02-10-062, Finding of Fact 23, mimeo, p. 71.

42 D.04-01-048, mimeo, p. 10, Ordering Paragraph 4, p. 23.

40

SCE’s five-year, $2.75 billion revolving credit facility can be utilized for short-term borrowing 1

requirements. The credit facility is a very flexible financial arrangement, as it provides support for both 2

SCE’s commercial paper program and for SCE’s collateral requirements. It can be used either to back 3

commercial paper and letters of credit that SCE may need in order to meet collateral requirements,43 or 4

SCE can borrow directly from the banks in the credit facility to meet its collateral or working capital 5

requirements. Furthermore, the credit facility carries only a marginal facility fee if no borrowings or 6

other usage is required. 7

SCE’s five-year, $2.75 billion revolving credit facility has the following features: 8

• July 2020 maturity; 9

• $2.75 billion credit limit; 10

• Arrangement and up-front costs and fees were initially incurred in May 2012. Similar costs 11

are incurred each year when the credit facility is extended. In July 2015, these costs included 12

up-front costs of $1,742,538 and legal fees of $98,603; 13

• $20,000 annual administrative fee; 14

• 10 basis point annual facility fee; 15

• 90 basis point participation fee on any outstanding letters of credit; 16

• LIBOR plus 90 basis points borrowing (loan) rate; and 17

• 20 basis point issuer fees on any letters of credit. 18

As described in the previous section, the revolver is sized to meet collateral requirements, 19

support balancing account undercollections, and provide SCE with short-term general purpose 20

borrowing capacity. A pro-rata share of the fixed cost of the revolver, corresponding to the capacity 21

required to support potential collateral requirements and balancing account undercollections financed by 22

the revolver, should be recovered through the ERRA. For 2017, SCE forecasts that of 23

the five-year revolver credit limit will be dedicated to providing capacity for collateral and supporting 24

balancing accounts. The facility fees associated with this $1.2375 billion amount should therefore be 25

43 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.

41

recorded in the ERRA balancing account. ERRA undercollections that are financed by the revolver 1

should be charged the appropriate interest rate on the undercollected balance pursuant to D.04-01-048. 2

SCE will recover the remaining fixed and commitment fees that are associated with general corporate 3

borrowing, along with general purpose interest costs, through base rates. 4

2. Collateral Requirements 5

Collateral requirements vary with changes in power prices and must be provided to 6

counterparties within a few days of a collateral call. As a result, the capacity for the maximum collateral 7

draw must be maintained at all times. Up to $1.2375 billion of SCE’s current credit facility is dedicated 8

to supporting its collateral requirements and balancing account undercollections. SCE currently 9

maintains approximately of available capacity for general purpose working capital 10

needs. For 2017, SCE projects that it will need approximately the same of available 11

capacity for general purpose working capital needs. 12

SCE’s collateral requirements will change if the Commission requires SCE to change its planned 13

procurement of reserves to meet resource adequacy requirements or requires SCE to sign additional 14

long-term contracts for other purposes. As a result, if SCE needs to increase its collateral capacity in 15

2017, it will recover any such increased costs through the ERRA balancing account. 16

SCE’s ability to finance its short-term liquidity and collateral requirements is contingent upon 17

retaining its investment grade credit rating and continued stable financial market conditions. As a result, 18

SCE may need to adjust its financing plans -- in order to achieve the most economic combination of 19

financial instruments to satisfy its overall short-term borrowing requirements -- if either its credit rating 20

falls below investment grade for an extended period of time or bank or capital market conditions vary 21

substantially. 22

3. Fixed Rate Bonds Supporting Fuel Inventories 23

In November 2014, SCE issued a $100 million fixed rate bond to support the minimum balance 24

of all fuel inventories projected in 2017. The $100 million fixed rate bond has a three-year term, 25

maturing in November 2017. The bond incurred $590,000 in issuance costs and expenses. SCE will 26

issue another $100 million fixed rate bond in November 2017 to replace the expired fixed rate bond. 27

42

The new issuance is expected to have the same issuance costs and expenses ($590,000) and term (three 1

years) as the current fixed rate bond. 2

4. Commercial Paper 3

In January 2011, SCE expanded its commercial paper program to $2.0 billion. In 2017, SCE’s 4

$2.0 billion commercial paper program will finance fuel inventories in excess of the amount covered by 5

the $100 million fixed rate bond.44 SCE’s 2017 forecast assumes that the market for A2/P1 commercial 6

paper will continue to remain stable, and that SCE will be able to utilize the commercial paper program 7

for its short-term borrowing needs. 8

SCE’s commercial paper program has the following features: 9

• $2 billion capacity; 10

• A2/P1/F1 rating; and 11

• 5 basis point annualized dealer fee on each issue. 12

5. Costs of Collateral Issuance 13

For most counterparties, SCE will provide collateral in the form of letters of credit rather than 14

having to borrow cash. The participation fees and additional fees associated with the letters of credit 15

issued under the revolver will be charged to the ERRA. 16

C. Additional Financial Instruments Supporting Collateral 17

As previously discussed, the revolvers may not be large enough to support all of SCE’s collateral 18

requirements during 2017. SCE’s current credit facility includes an option to increase its credit facility 19

limit from . If additional collateral support is required, SCE may seek to 20

increase the limits of its credit facility up to . In the event that SCE is unable to increase its 21

limits, SCE reserves the right to issue debt in the capital markets and hold these funds in trust to meet its 22

44 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.

43

collateral needs. To the extent that letters of credit are issued against the trust, the cost of the associated 1

bank fees, along with the cost of the debt, will also be recovered through the ERRA. 2

44

VI. 1

CARRYING COSTS 2

The purpose of this chapter is to set forth SCE’s 2017 estimated fuel inventory carrying costs for 3

nuclear,45 natural gas, propane, and diesel fuel inventories for inclusion in SCE’s 2017 ERRA revenue 4

requirement. In addition, this chapter sets forth SCE’s estimated 2017 GHG compliance carrying cost 5

and collateral carrying costs. Table VI-17 shows SCE’s estimated 2017 fuel inventory, GHG 6

compliance, and collateral carrying costs. 7

Table VI-17 Estimate of 2017 Carrrying 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 PVNGS, natural gas storage and imbalance, propane for the micro turbines on Catalina Island, 17

45 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, Propane2. Greenhouse Gas3. Collateral4. Total

45

and diesel fuel for the diesel generators on Catalina Island. The calculation of ERRA fuel inventory 1

carrying costs is based on forecast average monthly ERRA inventory balances (PVNGS nuclear in-core, 2

diesel, propane, and natural gas) and the carrying cost rate. The total 2017 ERRA fuel inventory balance 3

and associated financing costs are presented in Table VI-18. 4

Table VI-18 Estimated 2017 Fuel Inventory Carrying Costs

($000)

B. GHG Compliance Carrying Costs 5

This section discusses the forecast of GHG procurement compliance carrying costs in 2017. 6

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

procurement compliance costs.46 To forecast carrying costs, SCE uses the ERRA balancing account 8

interest rates to finance GHG procurement compliance carrying costs. The forecast 2017 GHG 9

procurement compliance carrying costs and applicable carrying cost rates are shown in the Table VI-19 10

below. 11

Table VI-19 Estimated 2017 GHG Compliance Carrying Costs

($000)

C. Collateral Carrying Costs 12

Table VI-20 sets forth the calculation of the carrying costs associated with SCE’s collateral 13

requirements necessary to procure power. This calculation is based on estimated average collateral 14

requirements and the projected terms of SCE’s revolvers, discussed in Chapter V.B. As SCE’s collateral 15

46 See D.14-10-033, Attachment B, Section G - GHG Accounting Procedures for Ratesetting Purposes

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 Total1. Average ERRA Fuel Inventory Value2. Inventory Carrying Cost

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 TotalAverage Total Inventory ValueInventory Carrying Cost

46

requirements change during 2017, SCE will use actual collateral requirements in determining its 1

carrying costs recorded in the ERRA. 2

Table VI-20 Estimated 2017 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 Total1. Average Collaterral Value2. Inventory Carrying Cost

47

VII. 1

UPDATED GHG FORECAST COSTS AND REVENUES AND RECONCILIATION 2

A. Overview 3

As directed by Administrative Law Judge (ALJ) Miles’ Ruling Modifying Procedural Schedule 4

issued on September 26, 2016, SCE filed supplemental testimony on GHG costs, revenues and 5

reconciliation issues on October 21, 2016. The update provided in SCE-5 included data recorded 6

through August 2016 as well as an update of the 2017 GHG cost forecast based on SCE’s Fall 2016 Fuel 7

& Purchased Power (F&PP) refresh. The Phase II Decision requires the use of recorded GHG costs and 8

revenues through the third quarter (i.e., September) of the current year. Therefore, this chapter presents 9

SCE’s updated (1) forecast of 2017 GHG allowance revenue (allowance revenue) and revenue returns to 10

eligible customers, (2) reconciliation of prior period “computed” GHG costs to true-up the GHG 11

allowance revenue returns, (3) forecast of 2017 administrative and customer outreach costs, and (4) 12

reconciliation of the prior period activity to account for deviations between actual revenues returned to 13

customers, and actual revenues received from the consignment of allowances to the auction, net of 14

actual administrative and customer outreach costs, including GHG costs and revenues recorded through 15

September 30, 2016 where applicable. 16

In summary, SCE proposes to return a total of $327.941 million in net available GHG allowance 17

revenues (Line 17 of Table VII-30) to eligible customers in 2017 based on the Commission-adopted 18

methodologies and utilizing GHG revenues and cap-and-trade costs, including administrative and 19

customer outreach costs, as proposed and supported in this Application. Based on SCE’s estimated 20

GHG allowance revenues available for return to eligible customers in 2017 as set forth in this testimony, 21

and after accounting for administrative and customer outreach costs, the Assembly Bill (AB) 693 set 22

aside for Multi Family Affordable Housing Solar Roofs Program, Emissions-Intensive Trade-Exposed 23

(EITE) revenue returns, and small business customer volumetric returns set to offset all or a portion of 24

GHG costs in rates, residential customers can expect a semi-annual, on-bill California Climate Credit of 25

$31.00 in 2017. 26

48

B. Updated 2017 GHG Emissions and Cap-and-Trade Costs 1

Table VII-21 provides SCE’s updated forecast of 2017 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-21 SCE’s Updated Forecast of 2017 GHG Emissions Volumes

(Metric Tons CO2e)

Table VII-22 provides SCE’s updated forecast of $310.176 million in 2017 GHG costs. The 4

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

in Table VII-21 above by SCE’s forecast 2017 allowance price of $13.19/mt, which is the 6

Intercontinental Exchange (ICE) settlement price as of August 26, 2016. 7

Table VII-22 SCE’s Updated Forecast of 2017 GHG Costs ($000)

Table VII-23 below presents the updated reconciliation of SCE’s forecast and actual prior period 8

GHG costs based on the methodology adopted in the Phase 2 Decision and provides the information for 9

Template D-2 “Annual GHG Emissions and Associated Costs” consistent with the Phase 2 Decision. 10

The prior period reconciliation reflects amounts recorded in 2015, including true-ups, and amounts 11

recorded through September 30, 2016 and estimated through December 31, 2016, consistent with the 12

methodology established in D.14-10-033. 13

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 Total1. Procurement Contracts2. SCE-Owned Generation3. Out of State Imports4. Market Purchases5. QF and Non QF Renewables6. Total 23,515,963

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 Total1. Procurement Contracts2. SCE-Owned Generation3. Out of State Imports4. Market Purchases5. QF and Non QF Renewables6. Total 310,176$

49

Table VII-23 Updated Annual GHG Emissions and Associated Costs

(Template D-2)

As shown in Template D-2 (Line 20), SCE’s forecast of 2017 GHG costs is $310.176 million. 1

As presented in Section E of this chapter, SCE will adjust the 2017 allowance revenue returns to eligible 2

small business customers that receive volumetric returns of allowance revenue to account for the $8.503 3

million deviation between prior period forecasts and recorded costs (Line 21 in Template D-2) for both 4

the 2016 estimated forecast variance of $1.342 million and the 2015 true-up for the forecast variance of 5

$7.161 million. 6

Table VII-24 below provides the updated information for Template C-1 “Weighted Average Cost 7

of Compliance Instruments Calculation” consistent with the Phase 2 Decision and provides the support 8

for the 2016 recorded weighted average cost of compliance instrument inventory $/mt and the average 9

price for financial toll settlement $/mt used in Template D-2 above. 10

Line Description

ForecastFinal (Recorded

through December 2013)

Forecast

Recorded (Used to Set 2015 GHG

Revenue Returns)

Final (Recorded through

December 2014)Forecast

Recorded (Used to Set 2016 GHG

Revenue Returns)

Final (Recorded through December

2015)Forecast

Recorded Through

September 2016Forecast Recorded

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)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 Purchases10. Qualifying Facility (QF) Contracts 3/

11. Subtotal

12. Total Emissions (MTCO2e) 18,540,635 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 23,515,963 -

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$ 13.19$ -

16. GHG Costs ($)17. Direct GHG Costs18. Direct GHG Costs - Tolling Agreements19. Indirect GHG Costs20. Current Year Total GHG Costs 271,064,082$ 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$ 310,175,547$ -$ 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)$ -$ 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$ 343,101,122$ 301,672,623$ -$

23. Forecast Variance ($) 6/ N/A 42,786,203$ N/A 8,649,035$ 283,594$ N/A (765,541)$ (7,160,705)$ N/A (1,342,220)$ N/A -

1/ Emissions for Tolling Agreement exposure that is settled using inventory. 2/ Electricity importers may claim certain adjustments for renewable energy purchases and exported electricity. These adjustments may reduce a compliance entity's cap-and-trade compliance obligation and are accounted for in Line 5. 3/ SCE considers GHG costs associated with QF Contracts as an indirect GHG emissions obligation, since the GHG costs are embedded in the energy costs for these resources. 4/ In order to calculate the costs associated with Financial Toll Agreement Settlement consistent with the methodology described in Section 4.2.1 of the Phase II Decision, the utilities use the Average Settlement Price for these resources, as calculated in Template C-1. 5/ Recorded Proxy GHG Price = Average CAISO Daily GHG Allowance Price Index . 6/ The Forecast Variance of ($0.482) million shown in Column 9 was previously reflected in the GHG cost true-up in the 2016 GHG revenue returns (D.15-12-033). The Forecast Variance of ($8.503) million shown in Column 11 is the incremental true-up amount for 2015 associated with using actual year-end data of ($7.161) million plus a forecast variance of ($1.342) million in 2016 (using September recorded).

