r1502020-sce 2018 draft rps plan-public vol. 1...renewables portfolio standard program. rulemaking...

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Order Instituting Rulemaking to Continue Implementation and Administration, and Consider Further Development, of California Renewables Portfolio Standard Program.

Rulemaking 15-02-020

(Filed February 26, 2015)

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) 2018 DRAFT RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN

VOLUME 1

PUBLIC VERSION

JANET S. COMBS CAROL A. SCHMID-FRAZEE

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1337 Facsimile: (626) 302-1910 E-mail: [email protected]

Dated: August 20, 2018

1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Order Instituting Rulemaking to Continue Implementation and Administration, and Consider Further Development, of California Renewables Portfolio Standard Program.

Rulemaking 15-02-020

(Filed February 26, 2015)

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) 2018 DRAFT RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN

Pursuant to the Assigned Commissioner and Assigned Administrative Law Judge’s

Ruling Identifying Issues and Schedule of Review for 2018 Renewables Portfolio Standard

(“RPS”) Procurement Plans, dated June 21, 2018 (“ACR”) and the E-Mail Ruling Granting, in

Part, IOUs1 Request for an Extension of Time to Produce the 2018 RPS Procurement Plans,

dated July 9, 2018, Southern California Edison Company (“SCE”) respectfully submits its 2018

Draft Renewables Portfolio Standard (“RPS”) Procurement Plan (“2018 RPS Plan”) to the

California Public Utilities Commission (“Commission” or “CPUC”).2 On August 20, 2018, SCE

filed its 2018 RPS Plan in the R.18-07-003 docket. On August 28, 2018, Administrative Law

Judge (“ALJ”) Robert Mason, issued an E-Mail Ruling ordering SCE to refile its 2018 RPS Plan

in the R.15-02-020 docket. So, SCE now resubmits this 2018 RPS Plan in the R.15-02-020

docket.

1 The IOUs are the Investor Owned Utilities, which include Pacific Gas and Electric Company

(“PG&E”), Southern California Edison Company (“SCE”), and San Diego Gas & Electric Company (“SDG&E”).

2 SCE is concurrently filing a Motion for Leave to File its Confidential 2018 Renewables Portfolio Standard Procurement Plan Under Seal.

2

SCE’s 2018 RPS Plan consists of a Written Plan and Appendices thereto.3

The Appendices include:

Confidential/Public Appendix A – Redline of 2017 Written Plan

Confidential/Public Appendix B – Project Development Status Update

Confidential/Public Appendix C.1 – Physical Renewable Net Short Calculations

Based on CPUC Assumptions, with GAM


Based on SCE Assumptions, with GAM

Confidential Appendix C.3 – Optimized Renewable Net Short Calculations Based on

CPUC Assumptions, with GAM


SCE Assumptions, with GAM


Based on CPUC Assumptions, with PCIA


Based on SCE Assumptions, with PCIA


CPUC Assumptions, with PCIA


SCE Assumptions, with PCIA

Confidential/Public Appendix D – Cost Quantification Table

Confidential Appendix E –Renewable Energy Sales

Public Appendix F.1 – 2018 Pro Forma Renewable Power Purchase Agreement

Public Appendix F.2 – Redline of 2017 Pro Forma Renewable Power Purchase

Agreement

3 SCE worked with PG&E and SDG&E to make the format of the utilities’ plans as uniform as

possible.

3

Public Appendix G.1 – SCE’s Least-Cost Best-Fit Methodology

Public Appendix G.2 – Redline of SCE’s Least-Cost Best-Fit Methodology

Public Appendix H.1 – 2018 Procurement Protocol

Public Appendix H.2 – Redline of 2017 Procurement Protocol

Public Appendix I.1 – 2018 Pro Forma Renewable Energy Credits Sales Agreement

Public Appendix I.2 – SCE Cover Sheet to EEI Master Power Purchase and Sale

Agreement

Public Appendix I.3 – EEI Master Power Purchase and Sale Agreement

Public Appendix I.4 – Collateral Annex to the EEI Master Power Purchase and Sale

Agreement

Public Appendix I.5 – Paragraph 10 to the Collateral Annex to the EEI Master Power

Purchase and Sale Agreement

Respectfully submitted, JANET S. COMBS CAROL A. SCHMID-FRAZEE

/s/ Carol A. Schmid-Frazee By: Carol A. Schmid-Frazee

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1337 Facsimile: (626) 302-1910 E-mail: [email protected]

August 20, 2018

VERIFICATION

I am a Manager in the Regulatory Affairs Organization of Southern California Edison

Company and am authorized to make this verification on its behalf. I have read the foregoing

Southern California Edison Company’s (U 338-E) 2018 Draft Renewables Portfolio

Standard Procurement Plan. I am informed and believe that the matters stated in the foregoing

pleading are true.

I declare under penalty of perjury that the foregoing is true and correct.

Executed this 20th day of August, 2018, at Rosemead, California.

/s/ David LeBlond By: David LeBlond

SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

(U 338-E)

2018 Written Plan

August 20, 2018

PUBLIC VERSION

2018 Written Plan Table Of Contents

Section Page

-i-

I. EXECUTIVE SUMMARY OF 2018 RPS PLAN ...........................................................................1

II. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND ........................................................................................................................................7

A. SCE’s Renewables Portfolio ................................................................................................7

B. SCE’s Forecast of Renewable Procurement Need ...............................................................8

C. SCE’s Plan for Achieving RPS Procurement Goals ..........................................................16

D. SCE’s Portfolio Optimization Strategy ..............................................................................18

E. SCE’s Management of its Renewables Portfolio ...............................................................20

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues .................................................................................................22

1. Lessons Learned and Past and Future Trends ........................................................22

a) Possible Future Trend Toward Departing Load ...........................................................................................................22

b) Need for REC Sales ...................................................................................24

III. PROJECT DEVELOPMENT STATUS UPDATE .......................................................................25

IV. POTENTIAL COMPLIANCE DELAYS ......................................................................................25

A. Curtailment ........................................................................................................................26

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio .........................................................................................................27

C. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and Transmission ............................................................28

D. A Heavily Subscribed Interconnection Queue ...................................................................29

E. Developer Performance Issues ...........................................................................................29

F. Load Uncertainty Including Faster Implementation of Transportation Electrification And Departing Load ..........................................................30

V. RISK ASSESSMENT ....................................................................................................................30

2018 Written Plan Table Of Contents (Continued)

Section Page

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VI. QUANTITATIVE INFORMATION .............................................................................................31

A. RNS Calculations ...............................................................................................................31

B. Response to RNS Questions ..............................................................................................32

1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? ...................................................................................................32

2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. ...............................................................33

3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ...................................................................................................33

4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? ..................................................34

5. As projects in development move towards their commercial operation date, are there any changes to the expected RPS deliveries? If so, how do these changes impact the RNS? ......................................................................................35

6. What is the appropriate amount of RECs above the procurement quantity requirement (“PQR”) to maintain? Please provide a quantitative justification and elaborate on the need for maintaining banked RECs above the PQR. ............................................................................................35

7. What are your strategies for short-term management (10 years forward) and long-term management (10-20 years forward) of RECs above the PQR? Please discuss any plans to use RECs above the PQR for future RPS compliance and/or to sell RECs above the PQR. .................................................................................................................35


Section Page

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8. Provide Voluntary Margin of Over-procurement (“VMOP”) on both a short-term (10 years forward) and long-term (10-20 years forward) basis. This should include a discussion of all risk factors and quantitative justification for the amount of VMOP. ...................................................................................................................36

9. Please address the cost-effectiveness of different methods for meeting any projected VMOP procurement need, including application of forecast RECs above the PQR. ............................................................................................37

10. Are there cost-effective opportunities to use banked RECs above the PQR for future RPS compliance in lieu of additional RPS procurement to meet the RNS? ......................................................................................................................37

11. How does your current RNS fit within the regulatory limitations for portfolio content categories? Are there opportunities to optimize your portfolio by procuring RECs across different portfolio content categories? ..................................................................................37

VII. MINIMUM MARGIN OF PROCUREMENT ..............................................................................38

VIII. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES .....................................................................................................................39

A. Bid Solicitation Protocol ....................................................................................................39

B. LCBF Methodology ...........................................................................................................40

IX. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..............................................41

X. ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING ............................................................................................................................42

XI. AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS .......................................................................................................................................44

A. Justification of SCE’s Request for a Tier 1 Advice Letter Approval Process for a Limited Amount of RPS-Eligible Transactions .......................................................................................................................44


Section Page

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1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future .................................................44

2. California Customers Need an Open Market for RECs ......................................................................................................................44

3. REC Sales Will Create Customer Value ................................................................46

a) Selling is better than banking up to the established limits ........................................................................................46

b) REC Sales Stabilize Rates By Realizing Near Term Value........................................................................................47

c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could Help Lower Costs for Customers, While Requiring Other LSEs to Use More Long-term Products .............................................................................................48

B. SCE’s Proposal ..................................................................................................................49

1. Tier 1 Advice Letter Approach ..............................................................................49

2. Tier 3 Approval Process .........................................................................................51

C. SCE’s Proposed Limits on REC Sales ...............................................................................51

D. Acceptable REC pricing ....................................................................................................51

E. Proposed Transactional Methods .......................................................................................51

1. Competitive Solicitations .......................................................................................52

2. Bilateral Transactions ............................................................................................52

F. Proposed Timeline for REC Sales .....................................................................................52

G. Alternate Approach Is Adopted In PCIA OIR Proceeding ................................................53

XII. COST QUANTIFICATION ..........................................................................................................53

XIII. IMPERIAL VALLEY ....................................................................................................................53

XIV. IMPORTANT CHANGES FROM 2017 RPS PLAN ...................................................................54


Section Page

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A. Important Changes in 2018 Pro Forma .............................................................................54

B. Important Changes in the Written Plan ..............................................................................55

1. Removal of Time-of-Use and Expiring Contracts Information ............................................................................................................55

2. Addition of Information on Electrification of Transportation ........................................................................................................56

3. Revisions to REC Sales Strategy ...........................................................................56

4. Removal of Information on Expiring Contracts ....................................................57

XV. SAFETY CONSIDERATIONS .....................................................................................................57

XVI. STANDARD CONTRACT OPTION ............................................................................................58

A. Procurement Need ..............................................................................................................59

B. Standard Contract ...............................................................................................................59

XVII. GREEN TARIFF SHARED RENEWABLES PROGRAM ..........................................................60

A. Community Renewables - Background .............................................................................61

B. Community Renewables - Modifications to the 2018 Procurement Protocol, 2018 Pro Forma Standard Contract Option, and LCBF Methodology .......................................................................................64

1. 2018 Procurement Protocol – CR Modifications ...................................................65

C. SCE’s Request to Terminate the GTSR Program ..............................................................65

D. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar Programs ........................................................................................65

E. SCE’s GTSR Replacement Program .................................................................................66

XVIII. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .................................................66

A. Bilateral Transactions ........................................................................................................66

B. Energy Storage Procurement .............................................................................................66


-vi-

CONFIDENTIAL/PUBLIC APPENDIX A

REDLINE OF 2017 WRITTEN PLAN

CONFIDENTIAL/PUBLIC APPENDIX B PROJECT DEVELOPMENT STATUS UPDATE

CONFIDENTIAL/PUBLIC APPENDIX C.1 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH GAM

CONFIDENTIAL/PUBLIC APPENDIX C.2 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS,WITH GAM

CONFIDENTIAL APPENDIX C.3 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH GAM

CONFIDENTIAL APPENDIX C.4 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH GAM

CONFIDENTIAL/PUBLIC APPENDIX C.5 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH PCIA

CONFIDENTIAL/PUBLIC APPENDIX C.6 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH PCIA

CONFIDENTIAL APPENDIX C.7 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH PCIA

CONFIDENTIAL APPENDIX C.8 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH PCIA

CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE

CONFIDENTIAL APPENDIX E RENEWABLE ENERGY SALES


-vii-

PUBLIC APPENDIX F.1 2018 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT

PUBLIC APPENDIX F.2 REDLINE OF 2017 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT

PUBLIC APPENDIX G.1 SCE’S 2018 LEAST-COST BEST-FIT METHODOLOGY

PUBLIC APPENDIX G.2 REDLINE OF SCE’S 2017 LEAST-COST BEST-FIT METHODOLOGY

PUBLIC APPENDIX H.1 2018 PROCUREMENT PROTOCOL

PUBLIC APPENDIX H.2 REDLINE OF 2017 PROCUREMENT PROTOCOL

PUBLIC APPENDIX I.1 2018 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX I.2 SCE COVER SHEET TO EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX I.3 EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX I.4 COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX I.5 PARAGRAPH 10 TO THE COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

1

I.

EXECUTIVE SUMMARY OF 2018 RPS PLAN

In accordance with the Assigned Commissioner and Assigned Administrative Law Judge’s

Ruling Identifying Issues and Schedule of Review for 2018 Renewables Portfolio Standard (“RPS”)

Procurement Plans, dated June 21, 2018 (“ACR”) and the E-Mail Ruling Granting, in Part, IOUs1

Request for an Extension of Time to Produce the 2018 RPS Procurement Plans, dated July 9, 2018,

Southern California Edison Company’s (“SCE’s”) 2018 RPS Procurement Plan (“2018 RPS Plan”)

details SCE’s plan for satisfying the State’s RPS goals in a manner that minimizes costs and

maximizes value for SCE’s customers. On August 20, 2018, SCE filed its 2018 RPS Plan in the

R.18-07-003 docket. On August 28, 2018, Administrative Law Judge (“ALJ”) Robert Mason, issued

an E-Mail Ruling ordering SCE to refile its 2018 RPS Plan in the R.15-02-020 docket. So, SCE now

resubmits this 2018 RPS Plan in the R.15-02-020 docket.

This 2018 RPS Plan discusses SCE’s renewables portfolio, the process SCE uses for

forecasting its renewable procurement need, SCE’s forecasted renewable procurement position

through 2030, SCE’s portfolio optimization strategy and management of its renewables portfolio,

lessons learned from SCE’s experience with renewable procurement, past and future trends, and

additional policy and procurement issues. Additionally, SCE explains its plans for achieving

California’s RPS targets, including SCE’s plan on whether or not to conduct a solicitation in 2018

(“2018 RPS Solicitation”) to procure new RPS eligible resources, and its plan to sell Renewable

Energy Credits (“RECs”).

There is no final decision in the Power Charge Indifference Adjustment (“PCIA”) OIR,

Rulemaking (“R.”) 17-06-026, at this time. SCE will present one methodology regarding a 2018

RPS Solicitation for REC Sales assuming two different outcomes to that proceeding.2 SCE also

1 The IOUs are the Investor-Owned Utilities, which include Pacific Gas and Electric Company (“PG&E”),

Southern California Edison Company (“SCE”), and San Diego Gas & Electric Company (“SDG&E”). 2 SCE is aware of the California Public Utilities Commission’s (“Commission’s”) plan to provide further

guidance to the IOUs in managing their legacy portfolios in a PCIA Phase 2 proceeding. If a final PCIA (Continued)

2

requests an opportunity to update the REC Sales methodology in this 2018 RPS Plan 60 days after

the issuance of a final decision in the PCIA OIR, if the ultimate outcome of the PCIA OIR differs

from the two outcomes upon which SCE based its REC sales strategy presented here. SCE’s 2018

RPS Plan includes its 2018 Procurement Protocol, 2018 Pro Forma Renewable Power Purchase

Agreement, 2018 Pro Forma RECs Sales Agreement, and a description of SCE’s least-cost best-fit

(“LCBF”) evaluation methodology, including consideration of workforce development and

disadvantaged communities, and a summary of the important changes from SCE’s 2017 RPS

solicitation documents.