2013 2015 20162014 2017

50

Table VII-24 Updated Weighted Average Cost of GHG Compliance Instruments Calculation

(Template C-1)

MonthTransaction Date

Transaction Type Quantity

Cost ($/mt)

Sales Price ($) Total Cost ($) WAC ($)

Dec-15 Carry forward 6,635,199 $78,936,658.97 True up Total after true up True up After True upJan-16 $0.00 Month Jan-16 Month Jan-16Jan-16 $0.00 End of Month WAC 2015 ICE forward priceJan-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Jan-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthJan-16 $0.00Feb-16 $0.00 Month Feb-16 Month Feb-16Feb-16 $0.00 End of Month WAC 2015 ICE forward priceFeb-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Feb-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthFeb-16 $0.00Mar-16 2,327,000 12.73 $29,622,710.00 Month Mar-16 Month Mar-16Mar-16 (1,313,560) $11.79 ($15,480,964.60) End of Month WAC 2015 ICE forward priceMar-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Mar-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthMar-16 $0.00Apr-16 200,000 $12.45 $2,490,000.00 Month Apr-16 Month Apr-16Apr-16 100,000 $12.52 $1,252,000.00 End of Month WAC 2016 ICE forward priceApr-16 200,000 $12.54 $2,508,000.00 Monthly Emissions (mt) Monthly Emissions (mt)Apr-16 150,000 $12.55 $1,882,500.00 Balancing Account Entry for Month Balancing Account Entry for MonthApr-16 $0.00May-16 456,000 12.41 $5,660,800.00 Month Month May-16May-16 (723,673) 12.20 ($8,826,482.50) End of Month WAC 2016 ICE forward priceMay-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)May-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthMay-16 $0.00Jun-16 325,000 12.55 $4,080,250.00 Month Jun-16 Month Jun-16Jun-16 (479,802) 11.99 ($5,753,310.66) End of Month WAC 2016 ICE forward priceJun-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Jun-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthJun-16 $0.00Jul-16 150,000 $12.63 $1,894,500.00 Month Jul-16 Month Jul-16Jul-16 50,000 $12.60 $630,000.00 End of Month WAC 2016 ICE forward priceJul-16 50,000 $12.70 $635,000.00 Monthly Emissions (mt) Monthly Emissions (mt)Jul-16 100,000 $12.69 $1,269,000.00 Balancing Account Entry for Month Balancing Account Entry for MonthJul-16 $0.00

Aug-16 1,191,000 $12.73 $15,161,430.00 Month Aug-16 Month Aug-16Aug-16 $0.00 End of Month WAC 2016 ICE forward priceAug-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Aug-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthAug-16 $0.00Sep-16 (744,724) $12.31 ($9,170,462.82) Month Month Sep-16Sep-16 $0.00 End of Month WAC 2016 ICE forward priceSep-16 $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Sep-16 $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthSep-16 $0.00Oct-16 - $0.00 Month Oct-16 Month Oct-16Oct-16 - $0.00 End of Month WAC 2016 ICE forward priceOct-16 - $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Oct-16 - $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthOct-16 - $0.00Nov-16 - $0.00 Month Month Nov-16Nov-16 - $0.00 End of Month WAC 2016 ICE forward priceNov-16 - $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Nov-16 - $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthNov-16 - $0.00Dec-16 $0.00 Month Dec-16 Month Dec-16Dec-16 - $0.00 End of Month WAC 2016 ICE forward priceDec-16 - $0.00 Monthly Emissions (mt) Monthly Emissions (mt)Dec-16 - $0.00 Balancing Account Entry for Month Balancing Account Entry for MonthDec-16

Sum of Monthly Balancing Account EntriesTotal Volume (mt)Total Amount ($)

Total Volume (mt)1/ Recorded through September 30, 2016 and estimated through December 31, 2016

Total physical and financial volume (mt)

Physical Settlement 1/ Financial Settlement 1/

51

C. Updated 2017 GHG-related Administrative and Customer Outreach Expenses 1

As detailed in Table VII-25 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 $260,023 in 2016 associated with administrative and internal customer outreach-related 4

costs. The recorded costs include the marketing costs associated with the April and October Climate 5

Credits and also include one-time IT billing system work of $44,129 to allow for the return of GHG 6

revenue to EITE customers. 7

For 2017, SCE forecasts $250,000 in SCE-internal customer outreach and education costs (which 8

are accounted for in the GHG Administrative Costs Memorandum Account (GHGACMA) primarily to 9

be spent on marketing, with the bulk associated with the April and October residential climate credit bill 10

inserts. SCE did not incur incremental Customer Call Center costs or Other - Marketing 11

Advertising/Agency costs related to the administration of the GHG climate credit in 2013 - 2015, does 12

not anticipate these costs in 2016, and is therefore removing these costs from the forecast of SCE’s 13

outreach and administrative expenses provided in the May 2016 testimony. On June 23, 2016, the 14

Commission issued D.16-06-041 clarifying the activities that the utilities should pursue in relation to 15

GHG Climate Credit outreach, and Ordering Paragraph 4 authorizes continued tracking of Customer 16

Call Center costs in memorandum accounts. To the extent SCE incurs incremental Customer Call 17

Center costs in the future, it will record the costs in the GHG Administrative Costs Memorandum 18

Account for future recovery. Finally, SCE does not expect to incur any further IT related costs. 19

52

Table VII-25 Updated Detail of Outreach and Administrative Expenses

(Template D-3)

1

D. Updated 2017 GHG Allowance Revenue Forecast 2

SCE forecasts each year’s GHG allowance revenue by multiplying the total volume of 3

allowances that the California Air Resources Board (CARB) has allocated to SCE for 2017 by a forecast 4

proxy price for these allowances. This is consistent with the Phase 2 Decision adopted methodology for 5

forecasting GHG allowance revenues. Based on SCE’s forecast GHG exposures and planned settlement 6

strategies in 2017, SCE has planned consignment volumes in the 2017 ARB auctions as shown below in 7

Table VII-26 below. 8

Table VII-26 SCE’s Updated 2017 Forecast Consignment in ARB Auctions

(Metric Tons CO2e)

Line Description Forecast Recorded Forecast Recorded Forecast Recorded Forecast Recorded 1/ Forecast Recorded 1. Utility Outreach Expenses ($)2. Customer Call Center -$ -$ -$ -$ 95,000$ -$ 95,000$ -$ -$ -$ 3. Marketing - SCE (incl. email, bill inserts) -$ -$ -$ 219,112$ 305,000$ 266,961$ 305,000$ 215,894$ 250,000$ -$ 4. Targetbase 225,000$ -$ -$ 227,045$ -$ -$ -$ -$ -$ -$ 5. Other - Marketing/Advertising Agency -$ -$ -$ -$ 162,500$ -$ 162,500$ -$ -$ -$ 6. Subtotal Outreach 225,000$ -$ -$ 446,157$ 562,500$ 266,961$ 562,500$ 215,894$ 250,000$ -$

7. Utility Administrative Expenses ($)8. IT-related expenses 850,000$ 326,828$ 50,000$ 140,437$ 30,000$ 146,300$ 30,000$ 44,129$ -$ -$

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$ 260,023$ 250,000$ -$

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$ 260,023$ 250,000$ -$

1/ Recorded through September 30, 2016 plus estimated through December 31, 2016.

20172015 201620142013

Line Auction Date Metric Tons CO2e1. February 20172. May 20173. August 20174. November 20175. Total 2017 Forecast 26,868,834

53

SCE’s updated forecast cap-and-trade auction revenues for 2017, calculated by multiplying the 1

expected consignment volumes by the proxy allowance price of $13.49/mt, based on a recent estimate of 2

the 2017 auction floor price,47 are shown below in Table VII-27. 3

Table VII-27 SCE’s Updated Forecast 2017 Allowance Revenue

($000)

SCE now has actual allowance revenue amounts from the February, May and August 2016 4

auctions. SCE’s updated forecast for the November 2016 auction is based on an updated forecast proxy 5

price of $12.89/mt, which is the ICE settlement price for vintage 2016 allowances with delivery in 6

December 2016. Table VII-28 below presents SCE’s updated 2016 GHG allowance revenue amounts. 7

Table VII-28 SCE’s Updated Recorded/Forecast 2016 Allowance Revenue

E. Updated 2017 Proposed GHG Revenue Returns 8

Table VII-29 below provides the information for Template D-1 “Annual Allowance Revenue 9

Receipts and Customer Returns” pursuant to the Phase 2 Decision, presents an accounting of the 10

47 In previous filings, and consistent with the Phase II Decision, SCE had applied an ICE settlement price for

December delivery of the corresponding calendar year. However, as of the August 26, 2016 trade date referenced in this testimony, the ICE settlement price for vintage 2017 December delivery allowances is $13.19/mt, which is below the minimum achievable auction price estimated for 2017.

Line Auction Date ($000)1. February 20172. May 20173. August 20174. November 20175. Total 2017 Forecast 362,461$

Line Auction Date ($000)1. February 2016 (Recorded)2. May 2016 (Recorded3. August 2016 (Recorded)4. November 2016 (Forecast)5. Total 2016 Fcst./Rcrd. 378,418$

54

recorded GHGRBA activity through September 30, 2016 and estimated activity for October 1 – 1

December 31, 2016. This reconciliation produces an “under-collection” (meaning that the 2016 forecast 2

revenue returns were overstated) due to the difference in forecast and actual auction allowance revenues 3

and allowance revenue returns. This undercollected amount of $30.397 million is subtracted from the 4

forecast year 2017 auction allowance revenues to determine the net revenue amount available for 5

disbursement to eligible customers in 2017. 6

D.14-12-037 requires the Commission’s Energy Division to perform the calculations necessary 7

to determine the specific amount of GHG allowance revenue that will be returned to individual EITE 8

entities. In September 2016, the Energy Division provided the Investor Owned Utilities (IOUs) the 9

amounts of the EITE credits to begin distributing to eligible EITE customers in October 2016.48 As 10

provided by the Energy Division, the amount of EITE credits for SCE to distribute associated with the 11

2013 – 2016 period, including interest, is $116.088 million. 12

Although GHG revenues have not been returned to EITE customers prior to October 2016, for 13

the purposes of setting the residential California Climate Credit in 2014, 2015 and 2016, SCE “reserved” 14

approximately $90 million of GHG revenues (i.e., held back and therefore did not return this “set aside” 15

amount in the residential California Climate Credit each year). As shown on Line 19 of Table VII-29, 16

SCE held back $30.008 million of GHG revenues in 2014, $34.673 million of GHG revenue in 2015 17

(includes 50% of 2013 GHG allowance revenues allocated to EITE customers in 2014 and 2015), and 18

$25.489 million of GHG revenue in 2016. To properly reflect the October 2016 EITE customer revenue 19

return of $116.088 million in the forecast of the 2017 residential California Climate Credit, SCE is 20

computing a “recorded 2016” EITE revenue return amount of $51.406 million; in this way, the total 21

2014 – 2016 “recorded” EITE revenue returns sum to the $116.088 million. SCE set the forecast 2017 22

EITE revenue return amount at the actual 2016 amount provided by the Energy Division. 23

48 From 2017-2020, EITE credits will be distributed annually in April.

55

Under Public Utilities Code (PUC) Section 748.5(c), the Commission may allocate up to 15% of 1

GHG allowance revenue for clean energy and energy efficiency (EE) projects that are not funded by 2

another source and already approved by the Commission. Assembly Bill (AB) 693 directs the 3

Commission to authorize the allocation of $100 million or 10% of available funds, whichever is less, for 4

the Multifamily Affordable Housing Solar Roofs Program, commencing July 1, 2016 and ending June 5

30, 2020. On March 18, 2016, in response to AB 693, ALJ Simon issued a ruling in R.14-07-002 6

directing the IOUs in their 2017 ERRA Forecast applications to take steps to estimate funds to be 7

allocated to the Multifamily Affordable Housing Solar Roofs Program, which will result in more 8

accurate calculations of proceeds distribution and minimize true-ups needed in future years. In 9

compliance with the ALJ ruling, SCE includes on Line 14 of Template D-1 an estimate of the AB 693 10

set aside amount of $3.037 million in 2016 (based on 5% of recorded allowance funds available for 11

clean energy and EE projects), and $5.040 million in 2017 (based on 10% of forecast funds available). 12

On July 8, 2016, ALJ Simon issued an additional ruling in R.14-07-002 seeking proposals and 13

comments on implementation of AB 693. For the purposes of setting the proposed 2017 residential 14

climate credit in this testimony, SCE interprets “ten percent of available funds” as ten percent of the 15

15% of allowance revenue to be allocated for clean energy and EE projects per PUC Section 748.5(c). 16

The Commission continues to implement AB 693 in R.14-07-002 and the mechanisms to account for the 17

funds to be used to implement the Multifamily Program are under review. If the Commission issues a 18

decision in R.14-07-002 with an outcome that differs from SCE’s AB 693 GHG revenue set aside 19

methodology used in this testimony before it issues a decision in the 2017 ERRA Forecast proceeding, 20

SCE will update the residential climate credit to account for this difference in the advice letter 21

implementing the 2017 ERRA Forecast decision.49 22

49 In a situation where a Commission decision in R.14-07-002 is issued after a 2017 ERRA Forecast decision is

issued, but before April 2017 (the first month of the 2017 semi-annual residential climate credit return to customers), SCE could also update the residential climate credit in a supplemental advice letter.

56

Based on the updated costs and revenues as set forth in this testimony, SCE’s proposed 2017 1

California Climate Credit is $31.00 (Line 24) to be distributed twice (April and October) in 2017 on 2

residential customer bills. 3

Table VII-29 Updated Annual Allowance Revenue Receipts and Customer Returns (Template D-1)

Table VII-30 below sets forth the support for the updated 2017 amounts of GHG revenue 4

allocated to small business customers (utilizing a 80% small business assistance factor in 2017 per D.13-5

12-002) on a volumetric return basis necessary to offset the amount of cap-and-trade costs in rates, 6

based on the updated cap-and-trade costs described in Chapter IV of this exhibit, and including a true-up 7

for the deviation between the forecast authorized prior period GHG costs (used to set the 2016 revenue 8

returns) and actual prior period GHG costs as supported in Section B of this chapter. The table below 9

also shows the forecast 2017 EITE revenue returns by rate class and customer group. 10

Line Description 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$ N/A 13.50$ 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

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$ -$ 5. Allowance Revenue (389,232,000)$ (384,638,000)$ (394,304,000)$ (368,730,000)$ (397,199,000)$ (390,808,663)$ (388,290,705)$ (378,417,730)$ (362,460,584)$ -$ 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)$ (4,392,750)$ (4,207,516)$ -$ 8. Subtotal Revenues (389,586,000)$ (384,888,000)$ (790,333,000)$ (761,558,600)$ (562,499,489)$ (563,533,494)$ (393,000,398)$ (405,189,043)$ (336,271,441)$ -$

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$ 260,023$ 250,000$ -$ 11. Franchise Fees and Uncollectibles -$ -$ -$ -$ 6,658 4,797 6,658 3,018 2,902 -$ 12. Interest -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 13. Subtotal Expenses 2,475,000$ -$ 50,000$ 2,313,000$ 599,158$ 418,058$ 599,158$ 263,041$ 252,902$ -$

14. AB693 Set Aside for Multi Family Solar Rooftops 2/ 3,036,945$ 5,040,278$

15. Net GHG Revenues ($) (Line 8 + Line 13 + Line 14) (387,111,000)$ (384,888,000)$ (790,283,000)$ (759,245,600)$ (561,900,331)$ (563,115,436)$ (392,401,240)$ (404,926,002)$ (327,941,316)$ -$ 16. GHG Revenues to be Distributed in Future Years ($) -$ -$ 194,616,000$ 192,319,000$ -$ -$ -$ -$ -$ -$

17.Net GHG Revenues Available for Customers in Forecast Year ($) (Line 15 + Line 16)

(387,111,000)$ (384,888,000)$ (595,667,000)$ (566,926,600)$ (561,900,331)$ (563,115,436)$ (392,401,240)$ (404,926,002)$ (327,941,316)$ -$

18. GHG Revenue Returned to Eligible Customers ($)19. EITE Customer Return 3/ -$ -$ 30,008,000$ 30,008,000$ 34,673,000$ 34,673,000$ 25,488,811$ 51,406,865$ 26,673,763$ -$ 20. Small Business Volumetric Return -$ -$ 30,550,000$ 40,961,000$ 39,496,000$ 52,964,531$ 24,446,633$ 30,442,413$ 21,725,095$ -$ 21. Residential Volumetric Return -$ -$ 178,425,000$ 169,887,000$ 225,679,000$ 194,522,279$ -$ 11,007,587$ -$ -$ 22. Subtotal EITE + Volumetric Returns -$ -$ 238,983,000$ 240,856,000$ 299,848,000$ 282,159,809$ 49,935,444$ 92,856,865$ 48,398,858$ -$

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

(0.5 x Line 17 + Line 22) / Line 23)

25.Revenue Distributed for the Climate Credit ($)(2 x Line 24 x Line 23)

-$ -$ 356,684,000$ 351,271,000$ 262,052,331$ 258,577,064$ 342,465,796$ 342,465,796$ 279,542,458$ -$

26. Revenue Balance ($) (in the GHGRBA) (Line 8 + Line 13 + Line 22 + 25) (387,111,000)$ (384,888,000)$ (194,616,000)$ (167,118,600)$ -$ (22,378,563)$ -$ 30,396,659$ (8,077,223)$ -$

1/ Recorded through September 30, 2016 plus estimated through December 31, 2016. Note that although the residential volumetric offset ended January 1, 2016, due to billing lag SCE has returned approximately $11 million through September 2016.

2/ Set aside from prior year to be returned at a later date. The 2016 set aside does not affect the Revenue Balance put into rates in 2016.3/ 2014 - 2016 EITE recorded amounts equal EITE returns expected to be paid out in October 2016 (source: Energy Divison).4/ The number of 2017 forecast households has been revised from the amount shown in SCE-1 to correct an inadvertant error.

20162014 2015 20172013

57

In 2017, SCE is proposing recovery of 2017 forecast cap-and-trade costs of $310.176 million, or 1

$313.776 million including FF&U, through all bundled service customers’ generation rates. For the 2

purposes of setting the small business volumetric credits in 2017, this total 2017 GHG cost amount of 3

$313.776 million is decreased to account for the $8.503 million ($8.602 million including FF&U) 4

deviation between the forecast authorized prior period GHG costs and actual prior period GHG 5

computed costs as presented in Template D-2. This results in an amount of $305.175 million to be used 6

to set the 2017 allowance revenue returns (i.e., volumetric ¢/kWh credits) to eligible small business 7

customers as shown in Table VII-30 below. 8

Table VII-30 Updated GHG Allowance Revenue Allocation by Class

Finally, Table VII-31 below provides the GHG costs and revenues by rate schedule, and Table 9

VII-32 provides the history of GHG revenue, costs and emissions intensity, as required by the Phase 2 10

Decision (Templates D-4 and D-5 of Attachment D of the Phase 2 Decision).11

(1) (2) (3) (4) (5) (6) (7) (9) (10) (11) (12)Rate Class GHG GHG 2017 Forecasted GHG GHG GHG EITE Non-EITE Non-EITE Total

By Bndl Cost Bndl Cost Bundled Unit Cost Bndl Cost w/true up Unit Cost Credit Credit Credit CreditCustomer Group Allocator ($000) MWh Rate ($000) w/true up ($000) System MWh ($000) ($000)

DomesticGroup Total 44.1% $0.00503 $0.00490 -$

Lighting-SM Med PowerGS-1 8.3% $0.00466 $0.00454 20,802$ GS-2 17.0% $0.00427 $0.00416 801$ TC-1 0.1% $0.00351 $0.00342TOU-GS-2 7.9% $0.00400 $0.00389 171$

Large PowerTOU-8-SEC 7.2% $0.00371 $0.00361 1,473$ TOU-8-PRI 4.1% $0.00344 $0.00335 2,918$ TOU-8-SUB 4.1% $0.00332 $0.00323 12,877$

Agricultural & PumpingTOU-PA-2 2.6% $0.00425 $0.00414 1,032$ TOU-PA-3 1.4% $0.00345 $0.00335 261$

Street & Area LightingLS-1 0.3% $0.00258 $0.00251 -$ LS-2 0.1% $0.00245 $0.00238LS-3 0.2% $0.00235 $0.00228DWL 0.0% $0.00253 $0.00246OL-1 0.0% $0.00255 $0.00248

StandbyTOU-8-SEC 0.2% $0.00381 $0.00371 72$ TOU-8-PRI 0.6% $0.00362 $0.00352 542$ TOU-8-SUB 1.8% $0.00317 $0.00308 7,452$

Total 100% 313,776$ 305,175$ 48,399$

58

Table VII-31 Updated GHG Costs and Revenues by Rate Schedule (Template D-4)

Table VII-32 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 0 0 (3,231,828)

Lighting-SM Med PowerGS-1 0 0 0 (624,198)GS-2 0 0 0 (638,671)TC-1 0 0 0 0TOU-GS-2 0 0 0 (19,389)

Large PowerTOU-8-SEC 0 0 0 (612,090)TOU-8-PRI 0 0 0 (1,431,674)TOU-8-SUB 0 0 0 (4,423,451)

Agricultural & PumpingTOU-PA-2 0 0 0 (21,313)TOU-PA-3 0 0 0 0

Street & Area LightingLS-1 0 0 0 0LS-2 0 0 0 0LS-3 0 0 0 0DWL 0 0 0 0OL-1 0 0 0 0

StandbyTOU-8-SEC 0 0 0 (63,729)TOU-8-PRI 0 0 0 (301,006)TOU-8-SUB 0 0 0 (1,291,283)

Total 313,776,128 (315,282,685) 0 0 (12,658,631)

Bundled Customers DA Customers

Recorded Recorded Recorded Forecast 1/ ForecastLine Description 2013 2014 2015 2016 2017

1. Total GHG Revenues (Net available for customers) 384,888,000$ 370,569,587$ 396,414,894$ 382,547,439$ 366,415,199$ 2. Total GHG Costs 313,850,286$ 293,315,968$ 304,588,374$ 343,583,069$ 310,175,547$

3. Emissions Intensity (MTCO2e/MWH) 0.33 0.33 0.331/ Recorded through September 2016 plus estimated through December 2016. 2016 emissions intensity is calculated using the sales forecast shown in SCE-1C, Table III-3, A.16-05-001.

59

VIII. 1

UPDATED 2017 FORECAST REVENUE REQUIREMENT AND RATEMAKING PROPOSAL 2

A. Introduction 3

The purpose of this chapter is to present SCE’s updated 2017 ERRA Forecast Proceeding 4

revenue requirement of $4.485 billion, as shown on Line No. 14 in Table VIII-33. This 2017 ERRA 5

Forecast revenue requirement includes 2017 GHG cap-and-trade costs and allowance revenues to be 6

returned to eligible customers in 2017 as supported in Chapter VII of this exhibit. 7

SCE will include the actual December 31, 2016 year-end (or November 30, 2016 recorded with 8

estimated December 31, 2016 activity) recorded balancing account balances in the ERRA revenue 9

Table VIII-33 Updated Estimate of 2017 ERRA Forecast Proceeding Revenue Requirement

($000)

Line Description Updated Estimate 2017 Revenue Requirement

1. Generation Service

2. Generation Fuel and Purchased Power Revenue Requirement 3,899,757$

3. Estimated December 31, 2016 ERRA Balance (94,007)$

4. Estimated Generator Refunds as of December 31, 2016 1/ 0$

5. GHG Cap-and-Trade Costs 313,776$

6. TOTAL ERRA PROCEEDING GENERATION SERVICE 4,119,526$

7. Delivery Service

8. New System Generation Revenue Requirement 659,168$

9. Estimated December 31, 2016 NSGBA Balance 8,896$

10. LCR Fuel and Purchased Power Revenue Requirement 21,252$

11. Spent Nuclear Fuel Storage Revenue Requirement 4,157$

12. GHG Allowance Revenues (327,941)$

13. TOTAL ERRA PROCEEDING DELIVERY SERVICE 365,531$

14. TOTAL ERRA PROCEEDING REVENUE REQUIREMENT 4,485,057$

1/ Estimated Generator Refunds are net of litigation costs.

60

requirement rate change and advice letter filed in compliance with a Commission decision in this 1

proceeding, if available. 2

B. Updated Estimate of 2017 ERRA-Related Generation Service Revenue Requirement 3

As shown above on Line No. 6 of Table VIII-33, SCE requests a 2017 ERRA generation service 4

revenue requirement of $4.120 billion. This revenue requirement is a consolidation of estimated fuel 5

and purchased power expenses, GHG cap-and-trade costs, the estimated December 31, 2016 balance in 6

the ERRA balancing account and estimated net50 generator refunds stemming from electricity 7

overcharges to SCE during the 2000-2001 California Energy Crisis. 8

1. Updated Estimate of 2017 Fuel and Purchased Power Revenue Requirement 9

As shown below on Line No. 33 in Table VIII-34, SCE’s requested 2017 fuel and purchased 10

power cost revenue requirement is $4.894 billion. This amount includes $59.975 million for franchise 11

fees and uncollectible (FF&U) expense and municipal surcharges.51 12

50 The forecast estimated net generator refunds are net of associated litigation costs, which are recorded in the

LCTA.

51 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 2017.