Further, this 2018 RPS Plan addresses other issues set forth in the ACR, statute, and other

California Public Utilities Commission (“Commission” or “CPUC”) decisions. Specifically, SCE’s

2018 RPS Plan includes discussion of the following additional topics:

Project development status update;

Potential compliance delays and risks;

Quantitative information discussing SCE’s renewable compliance;

Minimum margin of procurement;

Consideration of price adjustment mechanisms;

Economic curtailment;

One REC sales methodology assuming two different potential outcomes of the PCIA

OIR, including the same Tier 1 and Tier 3 Advice Letter processes for Commission

review of REC sales as in the 2017 RPS Plan;

Expiring contracts;

Continued from the previous page

Phase 2 decision warrants change to our then existing 2018 RPS Solicitation for REC Sales, we will request a change to the 2018 RPS Plan after the issuance of that decision. In the meantime, SCE understands that all actions taken consistent with a Commission-adopted 2018 RPS Plan, prior to any change associated with a PCIA Phase 2 final decision, are per se reasonable consistent with the Assembly Bill (“AB”) 57 procurement framework.

3

Cost quantification tables;

Imperial Valley issues;

Safety considerations;

Standard Contract Option using the streamlined Renewable Auction Mechanism

(“RAM”) procurement tool;

The potential termination of the Green Tariff Shared Renewables (“GTSR”) program,

in particular the enhanced Community Renewables (“ECR” or “CR” by SCE)

program and its replacement with another program; and

Other RPS planning considerations and issues.

SCE takes the RPS program’s regulatory framework into account. Senate Bill (“SB”) 2 (1x),

which took effect on December 10, 2011, increased the overall target percentage of procurement

from renewable resources from 20% to 33% by 2020, and departed from the prior structure of annual

RPS goals and moved to multi-year compliance periods, with interim procurement targets

established for each multi-year compliance period. The Commission has issued several decisions

implementing SB 2 (1x), including Decision (“D.”) 11-12-020 setting RPS procurement quantity

requirements,3 D.11-12-052 implementing the three portfolio content categories of renewable energy

products that may be used to satisfy RPS targets,4 D.12-06-038 establishing new compliance rules

3 As implemented by the Commission in D.11-12-020, pp. 2-3, the RPS procurement quantity requirements

applicable to all retail sellers are as follows: (1) 20% of overall retail sales for the first compliance period from 2011-2013; (2) 21.7% of 2014 retail sales, plus 23.3% of 2015 retail sales, plus 25% of 2016 retail sales for the second compliance period from 2014-2016; (3) 27% of 2017 retail sales, plus 29% of 2018 retail sales, plus 31% of 2019 retail sales, plus 33% of 2020 retail sales for the third compliance period from 2017-2020; and (4) 33% of retail sales in each year thereafter.

4 The first portfolio content category (“Category 1”) includes products from renewable generators with a first point of interconnection to the Western Electricity Coordinating Council (“WECC”) transmission system within the boundaries of a California Balancing Authority Area (“CBA”), or with a first point of interconnection with the electricity distribution system used to serve end users within the boundaries of a CBA, or where the renewable generation is dynamically transferred to a CBA, or scheduled into a CBA on an hourly basis without substituting electricity from another source. The second portfolio content category (“Category 2”) includes firmed and shaped products. The third portfolio content category (“Category 3”) includes all other renewable electricity products, including unbundled RECs. Retail sellers are subject to a minimum portfolio content category target (varying by compliance period) for

(Continued)

4

for the RPS program, and D.14-12-023 setting enforcement rules for the RPS program. The

Commission has not yet established a cost limitation for RPS-related procurement expenditures for

each electrical corporation.

On October 7, 2015, Governor Brown signed SB 350 which, among other significant changes

to the RPS program, increases the State’s RPS goals to 50% by 2030. In 2016, the Commission

issued D.16-12-040 implementing compliance periods and Procurement Quantity Requirements

(“PQR”) for compliance with the revised requirements of California RPS mandated by SB 350.

On June 29, 2017, the Commission issued D.17-06-026 revising compliance requirements for the

California RPS in accordance with SB 350. D.17-06-026 focused on changes affecting the role of

long-term contracts in RPS procurement and the methodology for determining how excess

procurement in one compliance period may be applied to later compliance periods.

D.17-06-026 adopted SB 350 requirements that California Load Serving Entities (“LSEs”) must

enter into ownership or contractual arrangements of 10 years or more for eligible renewable

resources for 65% of their PQR for all compliance periods beginning January 1, 2021.5

D.17-06-026 also requires retail sellers to give notice of their election for early compliance with

long-term contracting requirements in Pub. Util. Code §399.13(b) by a letter sent to the Director of

Energy Division within 60 days from the effective date of the decision (which was August 28,

2017).6

On August 28, 2017, SCE sent a letter to the Director of Energy Division giving notice of its

election for early compliance with long-term contracting requirements in Pub. Util. Code §399.13.7

Continued from the previous page

Category 1 products and a maximum portfolio content category target (varying by compliance period) for Category 3 products. The remainder may be satisfied by Category 2 products.

5 D.17-06-026, pp. 8-10. 6 D.17-06-026, Ordering Paragraph 23, p. 56. 7 On the same day, Energy Division, through an email from Brent Tarnow, acknowledged receipt of SCE’s

notice.

5

D.17-06-026 also requires that any “retail seller making the early election in 2017 must file a motion

to update its 2017 renewable portfolio standard procurement plan to reflect the election not later than

the deadline for filing motions to update such plans”8 As required by D.17-06-026, SCE filed a

motion to update its 2017 RPS Plan to reflect its election for early compliance and to reflect

compliance with requirements in D.17-01-006 that it include its current TOU rate periods in its 2017

RPS Plan. D.17-12-007, dated December 14, 2017, granted SCE’s motion to update in Ordering

Paragraph No. 13.9

While SCE has elected early compliance with long-term contracting requirements in SB 350,

not all LSEs have done so. Beginning in 2021, all LSEs will need to comply with the 65% of PQR

long-term contracting requirements in SB 350. In anticipation of this change in 2021, SCE requests

authority to make REC sales for the balance of a particular contract or of 10 years in order to

maximize the value of its RECs for its bundled service customers.

On June 6, 2018, the Commission issued D.18-05-026 implementing SB 350 provisions on

penalties and waivers in the RPS program. D.18-05-026 maintained the existing RPS penalty

scheme and integrated changes made by SB 350 into the current RPS waiver scheme. Ordering

Paragraph No. 3 of D.18-05-026 requires that:

Beginning with the 2018 Renewables Portfolio Standard Procurement Plan cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually demonstrate that transportation electrification is accounted for in their procurement plans by explicitly referencing forecasted transportation electrification in their Renewables Portfolio Standard procurement plans; providing a detailed description of the data and method used to support their forecast; and explaining how they considered the California Energy Commission’s Integrated Energy Policy Report transportation electricity demand forecast in creating their own forecast.10

Accordingly, SCE is adding a discussion of its forecast of transportation electrification in Section

II.B, which discusses how SCE forecasts RPS need.

8 D.17-06-026, Ordering Paragraph 24, p. 56. 9 D.17-12-007, Ordering Paragraph 13, p. 73. 10 D.18-05-026, Ordering Paragraph 3, p. 32.

6

SCE’s renewable procurement planning may change as a result of the Commission’s further

implementation of SB 350’s changes to the RPS program, adoption of new RPS legislation, a

procurement expenditure limitation mechanism, or other changes to the RPS program.

SCE’s analysis of its renewable procurement need is discussed herein. SCE does not have a

need for renewable energy at this time to satisfy its RPS program targets. In this 2018 RPS Plan,

SCE proposes to not hold a 2018 RPS solicitation for the procurement of eligible renewable

resources. If SCE’s preferred scenario as set forth in the Integrated Resource Plan (“IRP”)

proceeding11 is adopted, then SCE may seek to hold a solicitation to procure non-Greenhouse Gas

(“GHG”) emitting resources, including renewable energy, under the IRP docket. In this RPS docket,

SCE proposes to sell RECs, as described in Section XI below and in Appendix E.

If in future years SCE holds a solicitation, SCE would use a solicitation process that is

intended to capitalize on the maturing renewables market and target the most viable proposals that fit

SCE’s compliance and reliability needs and provide the most value to customers. In order to submit

a proposal, SCE will require that projects have: (1) a Phase II Interconnection Study (or an

equivalent or more advanced interconnection status or exemption); and (2) an “application deemed

complete” (or equivalent) status within the applicable land use entitlement process. Because of

uncertainty surrounding SCE’s long-term load forecast due to potential changes in its load profile

(i.e., the effects of electric transportation, local solar photovoltaic (“PV”) generation, and departing

load), SCE would request that all bidders submit one offer for a term of 10 years or less for each

project.

In this 2018 RPS Plan, SCE will request offers from parties interested in purchasing REC

products from SCE. In its 2017 RPS Plan, SCE planned to request offers from parties interested in

purchasing Category 1 REC products only. In this 2018 RPS Plan, SCE expands its proposal for the

REC products that it may sell in order to maximize its flexibility to sell a variety of REC products.

11 R.16-02-007.

7

Also, SCE may bid into other parties’ solicitations seeking REC products. Assuming the adoption of

the IOUs’ Green Allocation Mechanism (“GAM”) proposal in the PCIA OIR, SCE forecasts a net

short position after 2027 with the use of bank. Assuming that no REC allocation methodology is

adopted in the PCIA proceeding, SCE does not forecast a net short position potential through 2030

and beyond with the use of bank. Although the Commission has issued both a proposed decision

and an alternate decision in the PCIA OIR, at this time, the outcome of that proceeding is unknown.

Additional uncertainty exists regarding other factors such as the future departing load levels,

especially as it relates to the formation of additional Community Choice Aggregators (“CCAs”)

(see Section II.F.1.A below for a discussion on CCAs). Therefore, in order to maximize value for

customers, SCE may sell REC products, consistent with its proposal in this 2018 RPS Plan.

II.

ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND

A. SCE’s Renewables Portfolio

Table II-1 below shows SCE’s percentage of retail sales for its RPS-eligible resources:

Table II-1 Percentage of SCE’s Retail Sales from RPS-Eligible Resources

Compliance Period Year(s) % of Retail Sales from RPS Eligible Resources

First 2011-2013 20.6

Second 2014-2016 25.3

2017 2017 31.6

To date, SCE’s RPS-eligible deliveries and executed renewable procurement contracts have

resulted from SCE’s RPS solicitations, SCE’s Renewables Standard Contract program, the

Assembly Bill 1969 feed-in tariffs, RAM and Bioenergy Renewable Auction Mechanism

8

(“BioRAM”) auctions, the Renewable Market Adjusting Tariff (“ReMAT”)12, the Bioenergy Market

Adjusting Tariff (“BioMAT”), the utility-owned generation and independent power producer (“IPP”)

portions of SCE’s Solar Photovoltaic Program (“SPVP”), the GTSR program,13 qualifying facility

(“QF”) contracts, utility-owned small hydro projects, and bilateral opportunities.

SCE did not hold an RPS Solicitation in either 2016 or 2017. However, in 2017 and so far in

2018, SCE has signed the following renewable contracts:

Three ReMAT contracts for 7.5 MW

Two QF standard offer contracts for approximately 0.6 MW; and

Five BioMAT contracts for approximately 8.2 MW

B. SCE’s Forecast of Renewable Procurement Need

SCE determines its expected renewable procurement need by comparing its forecasted RPS

targets to its forecasted energy deliveries from contracted projects. The forecasted energy deliveries

include SCE’s probabilistic risk-adjusted forecast of generation from contracted projects that are not

yet online. SCE also considers generation from pre-approved procurement programs (i.e., ReMAT,

BioMAT), among other factors.

Appendices C.1 through C.8 include SCE’s forecast of its renewable procurement position

and need – i.e., SCE’s renewable net short (“RNS”) – based on the RPS targets adopted by the

Commission in D.11-12-020 for all years through 2020 as well as the RPS targets adopted by the

Commission in D.16-12-040 for the years 2021 through 2030. Table II-2 below summarizes the

types of information presented in Appendices C.1 through C.8.

12 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs

ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).

13 Only RECs associated with unsubscribed GTSR energy deliveries may be used for SCE’s RPS compliance. See D.15-01-051 at pp. 43-44; Ordering Paragraph 12.

9

Table II-2 Summary of Information Included in Appendices C.1-C.8

Appendix PCIA Outcome Nature of Calculation

Assumptions Used

C.1 GAM Physical RNS Commission’s Assumptions with adoption of GAM

C.2 GAM Physical RNS SCE’s assumptions with adoption of GAM

C.3 GAM Optimized RNS

Commission’s assumptions with adoption of GAM

C.4 GAM Optimized RNS

SCE’s assumptions with adoption of GAM

C.5 No Allocation of RECs in PCIA Physical RNS Commission’s Assumptions with No Allocation of RECs

C.6 No Allocation of RECs in PCIA Physical RNS SCE’s assumptions with No Allocation of RECs

C.7 No Allocation of RECs in PCIA Optimized RNS

Commission’s Assumptions with No Allocation of RECs

C.8 No Allocation of RECs in PCIA Optimized RNS

SCE’s Assumptions with No Allocation of RECs

These Appendices use the standardized reporting template included in the Administrative

Law Judge’s Ruling on Renewable Net Short, R.11-05-005, dated May 21, 2014 (“RNS Ruling”),14

as required in the Revised Energy Division Staff Methodology for Calculating the Renewable Net

Short (“Revised RNS Methodology”) attached to the RNS Ruling. 14 SCE’s forecasts only extend through 2030, therefore, SCE’s forecasted RNS information is only included

through 2030.

10

All forecasts include projects under contract and assume that contracted projects which are

currently online will deliver 100% of their expected amount of renewable energy. All forecasts also

include generation from pre-approved procurement programs (i.e., ReMAT, BioMAT) at a 100%

success rate before contracts are signed.15 Additionally, all forecasts incorporate current expected

online dates for all projects that are not yet online.

Furthermore, all forecasts account for potential issues that could delay RPS compliance,

project development status, minimum margin of procurement, and other potential risks through the

use of SCE’s probabilistic risk-adjusted success rates for energy deliveries from contracted projects

that are not yet online. These probabilistic risk-adjusted success rates are intended to reflect a

number of dynamic factors and are periodically adjusted based on new information. The forecasts

include individual project-specific, risk-adjusted success rates for large, near-term projects and a flat

70% success rate for the remaining projects, which is based on these projects’ overall weighted-

average success rate. The overall probabilistic risk-adjusted success rate for energy deliveries from

SCE’s portfolio of contracts with projects that are not yet online varies from approximately 78% in

the Compliance Period (“CP”) 3 and approximately 76% thereafter.

Additionally, SCE adjusted its load forecast to remove customer load served under the Green

Tariff portion of the GTSR program (called the “Green Rate” by SCE).16 This is because the GTSR

program is a separate program from the RPS program, and therefore customer load under the Green

Rate load should not be included.17 For this reason, Green Rate subscriptions are also deducted from

SCE’s generation forecasts to remove energy deliveries associated with the load served under the

15 After contracts from such programs are signed, they are risk-adjusted in the same manner as other

projects with executed contracts that are not yet online. 16 No customers are presently being served under the Community Renewables Rate. As a result, SCE only

counted Green Rate customers here. 17 See CAL. PUB. UTIL. CODE § 2833(s).