61

Table VIII-34 Updated Estimate of 2017 Fuel and Purchased Power Revenue Requirement

($000)

LineUpdated 2017

Revenue Requirement

1. Fuel2. Palo Verde - Nuclear3. Catalina - Diesel and Propane 5,779$ 4. Peakers - Gas5. Mountainview - Gas6. Fuel Inventory Carrying Cost7. Subtotal Fuel 178,706$

8. Purchased Power9. CHP and Renewables 10. Interutility11. 2013 Bilateral 12. Demand Response -$ 13. Bilateral & Generic RA14. ISO & S/T Market Activities15. Gas Hedging16. Gas Transportation and Storage17. Direct and Tolling Contract GHG Costs18. Green Rate Program 1,582$ 19. Collateral20. Subtotal Purchased Power 3,982,661$

21. Total - Generation Service 4,161,367$

22. FF&U 48,306$ 23. Municipal Surcharge (Franchise Fees) 3,861$ 24. Subtotal FF&U and Municipal Surcharge 52,167$

25. Total - Generation Service 4,213,534$

26. Delivery Service27. New Gen CAM Capacity28. CHP Settlement29. CAM-related Peakers

30. LCR Contracts31. FF&U

32. Total - Delivery Service 680,419$

33. TOTAL F&PP Revenue Requirement 4,893,953$

Component

62

a) Fuel Expense 1

As shown below on Line No. 11 in Table VIII-35, SCE has estimated its total 2017 fuel costs to 2

be $178.7 million. 3

Table VIII-35 Updated Estimate of 2017 Fuel Expense

($000)

The estimated 2017 PVNGS, Mountainview, Peakers, and Catalina fuel costs are supported in 4

Chapter IV. 5

The forecast of fuel inventory carrying costs associated with nuclear, natural gas, diesel, 6

propane, and GHG fuel inventories are supported in Chapter VI. 7

b) Purchased Power Expense 8

As shown below on Line No. 24 in Table VIII-36, SCE has estimated its total 2017 purchased 9

power costs to be $4.656 billion as supported in Chapter IV. Collateral costs, as shown on Line No. 23, 10

are supported in Chapter VI. 11

Line Amount

1. Nuclear - Palo Verde 38,684$

2. Gas3. Peakers4. Mountainview5. Gas Subtotal 132,837$

6. Catalina7. Diesel 5,623$ 8. Propane 156$ 9. Catalina Subtotal 5,779$

10. Fuel Inventory Carrying Cost

11. TOTAL 178,706$

Component

63

Table VIII-36 Updated Estimate of 2017 Purchased Power Expense

($000)

2. Updated December 31, 2016 ERRA Balance 1

As set forth on Line No. 17 of Table 1 in Appendix A and as shown on Line 3 of Table VIII-33, 2

SCE estimates that the balance in the ERRA balancing account as of December 31, 2016 will be an 3

over-collection of $92.9 million. In order to estimate the year-end ERRA balancing account balance, 4

SCE has used recorded amounts through October 31, 2016, plus a forecast of the activity SCE expects to 5

be recorded in the ERRA during November through December 2016. Including FF&U of $1.1 million, 6

the total estimated ERRA year-end over-collection is $94.0 million. SCE’s forecast year-end 2016 7

Line Amount

1. CHP & Renewables2. Capacity3. Energy4. Other5. Subtotal

6. 2013 Bilateral7. Capacity8. Energy9. Subtotal

10. LCR Contracts11. Capacity12. Energy13. Subtotal

14. Demand Response (Energy) -$

15. Bilateral & Generic RA

16. Interutility

17. Total ISO & S/T Market

18. Gas Hedging

19. Gas Transportation and Storage

20. New Gen CAM

21. Direct and Tolling Contract GHG Costs

22. Green Rate Program 1,582$

23. Collateral

24. TOTAL 4,655,973$

Component

64

ERRA over-collected balance primarily reflects the remaining amount to be amortized in rates related to 1

the two-year amortization of the year-end 2015 ERRA over-collected balance, as adopted in D.15-12-2

033. SCE will include the recorded operation of the ERRA balancing account for the 2016 Record 3

Period in its April 1, 2017 ERRA Review application. 4

3. Updated Energy Settlement Refunds and Litigation Costs 5

SCE is pursuing refunds from generators who overcharged SCE (and the other California IOUs) 6

for electricity during the 2000-2001 California Energy Crisis. As shown on Line No. 14 of Table 3 in 7

Appendix A, SCE is estimating a December 31, 2016 over-collected balance of $3.8 million (including 8

FF&U) in the ESMA. SCE will include the recorded operation of the ESMA for the 2016 Record 9

Period in its April 1, 2017 ERRA Review application. 10

Also included in Table 3 in Appendix A is the Litigation Costs Tracking Account (LCTA). In 11

accordance with Resolution E-3894, SCE shall maintain a LCTA within the ESMA to track: 1) 12

litigation costs that are “set-aside” in the FERC investigation settlement agreements; and 2) actual 13

litigation costs incurred by SCE. As shown on Line No. 32 of Table 3 in Appendix A, SCE is 14

estimating a December 31, 2016 under-collected balance of $3.8 million (including FF&U) in the 15

LCTA. SCE will include the recorded operation of the LCTA for the 2016 Record Period in its April 1, 16

2017 ERRA Review application. Combining the ESMA and LCTA estimated December 31, 2016 17

ending balances results in a net zero balance, as shown on Line 4 of Table VIII-33. 18

C. Updated 2017 ERRA-Related Delivery Service Revenue Requirement 19

As shown on Line No. 13 of Table VIII-33 above, SCE requests a 2017 ERRA Forecast 20

Proceeding delivery service revenue requirement of $366 million. This amount is a consolidation of 21

New System Generation costs, the estimated December 31, 2016 balance in the NSGBA, the estimated 22

spent nuclear fuel storage revenue requirement, the estimated LCR contracts revenue requirement, and 23

estimated GHG allowance revenues to be returned to eligible customers in 2017. GHG allowance 24

revenue returns are discussed in Chapter VII. 25

65

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

a) 2017 CAM Eligible Costs 2

Table VIII-37 below presents the contracts and UOG resources for which the Commission has 3

authorized CAM cost recovery (i.e., the net costs are to be recovered from all benefiting customers). 4

Table VIII-37 CAM Applicable Resources

Only the net capacity costs of these resources are recovered through the CAM (i.e., NSGBA). 5

As shown in Table VIII-38 below, the estimated value of the energy and ancillary services is subtracted 6

from the total estimated annual payment for each contract. The resulting amount constitutes the net 7

capacity costs.52 8

52 If a third party receives the use of the generation from a CAM-related resource through an energy auction or

otherwise, the payment for the energy and ancillary services (i.e., value) is recorded in the CAM. If SCE uses the generation of the resource to serve its bundled service customers’ load, only then will the value of the energy be recorded in the ERRA balancing account.

CAM All Customers: 1) pay their share of the net costs Authorization(i.e. total costs less value of energy and ancillary services)and, 2) receive RA capacity benefits

Peakers D.09-03-031Long Beach Generation, LLC D.07-01-041Blythe Energy, LLC D.08-05-028Wellhead Power Delano D.08-09-041Walnut Creek Energy, LLC D.08-09-041CPV Sentinel, LLC D.08-04-011/D.08-09-041El Segundo Energy Center, LLC D.08-09-041Qualifying Facilities and Combined Heat and Power: D.10-12-035

AB1613 CHP Feed in Tariff (CHP up to and including 20 MW)Qualifying Facility PURPA Contract (all CHP QFs up to and including 20 MW)CHP RFO and Bilateral Contracts

Aliso Canyon Energy Storage Resolution E-4791

66

Table VIII-38 Updated Estimate of 2017 CAM-Related Revenue Requirement

($000)

SCE is forecasting that the 2017 net capacity costs of the CAM-related PPA and CHP resources 1

will be $651.6 million. Including an allowance for FF&U, the total CAM-related revenue requirement 2

to be included in the New System Generation Rate Component is $659.2 million. 3

2. Updated December 31, 2016 NSGBA Balancing Account 4

As set forth on Line No. 17 of Table 2 in Appendix A, SCE estimates that the balance in the 5

NGSBA as of December 31, 2016 will be an under-collection of $8.8 million. In order to estimate the 6

year-end NSGBA balance, SCE has used recorded amounts through October 31, 2016, plus a forecast of 7

the activity SCE expects to be recorded in the NSGBA during November through December 2016. SCE 8

has included in the 2017 ERRA Forecast Proceeding delivery service revenue requirement the estimated 9

year-end over-collection in the NSGBA, plus $0.1 million for FF&U, for a total over-collection of $8.9 10

million. SCE will include the recorded operation of the NSGBA for the 2016 Record Period in its April 11

1, 2017 ERRA Review application. 12

3. Estimated 2017 Spent Nuclear Fuel Revenue Requirement 13

SCE requests that the Commission adopt a revenue requirement of $4.157 million associated 14

with spent nuclear fuel in its 2017 ERRA Forecast Proceeding delivery service revenue requirement, as 15

discussed in Chapter IV. These amounts are considered fuel-related costs and are not litigated 16

elsewhere. See Table VIII-39 below. 17

Line Description Total Est. Payment Less: Energy/AS Value CAM Net Cost

1. New Generation PPAs2. Combined Heat and Power3. Peakers4. Subtotal 651,604$ 5. FF&U 7,564$ 6. Total CAM-Related Purchased Power Revenue Requirement 659,168$

67

Table VIII-39 Estimated 2017 Spent Nuclear Fuel Revenue Requirement

($000)

Line Component Amount

1. Spent Nuclear Fuel (Interim Storage) 4,109$

2. FF&U 1/ 48$

3. TOTAL 4,157$ 1/ Currently authorized FF&U factor adopted in D.15-11-021.

68

IX. 1

DIRECT ACCESS, DEPARTING LOAD AND COMMUNITY CHOICE AGGREGATION 2

COST RESPONSIBILITY SURCHARGES 3

A. Introduction 4

The purpose of this chapter is to describe the methodology used to determine the 2017 Cost 5

Responsibility Surcharge (CRS)53 for Direct Access (DA), Departing Load (DL), and Community 6

Choice Aggregation (CCA) customers, collectively CRS. In this Update Testimony, SCE is providing 7

an updated CRS using the on- and off-peak daily trading prices, Renewable Green Benchmark, and 8

Capacity Adder, collectively known as the Market Price Benchmark (MPB), as calculated pursuant to 9

Resolution E-4475. Calculations for the Competition Transition Charge (CTC) and Power Charge 10

Indifference Adjustment (PCIA), which together constitute the CRS Indifference Charge, are included in 11

Appendix B.54 12

The CRS Indifference Charge, as established in D.02-11-022 and modified by D.03-07-030, 13

D.06-07-030, D.08-09-012, D.11-12-018, and Resolution E-4475, is designed to maintain bundled 14

customer indifference to departing load by ensuring that departing load customers remain responsible 15

for the stranded, or above-market, costs of generation resources procured on their behalf prior to their 16

departure from bundled customer service.55 To derive this “Indifference Amount,” SCE quantifies the 17

difference between the forecasted annual cost of the generation portfolio procured by SCE (“Total 18

Portfolio Cost”), and the forecasted market value of that portfolio (defined as the forecast output of the 19

53 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 tentatively approved in the November 1, 2016 Proposed Decision in R.15-02-012.

54 Based on informal feedback received from Departing Load customers at the October 27, 2016 PCIA Working Group meeting, SCE has included a new workpaper in Appendix B (“Total Indifference Amount Calculation”). This new workpaper is simply a different presentation of the data included in the “Unit Indifference Amount Calculation” workpaper format that was used in the May filing. For reference, SCE has also included the May filing data in this new workpaper format in its digital workpapers.

55 See Resolution E-4475 at p. 2.

69

resources in the generation portfolio multiplied by the total MPB). A positive Indifference Amount 1

indicates that the utility’s generation portfolio is “above-market” for that year, and similarly, a negative 2

Indifference Amount indicates that the utility’s generation portfolio is “below market” for that year. In 3

D.08-09-012, the Commission adopted the practice of vintaging the utility’s generation portfolio to 4

ensure that departing load customers be held responsible only for generation procured prior to the date 5

of their departure from bundled customer service. Accordingly, SCE has calculated Indifference 6

Amounts for each “vintage year” based on the generation resources that were committed in each 7

calendar year.56 8

The vintaged Indifference Amount is then used to set the Indifference Charge, which consists of 9

two separate rate components: the Ongoing CTC, which recovers the above-market costs of pre-10

restructuring resources such as eligible QF and interutility contracts and is the same for all vintages; and 11

the PCIA, which recovers the above-market costs of all non-CTC-eligible resources (i.e., UOG and 12

“New-World” generation resources as authorized in D.04-12-048) and varies by vintage based on the 13

generation resources included in that vintage. As described in D.06-07-030, the CTC and PCIA are set 14

such that the sum of the two equals the Indifference Charge. 15

Overall, vintaged Indifference Amounts (unadjusted amounts that do not reflect any one-time 16

credits) increased between 2% (2001 vintage) and 40% (2017 vintage) from the Indifference Amounts 17

estimated in the initial May filing.57 A comparison of the vintaged Total Portfolio Costs (which varied 18

less than 1%) and expected energy (which increased) included in the May and November filings reveals 19

that the increase in Indifference Amounts is wholly attributable to updates to the Market Price 20

Benchmark—specifically, updates to the Renewable Green Benchmark. As will be described in further 21

detail in Section C, the Renewable Green Premium included in the May filing was the value approved in 22

56 Pursuant to D.08-09-012, customers are assigned a vintage based on the date of their departure. If they

departed on or before June 30 of a given year, they are assigned to the prior year’s vintage. Alternatively, if they departed on or after July 1 of a given year, they are assigned that year’s vintage.

57 Additionally, SCE’s initial May filing estimates included a forecast of $25 million in DWR revenue return. Pursuant to the November 1, 2016 Proposed Decision in R.15-02-012, SCE has updated this forecast to $0.

70

D.15-12-033.58 Going forward, SCE will provide an estimated Renewable Green Premium in the May 1

filing based on its internal forecast of newly-delivering renewable resources. 2

B. Total Portfolio Costs 3

The Portfolio Costs for each vintage are determined based on the forecasted fixed and variable 4

costs, consistent with those outlined in Table IV-8, of generation resources forecasted to be used to serve 5

bundled service customers in 2017. Specifically, these costs include the base generation capital revenue 6

requirement, as set in the most recent General Rate Case (GRC) Phase 1, fuel costs, and direct GHG 7

costs for all eligible UOG;59 RPS-eligible contract costs; qualifying facility and non-CAM-eligible CHP 8

contract costs; all bilateral and RFO contract costs, including fuel costs and direct GHG costs; and any 9

applicable one-time refunds or adjustments.60 The Portfolio does not include any costs associated with 10

CAM and LCR-eligible resources, ISO-load related costs, Residual Net Position spot market purchases, 11

or balancing account balances. The Total Portfolio Costs and energy by vintage included in this update 12

are not materially different than those included in the initial May filing. 13

As described in Chapter IX of the Update Testimony in SCE’s 2016 ERRA Forecast 14

Application, half of the proceeds from the Nuclear Decommissioning Trust and NEIL Litigation 15

Settlement refunds received in 2015 will be included as a credit to the Total Portfolio Costs in the 2017 16

ERRA Indifference Charge calculation. Additionally, negative Indifference Amounts for the 2001-2008 17

vintages from the 2016 ERRA Forecast have been carried over and have been applied as a downward 18

58 Pursuant to Resolution E-4475, the Renewable Green Premium is updated by the Energy Division in early

November of each year using October Platts data and data provided by the IOUs in their annual October 1 advice letter filings.

59 Pursuant to D.03-07-032 and D.04-12-048, the ten-year limit on stranded cost recovery for SCE’s UOG Mountainview Generating Station has ended. As such, its costs, energy, and capacity have been removed from the Total Portfolio calculation.

60 Pursuant to D.15-10-037, the Total Portfolio Costs for all non-Lancaster vintages shall reflect an adjustment such that those customers receive 10.05% of the refunds and costs recorded in 2016 in the ESMA and LCTA, respectively. The 2014 vintage shall reflect an adjustment such that those customers receive their share of the refunds and costs recorded in 2016 in the ESMA and LCTA as though they were bundled service customers. SCE is currently forecasting to receive approximately $3M in Energy Crisis-related refunds and incur $3M in litigation costs. As such, no adjustment for Energy Crisis-related revenues has been included in the Indifference Amount calculation.

71

adjustment to their otherwise applicable 2017 ERRA Forecast Indifference Amount.61 The inclusion of 1

these one-time adjustments results in a Total Portfolio Cost, and consequently an Indifference Amount, 2

that is not necessarily representative of the above- or below-market costs of SCE’s 2017 ERRA 3

generation portfolio. For reference, the “unadjusted” Indifference Amount that would have been in 4

effect absent the various one-time credits and adjustments described here is also included in Appendix 5

B. 6

C. 2017 Market Price Benchmark 7

• The 2017 MPB shown in Appendix B was calculated based on the methodology described in 8

D.11-12-018 and Resolution E-4475. The following steps describe the proxy inputs and their 9

use in estimating the 2017 MPB:Collect daily forward price quotes from October 1 through 10

October 31, 2016, for 12 months of on-peak (6 days × 16 hours/day) and off-peak (6 days × 8 11

hours/day; 1 day × 24 hours/day) power delivered at SP-15 in 2017, as published in Platts-12

ICE Forward Curve – Electricity for SP-15. 13

• Average the daily quotes to get an annual on-peak forward price and an annual off-peak 14

forward price. 15

• Determine a weighted average forward power cost for 2017 by multiplying the average on-16

peak and off-peak price times the weighting factors adopted in Decision 11-12-018, which 17

are based on the most recent publicly available on- and off-peak bundled load weighting. 18

• Determine the weighted-average Renewable Green Benchmark based on the DOE Green 19

adder (weighted at 32%) and the average cost of newly-delivering renewable IOU projects 20

(“IOU Green Benchmark”) (weighted at 68%) as called for in D.11-12-018 and Resolution 21

E-4475, which is then applied to the renewable proportion of load in each vintage year. The 22

61 Similarly, pursuant to D.06-07-030 and D.07-05-005, any negative Indifference Amounts in this 2017 ERRA

Forecast will be tracked, by vintage, and will be applied to any future positive Indifference Amounts that may accrue in future years for those vintages, and the Indifference Charge for any vintages with a negative Indifference Amount will be set to zero.

72

DOE Green adder and IOU Green Benchmark are calculated by the Energy Division using 1

data submitted by the IOUs in their annual October 1 informational advice letters.62 2

• Add an RA/capacity cost to the forward price based on the net qualifying capacity value in 3

the portfolio, using the RA/capacity costs from SCE’s 2016 ERRA Forecast application 4

(A.15-05-007). 5

• Add a line loss factor. The line loss factor accounts for delivery losses from SP-15 to load 6

centers and is applied to the sum of the forward price cost, the weighted average green 7

benchmark results, and the capacity adder to arrive at the final MPB value for each vintage 8

portfolio. Decision 07-01-030 set the line loss factor at 5.3 percent for SCE, which remained 9

unchanged in Decision 11-12-018, as described in Resolution E-4475. 10

As shown below in Table IX-40, the 2017 MPB components have changed significantly from 11

those used to estimate the Indifference Amounts in SCE’s initial May filing. Specifically, the non-12

renewable, or “brown,” benchmark has increased by approximately 20% (over $5/MWh) over the 13

benchmark used in the May filing, which is consistent with the higher SP-15 forecast prices described in 14

Chapter IV. An increase in the “brown” benchmark (all other things being equal) reduces the PCIA. 15

Conversely, the renewable, or “green,” benchmark has decreased by approximately 20% (over 16

$10/MWh) since the May filing. A decrease in the “green” benchmark (all other things being equal) 17

increases the PCIA. In total, latter vintages with large proportions of renewable resources (e.g., 18

approximately 70% of the 2017 vintaged portfolio’s energy is renewable) have more significant PCIA 19

increases than early vintages with a lower proportion of renewable resources. 20

62 SCE Advice 3484-E, PG&E Advice 4927-E, and SDG&E Advice 2981-E.

73

Table IX-40 Comparison of Market Price Benchmarks

74

X. 1

ESTIMATED RATE INFORMATION 2

The average rates contained herein reflect estimated 2017 ERRA rate forecast by class and 3

functional rate component. The average rates are estimated by applying the current revenue requirement 4

in addition to 2017 ERRA-related revenue changes, as proposed in SCE’s 2017 ERRA Forecast Update 5

Testimony, to the forecasted sales by class. The rate information is limited to the proposed revenue 6

changes in the ERRA Update and does not reflect the consolidated revenue requirement changes SCE 7

expects to implement on January 1, 2017. 8

The estimated average rate levels also reflect the proposed revision to SCE’s rate setting 9

methodology to account for the difference between billed and delivered kWh arising from the 10

penetration of rooftop solar generation and the Net Energy Metering (NEM) rate structure. The 11

proposed revision is intended to result in a more accurate setting of retail rate levels by accounting for 12

the credit revenues under the current NEM ratemaking structure. 13

75

Table X-41 SCE 2017 ERRA Forecast Class Average Rates

1

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 0.01509 0.08844 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07514 (0.00023) 0.13587 0.07491 0.21078 3 D-CARE 0.01509 0.01047 0.01032 (0.00089) 0.01769 - 0.00034 0.07510 (0.00023) 0.05302 0.07488 0.12790 4 D-APS 0.01509 0.06779 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07479 (0.00023) 0.11522 0.07457 0.18979

DE 0.01509 0.02653 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07479 (0.00023) 0.07395 0.07456 0.14852 6 DM 0.01509 0.10947 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07524 (0.00023) 0.15690 0.07502 0.23192 7 DMS-1 0.01509 0.10018 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07524 (0.00023) 0.14761 0.07502 0.22262 8 DMS-2 0.01509 0.07924 0.01032 (0.00089) 0.01718 0.00539 0.00034 0.07523 (0.00023) 0.12666 0.07500 0.20167 9 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------10 Group Total 0.01509 0.06742 0.01032 (0.00089) 0.01731 0.00404 0.00034 0.07511 (0.00023) 0.11363 0.07488 0.18851 1112 Lighting-SM Med PoTer13 GS-1 0.01390 0.06624 0.00965 (0.00089) 0.00771 0.00539 0.00033 0.07435 (0.00022) 0.10233 0.07413 0.17646 14 GS-2 0.01391 0.06849 0.00906 (0.00089) 0.00717 0.00539 0.00033 0.06739 (0.00022) 0.10346 0.06717 0.17063 16 TC-1 0.00847 0.09988 0.00642 (0.00089) 0.00852 0.00539 0.00033 0.05680 (0.00022) 0.12812 0.05658 0.18470 17 TOU-GS 0.01283 0.05612 0.00865 (0.00089) 0.00656 0.00539 0.00033 0.06340 (0.00022) 0.08899 0.06318 0.15217 18 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------19 Group Total 0.01362 0.06490 0.00909 (0.00089) 0.00714 0.00539 0.00033 0.06795 (0.00022) 0.09958 0.06773 0.16730 2021 Large PoTer22 TOU-8-S 0.01140 0.04657 0.00788 (0.00089) 0.00608 0.00539 0.00033 0.05909 (0.00022) 0.07676 0.05886 0.13562 23 TOU-8-P 0.01039 0.04007 0.00708 (0.00089) 0.00553 0.00539 0.00033 0.05546 (0.00022) 0.06790 0.05524 0.12314 24 TOU-8-T 0.00861 0.00829 0.00584 (0.00089) 0.00391 0.00539 0.00033 0.05063 (0.00022) 0.03148 0.05041 0.08189 25 TOU-8-S-S 0.01179 0.04616 0.00771 (0.00089) 0.00602 0.00539 0.00033 0.05939 (0.00022) 0.07651 0.05917 0.13568 26 TOU-8-S-P 0.01111 0.04646 0.00676 (0.00089) 0.00591 0.00539 0.00033 0.05634 (0.00022) 0.07507 0.05612 0.13118 27 TOU-8-S-T 0.00822 0.00786 0.00511 (0.00089) 0.00397 0.00539 0.00033 0.04913 (0.00022) 0.02999 0.04891 0.07890 28 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------29 Group Total 0.01014 0.03165 0.00686 (0.00089) 0.00520 0.00539 0.00033 0.05504 (0.00022) 0.05868 0.05482 0.11350 3031 Agricultural & Pumping34 TOU-PA-2 0.00846 0.04942 0.00605 (0.00089) 0.00594 0.00539 0.00033 0.05963 (0.00022) 0.07471 0.05941 0.13412 35 TOU-PA-3 0.00854 0.04248 0.00548 (0.00089) 0.00504 0.00539 0.00033 0.05065 (0.00022) 0.06637 0.05043 0.11680 36 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------37 Group Total 0.00850 0.04656 0.00581 (0.00089) 0.00557 0.00539 0.00033 0.05593 (0.00022) 0.07127 0.05570 0.12697 3839 Street & Area Lighting40 LS-1 0.00692 0.20653 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03942 (0.00022) 0.23211 0.03920 0.27131 41 LS-2 0.00692 0.03993 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03925 (0.00022) 0.06551 0.03903 0.10454 42 LS-3 0.00692 0.01290 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03941 (0.00022) 0.03848 0.03919 0.07768 43 DTL 0.00692 0.10470 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03942 (0.00022) 0.13028 0.03920 0.16948 44 OL-1 0.00692 0.17452 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03942 (0.00022) 0.20010 0.03920 0.23930 45 ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ---------------- ----------------46 Group Total 0.00692 0.11332 0.00505 (0.00089) 0.00878 0.00539 0.00033 0.03939 (0.00022) 0.13890 0.03917 0.17807 474849 Total 5 Cust Gps. 0.01311 0.05809 0.00888 (0.00089) 0.01058 0.00487 0.00033 0.06701 (0.00022) 0.09498 0.06679 0.16177

76

Table X-42 Rate Schedule By Customer Group

Rate Schedule Current ProposedBy Generation Generation

Customer Group (¢ / kWh) (¢ / kWh)

DomesticNon-CARE 6.88 7.49D-CARE 6.88 7.49

---------- ----------Group Total 6.88 7.49

Lighting-SM Med PowerGS-1 6.99 7.41GS-2 6.31 6.72TC-1 5.35 5.66TOU-GS-3 5.90 6.32

---------- ----------Group Total 6.36 6.77

Large PowerTOU-8-SEC 5.52 5.89TOU-8-PRI 5.18 5.52TOU-8-SUB 4.75 5.04TOU-8-SEC-S 5.58 5.92TOU-8-PRI-S 5.29 5.61TOU-8-SUB-S 4.61 4.89

---------- ----------Group Total 5.15 5.48

Agricultural & PumpingTOU-AG 5.60 5.94TOU-PA-5 4.71 5.04

---------- ----------Group Total 5.23 5.57

Street & Area LightingLS-1 3.70 3.92LS-2 3.69 3.90LS-3 3.70 3.92DWL 3.70 3.92OL-1 3.70 3.92

---------- ----------Group Total 3.70 3.92

---------- ----------Grand Total 6.21 6.68

Appendix A

Estimated December 31, 2016 Balancing Account Balances

TABLE 1

Line Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Recorded Forecast Forecast Annual

No. Description January February March April May June July August September October November December Summary

1. Beginning Balance (439,063) (401,722) (370,783) (364,287) (292,589) (244,524) (251,506) (278,041) (255,001) (208,668) (179,300) (135,668) (439,063)

2. Transfer From Energy Set lements Memo Account (ESMA) (4,517) - - - - - - - - - - - (4,517)

3. Transfer from Litigation Costs Tracking Account (LCTA) 6,251 - - - - - - - - - - - 6,251

4. LCTA Interest 7 - - - - - - - - - - - 7

5. ERRA 2013-2014 SONGS Decommission Trust True Up - - - - - - (25) - - - - - (25)

6. ERRA 2013-2014 SONGS Decommission Trust True Up Interest - - - - - - (0) - - - - - (0)

7. Adjusted Beginning Balance (437,321) (401,722) (370,783) (364,287) (292,589) (244,524) (251,531) (278,041) (255,001) (208,668) (179,300) (135,668) (437,346)

8. ERRA Revenue (251,174) (214,491) (225,370) (218,745) (229,442) (449,952) (493,618) (499,067) (408,993) (250,404) (237,424) (249,234) (3,727,915)

9. Expenses:

10. Fuel 15,003 12,002 10,027 3,006 6,765 14,406 17,010 18,624 24,363 14,658 18,692 13,020 167,576

11. Purchased Power

12. Cogen and Renewables 129,311 112,020 123,346 175,975 168,639 276,952 248,613 276,674 265,024 97,071 122,082 121,824 2,080,054

13. Other Purchased Power 142,585 121,559 98,637 111,591 102,211 151,710 201,594 226,910 166,036 168,129 140,467 157,265 1,788,695

14. Subtotal Purchased Power 286,899 245,581 232,010 290,571 277,615 443,069 467,217 522,209 455,423 279,858 281,242 292,109 4,073,802