11

Green Rate.18 Prior to dedicated resources procured to serve Green Rate customers beginning

service, SCE transferred RECs from other RPS-eligible resources in its Interim Green Rate Pool to

serve Green Rate subscriptions. In March 2018, one dedicated Green Rate resource became

operational. SCE expects to begin transferring RECs from this dedicated Green Rate resource in

2019 for 2018 customer subscriptions. SCE also reduced its bundled retail sales forecast used to

calculate its RPS goals by the amount of energy used to serve Green Rate customer load, as

permitted by the GTSR program.19

SCE's load forecast also accounts for future Transportation Electrification (“TE”) load

growth.20 SCE developed its own internal model to forecast electric vehicle (“EV”) adoption and

considers TE load as a positive load contributor.

As a nascent and dynamic market, EV adoption is affected by multiple drivers such as

manufacturer supply, policies set by federal, state, and local governments, and EV technology

advancement. SCE models light-duty EV through a Generalized Bass Diffusion model. Once

vehicle population numbers are determined for each year, SCE calculates the total annual load by

multiplying the number of forecasted EVs by the weighted average KWh usage per vehicle.

Multiple factors are considered to determine hourly, daily, and annual EV charging load shapes.

SCE then incorporates the EV load forecast into its demand forecast used in this 2018 RPS Plan.

The difference between the RNS forecasts using SCE’s assumptions, as reflected in

Appendices C.2, C.4, C.6, and C.8 and the Commission’s assumptions, as reflected in Appendices

C.1, C.3, C.5, and C.7 is that SCE uses its most recent bundled retail sales forecast for all years

while the Commission’s assumptions use SCE’s most recent bundled retail sales forecast for 2018

through 2022 and the annual load forecasts through 2030 reflected in the 2017 Integrated Energy

18 Because no customers are presently being served under the Community Renewables Rate, SCE did not

make any assumptions about how many customers would be served in the future, under the Community Renewables Rate.

19 CAL. PUB. UTIL. CODE § 2833(u). 20 TE refers to only light-duty electric vehicles (“EV”) here.

12

Policy Report with adjustments for updates to certain CCA load forecasts. This is consistent with

the adopted standardized planning assumptions laid-out in the June 18, 2018 Assigned

Administrative Law Judge’s Ruling in the IRP docket, R.16-02-007.21 SCE uses its own bundled

retail sales forecast for renewable procurement planning because it is SCE’s best forecast of bundled

retail sales.

Table II-3 below summarizes information on SCE’s RNS position assuming adoption of

GAM:

21 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail

sales for the first five years and should use the LTPP standardized planning assumptions thereafter. See RNS Ruling, Attachment A at p. 25. The Commission adopted the standardized planning assumptions in R.16-02-007 in the June 18, 2018 Assigned Administrative Law Judge’s Ruling for the purpose of filing 2018 IRPs.

13

Table II-3 SCE’s RNS Position assuming adoption of GAM

Compliance Period

Assumptions Used

PQR Billion

Kilowatt-hours (KWh)

RPS-eligible Procurement

Billion Kilowatt-hours

(KWh)

End Bank Balance / <Shortfall> Billion

Kilowatt-hours (KWh)22

1 (2011-2013) SCE’s assumptions with adoption of GAM

44.8 46.2 1.4


52.4 56.8 5.6


90.9


77.6


62.5 54.3 12.2


71.2 47.0 -12.0

1 (2011-2013) Commission’s assumptions with adoption of GAM

44.8 46.2 1.4


52.4 56.8 5.6


90.9


77.6


72.1 54.3 -3.8


78.4 47.0 -31.5

22 For rows associated with CP 3-6 in this column, the bank balance assumes bank allocation to CCAs.

14

Assuming adoption of GAM with SCE’s assumptions, SCE forecasts a net short position

starting in 2024 without the use of bank (as shown in Appendix C.2). But with the use of bank, SCE

forecasts a net long position through the end of CP 5 (2025-2027) (as shown in Appendix C.4).

Using the Commission’s assumptions, SCE forecasts a net short position starting in 2023 without the

use of bank (as shown in Appendix C.1) and a net long position through the end of CP 4 (2021-

2024) with the use of bank (as shown in Appendix C.3). Accordingly, SCE currently does not have

a near-term need for additional RPS-eligible energy assuming adoption of GAM.23

Using either Commission or SCE assumptions, SCE’s ability to meet its RPS requirements

may be constrained by any form of bank restrictions adopted under GAM.

Table II-4 below summarizes information on SCE’s RNS position assuming adoption of no

allocation of RECs in the PCIA:

23 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”)

development based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 2020 are currently accounted for in SCE assumptions for departing load. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division. See section II.F, subsection 1, pp. 22-24, for a detailed explanation of SCE’s CCA outlook.

15

Table II-4 SCE’s RNS Position assuming no allocation of RECs in PCIA

Compliance Period

Assumptions Used PQR Billion


RPS-eligible Procurement

Billion Kilowatt-

hours (KWh)

End Bank Balance /

<Shortfall> Billion


1 (2011-2013) SCE’s assumptions with no allocation of RECs in PCIA

44.8 46.2 1.4


52.4 56.8 5.6


101.3


108.2


62.5 77.2 79.9


71.2 66.8 75.5

1 (2011-2013) Commission’s assumptions with no allocation of RECs in PCIA

44.8 46.2 1.4


52.4 56.8 5.6


101.3


108.2


72.1 77.2 63.9


78.4 66.8 52.2

Assuming adoption of no allocation of RECs in PCIA with SCE’s assumptions, SCE

forecasts a net short position starting in 2029 without the use of bank (as shown in Appendix C.6).

But with the use of bank, SCE forecasts a net long position through the end of CP 6 (2028-2030) and

beyond (as shown in Appendix C.8). Using the Commission’s assumptions, SCE forecasts a net

short position starting in 2027 without the use of bank (as shown in Appendix C.5) and a net long

position through the end of CP 6 (2028-2030) and beyond with the use of bank (as shown in

16

Appendix C.7). Accordingly, SCE currently does not have a need for additional RPS-eligible energy

assuming adoption of no allocation of RECs in PCIA.24

C. SCE’s Plan for Achieving RPS Procurement Goals

Through its RPS procurement activities, SCE considers contracts for renewable energy that

will help achieve the State’s RPS goals, as well as provide needed energy to serve SCE’s customers

at rates competitive with the market. As mentioned above, in 2017, SCE served 31.6% of its retail

sales from RPS-eligible resources. SCE does not forecast a net short in its RPS compliance position

until 2029 without the use of bank and after 2030 with the use of bank under the current no REC

allocation PCIA scenario. Therefore, SCE does not intend to hold a 2018 RPS Solicitation in this

2018 RPS Plan. If SCE’s preferred scenario as set forth in the IRP is adopted, then SCE may seek to

hold a solicitation to procure non-GHG emitting resources, including renewable energy, under the

IRP. In addition, because of SCE’s long position, SCE may look to sell RECs consistent with its

proposal in this 2018 RPS Plan. Among additional factors, SCE makes these decisions taking into

account: (1) the renewable energy procured through SCE’s prior RPS solicitations and other

procurement mechanisms, (2) probabilistic risk adjustment of expected generation from executed

contracts with projects that are not yet online, (3) future RPS solicitations and other procurement

mechanisms that are expected to take place, (4) departing load uncertainty (including the outcome of

the PCIA OIR proceeding) and (5) the cost of procuring renewable energy via solicitation as

compared to the cost of procuring in the market.

SCE may seek to sell RECs to allow SCE to optimize its renewables portfolio and provide

value for all bundled and departing load customers. SCE may conduct a solicitation of offers,

24 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”)

development based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 2020 are currently accounted for in SCE assumptions for departing load. See section II.F, subsection 1, pp. 22-24 for a detailed explanation of SCE’s CCA outlook. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division.

17

negotiate bilaterally, or bid into other parties’ solicitations to sell such products to maximize value to

customers and optimize the RPS portfolio. Section XI contains a more thorough discussion of the

REC sales strategy.

The procurement in SCE’s current renewables portfolio is primarily from contracts executed

prior to June 1, 2010 or contracts for Category 1 products with a small amount of Category 3

RECs.25 SCE forecasts that it will meet its RPS targets primarily through long-term Category 1

products because they provide the most flexibility for SCE’s customers. However, SCE’s forecast

may evolve in this regard based on the Commission’s implementation of SB 350.

SCE considers its RPS position in light of how long it takes to bring new projects online,

SCE’s forecasted position, and how many solicitations SCE anticipates being able to complete in

order to meet SCE’s compliance requirements. SCE then makes a pro rata allocation of its need over

the remaining anticipated solicitations. Additionally, SCE generally executes contracts for deliveries

in excess of its renewable procurement need to account for the risk of project failure and other

relevant risks. This pro rata strategy allows SCE to adjust to changes in the RPS program, including

the potential for increased RPS targets, and to respond to changes in load forecasts and/or expected

generation from operating and previously contracted renewable resources.

SCE determines the value of resources with specific deliverability characteristics (such as

peaking, dispatchable, baseload, firm, and as-available) through its LCBF analysis. SCE uses its

LCBF methodology to compare project profiles, including duration of term, location, technology,

online date, viability, deliverability, and price, to estimate the value of each project to SCE’s

customers and its relative value in comparison to other proposals using both quantitative and

qualitative factors. SCE also considers resource diversity with respect to proposals featuring

differing technologies, generation profiles, and fuel sources, and performs a qualitative appraisal of

the various benefits and drawbacks of projects when considering over-generation and the duck

25 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues

delivering their product to CAISO. SCE has not contracted for Category 3 products.

18

curve.26 This process ensures that the projects that provide the most value align with SCE’s

procurement needs. SCE’s LCBF approach is described in more detail in Section VIII.B and

Appendix G.1.

In addition to RPS solicitations, SCE continues to utilize a variety of other procurement

methods to help meet the State’s RPS targets, including mandated programs such as ReMAT,27

BioMAT, QF standard contracts and other opportunities such as local capacity requirements

solicitations, all source solicitations, PRP, and bilateral negotiations for procuring renewable energy

products.

D. SCE’s Portfolio Optimization Strategy

The objective of SCE’s renewables portfolio optimization strategy is to minimize costs to its

customers while ensuring that RPS goals are met or exceeded. The first step in SCE’s portfolio

optimization strategy is developing a forecast of SCE’s renewable procurement position and need,

i.e., SCE’s RNS. This includes a calculation of SCE’s net position and SCE’s bank. SCE carefully

evaluates its renewable procurement need by assessing bundled retail sales, the performance and

variability of existing generation, the likelihood new generation will achieve commercial operation,

expected online dates, technology mix, expected curtailment, and the impact of pre-approved

procurement programs, among other factors. Annual variability of existing resources can either

26 The California Independent System Operator (“CAISO”) describes the Duck Curve in Fast Facts at -

http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf. In essence, the CAISO points out that as intermittent resources, and particularly solar resources, have a larger role, there is more available generation at mid-day, thus reducing the demand for other generation resources. This is the belly of the duck. Once the sun goes down, there is a need for other quick-ramping resources to become available to serve the growing demand for other generation resources. This is the head of the duck.

27 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).

19

increase or decrease SCE’s need and bank from year-to-year. However, over longer periods of time,

SCE expects generation levels to be relatively consistent.

SCE uses its LCBF methodology to evaluate renewable procurement opportunities as further

described in Section VIII.B and Appendix G.1. The primary quantitative metric used for evaluating

bundled renewable energy is Net Market Value (“NMV”). SCE also relies on a number of

qualitative factors such as resource diversity and transmission area, among other factors such as

impacts on Disadvantaged Communities (“DACs”), when evaluating proposals.

Because SCE’s need assessment results in a long position, SCE may use sales of renewable

energy products,28 project deferrals, and solicitation deferrals (as it did by not holding a 2012, 2016

or a 2017 RPS solicitation) in order to reduce customer cost while aligning procurement with its

forecasted need. Additionally, SCE actively administers its renewable procurement contracts to

manage customer cost.29

SCE evaluates various potential risks when considering whether to engage in sales of

renewable energy products including the risk of not meeting its RPS targets.30 This evaluation

includes, without limitation, a calculation of SCE’s renewable procurement position and RPS bank

with a set of adverse assumptions. Among others, these assumptions include lower performance of

existing resources than expected, lower risk-adjusted project success rates for contracted generation

that is not yet online, and higher levels of curtailment than expected. SCE assesses its renewable

procurement position with these adverse assumptions to ensure that SCE would still expect to meet

its RPS targets after making the sale. SCE’s overall approach appropriately balances the risks and

costs of selling renewable energy products with the risks and costs of maintaining an RPS bank.

28 SCE procures renewable energy in compliance with the preferred loading order and when it expects to

have a renewable procurement need. SCE does not purchase RPS-eligible energy for the express purpose of selling it at a later date.

29 Contract amendments have the potential to decrease contract prices or provide other benefits to customers.

30 SCE also considers statutory and regulatory restrictions on banking of excess procurement.

20

Finally, SCE continues to analyze the effects of procurement of RPS-eligible resources on

other procurement programs in order to consider portfolio impacts. The Commission and the

California Independent System Operator (“CAISO”) considered flexibility requirements in the

Resource Adequacy (“RA”) proceeding to help manage the intermittency created on the grid by

certain renewable resources. The CAISO launched a stakeholder process to discuss new obligations

for flexible capacity and how flexibility requirements will be allocated to load-serving entities.

The adopted proposal for allocating flexibility requirements directly allocates the identified

requirements based on the amount of intermittent generation contracted by the load-serving entity.

This creates a direct link between RPS procurement and flexibility requirements as the amount of

wind and solar resources in the portfolio impacts the magnitude of the flexibility requirement

allocated to the load-serving entity. A portfolio-wide optimization strategy needs to assess the

composition of SCE’s renewables portfolio, as resources such as geothermal and other baseload

resources may potentially reduce flexibility requirements.

E. SCE’s Management of its Renewables Portfolio

After SCE executes an RPS power purchase agreement (“PPA”), SCE’s Energy Contracts

Management group manages the PPA. Each PPA is assigned a contract manager who serves as the

primary point of contact to address all obligations and milestones under the PPA. To the extent

allowable, many PPAs will require some form of modification prior to attaining commercial

operation. Modifications may include financing consents, updates to facility descriptions,

amendments that reduce costs to the seller and/or SCE without increasing revenues, true-up of PPA

milestones and timelines as interconnection and permitting information is updated, and other

miscellaneous changes to accommodate adjustments during the project development process.

Generally, PPAs require few modifications after attaining commercial operation. At this juncture in

the contract lifecycle, contract administration efforts become more focused on monitoring the

contractual performance and payment obligations. However, disputes, settlements, outages, changes

to delivery obligations or other issues may arise and are also managed by the same contract

managers.