15. Monthly (Over)/Under Collection 35,725 31,090 6,640 71,827 48,173 (6,883) (26,401) 23,142 46,429 29,453 43,818 42,874 345,887

16. Total Interest: (126) (151) (144) (129) (107) (99) (108) (102) (97) (86) (186) (135) (1,469)

17. Total ERRA Ending Balance (401,722) (370,783) (364,287) (292,589) (244,524) (251,506) (278,041) (255,001) (208,668) (179,300) (135,668) (92,929) (92,929)

18. Interest Rates 0.36% 0.47% 0.47% 0.47% 0.48% 0.48% 0.49% 0.46% 0.50% 0.53% 1.42% 1.42%

Estimated ERRA Ending Balance (92,929)

FF&U (1,079)

Total ERRA w/ FF&U (94,007)

2016

Energy Resource Recovery Account

($000)

ERRAA-1

Appendix B

Indifference Rate Calculation

Rate GroupDWRBC (All

Vintages) 1/

CTC (For All

Vintages)2001 2004 2009 2010 2011 2012 2013 2014 2015 2016 2017

Domestic 0.00539 (0.00145) 0.00261 0.00317 0.00710 0.00798 0.00880 0.00889 0.00864 0.00683 0.00522 0.00522 0.00522

GS-1 0.00539 (0.00119) 0.00214 0.00260 0.00581 0.00653 0.00721 0.00727 0.00707 0.00559 0.00427 0.00427 0.00427

TC-1 0.00539 (0.00065) 0.00117 0.00142 0.00319 0.00358 0.00395 0.00399 0.00387 0.00307 0.00234 0.00234 0.00234

GS-2 0.00539 (0.00110) 0.00198 0.00241 0.00540 0.00607 0.00669 0.00675 0.00656 0.00519 0.00397 0.00397 0.00397

TOU-GS-3 0.00539 (0.00098) 0.00176 0.00214 0.00479 0.00539 0.00594 0.00600 0.00583 0.00461 0.00352 0.00352 0.00352

TOU-8-Sec 0.00539 (0.00085) 0.00154 0.00187 0.00418 0.00470 0.00518 0.00523 0.00508 0.00402 0.00307 0.00307 0.00307

TOU-8-Pri 0.00539 (0.00074) 0.00133 0.00161 0.00361 0.00406 0.00448 0.00452 0.00440 0.00348 0.00266 0.00266 0.00266

TOU-8-Sub 0.00539 (0.00063) 0.00114 0.00138 0.00310 0.00348 0.00384 0.00388 0.00377 0.00298 0.00228 0.00228 0.00228

Small AG 0.00539 (0.00100) 0.00179 0.00218 0.00488 0.00548 0.00604 0.00610 0.00593 0.00469 0.00358 0.00358 0.00358

Large AG 0.00539 (0.00074) 0.00134 0.00163 0.00365 0.00410 0.00452 0.00457 0.00444 0.00351 0.00268 0.00268 0.00268

St. Lighting 0.00539 - - - 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 - - -

Standby - Sec 0.00539 (0.00075) 0.00136 0.00165 0.00369 0.00415 0.00458 0.00462 0.00449 0.00355 0.00271 0.00271 0.00271

Standby - Pri 0.00539 (0.00101) 0.00181 0.00220 0.00493 0.00554 0.00611 0.00616 0.00599 0.00474 0.00362 0.00362 0.00362

Standby - Sub 0.00539 (0.00056) 0.00100 0.00122 0.00272 0.00306 0.00337 0.00341 0.00331 0.00262 0.00200 0.00200 0.00200

1/ 2016 DWR Bond Charge

2017 ERRA CRS Rates

B-1

Rate GroupDWRBC (All

Vintages) 1/

CTC (For All

Vintages)2001 2004 2009 2010 2011 2012 2013 2014 2015 2016 2017

Domestic 0.00539 (0.00145) 0.00866 0.00866 0.01186 0.01274 0.01356 0.01364 0.01339 0.01159 0.00997 0.00997 0.00997

GS-1 0.00539 (0.00119) 0.00708 0.00708 0.00971 0.01042 0.01110 0.01116 0.01096 0.00948 0.00816 0.00816 0.00816

TC-1 0.00539 (0.00065) 0.00388 0.00388 0.00532 0.00571 0.00608 0.00612 0.00601 0.00520 0.00447 0.00447 0.00447

GS-2 0.00539 (0.00110) 0.00658 0.00658 0.00901 0.00968 0.01030 0.01037 0.01018 0.00881 0.00758 0.00758 0.00758

TOU-GS-3 0.00539 (0.00098) 0.00584 0.00584 0.00800 0.00860 0.00915 0.00921 0.00904 0.00782 0.00673 0.00673 0.00673

TOU-8-Sec 0.00539 (0.00085) 0.00509 0.00509 0.00698 0.00749 0.00798 0.00802 0.00788 0.00682 0.00587 0.00587 0.00587

TOU-8-Pri 0.00539 (0.00074) 0.00440 0.00440 0.00603 0.00648 0.00690 0.00694 0.00681 0.00590 0.00508 0.00508 0.00508

TOU-8-Sub 0.00539 (0.00063) 0.00378 0.00378 0.00518 0.00556 0.00592 0.00595 0.00585 0.00506 0.00435 0.00435 0.00435

Small AG 0.00539 (0.00100) 0.00594 0.00594 0.00814 0.00875 0.00931 0.00937 0.00919 0.00796 0.00685 0.00685 0.00685

Large AG 0.00539 (0.00074) 0.00445 0.00445 0.00609 0.00655 0.00697 0.00701 0.00688 0.00596 0.00513 0.00513 0.00513

St. Lighting 0.00539 - 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001 0.00001

Standby - Sec 0.00539 (0.00075) 0.00450 0.00450 0.00617 0.00662 0.00705 0.00709 0.00696 0.00602 0.00519 0.00519 0.00519

Standby - Pri 0.00539 (0.00101) 0.00600 0.00600 0.00823 0.00884 0.00940 0.00946 0.00929 0.00804 0.00692 0.00692 0.00692

Standby - Sub 0.00539 (0.00056) 0.00332 0.00332 0.00454 0.00488 0.00520 0.00523 0.00513 0.00444 0.00382 0.00382 0.00382

1/ 2016 DWR Bond Charge

2017 ERRA CRS Rates (Unadjusted)

B-2

2017 ERRA Forecast ‐ Indifference Amount Calculation

Total Portfolio Calculation, 1 of 2

Pre‐2002 Pre‐2002

CTC‐Eligible CTC‐ineligible 2003 2004 2005 2006 2007 2008 2009 2010

1. CRS Eligible Portfolio Costs ($000)

2. UOG Capital and O&M (2015 GRC Phase 1) 575,498 63,275

3. SONGS Settlement Revenue Requirement 250,000

4. UOG Fuel

5. QF‐Eligible CHP

6. Renewable QF

7. Bilateral/RFO/IU

8. Common

9. FF&U

10. Total 402,874 891,191 ‐ ‐ 55,636 87,434 71,415 206,791 569,985 285,973

11. Vintaged Costs 402,874 1,294,065 1,294,065 1,294,065 1,349,700 1,437,134 1,508,550 1,715,341 2,285,326 2,571,299

12. GWhs ‐ Excludes CAM‐eligible

13. UOG


15. Renewable QF

16. Bilateral/RFO/IU

17. Subtotal

18. TOTAL Vintaged GWh @ Generator

19. Vintaged GWhs @ Meter 6,081 14,334 14,334 14,334 14,836 15,994 17,397 19,579 23,583 26,276

20. Net Qualifying Capacity ‐ Excludes CAM‐eligible

21. UOG ‐ 1,650 ‐ ‐ ‐ ‐ ‐ ‐ 17 ‐

22. QF‐Eligible CHP 207 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

23. Renewable QF 695 ‐ ‐ ‐ 6 83 ‐ 11 378 280

24. Bilateral/RFO/IU 309 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

25. Subtotal 1,211 1,650 ‐ ‐ 6 83 ‐ 11 396 280

26. TOTAL Vintaged GWh @ Generator 1,211 2,861 2,861 2,861 2,868 2,951 2,951 2,961 3,357 3,637

CRS‐Ineligible Portfolio Costs Energy

27. Green Rate

28. Mountainview

29. DR and LCR

30. < 1 Year Contracts (Generic RA, ISO, ST Purchases)

31. CAM Eligible Costs

Vinta

B-3

2017 ERRA Forecast ‐ Indifference Amount Calculation

Total Portfolio Calculation, 2 of 2

1. CRS Eligible Portfolio Costs ($000)

2. UOG Capital and O&M (2015 GRC Phase 1)

3. SONGS Settlement Revenue Requirement

4. UOG Fuel


6. Renewable QF

7. Bilateral/RFO/IU

8. Common

9. FF&U

10. Total

11. Vintaged Costs

12. GWhs ‐ Excludes CAM‐eligible

13. UOG


15. Renewable QF


17. Subtotal


19. Vintaged GWhs @ Meter

20. Net Qualifying Capacity ‐ Excludes CAM‐eligible

21. UOG


23. Renewable QF


25. Subtotal


CRS‐Ineligible Portfolio

27. Green Rate

28. Mountainview

29. DR and LCR

30. < 1 Year Contracts (Generic RA, ISO, ST Purchases)

31. CAM Eligible Costs

2011 2012 2013 2014 2015 2016 2017 Total

638,773

250,000

329,914 62,960 279,547 165,717 161,121 270 3,570,828

2,901,212 2,964,173 3,243,720 3,409,437 3,570,558 3,570,828 3,570,828

29,435 30,124 31,782 33,611 35,742 35,745 35,745

‐ ‐ ‐ ‐ ‐ ‐ ‐ 1,667

‐ ‐ ‐ ‐ ‐ ‐ ‐ 207

347 30 90 259 171 ‐ ‐ 2,350

‐ ‐ 3,366 1,911 1,329 ‐ ‐ 6,916

347 30 3,456 2,170 1,500 ‐ ‐ 11,141

3,984 4,014 7,470 9,640 11,141 11,141 11,141 11,141

age

B-4

2017 ERRA Forecast Indifference Amount Calculation

1 of 2

Line No. Description Equation Unit 2001 2003 2004 2005 2006 2007 2008

Cost of Portfolio

1. Total Portfolio Cost (Already Excludes ISO-Load Related Costs) $000 1,294,065 1,294,065 1,294,065 1,349,700 1,437,134 1,508,550 1,715,341

2. Supply At Customer Meter GWh 14,334 14,334 14,334 14,836 15,994 17,397 19,579

3. Renewable Supply at Customer Meter GWh 4,493 4,493 4,493 4,995 6,153 7,557 9,738

4. Renewable Percentage in Portfolio Line 3 / Line 2 % 31.35% 31.35% 31.35% 33.67% 38.47% 43.44% 49.74%

5. Portfolio Unit Cost Line 1 / Line 2 $/MWh $90.28 $90.28 $90.28 $90.98 $89.86 $86.71 $87.61

6. Market Value of Portfolio

7. Market Value of Brown Portfolio

8. Platt's On Peak Price $/MWh

9. Platt's Off Peak Price $/MWh

10. Brown MPB 63% x Line 8 + 27% x Line 9 $/MWh $28.18 $28.18 $28.18 $28.18 $28.18 $28.18 $28.18

11. Market Value of Brown Portfolio (1 - Line 4) x Line 10 $MWh $19.35 $19.35 $19.35 $18.69 $17.34 $15.94 $14.16

12. Market Value of Green Portfolio

13. IOU RPS Premium $/MWh $63.95 $63.95 $63.95 $63.95 $63.95 $63.95 $63.95

14. DOE Renewable Program $/MWh $16.55 $16.55 $16.55 $16.55 $16.55 $16.55 $16.55

15. Weighted Average Renewable Premium 68% x Line 13 + 32% x Line 14 $/MWh $48.78 $48.78 $48.78 $48.78 $48.78 $48.78 $48.78

16. Weighted Average Green Benchmark Line 15 + Line 10 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96

17. Market Value of Green Portfolio Line 16 x Line 4 $/MWh $24.13 $24.13 $24.13 $25.91 $29.61 $33.43 $38.28

18. Capacity Adder

19. Average Monthly NQC MW 2,861 2,861 2,861 2,868 2,951 2,951 2,961

20. Capacity Value per Resolution E-4475 $/MW $58.26 $58.26 $58.26 $58.26 $58.26 $58.26 $58.26

21. Market Value of Capacity Line 19 x Line 20 $ $166,695 $166,695 $166,695 $167,063 $171,914 $171,914 $172,529

22. Capacity Adder Line 21 / Line 2 $/MWh $11.63 $11.63 $11.63 $11.26 $10.75 $9.88 $8.81

23. Portfolio Unit Value Line 11 + Line 17 + Line 22 $/MWh 55.10$ 55.10$ 55.10$ 55.87$ 57.70$ 59.25$ 61.26$

24. Line Loss Adjusted Portfolio Value Line 23 x 1.053 $/MWh 58.02$ 58.02$ 58.02$ 58.83$ 60.76$ 62.39$ 64.50$

25. Indifference Amount

26. Portfolio Unit Cost Line 5 $/MWh 90.28$ 90.28$ 90.28$ 90.98$ 89.86$ 86.71$ 87.61$

27. Portfolio Unit Value Line 24 $/MWh 58.02$ 58.02$ 58.02$ 58.83$ 60.76$ 62.39$ 64.50$

28. Indifference Amount by Unit Line 26 - Line 27 $/MWh 32.26$ 32.26$ 32.26$ 32.15$ 29.10$ 24.32$ 23.11$

29. Total Unadjusted Indifference Amount Line 28 x Line 2 $000 462,388$ 462,388$ 462,388$ 476,963$ 465,437$ 423,119$ 452,459$

30. DWR Revenue Requirement $000 (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$

31. 1/2 Nuclear Decommissioning Trust $000 (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$

32. 1/2 NEIL Settlement $000 (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$