21

In evaluating modifications or amendments to a PPA, SCE applies guidance from

D.88-10-032. Although D.88-10-032 was enacted as a set of guidelines for the administration of QF

contracts, SCE has been using it when administering all forms of PPAs. At a high level,

D.88-10-032 gave the IOUs the option to determine whether to enter into- an amendment with any

counterparty.31 In the event an amendment is elected, the IOU should negotiate in good faith.32

The decision also provides that in response to requests for contract modifications, an IOU is to seek

concessions that are commensurate with the change being sought.33 The details of D.88-10-032

provide further guidance to the IOUs to restrict modifications to PPAs with viable projects,34 and

reject modifications that would result in creating an essentially new project.35

As appropriate, SCE also considers the standards of review for PPA amendments set forth in

D.14-11-042, including assessment of SCE’s renewable procurement need, NMV, contract price,

project viability, consistency with Commission decisions, and other required updated information.36

SCE seeks approval by the Commission of all PPA modifications either through its annual

Energy Resource Recovery Account (“ERRA”) application or through advice letters or applications,

depending on the type of PPA and nature of the amendment, and based on guidance from

Commission decisions regarding specific modifications to PPAs.37

31 See D.88-10-032 at p. 16. 32 Id. at Conclusion of Law 8. 33 Id. at p. 16, Conclusions of Law 13-14. 34 Id. at p. 17, Conclusion of Law 4, Appendix A at pp. 4-5. 35 Id. at p. 26, Conclusion of Law 17. 36 See D.14-11-042 at pp. 80-82. The standards of review do not apply to amendments that are minor or

non-material. Id. at p. 80. 37 For example, the Commission has indicated specific IOU actions regarding amendments to certain terms

in tariff-based agreements.

22

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues

1. Lessons Learned and Past and Future Trends

SCE’s experience in renewable contracting has enabled SCE to negotiate successfully

and bring projects online with a variety of counterparties on a diverse array of technologies. SCE is

committed to recognizing the unique characteristics of each situation and working toward balanced

and mutually-acceptable agreements. To this end, SCE continues to refine both its RPS solicitation

process and its pro forma PPA as a result of lessons learned from SCE’s extensive experience in

contracting for renewable resources and working with developers. Over the course of the last

several years, SCE has also incorporated or accounted for several trends in its renewable

procurement planning and solicitation process. SCE discusses important lessons learned and

significant past and future trends below. Additionally, as SCE has noted in past RPS Procurement

Plans, more stringent eligibility requirements, such as the requirement that projects have a Phase II

Interconnection Study (or an equivalent or more advanced interconnection status or exemption) and

an “application deemed complete” (or equivalent) status within the applicable land use entitlement

process in order to submit a proposal, have resulted in higher viability project proposals.

SCE intends to continue these requirements in any future solicitations for all projects.

a) Possible Future Trend Toward Departing Load

SCE expects additional cities and eligible public entities within the SCE

service territory to begin CCA service. SCE had its first departing CCA load starting in May 2015

in the form of Lancaster Choice Energy (“LCE”). Apple Valley Choice Energy (“AVCE”) began

operations at the beginning of April 2017, followed by Pico Rivera Innovative Municipal Energy

(“PRIME”) in October 2017, Clean Power Alliance (“CPA” or Los Angeles County) Phase I

implementation in February 2018, San Jacinto Power (“SJP”) in April 2018, Rancho Mirage Energy

Authority (“RMEA”) in May 2018, and CPA Phase 2 in June 2018. Desert Communities Energy

23

(“DCE”) was expected to begin service in August 201838 followed by three additional phases of

CPA covering much of Los Angeles and Ventura counties in 2019. Additional cities, counties, and

governmental aggregations within the SCE service territory have either initiated contact, requested

load data from SCE, or passed a municipal ordinance related to their interest and intention to

developing CCAs. These entities have the potential to represent a significant departure of load from

SCE’s bundled procurement service. As additional large departures come to fruition, they will have

proportionally significant impacts on SCE’s progress towards meeting its RPS compliance goals by

reducing SCE’s potential RPS need.

Departing load should not impact SCE’s planned procurement activities

unless and until new LSEs formalize their departure through a Binding Notice of Intent (“BNI”), an

initial RA filing, the start of CCA service, or formal submission of an April RA forecast for the

following year pursuant to California Public Utilities Code Section 380.39 In expectation of growing

CCA departing load in the near future, SCE prepared a Monte Carlo simulation of CCA departing

load starting in 2020 and has accordingly adjusted its procurement plan at this time.40 As these

actual load departures materialize, SCE will consider how these departures impact its RPS

compliance, including the size of the RPS bank and the need to sell RECs to newly forming CCAs.

If a sufficiently large amount of SCE’s current bundled service customers depart bundled service,

38 At a July 25, 2018 DCE Board Meeting, DCE voted to indefinitely delay their previously-planned August

2018 implementation date. Their new implementation date (if any) is not currently known. SCE will not know about DCE’s final decision on all of the implementation plan changes -- especially for 2019 -- in time for us to make appropriate changes to our load forecast for this filing. It should be noted, however, that DCE’s forecast peak load was only 385 megawatts in 2018, and DCE’s delay in pursuing CCA implementation does not materially affect the overall point that SCE is significantly long regarding RPS targets for the foreseeable future.

39 SCE’s internal criteria for a qualifying governmental entity to be included in the CCA departing load forecast with full certainty for bundled procurement forecast purposes.

40 SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its PRG, including Energy Division. SCE’s current scenario analysis for departing load includes Lancaster, Apple Valley, Pico Rivera, CPA Phase One, San Jacinto, Rancho Mirage, CPA Phase Two, DCE, CPA Phases Three to Five, and the Monte Carlo simulation for departing load beginning in 2020.

24

SCE may be significantly over-procured to meet its RPS compliance goals, depending somewhat on

the outcome of the PCIA OIR. If the outcome of that proceeding is that the IOUs do not allocate a

portion of their RECs (i.e., GAM is not adopted) then, as mentioned above, SCE’s position will

remain long through 2030 and beyond with the use of bank.

Finally, as the potential for departures from bundled service increases, the

Commission should consider the cost impacts of mandated special purpose above-market, RPS

procurement. Examples include: BioRAM, ReMAT,41 and BioMAT. Because only the IOUs

undertake this procurement and only bundled service customers fund such programs, as customers

depart from bundled service, the remaining bundled service customers will be disproportionately

affected by the costs of these programs. To ensure equitable allocation of these costs, particularly as

increases in departing load materialize, it will be important to develop a way to support mandated

special purpose RPS programs without unfairly burdening bundled service customers.

b) Need for REC Sales

SCE is well positioned to meet its RPS compliance obligation both in the near

term and in the future. As described in confidential Appendix E, SCE has more renewable energy to

meet its compliance responsibilities than it needs for the forseeable future. Additionally, SCE can

create customer value and introduce some rate stability by engaging in sales transactions..

The Commission adopted SCE’s REC sales strategy in its Draft 2017 RPS Plan, with some minor

modifications, in D.17-12-007.42

In addition to providing benefits to SCE’s customers, an open market for REC

sales may provide for a low cost option for RPS compliance for other LSEs in California.

Long-term contracting may not be an option for smaller LSEs given the higher costs and long-term 41 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs

ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).

42 D.17-12-007, Ordering Paragraph 8, pp. 71-72.

25

commitments. In absence of that option, an open market can provide for a lower-cost option for

short-term REC purchases.43

Finally, given the SB 350 changes in compliance rules confirmed in

D.17-06-026, IOUs will have some flexibility to fulfill their compliance requirements through a

combination of long term contracts and short-term products, reducing the overall costs for their

customers. Given this change, SCE will seek portfolio optimization opportunities to make those

tradeoffs between long-term contracts and short-term purchases. An active REC sales strategy will

be a key part of SCE’s portfolio optimization strategy.

III.

PROJECT DEVELOPMENT STATUS UPDATE

Appendix B contains a status update on the development of RPS-eligible projects currently

under contract, but not yet delivering generation. SCE received some of the information in this

status update from its counterparties. The status of these projects impacts SCE’s renewable

procurement position and procurement decisions. For instance, SCE adjusts its renewable

procurement position during the development stage of a project once it is determined whether the

project will or will not meet its contractual obligations through its forecasted probabilistic

risk-adjusted success rates.

IV.

POTENTIAL COMPLIANCE DELAYS

Six primary factors may challenge SCE’s achievement of the RPS goals: (1) curtailment;

(2) the increasing proportion of intermittent resources in SCE’s renewables portfolio; (3) permitting,

siting, approval, and construction of both renewable generation projects and transmission;

(4) a heavily subscribed interconnection queue; (5) developer performance issues; and (6) load

uncertainty associated with possible departing load and increasing electrification of transportation.

43 As explained in more detail in section XI and confidential Appendix E.

26

SCE discusses each of these potential issues that could cause compliance delays below and describes

the steps it has taken to mitigate the effects of these challenges.

As discussed in Section II.B, in forecasting its renewable procurement position and need,

SCE accounts for potential issues that could delay RPS compliance, project development status,

minimum margin of procurement, and other potential risks through the use of probabilistic

risk-adjusted success rates for energy deliveries from contracted projects that are not yet online.

SCE considers the factors discussed below in this process.

A. Curtailment

As more renewable generation comes online, congestion at the transmission and distribution

levels can become more common. Several of SCE’s contracted wind projects in the Tehachapi

region in Kern County, California, for example, have had to curtail deliveries to maintain system

reliability in this area. Similarly, many projects in the Antelope and Devers areas have been required

to curtail in order to accommodate outages needed for system maintenance and upgrades.

The increase in California’s RPS goal from 33% to 50% will result in more intermittent resources on

the grid and increased deliveries from RPS-eligible resources, likely resulting in more curtailment of

renewable output due to over-generation.

SCE has been working on multiple fronts to mitigate the risk of curtailment. SCE has

continued working to increase the level of coordination with generators during the construction

phases of major transmission projects in the Tehachapi, Lugo, and Devers areas, with a particular

focus on minimizing the duration of outages that will require curtailments and scheduling work

during periods of low production for renewable resources. Further, SCE is developing strategies to

utilize economic curtailment rights to enable CAISO to more efficiently achieve generation

reductions when and where needed to alleviate congestion in the course of normal operations, and

during transmission outages and periods of over-generation. This practice will enable the CAISO to

fold renewable resources more directly into market optimization runs.

SCE has had some success reducing curtailment at the distribution level, in part by

completing needed system upgrades, but also by giving SCE switching center operators better tools

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to monitor real-time production levels during outages. This increased visibility enables operators to

take more targeted action when generators exceed pro rata limitations, and to more effectively

manage aggregate limits in the event not all resources are generating their full pro rata share.

SCE will continue to look for opportunities to mitigate the impacts of curtailment on meeting RPS

goals.

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio

Over the last several years, a number of large wind projects in SCE’s renewables portfolio

have achieved commercial operation. These projects include (among others) the Alta Wind and

Caithness Shepherds Flat projects totaling nearly 2,400 MW as well as the El Cabo and Broadview

wind projects which came online in 2017 and total 622 MW. While these resources contribute

significantly toward SCE’s renewables portfolio, they have also made forecasting SCE’s renewable

procurement position and need more complex. Wind generation output is difficult to predict.

Actual production from wind generators varies significantly from hour-to-hour, month-to-month,

and year-to-year, thereby exposing SCE to large fluctuations in renewable energy deliveries.

Although not as unpredictable as wind generation, solar production also varies over time depending

on weather conditions and project performance, among other factors. As wind and solar projects

come to represent an ever-larger proportion of SCE’s renewables portfolio, these effects will be

magnified, particularly with California’s RPS target increasing to 50%, which has resulted in more

wind and solar projects in SCE’s renewables portfolio.

Given the number of intermittent resources expected to achieve commercial operation in the

coming years, SCE is preparing to successfully integrate new wind and solar resources.

For example, SCE is working on ways to improve forecasting accuracy by collecting actual

generation data from new wind and solar resources and analyzing forecasted output versus actual

production after-the-fact. SCE is also seeking to maintain a balanced portfolio, while keeping

customer cost in mind, in order to ensure there is sufficient diversity of renewable resource types to

manage intermittency risk going forward.

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C. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and

Transmission

The lack of sufficient transmission infrastructure and the process for permitting and approval

of new transmission lines continues to be a challenge to reaching the State’s renewable energy

targets. Lack of adequate transmission infrastructure and the lengthy process of siting, permitting,

and building new transmission continues to impede bringing new renewable resources online.

As stated in the CAISO’s 2015-2016 Transmission Plan, “[t]he transition to greater reliance

on renewable generation has created significant transmission challenges because renewable resource

areas tend to be located in places distant from population centers.”44 Through its transmission

planning process, the CAISO utilizes renewable resource portfolios from the Commission and the

CEC to identify transmission projects that will support the development of renewable resources in

areas where they are most likely to occur. This “least regrets” approach helps to address an element

of uncertainty that generation developers may have regarding the approval of transmission projects

that are necessary for the delivery of renewable energy. Some transmission projects have already

been approved and are progressing and may help in alleviating transmission constraints once the

projects are completed. However, more projects have been identified in the CAISO’s 2017-2018

Transmission Plan as necessary to maintain safe, reliable delivery of energy while meeting the

State’s clean energy goals.45

The long and complicated permitting process for renewable generation facilities is also a

barrier to meeting RPS goals. Moreover, environmental concerns, legal challenges, and public

opposition can impact the timeline for bringing renewable generation projects online.

44 CAISO 2015-2016 Transmission Plan, at p. 6. 45 A copy of the CAISO Transmission Plan can be found at:

http://www.caiso.com/Documents/BoardApproved-2017-2018_Transmission_Plan.pdf

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D. A Heavily Subscribed Interconnection Queue

A heavily subscribed CAISO interconnection queue is also a major barrier to achieving the

State’s RPS goals. The June 2018 CAISO Interconnection Queue reports 140 solar and wind

projects seeking interconnection to the CAISO controlled grid representing more than 24,000 MW of

capacity.46

The large number of interconnection requests, particularly from renewable generators,

presents significant challenges for SCE, the CAISO, and renewable generators. Generators that have

completed their studies, but not signed generation interconnection agreements, contribute to the

uncertainty around available system capacity. When capacity is reserved for generators that have

not signed interconnection agreements, other potentially more viable later-queued generators can

appear to trigger upgrades that may not be necessary. Although protocols exist to allow for the

removal of languishing generators from interconnection queues, these protocols are difficult to

implement because they can lead to litigation.

E. Developer Performance Issues

Achieving California’s renewable energy goals also depends on the successful performance

of renewable developers in meeting contractual obligations, timely completing construction

milestones, and achieving commercial operation. Hurdles encountered during these activities

require developers to alter their milestone schedules. This can result in delays, lengthy contract

amendment negotiations, and contract terminations. Recently, developer performance has become

less of an issue as the renewables market has matured and RFP requirements such as a Phase II

Interconnection Study have been implemented. However, there have been developer performance

issues in some cases especially among the mandated carve-out feed-in-tariff programs such as

CREST and, more recently, ReMAT. Several of SCE’s contracts have terminated due to developer

performance issues (e.g., poor site selection, failure to timely secure the necessary permits, and

46 See http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx.

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inability to complete the CAISO new resource implementation processes in a timely manner).

As stated above, this is especially true in SCE’s smaller and mandated procurement programs.

In these programs, requirements showing the viability of a project, such as the requirement of a

Phase II Transmission Study or equivalent, are not an eligibility criteria. Projects that have achieved

this level of development typically have significant dollars invested and secured project-backing.

As a result, in most cases potential fatal flaws in project location, technology, or environmental

factors have been identified and resolved.

To the extent that delays, termination events, and under-performance occur, the amount of

delivered energy on which SCE can rely to reach the State’s goals is reduced.

F. Load Uncertainty Including Faster Implementation of Transportation Electrification

And Departing Load

There are two key factors that create load uncertainty which could impact SCE’s ability to

achieve its RPS goals. First, as discussed in Section II.B above, SCE’s load forecast accounts for

currently-anticipated future transportation electrification load growth. However, if future TE load

growth is more accelerated or in excess of SCE’s current forecasts, SCE’s ability to reach its RPS

target may be negatively impacted because it may not have sufficient RPS-eligible resources to serve

a significantly larger load than it presently forecasts. Given predicted levels of future departing load

to CCAs, however, even TE adoption materially in excess of SCE’s current forecasts is unlikely to

change the overall fact that SCE will be significantly long on RPS for the foreseeable future.

That said, it is also possible that SCE may experience significant returns of CCA (or other alternate

ESP-served) load, which could negatively impact its ability to achieve its RPS targets.

V.

RISK ASSESSMENT

SCE describes risks that may result in compliance delays in Section IV. As explained in

Section II.B, in forecasting its renewable procurement position and need, SCE accounts for potential

issues that could delay RPS compliance, project development status, minimum margin of

procurement, and other potential risks through the use of probabilistic risk-adjusted success rates for

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energy deliveries from contracts that are executed but not yet online. SCE considers these risk

factors in this process. Additionally, SCE takes into account historic generation from existing

resources, including lower than expected generation, variable generation, and resource availability,

among other factors, when forecasting expected generation from its contracted renewable projects.

The quantitative analysis provided in Appendices C.1 through C.8 reflects these considerations.

VI.

QUANTITATIVE INFORMATION

A. RNS Calculations

As discussed in Section II.B, Appendices C.1 through C.8 include SCE’s RNS calculations

using the standardized reporting template included in the RNS Ruling under the RPS program rules.

As required by the Commission’s RNS Methodology, Appendices C.1, C.2, C.5, and C.6 include

physical RNS calculations and Appendices C.3, C.4, C.7, and C.8 include optimized RNS

calculations.

Appendices C.2, C.4, C.6, and C.8 include SCE’s physical RNS and optimized RNS through

2030, based on the following SCE assumptions:

SCE’s most recent bundled retail sales forecast for 2018 through 2030 which excludes

Green Rate customer subscriptions;

Transfers of energy deliveries from SCE’s interim pool of RPS eligible resources to the

Green Rate program to serve Green Rate customers until dedicated Green Rate resources

come online; and conversely, transfers of energy deliveries from dedicated Green Rate

resource that are not used by Green Rate customers;

Contracted projects that are currently online will deliver 100% of their expected amount

of renewable energy;

Probabilistic risk-adjusted success rates for energy deliveries from contracted projects

that are not yet online. SCE’s forecasts include individual project-specific, risk-adjusted

success rates for large, near-term projects and a flat 70% success rate for the remaining

projects, which is based on these projects’ overall weighted average success rate; and

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100% success rate for projects originating from pre-approved programs such as ReMAT

and BioMAT before contracts from such programs are signed.47

Appendices C.1, C.3, C.5, and C.7 provide SCE’s physical and optimized RNS through 2030

using the Commission’s RNS Methodology. Appendices C.1, C.3, C.5, and C.7 use the same

assumptions as in Appendices C.2, C.4, C.6, and C.8 except that:

Instead of using SCE’s most recent bundled retail sales forecast for all years, they use

SCE’s most recent bundled retail sales forecast for 2018 through 2022 and the annual

load forecasts through 2030 reflected in the 2017 Integrated Energy Policy Report

with adjustments for updates to certain CCA load forecasts.48

At this time, SCE does not propose including a voluntary margin of over-procurement

(“VMOP”) in its renewable procurement planning. SCE will account for RPS need forecasting risks

through the identification and forecast of RECs above its RPS procurement quantity requirements

based on its forecast RPS portfolio.

B. Response to RNS Questions

SCE provides the following responses to the RNS questions included in Appendix D to the

RNS Ruling.

1. How do current and historical performance of online resources in your RPS

portfolio impact future projection of RPS deliveries and your subsequent RNS?

SCE considers weather and specific resource conditions, including maintenance

issues, degradation of output, and contractual issues that have impacted historic performance and

may cause the output of a facility to be different than what SCE anticipates for the future. SCE takes

these considerations into account when it is forecasting its RNS. In particular, if SCE determines

47 After contracts from such programs are signed, they are risk-adjusted in the same manner as other

projects with executed contracts that are not yet online. 48 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail

sales for the first five years and should use the LTPP standardized planning assumptions thereafter. See RNS Ruling, Attachment A at p. 25.

33

any of these conditions will impact a facility’s future generation, such generation will be increased

or decreased in the forecast for as long as SCE expects the situation to persist. SCE reviews these

conditions on a regular basis and updates its generation forecast accordingly.

2. Do you anticipate any future changes to the current bundled retail sales

forecast? If so, describe how the anticipated changes impact the RNS.

There are many factors that can impact SCE’s bundled retail sales forecast.

Those factors include, but are not limited to, demographic and macroeconomic drivers, electricity

prices, impact from utilities’ energy conservation programs, federal and state codes and standards,

the California Solar Initiative Program, future customer adoption of distributed generation, future

electric vehicle use, and other electrification load growth. In addition, in recent years, rapid

acceleration of actual and predicted CCA formation have led to materially longer forecast RPS

positions for SCE. SCE expects its bundled retail sales forecast to change over time as SCE

incorporates the best available information on the various drivers into its forecast. SCE’s overall

bundled retail sales forecast and resulting forecast RPS RNS will change depending on the net

impact of all of these factors. It is not possible for SCE to predict the future changes to its bundled

retail sales forecast due to the complex nature of the modeling efforts involved. Accordingly, the

bundled retail sales forecast that SCE uses at any given point in time is SCE’s best prediction of

bundled retail sales. As the bundled retail sales forecast goes up or down, it will increase or decrease

SCE’s projected RNS accordingly.

3. Do you expect curtailment of RPS projects to impact your projected RPS

deliveries and subsequent RNS?

SCE currently forecasts a very small but increasing level of curtailment in solar

between 2018 and 2020. Wind remains less predictable but is forecasted to have little to no

curtailment during this time period. SCE currently uses its forecasted curtailment in 2020 as its

forecast for future years. Some details around how SCE makes its curtailment forecast are included

below.

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For projects in development in the Tehachapi Wind Resource Area (“TWRA”), SCE

includes an estimate of curtailed generation based on analysis submitted in SCE’s testimony

regarding the Tehachapi Renewable Transmission Project (“TRTP”) in its generation forecasts for

projects in that location.49 While potentially conservative, this analysis takes into account expected

new interconnections in the TWRA, hourly generation profiles for wind and solar, and expected

increases in transmission capacity as TRTP construction progresses. The amount of generation

actually curtailed will be a function of real-time load, generation bids for dispatch, actual generation

output that differs from cleared bids for dispatch, and the amount of transmission capacity available.

Additionally, to the extent that other projects have been curtailed, or in the event SCE

revises its curtailment estimates for resources in Tehachapi or elsewhere in California, those

curtailment estimates may be incorporated into forecasts of generation in the future.

4. Are there any significant changes to the success rate of individual RPS projects

that impact the RNS?

SCE reviews the status of contracted projects that are not yet online every quarter to

assess the likelihood that each project will be successfully constructed and deliver energy. For the

larger contracted projects that terminated in the last year, SCE had gradually dropped their

likelihood of success over time such that when the projects eventually terminated, there was not a

significant impact to SCE’s forecast RNS. Overall, SCE has seen a number of large, near-term

projects continue to make strides towards completion, resulting in a collectively higher anticipated

success rate for these large, near-term projects than was allocated to similar projects prior to 2016.

As mentioned in Section IV.E above, the requirement of a Phase II Interconnection Study or better

has contributed to a higher project success rate.

49 See SCE’s Testimony in Response to the Assigned Commissioner’s Ruling on the Tehachapi Renewable

Transmission Project (“TRTP”), Application 07-06-031 (January 10, 2012); Southern California Edison Company’s Supplemental Testimony in Response to the Assigned Commissioner’s Ruling on the TRTP, Application 07-06-031 (February 1, 2012).

35

5. As projects in development move towards their commercial operation date, are

there any changes to the expected RPS deliveries? If so, how do these changes

impact the RNS?

As projects move closer to their commercial operation dates, there may be a number

of reasons to change the expected RPS-eligible deliveries, including schedule changes from phased

projects, commercial operation date changes, and availability of updated forecasted production

information. These factors may either increase or decrease the RNS.

6. What is the appropriate amount of RECs above the procurement quantity

requirement (“PQR”) to maintain? Please provide a quantitative justification

and elaborate on the need for maintaining banked RECs above the PQR.

SCE does not target a minimum amount or range of RECs above the PQR for

banking. Instead, SCE includes the expected success rate for projects in development and

incorporates the above risk factors in its forecast, which creates an adequate margin of procurement.

While SCE intends to maintain a bank, determining the appropriate level of RECs

above the PQR is dependent on a number of factors: the forecast level and uncertainty of bundled

retail sales, the outcome of the PCIA proceeding, possible disallowance of RECs by the CEC during

RPS verification, fuel source mix in the renewables portfolio, performance of existing resources,

project success rates, delay or acceleration of online dates, performance of new facilities once they

are operational, the level of the existing portfolio that is re-contracted, and curtailment, among other

factors. Annual variability of these factors can either increase or decrease the bank from year-to-

year.

7. What are your strategies for short-term management (10 years forward) and

long-term management (10-20 years forward) of RECs above the PQR? Please

discuss any plans to use RECs above the PQR for future RPS compliance and/or

to sell RECs above the PQR.

When sufficiently long during short-term periods, SCE has used sales of renewable

energy products, project deferrals, portfolio optimization, and solicitation deferrals in order to adjust

36

its renewable procurement back in line with its forecasted RNS. If SCE forecasted short-term

shortfalls, SCE would satisfy the need through additional procurement. For example, SCE could re-

contract with existing projects, initiate an RPS solicitation, procure through pre-approved

procurement programs, or make short-term purchases with Commission approval.

Additionally, SCE diligently manages contracts to ensure all contractual obligations are met.

SCE uses these activities for renewables portfolio optimization.

Specifically regarding the sale of RECs, when SCE has a long position in the near

term, SCE evaluates whether a sale of renewable energy products is appropriate. This evaluation

includes a calculation of SCE’s renewable procurement position and RPS bank under a set of

adverse assumptions. These assumptions include, but are not limited to, lower performance of


that is not yet online, lower load requirements due to departing load, and higher levels of curtailment

than expected. SCE assesses its renewable procurement position with such adverse assumptions to

ensure that, even in an adverse case scenario, SCE would still expect to meet its RPS targets after

making the sale. It is not SCE’s intent to purchase renewable energy products solely for the purpose

of selling them at a later date.

At this time, SCE considers holding an excessive amount of bank in the long-term to

be an inefficient use of resources. Rather, SCE generally allocates any near-term forecasted RECs

above the PQR to years of forecasted shortfall. Additionally, as described in Section XI.C, SCE will

setup limits for REC sales using a margin of safety for compliance.

8. Provide Voluntary Margin of Over-procurement (“VMOP”) on both a

short-term (10 years forward) and long-term (10-20 years forward) basis.

This should include a discussion of all risk factors and quantitative justification

for the amount of VMOP.

SCE currently does not use a VMOP methodology on either a short-term or long-term

basis. While there are different risks that have different impacts in the short and long-term, SCE

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believes it appropriately accounts for these risk factors in its forecasted RNS as described in prior

sections.

9. Please address the cost-effectiveness of different methods for meeting any

projected VMOP procurement need, including application of forecast RECs

above the PQR.

SCE procures what it believes is needed to meet its RPS targets, allocating any near-

term forecasted RECs above the PQR to years of forecasted shortfall. SCE’s forecasted need is far

enough in the future that SCE believes it can fill that need through additional procurement on a

ratable basis. SCE believes it appropriately accounts for risk through the risk factors identified in its

response to question 6 above, and currently does not utilize a VMOP.

In the event that SCE implements a VMOP methodology in the future, SCE would

use the same methods to procure its projected VMOP procurement need as it uses to procure towards

its RPS targets, including procurement of Category 1 products.

10. Are there cost-effective opportunities to use banked RECs above the PQR for

future RPS compliance in lieu of additional RPS procurement to meet the RNS?

There are a few alternatives for the potential use of banked RECs above the PQR,

including applying them in the future compliance periods, engaging in sales for the amount of bank,

and a combination of sales of products and procurement of other products. As noted above in

response to question 7, SCE does not hold an excessive amount of bank for the sole purpose of

selling it later. SCE generally allocates any near-term forecasted RECs above the PQR to years of

forecasted shortfall. SCE conducts various portfolio optimization strategies also described in its

response to question 7 to manage its renewables portfolio.

11. How does your current RNS fit within the regulatory limitations for portfolio

content categories? Are there opportunities to optimize your portfolio by

procuring RECs across different portfolio content categories?

The procurement in SCE’s current renewables portfolio is primarily from either

contracts executed prior to June 1, 2010 or contracts for Category 1 products with a small amount of

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Category 3 RECs.50 Accordingly, SCE’s procurement fits within the minimum target for Category 1

products and the maximum target for Category 3 products established by SB 2 (1x) and D.11-12-

052, as well as the targets established in SB 350 and D.17-06-026. SCE does see opportunities to

optimize its portfolio and achieve customer value through sales across the three portfolio content

categories. Given SCE’s current position of no RPS need in the near term, SCE may conduct

solicitations for sales of REC products in 2018. Through soliciting REC sales, SCE may find

opportunities to create value for its customers.

VII.

MINIMUM MARGIN OF PROCUREMENT

SCE’s renewable procurement efforts will be guided by its forecast of its renewable

procurement needs, as described in Section II.B and provided in Appendices C.1 through C.4. In its

forecast of its renewable procurement position and need, SCE currently accounts for the risks of

project failure and delay associated with contracted projects that are not yet online. To this end,

SCE uses individual project-specific, risk-adjusted success rates for large, near-term projects and a

flat 70% success rate for the remaining projects, which is based on these projects’ overall weighted

average success rate. This probabilistic risk adjustment methodology for discounting expected

energy deliveries from projects under development is modeled to represent project development

success rates as well as any contingency that would make meeting the State’s RPS goals less likely

(e.g., delays due to transmission, curtailment, material shortages, load growth beyond that which is

forecasted, or less than expected output from resources). Additionally, this methodology provides an

appropriate minimum margin of procurement “necessary to comply with the renewables portfolio

standard to mitigate the risk that renewable projects planned or under contract are delayed or

50 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues

delivering their product to CAISO. SCE has not contracted for Category 3 products.

39

cancelled.”51 SCE will reassess its position on a periodic basis and, as such, expects that success

rates may need to be modified in the future to reflect changes to SCE’s portfolio.

The Commission should rely on retail sellers to calculate their minimum margins of

procurement and should not attempt to impose a one-size-fits-all approach. As many of the projects

in SCE’s portfolio become operational, SCE will face different risks, including integration of these

resources. The risks associated with project failure will be replaced by less significant risks of

projects generating below full capacity. Similarly, SCE expects that the portfolio risk picture is not

the same for each retail seller. For example, risks may vary depending on whether a portfolio

contains a high proportion of contracts that are online (as discussed above) or depending on the

various technologies being used (e.g., geothermal technology, which is a baseload resource, versus

wind or solar technologies, which are more intermittent as described in Section IV.B). For these

reasons, each retail seller should continue to have the authority to revise its approach to calculating

the minimum margin of procurement through the RPS procurement planning process and each retail

seller should have the flexibility to calculate this margin based on its unique portfolio make-up and

procurement needs.