33. Carry Over Negative Indifference $000 (82,857)$ (46,922)$ (46,922)$ (32,922)$ (34,013)$ (160,157)$ (111,647)$

34. Adjusted Indifference Amounts Sum of Lines 29, 30, 31, 32, 33 $000 74,532$ 110,467$ 110,467$ 139,041$ 126,424$ (42,038)$ 35,812$

B-5

2017 ERRA Forecast Indifference Amount Calculation

2 of 2

Line No. Description

Cost of Portfolio

1. Total Portfolio Cost (Already Excludes ISO-Load Related C

2. Supply At Customer Meter

3. Renewable Supply at Customer Meter

4. Renewable Percentage in Portfolio

5. Portfolio Unit Cost

6. Market Value of Portfolio


8. Platt's On Peak Price

9. Platt's Off Peak Price

10. Brown MPB



13. IOU RPS Premium

14. DOE Renewable Program

15. Weighted Average Renewable Premium

16. Weighted Average Green Benchmark


18. Capacity Adder

19. Average Monthly NQC

20. Capacity Value per Resolution E-4475

21. Market Value of Capacity

22. Capacity Adder

23. Portfolio Unit Value

24. Line Loss Adjusted Portfolio Value

25. Indifference Amount

26. Portfolio Unit Cost

27. Portfolio Unit Value

28. Indifference Amount by Unit

29. Total Unadjusted Indifference Amount

30. DWR Revenue Requirement

31. 1/2 Nuclear Decommissioning Trust

32. 1/2 NEIL Settlement

33. Carry Over Negative Indifference

34. Adjusted Indifference Amounts

2009 2010 2011 2012 2013 2014 2015 2016 2017 CTC

2,285,326 2,571,299 2,901,212 2,964,173 3,243,720 3,409,437 3,570,558 3,570,828 3,570,828 402,874

23,583 26,276 29,435 30,124 31,782 33,611 35,742 35,745 35,745 6,427

13,857 16,436 19,595 20,283 20,951 22,781 24,911 24,915 24,915 4,493

58.76% 62.55% 66.57% 67.33% 65.92% 67.78% 69.70% 69.70% 69.70% 69.91%

$96.90 $97.86 $98.56 $98.40 $102.06 $101.44 $99.90 $99.90 $99.90 $62.68

$28.18 $28.18 $28.18 $28.18 $28.18 $28.18 $28.18 $28.18 $28.18 $28.18

$11.62 $10.55 $9.42 $9.21 $9.60 $9.08 $8.54 $8.54 $8.54 $8.48

$63.95 $63.95 $63.95 $63.95 $63.95 $63.95 $63.95 $63.95 $63.95 $63.95

$16.55 $16.55 $16.55 $16.55 $16.55 $16.55 $16.55 $16.55 $16.55 $16.55

$48.78 $48.78 $48.78 $48.78 $48.78 $48.78 $48.78 $48.78 $48.78 $48.78

$76.96 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96 $76.96

$45.22 $48.14 $51.23 $51.82 $50.74 $52.16 $53.64 $53.64 $53.64 $53.81

3,357 3,637 3,984 4,014 7,470 9,640 11,141 11,141 11,141 1,211

$58.26 $58.26 $58.26 $58.26 $58.26 $58.26 $58.26 $58.26 $58.26 $58.26

$195,590 $211,887 $232,085 $233,828 $435,193 $561,640 $649,051 $649,051 $649,051 $70,578

$8.29 $8.06 $7.88 $7.76 $13.69 $16.71 $18.16 $18.16 $18.16 $10.98

65.14$ 66.76$ 68.54$ 68.79$ 74.03$ 77.95$ 80.34$ 80.34$ 80.34$ 73.27$

68.59$ 70.30$ 72.17$ 72.43$ 77.96$ 82.08$ 84.60$ 84.60$ 84.60$ 77.15$

96.90$ 97.86$ 98.56$ 98.40$ 102.06$ 101.44$ 99.90$ 99.90$ 99.90$ 62.68$

68.59$ 70.30$ 72.17$ 72.43$ 77.96$ 82.08$ 84.60$ 84.60$ 84.60$ 77.15$

28.32$ 27.56$ 26.39$ 25.96$ 24.11$ 19.35$ 15.30$ 15.30$ 15.30$ (14.47)$

667,791$ 724,209$ 776,861$ 782,163$ 766,157$ 650,477$ 546,889$ 546,870$ 546,870$ (92,976)$

(25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$ (25,000)$

(130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$ (130,000)$

(150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$ (150,000)$

362,791$ 419,209$ 471,861$ 477,163$ 461,157$ 345,477$ 241,889$ 241,870$ 241,870$ (92,976)$

B-6

Line No. Description Source of Data Value

1. On Peak SP 15 Price ($/MWh)

2. Off Peak SP 15 Price ($/MWh)

3. On Peak Load Weight (%) 2016 ERRA Forecast 63%

4. Off Peak Load Weight (%) 2016 ERRA Forecast 27%

5. Load Weighted Average Price ($/MWh) March 2016 SCE‐Estimate Based on F&PP Plexos Model 28.18

6. IOU Green Benchmark ($/MWh) Energy Division ‐‐ 2016 ERRA Forecast (See Below) $92.13

7. IOU RPS Premium ($/MWh) Line 6 ‐ Line 5 $63.95

8. DOE Renewable Adder ($/MWh) Department of Energy Website ‐‐ 2016 ERRA Forecast $16.55

9. Weighted Average Renewable Premium ($/MWh) 68% x Line 7 + 32% x Line 8 $48.78

10. Weighted Average Renewable Benchmark ($/MWh) Line 9 + Line 5 $76.96

11. Capacity Benchmark ($/kW‐Year) 2015 CEC Report ‐‐ 2016 ERRA Forecast $58.26

12. Total IOU Renewable Resource Cost ($000) 2016 ERRA Forecast ‐ ED Info Received 10/31/15 $461,792

13. Total IOU Renewable Resource Capacity (MW) 2016 ERRA Forecast ‐ ED Info Received 10/31/15 298

14. Total IOU Renewable Resource Capacity Value ($000) Line 13 x $58.26 $17,361

15. Revised IOU Renewable Resource Cost Line 12 ‐ Line 14 $444,431

16. Total IOU Renewable Energy (MWh) 2016 ERRA Forecast ‐ ED Info Received 10/31/15 4,824,465

17. IOU Green Benchmark Line 15 x 1000 / Line 16 $95.72

2017 Indifference Calculation Inputs and Sources

IOU Green Benchmark

B-7

Appendix C

Declarations Regarding the Confidentiality of Certain Data

C- 1

DECLARATION OF SUSAN P. DIBERNARDO REGARDING THE CONFIDENTIALITY OF 1

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 responsibility for 5

preparing portions of testimony and workpapers in the 2017 Forecast of Operations Exhibit (SCE-1) in 6

SCE’s Energy Resource Recovery Account (ERRA) Application. I make this declaration in accordance 7

with 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 knowledge 9

of the facts and representations herein and, if called upon to testify, could and would do so, except for 10

those facts expressly stated to be based upon information and belief, and as to those matters, I believe 11

them to be true. 12

2. I have reviewed those sections of Exhibit No. SCE-1 that I am sponsoring. Listed below are 13

the data in those portions of Exhibit No. SCE-1 for which SCE is seeking confidential protection and the 14

categories on the Matrix of Allowed Confidential Treatment Investor Owned Utility (IOU) Data 15

(Matrix) to which these data correspond. Also set forth is an explanation of why the data cannot be 16

aggregated, redacted, summarized, masked or otherwise protected in a way that allows partial 17

disclosure: 18

Description of the Data

Location of the Data

Line or Table

Matrix Category

Reason why data cannot be aggregated, etc.

SCE’s 2016 Annual Fuel - Peakers and Mountainview

SCE-1, p. 63 p. 64

Table VIII-34, Table VIII-35

II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in this proceeding.

SCE’s 2016 Fuel Inventory

SCE-1, p. 63 p. 64


II.A.2. Component of Utility Electric

Further aggregation, redaction, summarization or omission of this data would compromise

C-2

Carrying Costs

Price Forecast Confidential for three years.

SCE’s ability to meet its burden of proof in this proceeding.

SCE’s 2016 Annual CHP and Renewable (QF) Costs

SCE-1, p. 63 p. 65


II. Cost forecast data-Electric. B. Generation Cost Forecasts. 3. QF Contracts


SCE’s 2016 Annual Forecast of Other Purchased Power Contract Costs -Existing Interutility Contracts

SCE-1, p. 63 p. 65

Table VIII-34 Table VIII-36

II. Cost forecast data-Electric. B. Generation Cost Forecasts. (4) Non-QF bilateral contracts.


SCE’s New Gen Auction

SCE-1, p. 63 p. 65


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG).


SCE’s 2013 Bilateral

SCE-1, p. 63 p. 65


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


C-3

SCE’s Annual Bilateral Contracts (Capacity) & Generic RA

SCE-1, p. 63, p. 65


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 2016 Forecast of Annual Gas Hedging Costs

SCE-1, p. 63, p. 65


I. Natural Gas Information. (A) Forecasts (gas) (4) Long-term fuel (gas) buying and hedging plans.


SCE’s 2016 Forecast of Gas Transportation and Storage Costs

SCE-1, p. 63 p. 65


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-1, p. 63 p. 65


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR


SCE’s Least Capacity Requirements (LCR) Contracts

SCE-1, p. 63 p. 65


II. Cost forecast data-Electric. B. Generation Cost Forecasts. (1) Utility Retained Generation (URG) OR IV. Resource


C-4

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 confidentiality 1

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-sensitive, 3

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 2016 Collateral Costs

SCE-1, p. 63 p. 65


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-1, p. 63, p. 65 & p. 68

Table VIII-34, Table VIII – 36, and Table VIII – 38 (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 be 5

aggregated, redacted, summarized, masked or otherwise protected in a manner that would allow partial 6

disclosure of the data while still protecting confidential information without jeopardizing SCE’s ability 7

to provide sufficient evidence to support SCE’s Application. 8

C-5

6. I am informed and believe and thereon allege that the data in the tables in paragraphs 2 and 4 1

above have never been made publicly available. 2

I declare under penalty of perjury under the laws of the State of California that the foregoing is 3

true and correct. 4

Executed on November 10, 2016, at Rosemead, California. 5

/s/ Susan P. DiBernardo 6

Susan P. DiBernardo 7

C- 6

DECLARATION OF EDUARDO MARTINEZ REGARDING THE CONFIDENTIALITY OF 1

CERTAIN DATA 2

I, Eduardo Martinez, declare and state: 3

1. I am the Senior Energy Markets Specialist in the Demand and Distributed Energy Resources 4

Group within the Planning Analysis & Forecasting Department at Southern California Edison (SCE). 5

As such, I had responsibility for preparing the bundled sales and energy forecasts for the Energy 6

Resource Recovery Account (ERRA) 2017 Forecast of Operations November Update testimony (SCE 7

6C). I make this declaration in accordance with the Administrative Law Judge’s Ruling Clarifying 8

Interim 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 to 10

testify, could and would do so, except for those facts expressly stated to be based upon information and 11

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 confidential 13

protection and the categories on the Matrix of Allowed Confidential Treatment Investor Owned Utility 14

(IOU) Data (Matrix) to which these data correspond. Also set forth is an explanation of why the data 15

cannot be aggregated, redacted, summarized, masked or otherwise protected in a way that allows partial 16

disclosure: 17



Line or Table

Matrix Category


SCE’s Direct Access Sales Forecast

Page 10 of “SCE’s Bundled Energy Forecast”

Grey shaded area on line 2

V) C) LSE Total Energy Forecast – Direct Access Customer (MWh)

SCE must provide full disclosure to support ERRA testimony.

SCE’s Bundled Sales Forecast

Page 10 of “SCE’s Bundled Energy Forecast”


V) C) LSE Total Energy Forecast – Bundled Customer (MWh)


SCE’s Bundled Energy Forecast

Page 10 of “SCE’s Bundled Energy


V) C) LSE Total Energy Forecast – Bundled Customer


C-7

Forecast” (MWh) SCE’s Bundled Service Customer Load Forecast

Page 10 of “SCE’s Bundled Energy Forecast”.

Grey shaded area in Table III-4



SCE’s Bundled Energy at CAISO

Page 10 of “SCE’s Bundled Energy Forecast”.

Grey shaded area in Table III-7




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 above 7

has never been made publicly available. 8


true and correct. 10

Executed on November 10, 2016 at Rosemead, California. 11

/s/ Eduardo Martinez 12

Eduardo Martinez 13

C-8

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 Pricing Design and Research 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 2017 Forecast of Operations Exhibit (SCE-1) in 6

SCE’s Energy Resource Recovery Account (ERRA) Application. I make this declaration in accordance 7

with 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 knowledge 9

of the facts and representations herein and, if called upon to testify, could and would do so, except for 10

those facts expressly stated to be based upon information and belief, and as to those matters, I believe 11

them to be true. 12

2. I have reviewed those sections of Exhibit No. SCE-1 that I am sponsoring. Listed below are 13

the data in those portions of Exhibit No. SCE-1 for which SCE is seeking confidential protection and the 14




disclosure: 18


specified in the matrix that pertain to the data listed in the table above. 20

4. Additionally, SCE is seeking confidential treatment of certain data that is market-sensitive, 21

but does not fall into a category on the matrix. That data is listed below: 22



Line or Table

Matrix Category Basis for Assertion of Confidentiality

Appendix B – Platts On- and Off-Peak Prices

Appendix B, Page 3

Lines 1-2 Off Matrix Proprietary data available only to those with Platts subscription.

Appendix B –Total

Appendix B, Pages 4-

Lines 4-9, 27-31

II. Cost Forecast Data—Electric.

Further aggregation, redaction, summarization

C-9

Portfolio Costs for Indifference Amount Calculation

6

(B) Generation Cost Forecasts.

or omission of this data would compromise SCE’s ability to meet its burden of proof in this proceeding.

Appendix B – Total Portfolio Supply for Indifference Amount Calculation

Appendix B, Pages 4-6

Lines 13-18, 27-31

IV. Resource Planning Information – Electric. (A,B,C,E,F)






6. I am informed and believe and thereon allege that the data in the tables in paragraphs 2 and 4 5

above have never been made publicly available. 6


true and correct. 8


/s/ Desiree Wong 10

Desiree Wong 11

C-10

DECLARATION OF STANLEY LIU REGARDING THE CONFIDENTIALITY OF CERTAIN 1

DATA 2

I, Stanley Liu, declare and state: 3

1. I am a financial gas trader in Trading and Energy Operations at Southern California Edison 4

(SCE). As such, I had responsibility for preparing Chapter IV, Section J of the testimony served in 5

support of SCE’s 2017 ERRA Forecast Update Testimony. I make this declaration in accordance with 6

the Administrative Law Judge’s Ruling Clarifying Interim Procedures for Complying with Decision 06-7

06-066, issued on August 22, 2006 in Rulemaking 05-06-040. I have personal knowledge of the facts 8

and representations herein and, if called upon to testify, could and would do so, except for those facts 9

expressly stated to be based upon information and belief, and as to those matters, I believe them to be 10

true. 11

2. I have reviewed Chapter IV, Section J. Listed below are the data and text in Chapter IV, 12

Section J for which SCE is seeking confidential protection and the categories on the Matrix of Allowed 13

Confidential Treatment Investor Owned Utility (IOU) Data (Matrix) to which these data correspond. 14

Also set forth is an explanation of why the data cannot be aggregated, redacted, summarized, masked or 15

otherwise protected in a way that allows partial disclosure: 16



Line or Table

Matrix Category


Forecast 2017 Gas Hedging Costs (total cost, breakdown of Hedging Cost components)

Chapter IV, Section J

Page 36 --- Line 24; Page 37 ---Lines 4-5

I.A.4 Long-term gas hedging plans of any granularity are confidential for three years.

Estimated Cost of 2017 Gas Hedging Options (methodology for calculation

Chapter IV, Section J

Page 37 --- Lines 6-8

I.A.4 Long-term gas hedging plans of any granularity are confidential for three years.

C-11

and plan for options purchase)










true and correct. 10


/s/ Stanley Liu 12

Stanley Liu 13

C-12

DECLARATION OF TODD CAMERON REGARDING THE CONFIDENTIALITY OF

CERTAIN DATA

I, TODD CAMERON, declare and state: 1

1. I am a Project Manager in the Regulatory Finance and Economics Group, Treasurer’s 2

Department at Southern California Edison Company (SCE). As such, I had responsibility for preparing 3

portions of the 2017 Forecast of Operations Exhibit (SCE-6) in SCE’s Energy Resource Recovery 4

Account (ERRA) Application. I make this declaration in accordance with the Administrative Law 5

Judge’s Ruling Clarifying Interim Procedures for Complying with Decision No. 06-06-066, issued on 6

August 22, 2006 in Rulemaking No. 05-06-040. I have personal knowledge of the facts and 7

representations herein and, if called upon to testify, I could and would do so, except for those facts 8

expressly stated to be based upon information and belief, and as to those matters, I believe them to be 9

true. 10

2. I have reviewed those portions of Exhibit No. SCE-6 that I am sponsoring. Listed below are 11

the data in those portions of Exhibit SCE-5 for which SCE is seeking confidential protection and the 12




disclosure: 16

Data Page Line or Table

Matrix Category


SCE’s estimate of the amount of its revolving credit line necessary to support procurement collateral requirements and general purpose working capital needs.

39

40

41

42

Line 20

Lines 23

Lines 10-11

Lines 20-21

II.A.2. Component of Utility Electric Price Forecast Confidential for three years

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in this proceeding. Public disclosure of this number will allow SCE’s competitors to calculate the confidential number above

C-13

SCE’s Estimate of 2017 Carrying Costs

44 Table VI-17

II.A.2. Component of Utility Electric Price Forecast Confidential for three years.


SCE’s Estimated 2017 Fuel Inventory Carrying Costs

45 Table VI-18 II.A.2. Component of Utility Electric Price Forecast Confidential for three years.


SCE’s Estimated 2017 GHG Compliance Carrying Costs



SCE’s Estimated 2017 Procurement Collateral Carrying Costs



3. SCE is complying with the limitations on confidentiality specified in the Matrix that pertain 1

to the data listed in the table above. 2


cannot be aggregated, redacted, summarized, masked or otherwise protected in a manner that would 4

allow partial disclosure of the data while still protecting confidential information. 5

C-14




true and correct. 4


/s/ Todd Cameron 6

TODD CAMERON 7

C-15

DECLARATION OF MATT SHERIFF REGARDING THE CONFIDENTIALITY OF

CERTAIN DATA

I, Matt Sheriff, declare and state: 1

1. I am a Senior Project Manager in the State Regulatory Operations organization at Southern 2

California Edison (SCE). As such, I had responsibility for preparing SCE-06C, Chapter VII, Updated 3

Testimony Energy Resource Recovery Account (ERRA) 2017 Forecast of Operations: Updated GHG 4

Forecast Costs and Revenues and Reconciliation. I make this declaration in accordance with 5

Commission Decisions (D.) 06-06-066 and D.08-04-023, issued in Rulemaking 05-06-040, and D.14-6

10-033 issued in Application 13-08-003. I have personal knowledge of the facts and representations 7

herein and, if called upon to testify, could and would do so, except for those facts expressly stated to be 8

based upon information and belief, and as to those matters, I believe them to be true. 9

2. I have reviewed SCE-06C, Chapter VII. Listed below are the data and text in those sections 10

for which SCE is seeking confidential protection and the categories on the Matrix of Allowed 11

Confidential Treatment Investor Owned Utility (IOU) Data (Matrix) and the GHG Confidential 12

Information Protocols appended to D.14-10-033 to which these data correspond. Also set forth is an 13

explanation of why the data cannot be aggregated, redacted, summarized, masked or otherwise protected 14

in a way that allows partial disclosure: 15

Data Pages Table & Lines Matrix Category

Limitations on Confidentiality Specified in the Matrix

SCE’s Updated Forecast of 2017 GHG Emissions Volumes

Section VII-B

Table VII-21, Lines 1 -6, except the annual total of all lines

GHG Confidentiality Protocol 1.d

Not to be released to the public

SCE’s Updated Forecast of 2017 GHG Costs

Section VII-B

Table VII-22, Lines 1 -6, except the annual total of all lines



Updated Annual GHG Emissions

Section VII-B

Table VII-23, Lines 1 - 11,

GHG Confidentiality

Not to be released to the

C-16

and Associated Costs

13 -14, and 17 - 19

Protocol 1.d public

Updated Weighted Average Cost of GHG Compliance Instruments Calculation

Section VII-B

Table VII-24, Inventory Balance, Total Quantity in Inventory and the WAC ($), for both Physical and Financial Settlement the WAC ($), Emissions (mt), and Balancing Account ($)



SCE’s Updated 2017 Forecast Consignment in ARB Auctions

Section VII-D

Table Section VII-B II-26, Lines 1-4



SCE’s Updated Forecast 2017 Allowance Revenue

Section VII-D

Table VII-27, Lines 1-4

GHG Confidentiality Protocol 1.b


SCE’s Updated Recorded/Forecast 2016 Allowance Revenue

Section VII-D

Table VII-28, Lines 1-4



Updated GHG Allowance Revenue Allocation by Class

Section VII-E

Table VII-30, Columns 3, 4, 6, 9-11, except for Column 3, 6, 9, 11 totals, and Column 5 and 7 totals only



Updated GHG Costs and Revenues by Rate Schedule

Section VII-E

Table VII-31, Forecast MWh Sales and Revenue, except for revenue totals



Updated History of GHG Revenues, Costs,

Section VII-E

Table VII-32, Line 3, 2016 and 2017



C-17

and Emissions Intensity

Forecast Emissions Intensity







I am informed and believe and thereon allege that the data in the tables in paragraph 2 above has never

been made publicly available.


true and correct. 8


/s/ Matt Sheriff Matt Sheriff

C-18

DECLARATION OF ERIC LAVIK REGARDING THE CONFIDENTIALITY OF CERTAIN

DATA

I, Eric Lavik, declare and state: 1

1. I am a Manager within the Portfolio Planning and Analysis group in the Power Supply 2

Department at Southern California Edison (SCE). As such, I had responsibility for preparing Chapter 3

IV, Section I of the testimony served in support of SCE’s November 10, 2016 ERRA Forecast 4

Application. I make this declaration in accordance with the Administrative Law Judge’s Ruling 5

Clarifying Interim Procedures for Complying with Decision 06-06-066, issued on August 22, 2006 in 6

Rulemaking 05-06-040. I have personal knowledge of the facts and representations herein and, if called 7

upon to testify, could and would do so, except for those facts expressly stated to be based upon 8

information and belief, and as to those matters, I believe them to be true. 9

2. I have reviewed Chapter IV, Sections A, B, C, D, E, G, H, and I; Chapter VII, Section B. 10

Listed below are the data and text in those sections for which SCE is seeking confidential protection and 11

the categories on the Matrix of Allowed Confidential Treatment Investor Owned Utility (IOU) Data 12



disclosure: 15


Line or Table

Matrix Category


SCE’s Monthly and Annual Load Energy Forecast

Table IV-8 V. Load Forecast Information and Data – Electric. (C) LSE Total Energy Forecast – Bundled Customers


SCE’s Monthly and Annual Nuclear

Table IV-8 and Table IV-10

IV. Resource Planning Information – Electric. (A)

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in

C-19

Energy Forecast SCE’s Monthly and Annual Coal Energy Forecast SCE’s Monthly and Annual Mountainview Energy Forecast SCE’s Monthly and Annual SPVP Energy Forecast SCE’s Monthly and Annual Peakers Energy Forecast Green Rate Program Forecast 2006-2007 New Gen Solicitation

Forecast of IOU Generation Resources:

this proceeding.

SCE’s Monthly and Annual Hydro Energy Forecast

Table IV-8 IV. Resource Planning Information – Electric. (C) Forecast of IOU Hydro Greater than 30 Megawatts (MW):


C-20

SCE’s Monthly and Annual CHP& Renewables Energy Forecast

Table IV-8 IV. Resource Planning Information – Electric. (B) Forecast of Qualifying Facility Generation:


SCE’s Monthly and Annual Inter-Utility Contracts Energy Forecast

Table IV-8 IV. Resource Planning Information – Electric. (E) Forecast of Pre-1/1/2003 (“Old-World”) Bilateral Contracts:


SCE’s Monthly and Annual 2013 Bilateral Contracts Energy Forecast Local Capacity Requirements (LCR) Contracts Generics

Table IV-8 Iv. Resource Planning Information – Electric. (F) Forecast of Post-1/1/2003 (“New-World”) Bilateral Contracts.


SCE’s Monthly and Annual Total SCE Portfolio Energy Forecast

Table IV-8 IV. Resource Planning Information – Electric. (A,B,C,E,F) For reasons stated above with respect to individual components of subtotal.


SCE’s Monthly and

Table IV-8 VI. Net Open Position

Further aggregation, redaction, summarization or omission of this

C-21

Annual Open Energy Position Forecasts

Information – Electric. (B) Utility Bundled Net Open (Long or Short) Position for Energy.

data would compromise SCE’s ability to meet its burden of proof in this proceeding.

SCE’s Monthly and Annual CHP & Renewable Contracts Costs Forecast

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (3) QF Contracts.


Inter-Utility Contracts Demand Response New Gen RFO Contracts 2013 Bilaterals LCR Contracts New Gen CAM Capacity

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (4) Non QF bilateral contracts.


SCE’s Monthly and Annual Other Purchase

Table IV-9 XI. Monthly Procurement Costs (Energy Resource

Further aggregation, redaction, summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in

C-22

Power Contracts Costs Forecasts SCE Peakers Mountainview

Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (1) Utility Retained Generation (URG).

this proceeding.

SCE’s Monthly and Annual Generic, Bilateral and Aliso Canyon RA Contracts

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (7) Non-contractual and spot purchases of energy and capacity. Aggregated net sale and purchase cost public.


SCE’s Monthly and Annual Total Gas Hedging Costs and MTM, including components (expected to

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings).


C-23

be under contract)

I. Natural Gas Information. (A) Forecasts (gas). (4) Long-term fuel (gas) buying and hedging plans.

SCE’s Monthly and Annual CAISO Costs and Short Term Market Activity Costs

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (7) Non-contractual and spot purchases of energy and capacity. Aggregated net sale and purchase cost public.


SCE’s Monthly and Annual Total ERRA Purchase Power Costs

Table IV-9 XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings). II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (3), (4), (7).


Direct and Table IV-9 II. Cost Further aggregation, redaction,

C-24

Tolling GHG Costs

Forecast Data – Electric.

summarization or omission of this data would compromise SCE’s ability to meet its burden of proof in this proceeding.

SCE Forecast of Generation from CHP and Renewable Contracts

Table IV-13

IV. Resource Planning Information – Electric. (B) Forecast of Qualifying Facility Generation


SCE Forecast of CHP and Renewable contract costs

Table IV-13

II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (3) Forecast of QF Contract Costs


SCE Forecast of Avoided Energy Cost

Table IV-14

II. Cost Forecast Data—Electric. (B) Generation Cost Forecasts. (3) Forecast of QF Contract Costs

Disclosure of SCE avoided cost estimate will allow parties to estimate QF contract costs.

SCE’s 2015 Total ERRA Purchased Power Cost Delta between Base Case and high (or low) gas price scenario

Chapter IV Gas Price Sensitivity

XI. Monthly Procurement Costs (Energy Resource Recovery Account [ERRA] Filings).






C-25






true and correct. 6


/s/Eric Lavik Eric Lavik

Updated Testimony Energy Resource Recovery...

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