VIII.

BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES

A. Bid Solicitation Protocol

Depending on the outcome of the PCIA OIR proceeding, SCE may hold a 2018 RPS

solicitation, for sales of RECs. SCE will use the proposed 2018 Procurement Protocol, included here

as Appendix H.1, for these sales and for future RPS solicitations beyond 2018. The Procurement

Protocol includes, among other things, the following items, some of which are not relevant for

SCE’s contemplated REC sales solicitation but are relevant for purchase solicitations in future years:

SCE’s requirements for initial delivery dates and preferred contract term lengths;

51 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).

40

Deliverability characteristics and locational preferences;

SCE’s preference for LCR projects;

Encouragement for Women-Owned, Minority-Owned, Disabled Veteran-Owned,

Lesbian-Owned, Gay-Owned, Bisexual-Owned, and/or Transgender-Owned Business

Enterprises (“Diverse Business Enterprises”) to participate in SCE’s RPS solicitation and

information on how sellers can help SCE to achieve General Order (“GO”) 156 goals;

Requirements for each proposal submission;

A description of the type of products SCE is soliciting;

A schedule of key dates related to the RPS solicitation; and

SCE’s 2018 Pro Forma Renewable Power Purchase Agreement (“Pro Forma”), attached

as Appendix F.1; and

2018 REC Sales Confirmation (“2018 REC Sales Agreement”).

A discussion of the important changes in the proposed solicitation documents from SCE’s

2017 solicitation documents is included in Section XIV.

B. LCBF Methodology

In its LCBF evaluation process, SCE performs a quantitative assessment of each proposal

and subsequently ranks them based on each proposal’s benefit and cost relationship. The result of

the quantitative analysis is a rank order of all complete and conforming proposals’ net levelized

benefit that help define the preliminary shortlist. Following the quantitative analysis, SCE will

conduct an assessment of the top proposals’ qualitative attributes. These qualitative attributes,

including factors such as local reliability, resource diversity, and nominal contract payments, are

considered to either eliminate or add projects to the final shortlist or to determine tie-breakers, if any.

Once a project is added to the shortlist, SCE may enter into a PPA with the project. By taking many

quantitative and qualitative factors into consideration, SCE ensures that it will select projects best

suited for its portfolio in order to meet customer needs and attain the State’s RPS goals. Appendix

G.1 (the “LCBF Methodology”) describes this process, including capacity valuation and the

renewable integration cost adder, among other factors.

41

There is one element of the current LCBF Methodology about which SCE raised concerns in

its Opening Comments on LCBF Reform, dated July 22, 2016. That is the use of Time of Delivery

(“TOD”) factors for evaluation and payment purposes. As discussed in more detail in Appendix

G.1, TOD factors are unlikely to serve as an incentive for production of power when it is most

needed in the future as solar and wind renewable resources have limited flexibility in their time of

power production. While SCE does not eliminate the use of TOD factors in its LCBF valuation in

this Written Plan, it will continue to argue for their elimination in future consideration of LCBF

Reform.

SCE also considers as qualitative factors in its LCBF valuation, the impact of a project on:

(1) employment or Workforce Development; and (2) disadvantaged communities, which are

identified through California’s Environmental Protection Agency’s CalEnviroScreen 3.0.

As stated previously in this written plan, IOUs will have some flexibility to fulfill their

compliance requirements through a combination of long term contracts and short-term products,

reducing the overall costs for their customers. Given this change, SCE will seek portfolio

optimization opportunities to make those tradeoffs between long-term contracts and short-term

purchases. An active REC sales strategy will be a key part of SCE’s portfolio optimization

strategy. As part of its LCBF analysis of REC sales, SCE will establish a floor price,

and would not look to engage in a sales transaction below that

floor price. In Appendix E, SCE proposes the methodology to establish a REC sales price floor.

IX.

CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS

As in the past three RPS solicitations that SCE has held, SCE does not plan to solicit price

structures based on indices in future RPS solicitations. Sellers can, however, bid escalation factors

in their prices. Proposals with adjustable pricing based on indices were more common when the

renewable industry was starting out. Uncertainties over relatively new technologies made it

reasonable to tie pricing to certain commodity indices, inflation rates, or other indices that made

sense given the technology. However, the industry is more sophisticated now, supply chains are

42

becoming more stable, and price adjustment mechanisms based on indices are not needed. Sellers

and SCE want price certainty, and SCE does not want to be subjected to extraordinary high (or

unsustainably low) pricing due to fluctuations in a commodity or other indices. Additionally, the

ability to bid price adjustments based on indices increases complexity for sellers in the proposal

process and for SCE in the evaluation process. Developers are not requesting price adjustment

mechanisms and the contract price risk uncertainty associated with them does not warrant their

consideration.

X.

ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING

Although SCE has observed very few instances of negative pricing in the day-ahead

market,52 negative prices have been observed on a more regular basis in the real-time market.

SCE identifies several factors contributing to increases in instances of negative prices.

Over-generation typically occurs in off-peak hours when baseload and must-take renewable

generation is high and demand is low, which can cause negative market price hours. On-peak

negative prices tend to be localized, transient, and related to congestion caused by a particular

transmission bottleneck.

It is generally difficult to forecast negative prices. SCE continues to manage potential

instances of negative pricing and the associated impact to SCE customers through several different

strategies. As a general practice, SCE schedules variable energy resources, such as solar and wind

facilities, into the day-ahead market whenever possible. Because resources that are awarded day-

ahead schedules are only exposed to negative prices in real-time for actual deliveries in excess of

their bid-in, day-ahead awards, this practice helps to limit customer exposure to negative prices.

This practice is consistent with least-cost dispatch principles, which govern SCE’s approach to

marketing its entire portfolio of contracted and utility-owned resources.

52 ~ ~1.96% of hours in sampled nodes in the day-ahead market.

43

Additionally, SCE plans to economically bid resources with economic curtailment rights into

the day-ahead and real-time markets. Resources with these curtailment rights will then be curtailed

as needed based on CAISO’s economic dispatch. In some SCE PPAs, there is a pre-defined amount

of pre-paid energy per year that may be economically curtailed, subject to some restrictions, without

requiring SCE to pay for the energy that could have been delivered but for the curtailment

instruction. As noted above, this amount is commonly referred to as a “curtailment cap.” Once the

curtailment cap is reached, SCE must pay the contract price for energy that could have been

delivered but for the curtailment instruction. In other SCE PPAs, SCE has the right to curtail based

on economic factors, but must always pay the contract price for energy that could have been

delivered but for the curtailment instruction. These types of curtailment rights are commonly

referred to as “take-or-pay.” In instances where SCE has either exceeded the curtailment cap or only

has “take-or-pay” economic curtailment rights to begin with, if SCE were not to curtail deliveries in

excess of any schedules awarded at positive prices, customers would pay the contract price for that

excess delivered energy and incur the costs associated with negative pricing in such intervals.

SCE’s economic bids will therefore serve to further limit customer exposure to negative prices both

in day-ahead and in real-time, even if SCE ultimately pays the full contract price for curtailed

energy.

In future RPS solicitations, SCE plans to not require sellers to bid the pre-paid economic

curtailment option with the curtailment cap. SCE will retain the right to curtail at its discretion, but

will pay for curtailments directly resulting from SCE marketing decisions. As in prior years, SCE

will not pay for curtailments in response to an emergency, or due to CAISO or transmission provider

instructions.

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XI.

AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS

A. Justification of SCE’s Request for a Tier 1 Advice Letter Approval Process for a

Limited Amount of RPS-Eligible Transactions

SCE requests authorization to enter into a limited quantity of short-term renewable energy

transactions for REC products through a Tier 1 Advice Letter Approval Process. SCE will propose

and detail one REC sales strategy assuming two different outcomes to the PCIA proceeding within

Appendix E.

1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The

Foreseeable Future

SCE is well positioned to meet the CP 3 2020 33% RPS target with existing projects

and projects under development (risk-adjusted). Therefore SCE did not hold an RPS procurement

solicitation for the 2016 and 2017 cycles. Also, if the Commission adopts the GAM proposal in the

PCIA OIR proceeding, SCE forecasts that it will have excess RECs at least through 2023 without the

use of its REC bank and through CP 5 (2025-2027) with the use of the REC bank for compliance

purposes. If the Commission does not adopt REC allocation PCIA methodology in the PCIA OIR

proceeding, SCE forecasts that it will have excess RECs at least through 2029 without the use of its

REC bank and through CP 6 (2028-2030) and beyond with the use of the REC bank for compliance

purposes.

2. California Customers Need an Open Market for RECs

When entities only rely on long-term contracting and new projects to meet

compliance requirements, the costs of meeting RPS goals are higher. This cost increase comes from

an inability to make adjustments to the portfolio quickly using short term products. Until recently,53

the RPS rules did not allow for much flexibility in meeting RPS requirements if using a bank.

53 D.17-06-026.

45

LSEs with large procurement needs and therefore large uncertainties could not reasonably rely on

the use of short-term products to meet their requirements. This was especially true as the market

was forming and there was not significant depth in the short-term markets. Large LSEs instead used

the banking rules to build portfolios to account for uncertainties in project development, load

forecasts and production. This led to the development of banked positions that also resulted in an

inability to use short-term products to meet any future needs due to RPS retirement rules. New

legislation (SB 350) adopted in 2016 removed these barriers.

A combination of long-term and short-term procurement will allow LSEs to build

more cost-effective portfolios for customers. Long-term procurement can focus on bringing new

projects online. Short-term procurement can focus on balancing the portfolio to meet compliance

requirements at the lowest possible cost. This combination of long-term and short-term procurement

will also allow for a free exchange of RECs between different entities who may have over/under

procured for their compliance needs.

The Commission’s RPS compliance reports demonstrate the state’s progress in

meeting its aggressive RPS procurement targets, driven by the investments made by the three large

IOUs in California. Currently all IOUs are long for RPS energy,54 and some ESPs and/or CCAs may

need RECs to meet compliance requirements in the near future, as well as meeting their additional

sustainability goals that many have set forth - above and beyond their compliance requirements.55

Allowing for the free trade of these long positions between LSEs will allow for a lower cost outcome

for all customers. An open market will provide for a lower cost and flexible option for meeting RPS

requirements.

In addition, all retail sellers must procure a minimum level of Category 1 RECs; the

minimum level increases over multi-year compliance periods.56 For CP 3, the minimum requirement

54 Section XI.A.1 above. 55 Id. 56 CAL. PUB. UTIL. CODE § 399.16(c).

46

for Category 1 procurement is 75%, which is higher than previous compliance periods. Also, there

is a maximum limit on the amount of Category 3 procurement that may be used in each compliance

period, which decreases over the same time frame. As a result, entities cannot solely depend on s

Category 3 RECs acquired towards the end of a compliance period. Any newly formed entity during

the CP 3 timeframe (2018-2020) will have to meet the same requirements for RPS compliance as

described. Most of these requirements will have to be met using existing facilities, since

development of new projects (i.e., siting, licensing, construction, contracting) is a time-consuming

process that will likely not be able to be completed in time to meet the 33% RPS compliance

requirement by 2020. Accordingly, it is important for all market participants to have access to

purchase RECs sourced from existing facilities to avoid potential market distortions and compliance

shortfalls.

In addition, as discussed in Section I above, beginning in 2021, SB 350, as

implemented in D.17-06-026, requires that all entities must meet 65% of their RPS target with

eligible renewable resources having long-term contracts or ownership arrangements of 10 years or

more. Accordingly, it is important for all market participants to have access to purchase long-term

RECs sourced from existing facilities either for the duration of a contract for a specific facility or for

10 years for non-project specific contracts to avoid potential market distortions.

3. REC Sales Will Create Customer Value

a) Selling is better than banking up to the established limits

When SCE considers whether to engage in sales of renewable energy

products, SCE compares the value obtained from selling RECs to the costs of having to procure

additional renewable energy in the future. SCE analyzes the impact to its renewable needs and the

costs to customers through the use of the NMV calculation. SCE compares the NMV for the sales

transaction against the NMV of proposals submitted to SCE in recent solicitations and other

procurement. If the NMV for long-term renewable procurement is higher than the NMV for the

sales transaction, it would be more cost-effective for SCE to maintain its existing RPS bank for

future compliance periods and not to make renewable energy sales. Conversely, if the NMV from

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recent solicitations is lower than the NMV for the sales transaction, SCE has an opportunity to

optimize its renewables portfolio and realize value for its customers by selling renewable energy

products.

In addition to the NMV considerations discussed above, SCE evaluates

potential risks when determining its renewables portfolio optimization strategy, including the risk of

not meeting its RPS targets. When SCE has a long position in the near and intermediate term, SCE

evaluates whether a sale of renewable energy products is appropriate. This evaluation includes a

calculation of SCE’s renewable procurement position and RPS bank with a set of adverse

assumptions. These assumptions include, but are not limited to, lower performance of existing

resources than expected, lower risk-adjusted project success rates for contracted generation that is

not yet online, and higher levels of curtailment than expected. SCE assesses its renewable

procurement position with such adverse assumptions to ensure that, even in a sub-optimal scenario,

SCE would still expect to meet its RPS targets after making the sale. SCE’s overall approach

appropriately balances the risks and costs of selling renewable energy products with the risks and

costs of maintaining an RPS bank.

b) REC Sales Stabilize Rates By Realizing Near Term Value

Assuming adoption of the IOUs’ GAM proposal, SCE has a bank until the end

of CP 5 (2025-2027)57 for meeting RPS compliance established by SB 2 (1x) and D.11-12-052, as

well as the targets established in SB 350 and D.17-06-026. Assuming no allocation of RECs in the

PCIA methodology, SCE has a bank until CP 6 (2028-2030) and beyond58 for meeting RPS

compliance established by SB 2 (1x) and D.11-12-052, as well as the targets established in SB 350

and D.17-06-026. As a result, REC sales can help create near term value and in turn create near term

rate relief for SCE customers. SCE holds a significantly long position to meet compliance needs in

the near term. In future compliance periods, the length of this position is subject to fluctuation, 57 Section II.B. 58 Id.

48

depending on the final outcome of the PCIA OIR. For example, assuming adoption of GAM in CP 5

(2025-2027),59 SCE forecasts no need for new RPS resources with the use of bank, but by CP 6

SCE’s bank is not long on RECs. Adoption of no allocation of RECs in the existing PCIA

methodology results in SCE being significantly longer on RECs with the use of bank. If SCE can

generate some revenues through REC sales, it will help smooth out SCE’s RPS compliance positions

over these coming years. In turn, these REC sales would smooth out the rate impacts over the years

to SCE’s customers because RECs from more expensive contracts would be sold and replaced with

cheaper renewable energy for compliance for future years, taking advantage of declining renewable

prices.

c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could

Help Lower Costs for Customers, While Requiring Other LSEs to Use More

Long-term Products

SB 35060 requires that 65% of total renewable portfolio that a retail seller

counts toward the RPS target for each compliance period must be from long-term contracts, starting

no later than 2021. The previous long-term contracting requirement for retail sellers was smaller -

0.25% of prior period’s total retail sales.

Starting in 2017, any retail seller can elect to use the new SB 350 rules,

allowing 35% of RECs towards the RPS targets to come from short-term contracts.61 Any retail

seller making such an election must, however, meet 65% long-term contracting requirement.62

Short-term contracts would facilitate the following types of projects/products to count toward RPS

targets:

Seven-year renewable qualifying facility must-take contracts

59 Id. 60 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416. 61 Id. at Ordering Paragraphs 15-24, at pp. 54-56. 62 Id. at Conclusion of Law 6, at p. 42.

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Existing projects (including in-state) that can still produce and do not want

to repower and have a long-term contract terminating

New projects that are merchant prior to a long-term contract

Short-term Bundled RECs

Unbundled REC contracts

Given the changes in legislation, IOUs will now have more flexibility to fulfill

their compliance requirements through a combination of long-term contracts and short-term

products, including but not limited to the examples above, reducing the overall costs for their

customers.

B. SCE’s Proposal

1. Tier 1 Advice Letter Approach

SCE proposes a Tier 1 Advice Letter Approach for approval of REC sales.

SCE’s proposed approach includes terms, volume limits, and a pricing floor as part of the preferred

approach for the REC sales framework as summarized in Table XI-5 below.

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Table XI-5 SCE’s REC Sales Framework

Parameter Proposal

Transaction mediums 63 RFO Process, Electronic Solicitations, Bilateral (strong showing64)

Terms Remaining term of applicable contract or up to 10 years for non-project specific contracts

Sales Volume Limits 65 Based on load/gen forecast and uncertainty around it, changing RPS

legislation and anticipated pricing

Pricing 66 Price Floor based on market pricing

PRG Consultation Quarterly, at PRG meetings

Approval Process

Tier 1 if sold through solicitation process or a bilateral utilizing standard contract without modification after results of a solicitation are known. All others, Tier 3.

Consistent with D.17-12-007, Ordering Paragraph No. 8,67 SCE will submit a Tier 1

Advice Letter filing for each of its REC sales from solicitations resulting from this 2018 RPS Plan or

for bilaterally negotiated REC sales using the pro forma REC Sales Agreement attached to this

Written Plan as Appendices I.1-I.5 and executed after SCE receives bids for a sales solicitation

resulting from this Written Plan. For REC Sales PPAs resulting from solicitations, a Tier 1 Advice

Letter will include all REC Sales PPAs submitted as a group for the results of each concurrent

63 Explained in more detail in section XI.E below. 64 A strong showing could include competing price offers, broker or online quotes, published indices,

comparisons to recent solicitations. 65 Sales Volume Limits methodology is explained in detail in Appendix E, section II. 66 Price Floor methodology is explained in detail in Appendix E, Section III. 67 D.17-12-007, pp. 71-72.

51

solicitation (consistent with D.14-11-042). For bilaterally negotiated REC Sales PPAs using the pro

forma REC Sales Agreement in Appendices I.1-I.5 of this Written Plan and executed after SCE

receives bids for a sales solicitation resulting from this 2018 RPS Plan, a separate Tier 1 Advice

Letter will include each bilaterally negotiated REC Sales PPA.

2. Tier 3 Approval Process

Consistent with D. 17-12-007, SCE may also engage in bilateral REC sales

transactions that do not utilize the pro forma REC Sales Agreement attached as Appendices I.1-I.5 to

this Written Plan or that are not executed after SCE received bids for a sales solicitation resulting

from this 2018 RPS Plan.68 These bilateral REC sales transactions are subject to the Commission’s

review and approval of completed transactions through a Tier 3 Advice Letter process.69

C. SCE’s Proposed Limits on REC Sales

Appendix E, Section II describes and provides an example calculation of SCE’s proposed

volume limits. SCE will take into account any impact from the PCIA proceeding as it relates to how

it may impact its REC position in future years. Assuming the current PCIA methodology (or

something comparable) is adopted in the PCIA proceeding, SCE would expect to have substantially

more RECs compared to if the GAM proposal is adopted. As such, SCE would likely have a much

higher maximum sales volume limit if the current PCIA methodology is maintained.

D. Acceptable REC pricing

Appendix E, Section III sets out SCE’s confidential pricing standard for REC sales.

E. Proposed Transactional Methods

SCE proposes several methods for which it seeks approval to transact RECs. Below is a

description of some of these methods. SCE will consider several factors to determine the most

effective method for the sales of RECs including, but not limited to, liquidity of the product and

other market dynamics, price competitiveness, number of counterparties transacting in the product, 68 See, D.17-12-007, pp. 71-72, Ordering Paragraph 8. 69 Id.

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and quantities required by SCE. These factors change over time; thus, SCE may seek to transact at

various times using different methods.

1. Competitive Solicitations

SCE proposes to maximize value to its customers through competitive solicitations

that encourage participants to offer the highest possible price when purchasing RECs. When buying

renewable energy, SCE has seen much higher costs being offered through mandated procurement,

non-competitive programs. Typically, these programs may focus on specific technologies or project

size. Conversely, SCE’s RPS Solicitations have consistently brought the lowest renewable prices

through the competitive bidding process. Similarly, higher prices may be realized through a

competitive solicitation when SCE sells RECs. Additionally, a competitive solicitation will allow

SCE to discover where the market is, in terms of the prices buyers are willing to pay for RECs.

SCE may also bid into solicitations held by third parties seeking RECs.

2. Bilateral Transactions

In certain instances, SCE may accept bilateral offers to purchase RECs. For example,

if there are a small number of interested parties in the REC market or deadlines are approaching

where an interested party needs to purchase RECs, to meet a unique need, prior to a solicitation

being launched. These and other situations may lead to SCE selling RECs bilaterally rather than

through a competitive process. Such sales would be subject to review through a Tier 1 Advice Letter

process, if they utilize the pro forma REC Sales Agreement submitted in Appendices J.1-J.6 to this

Written Plan and occur after SCE receives bids for a sales solicitation resulting from this 2017 RPS

Plan. If such sales do not utilize the pro forma REC Sales Agreement submitted in Appendices J.1-

J.6 to this Written Plan or do not occur after SCE receives bids for a sales solicitation resulting from

this 2017 RPS Plan, such sales would be subject to review through a Tier 3 Advice Letter process.

F. Proposed Timeline for REC Sales

SCE’s Procurement Protocol in Appendix H.1 sets out its proposed timeline for any REC

Sales done through an RFO, and all other types of REC sales transactions would occur following

Commission approval of SCE’s 2018 RPS Plan.

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G. Alternate Approach Is Adopted In PCIA OIR Proceeding

Within the PCIA OIR proceeding, proposals other than an updating of the benchmarks using

the current PCIA methodology or the Joint Utilities’ PAM or GAM proposals have also been put

forward. These include a PCIA with updated benchmarks, (proposed by AReM/DACC),

Monetization in Market with a True-Up (proposed by TURN), Portfolio Securitization (proposed by

CalCCA), and different auction mechanisms (Commercial Energy and CalCCA). SCE expects to

hold a net long REC position with any of the current alternate proposals and would likely still

propose to sell RECs using the rationale and methods proposed above. However, SCE requests an

opportunity to update this 2018 RPS Plan with modifications to its REC sales approach 60 days from

the issuance of a final decision in R.17-06-026, if the Commission chooses an approach different

from using the current PCIA methodology or the Joint Utilities’ PAM or GAM proposals.

XII.

COST QUANTIFICATION

The spreadsheet attached as Appendix D includes actual expenditures per year for RPS-

eligible generation for every year from 2003 through 2017, as well as actual RPS-eligible generation

for every year from 2003 through 2017. Appendix D also includes a forecast of future expenditures

SCE may incur every year from 2018 through 2030, as well as a forecast of expected generation for

every year from 2018 through 2030.

XIII.

IMPERIAL VALLEY

In SCE’s last RPS solicitation (the 2015 RPS solicitation), SCE received 279 proposals.

Since SCE has not held an RPS solicitation

since 2015, SCE will not include this section in future RPS Plans, as it is not necessary when no

solicitations are being held.

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XIV.

IMPORTANT CHANGES FROM 2017 RPS PLAN

SCE, at present, has no need for more eligible renewable resources. As a result, SCE does

not propose to hold a 2018 RPS solicitation. If SCE’s preferred scenario as set forth in the IRP


(“GHG”) emitting resources, including renewable energy, through the IRP proceeding. Instead, in

this RPS proceeding, SCE seeks permission to sell SCE RECs, as discussed in Section XI above.

SCE’s 2018 RPS Plan includes changes to: (1) SCE’s 2017 Procurement Protocol; (2) SCE’s

2017 Pro Forma; and (3) SCE’s LCBF Methodology. Those changes are summarized below. SCE

has included redlines of its 2018 Procurement Protocol, 2017 Pro Forma, and LCBF Methodology

against the versions of those documents included in SCE’s 2017 RPS Plan as Appendices H.2, F.2,

and G.2, respectively. SCE has made relatively few changes to these documents from the 2017

documents. SCE did not include a redline of the 2017 Pro Forma REC Sales Agreement because

the 2018 Pro Forma REC Sales Agreement is identical to the 2017 Pro Forma REC Sales

Agreement. The most significant changes to the other 2017 documents are summarized below.

A. Important Changes in 2018 Pro Forma

The changes to the Pro Forma were mostly minor or clean-up items, with important changes

summarized below. A redline of the 2018 Pro Forma showing all of the changes from the 2017 RPS

Pro Forma is attached as Appendix F.2. Additionally, changes related specifically to the Standard

Contract Option are mentioned in Section XVI.B. For SCE’s Community Renewables solicitation

(“CR-RAM”) SCE will use the Community Renewables Rider (“CR Rider”) to the 2018 Standard

Contract Option, which SCE submitted to the Commission via Advice Letter 3422-E for its

Community Renewables PPAs.

70 R.16-02-007.

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Important changes in 2018 Pro Forma:

1. Added that either party may terminate in the event of a Force Majeure prior to the

Commercial Operation Date that extends beyond the Commercial Operation

Deadline. Also, made clear that Force Majeure does not include a curtailment at the

direction of the Transmission Provider or the CAISO when the curtailment is caused

by outages or capacity reductions due to maintenance construction or repair.

2. Added Seller indemnity obligations for: i) violation of Applicable Laws or CAISO

Tariff; ii) release of hazardous material; and iii) monetary penalties or fines against

SCE by the CPUC resulting from Sellers willful or negligent failure to provide SCE

with the full amount of RA.

3. Made changes related to late payment interest calculations including changing the

calculation of “Interest Rate” to incorporate the average annual interest rates reported

for all weekdays in the H.15 release published by the Federal Reserve.

4. Changed the Time of Delivery Periods and the Payment Allocation factors.

5. Modified language within certain sections of the agreement in order to address

conformity within SCE contracting language across all solicitations

6. Other non-substantive changes made to the 2018 Pro Forma reflect a re-organization

of certain credit terms and conditions in order to consolidate all of the credit related

provisions into a single article within the 2018 Pro Forma.

No changes were made to the 2018 Pro Forma REC Sales Agreement and the document remains the

same as in 2017.

B. Important Changes in the Written Plan

1. Removal of Time-of-Use and Expiring Contracts Information

In the 2017 RPS Plan, SCE included information on its Residential and Non-

Residential Time-of-Use (“TOU”) periods, in compliance with D.17-01-006, p. 67. In its 2017 Final

RPS Plan, approved by the Commission in D.17-12-007, SCE stated that “Going forward, Base TOU

periods will be addressed in SCE’s General Rate Case Phase 2 proceedings and consequently will

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not be included in subsequent RPS Plans.”71 Accordingly, in conformance with its statement in its

2017 RPS Plan, SCE has not included information on its Residential and Non-Residential TOU

periods in this 2018 RPS Plan.

2. Addition of Information on Electrification of Transportation

D.18-05-026 implementing SB 350 provisions on penalties and waivers in the RPS

program requires that: “Beginning with the 2018 Renewables Portfolio Standard Procurement Plan

cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually

demonstrate that transportation electrification is accounted for in their procurement plans by

explicitly referencing forecasted transportation electrification in their Renewables Portfolio Standard

procurement plans…”72 Accordingly, SCE added a discussion of its forecast of transportation

electrification in Section II.B, which discusses how SCE forecasts RPS need.

3. Revisions to REC Sales Strategy

In June of 2017, the Commission opened the PCIA OIR. SCE did not have the

opportunity to consider the impacts of that proceeding on its REC sales strategy in its 2017 RPS

Plan. However, at this point, the Commission has created a full evidentiary record in the PCIA OIR,

parties have submitted their briefs and the Commission has published both a Proposed and an

Alternate Proposed Decision in that proceeding. So, in this 2018 RPS Plan, SCE will present a REC

sales methodology that conforms to two possible scenarios for the outcome of the PCIA OIR. If the

final decision in the PCIA OIR differs from the two possible scenarios for the outcome of the PCIA

OIR that SCE presents, SCE may seek to update its 2018 RPS Plan to revise its REC sales strategies

in conformance with the final PCIA OIR decision.

In addition, in this 2018 RPS Plan, SCE generally proposes sale of all PCCs of RECs,

rather than just PCC 1, as it proposed in the 2017 RPS Plan. This is to give SCE the flexibility to

71 2017 Final RPS Plan, pp.62-63. 72 D.18-05-026, Ordering Paragraph No. 3, p. 32.

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sell more types of RECs in the market. SCE also proposes to sell RECs for longer terms (if there is a

market for such sales) and makes changes to its price floor methodology.

4. Removal of Information on Expiring Contracts

The ACR for the 2018 RPS Plan did not require inclusion of information on expiring

contracts, as the ACR for the 2017 RPS Plan did. Accordingly, SCE did not include information on

expiring contracts in this 2018 RPS Plan.

XV.

SAFETY CONSIDERATIONS

SCE is strongly committed to safety in all aspects of its business. Renewable sellers are

responsible for the safe construction and operation of their generating facilities and compliance with

all applicable laws and safety regulations. SCE has taken several steps to address those issues over

which it has the most visibility and control – the delivery of renewable electricity products to SCE in

a reliable, safe, and operationally sound manner.

As with past RPS pro forma PPAs, SCE’s 2018 Pro Forma provides that the seller must

operate the generating facility in accordance with “Prudent Electrical Practices.”73 The detailed

definition of “Prudent Electrical Practices” includes “those practices, methods and acts that would be

implemented and followed by prudent operators of electric energy generating facilities in the

Western United States, similar to the Generating Facility, during the relevant time period, which

practices, methods and acts, in the exercise of prudent and responsible professional judgment in the

light of the facts known or that should reasonably have been known at the time the decision was

made, could reasonably have been expected to accomplish the desired result consistent with good

business practices, reliability and safety. . . .”74

Consistent with SCE’s focus on safety, SCE’s 2018 Pro Forma also provides that, prior to

commencement of any construction activities on the project site, the seller must provide to SCE a 73 See 2018 Pro Forma (attached as Appendix F.1) at Section 3.12(a). 74 Id. at Exhibit A.

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report from an independent engineer certifying that seller has a written plan for the safe construction

and operation of the generating facility in accordance with Prudent Electrical Practices.75

SCE also has a safety section in its 2018 Procurement Protocol providing that sellers must

possess a written plan for the safe construction and operation of the generating facility as set forth in

the 2018 Pro Forma.76

XVI.

STANDARD CONTRACT OPTION

In D.14-11-042, the Commission ended the RAM program, as authorized in D.10-12-048,

after the conclusion of the RAM 6 auction.77 The Commission also authorized the IOUs to use an

optional streamlined RAM procurement tool in future RPS solicitations.78 The Commission directed

the IOUs to include the streamlined procurement tool in their RPS Procurement Plans, at their

discretion, starting with the 2015 RPS Procurement Plans.79

Since the Standard Contract Option is part of the RPS Solicitation, whether or not it gets

utilized will depend upon whether or not SCE holds a 2018 RPS Solicitation. Consistent with the

Commission’s intent to provide the IOUs with flexibility to optimize their portfolios based on their

procurement needs while providing a streamlined procurement tool,80 the Standard Contract Option

will allow for rapid development of renewable projects by avoiding the contract negotiation process

and expediting the Commission approval process of executed PPAs. The Standard Contract Option

75 Id. at Section 3.11(e). 76 See 2018 Procurement Protocol (attached as Appendix H.1) at Section 9.03. 77 See D.14-11-042 at pp. 91-92, pp. 102-104. 78 Id. at pp. 91-92. 79 Id. at p. 92. 80 Id.

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will only be available to projects with a first point of interconnection to the CAISO, and not to

dynamically scheduled projects.81

Once executed, the Standard Contract Option PPAs will be submitted to the Commission for

approval via a Tier 2 advice letter. This process uses the same approval process as in RAM, which

was one factor in SCE successfully procuring 787 MW of renewables over five years in six auctions.

In the sections below, SCE discusses the parameters of the Standard Contract Option and

their consistency with D.14-11-042.

A. Procurement Need

In D.14-11-042, the Commission stated that the IOUs should explain in their RPS

Procurement Plan filings how any proposed use of the streamlined RAM procurement tool could

satisfy an authorized procurement need, “including, for example, system Resource Adequacy needs,

local Resource Adequacy needs, RPS needs, reliability needs, LCR needs, GTSR needs, and any

need arising from Commission or legislative mandates.”82 If SCE holds a procurement for

Community Renewables, SCE will use the Standard Contract Option for Community Renewables

procurement needs as discussed in Section XVII. SCE may also use the Standard Contract Option to

fulfill other authorized procurement needs in the future.

B. Standard Contract

The Commission required IOUs to seek Commission authorization for a revised standard

contract so that the RAM tool can continue to be a more streamlined contracting and approval

process.83 SCE uses its current Pro Forma as the standard contract for the Standard Contract

Option. The RAM standard contract and SCE’s RPS pro forma PPAs are closely aligned.

Changes to the RPS pro forma PPA that were approved for use in RPS solicitations were

81 SCE’s 2018 Pro Forma is structured with the assumption that the generating facility will have a first

point of interconnection with the CAISO. Accordingly, changes to the 2018 Pro Forma will be required for dynamically scheduled projects.

82 D.14-11-042 at p. 92. 83 Id. at p. 93.

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subsequently requested and generally approved for use in the next RAM cycle, and vice versa.

Additionally, both the RPS pro forma PPA and the RAM standard contract have been drafted in a

manner that allows for the simple insertion of project specific information without any other

modifications to the terms and conditions. Specifically, project-specific parameters can be inserted

into the 2018 Pro Forma (e.g., project size, technology, location, and other project specific

attributes), and the resulting contract will be the standard contract. Additional non-material

ministerial changes to the 2018 Pro Forma may also be needed in the standard contracts; for

example, to correct typographical errors or section references or delete definitions that are not

needed for particular projects.

It will be considerably more efficient for SCE, the Commission, the parties, and the market to

update one pro forma PPA each year, rather than having separate pro forma PPAs for Standard

Contract Option and non-Standard Contract Option projects. Further, one pro forma PPA eliminates

market distortions that might come from commercial differences that could skew sellers toward or

away from the Standard Contract Option.

For 2018, SCE made changes to the SCE 2017 Pro Forma that are applicable to the Standard

Contract Option. Please see Section XIV(A).

XVII.

GREEN TARIFF SHARED RENEWABLES PROGRAM

On September 28, 2013, Governor Brown signed SB 43 into law.84 SB 43 enacted the GTSR

program, a 600 MW statewide program that allows participating utilities’ customers – including

local governments, businesses, schools, homeowners, municipal customers, and renters – to meet up

to 100% of their energy usage with generation from eligible renewable energy resources. As

required by SB 43, all of the IOUs filed applications with the Commission requesting approval of

GTSR programs consistent with the requirements and intent of the statute.

84 SB 43 was codified in California Public Utilities Code Section 2831 et seq.

61

On January 29, 2015, the Commission adopted D.15-01-051, implementing a GTSR program

framework and approving the IOUs’ applications with modifications. Among other things, the

Commission divided the GTSR program’s statewide limitation of 600 MW of customer participation

among the IOUs. Specifically, the Commission allocated 269 MW to SCE.85 SB 43 also provides

that 100 MW of the statewide limitation for the GTSR program shall be reserved for facilities that

are no larger than 1 MW and that are located in areas previously identified by the California

Environmental Protection Agency as “the most impacted and disadvantaged communities”86

(referred to as “environmental justice” or “EJ” projects by SCE). To implement this statutory

provision, the Commission established EJ and residential reservations for each IOU, including 45

MW to SCE.87

The GTSR program structure approved by the Commission consists of two elements: (1) a

green tariff option (called the “Green Rate” by SCE) allowing customers to purchase energy with a

greater share of renewables, and (2) an enhanced community renewables option (called the

“Community Renewables” or “CR” program by SCE) allowing customers to subscribe to renewable

energy from community-based projects.88 With regard to the Green Rate, SCE has already procured

its 50 MW advance procurement requirement in its 2015 RPS solicitation. SCE does not anticipate

doing additional Green Rate procurement. This is because the Green Rate program currently has a

limited number of subscribed customers and SCE’s advance procurement is expected to satisfy

initial customer enrollment.

A. Community Renewables - Background

The Commission authorized RAM as a procurement mechanism for the CR program,

including the streamlined RAM procurement tool that can be used as part of the IOUs’ RPS

85 See D.15-01-051 at Ordering Paragraph 7. 86 CAL. PUB. UTIL. CODE § 2833(d)(1). 87 See D.15-01-051 at Ordering Paragraph 7 and D.15-01-051 at pp. 4-5. 88 Id. at pp. 3-4.

62

solicitations.89 The Commission limited initial procurement to new solar facilities between 0.5 MW

and 3 MW,90 but modified this in D.16-05-006 to include all eligible renewable resources between

0.5 MW and 20 MW for CR projects and all eligible renewable resources between 0.5 MW and

1 MW for CR-EJ projects.91 Additionally, now that the CAISO has resolved Distributed Energy

Resource Provider issues, D.16-05-006 allows for aggregation of sub-500 kW resources to

participate in the CR program as long as they aggregate to at least 500 kW and meet all CAISO

requirements.92 CR projects must be located within SCE’s service territory93 and must satisfy the

eligibility requirements associated with the RAM procurement tool.94

SCE filed several advice letters to implement the CR program, including: (i) Advice 3180-E

identifying the eligible census tracts for EJ projects in its service territory;95 (ii) Advice 3218-E,

which is the IOUs’ Joint Procurement Implementation Advice Letter; (iii) Advice 3219-E, which is

SCE’s Customer-Side Implementation Advice Letter; (iv) Advice 3220-E, which is SCE’s

Marketing Implementation Advice Letter;96 (v) Advice 3432-E, which is the 20 Year Forecast of

GTSR bill credits and charges;97 and (vi) Advice 3422-E, which makes changes to SCE’s 2015 Pro

Forma Renewable Power Purchase and Sale Agreement , Standard Contract Option and RFO

instructions, needed to implement the CR program through the RAM procurement tool consistent

with D.16-05-006 (the “CR-RAM RFO”), and also requested closure of SCE’s CR-MAT program

89 Id. at Ordering Paragraph 1. 90 Id. at pp. 36-37, p. 39, Conclusion of Law 17. 91 See D.16-05-006, Conclusions of Law 2 and 4. 92 Id. at Ordering Paragraph 5. 93 See D.15-01-051 at pp. 21-23, Conclusion of Law 14. 94 See D.16-05-006 at p. 35, Conclusion of Law 4. 95 Advice 3180-E was approved by Energy Division, effective as of February 23, 2015. 96 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution

E-4734. 97 Advice 3432-E was approved by Energy Division, effective as of July 11, 2016.

63

because projects eligible for SCE’s CR-MAT program will also be eligible for SCE’s CR-RAM

program.98

Post-implementation of the CR program, SCE has filed several advice letters and other

compliance filing to update the CR program, including: (i) Advice 3461-E, which updated the CR-

RAM Rider and RFO Instructions for CR-RAM One;99 (ii) Advice 3496-E, 2017 annual marketing,

education and outreach plan and budget for the GTSR program;100 (iii) Advice 3525-E, which is

SCE’s GTSR program rate component updates for 2017;101 (iv) Advice 3525-E-A, supplemental

filing to make modifications to Advice 3525-E;102 (v) Advice 3536-E, which implements the

California alternate rates for energy for the GTSR Program;103 (vi) Advice 3557-E, which updated

the CR-RAM Rider and RFO Instructions for CR-RAM Two;104 (vii) Advice 3614-E, which is the

update to the 20 Year Forecast of GTSR bill credits and charges;105 (viii) Petition for Modification

(“PFM”) for D.15-01-051 to change the AmLaw 100106 securities opinion requirement;107

(ix) Advice 3638-E, modifying the securities opinion requirement in the CR-RAM Rider pursuant to

D.17-07-007;108 (x) Advice 3694-E, which updated the CR-RAM Rider and RFO Instructions for

CR-RAM Three;109 (xi) Advice 3678-E, 2018 annual marketing, education and outreach plan and 98 Advice 3422-E was approved by Energy Division, effective as of June 15, 2016. 99 Advice 3461-E was approved by Energy Division, effective as of September 25, 2016. 100 Advice 3496-E was approved by Energy Division, effective as of November 27, 2016. 101 Advice 3525-E was approved by Energy Division, effective as of January 1, 2017. 102 Advice 3525-E-A was approved by Energy Division, effective as of January 1, 2017. 103 Advice 3536-E was approved by Energy Division, effective as of October 26, 2017. 104 Advice 3557-E was approved by Energy Division, effective as of March 12, 2017. 105 Advice 3614-E was approved by Energy Division, effective as of June 5, 2017. 106 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United

States based on gross revenue. 107 SCE submitted the PFM on March 27, 2017; the CPUC issued D.17-07-007 on July 17, 2017,

implementing the requested changes in the PFM. 108 Advice 3638-E was approved by Energy Division, effective as of July 28, 2017. 109 Advice 3694-E was approved by Energy Division, effective as of November 15, 2017.

64

budget for the GTSR program;110 (xii) Advice 3678-E-A, supplement to Advice 3678-E;111

(xiii) Advice 3710-E, GTSR program rate component update for 2018;112 (xiv) Advice 3710-E-A,

supplement to Advice 3170-E;113 (xv) Advice 3737-E, which updated the 20-year forecast of GTSR

bill credits and charges;114 and (xvi) Advice 3790-E, which updated the CR-RAM Rider and RFO

Instructions for CR-RAM Four.115

B. Community Renewables - Modifications to the 2018 Procurement Protocol, 2018 Pro

Forma Standard Contract Option, and LCBF Methodology

SCE incorporated CR-related modifications into its 2016 Procurement Protocol, created a CR

Rider and Amendment to the 2016 Pro Forma Standard Contract Option, and incorporated

modifications to its LCBF Methodology for CR and CR-EJ eligible projects. SCE planned to

include a Community Renewables solicitation in any 2016 RPS solicitation that it would hold after

seeking and receiving Commission permission. SCE intended that if it did not go forward with a

2016 RPS solicitation, it would move forward separately with a second Community Renewables

Solicitation, which SCE launched on April 7, 2017.

SCE incorporated additional CR-related modifications into its 2017 Procurement Protocol

and updated its CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option, which

is the latest approved contract option. SCE subsequently launched its third and fourth Community

Renewables Solicitations on December 22, 2017 and May 23, 2018, respectively. As of CR-RAM 3,

110 Advice 3678-E was approved by Energy Division, effective as of November 15, 2017. 111 Advice 3678-E-A was approved by Energy Division, effective as of November 15, 2017. 112 SCE submitted Advice 3710-E on November 30, 2017, which has not been approved as of the date of this

filing. 113 SCE submitted Advice 3710-E-A on December 22, 2017, which has not been approved as of the date of

this filing. 114 Advice 3737-E was approved by Energy Division, effective as of January 31, 2018. 115 Advice 3790-E was approved by Energy Division, effective as of May 20, 2018.

65

SCE has provided two CR-RAM Rider options to offerors—one specifically for Distributed Energy

Resources (“DERs”) and the other for projects that do not aggregate resources.

1. 2018 Procurement Protocol – CR Modifications

The 2018 Procurement Protocol does not include any requirements applicable only to

CR and CR-EJ projects. If SCE holds a CR-RAM Solicitation, SCE will file an Advice Letter and

include a CR-RAM specific protocol.

C. SCE’s Request to Terminate the GTSR Program

On December 22, 2017, SCE filed a Tier 3 Advice 3722-E requesting the Commission’s

approval to terminate the GTSR program on January 1, 2019,116 and to seek approval to recover

outstanding GTSR costs through the 2018 ERRA Review of Operations Filing.117 As of the date of

this filing, Advice 3722-E is pending Commission approval.

D. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar

Programs

On June 21, 2018, the Commission approved D.18-06-027, Alternate Decision Adopting

Alternatives to Promote Solar Distributed Generation in Disadvantaged Communities, which

implements three new programs to promote solar energy in disadvantaged communities. Two of the

programs, the new DAC-Green Tariff program and the Community Solar Green Tariff program, are

similar to the GTSR Green Rate and Enhanced Community Renewables programs, respectively.

The DAC - Green Tariff Program will be available only to low-income residential customers in

DACs, defined as those meeting the qualifications for CARE and FERA. The Community Solar

Green Tariff Program will be similar to the DAC - Green Tariff program. The major difference

between the DAC-Green Tariff program and the Community Solar Green Tariff program is that the

Community Solar Green Tariff program requires community involvement with the solar project

through a local sponsor and will result in a solar facility serving a nearby community. The program 116 See D.15-01-051 at Ordering Paragraph 13. 117 Advice 3722-E.

66

is similar to Enhanced Community Renewables in that the developer contracts with the customer to

service the energy component of the bill and contracts with SCE for the energy not subscribed by the

SCE customer. Currently, SCE has not filed an Advice Letter nor received approval of Advice

Letters for implementation of the DAC-Green Tariff and Community Solar Green Tariff Programs.

Any details on the procurement would be premature without approval from the Commission of the

implementation Advice Letter. The Advice Letter is scheduled to be filed on August 20, 2018.

Details of the procurement will be addressed in that Advice Letter and can be incorporated in any

updated RPS Plan.

E. SCE’s GTSR Replacement Program

In Advice 3722-E, in which it requested the Commission’s approval to terminate the GTSR

program, SCE stated it would propose a replacement program for GTSR. SCE is projected to file an

Application for the GTSR replacement program later this year and full details of the program will be

included in the Application.

XVIII.

OTHER RPS PLANNING CONSIDERATIONS AND ISSUES

A. Bilateral Transactions

As part of its overall procurement strategy, SCE may engage in bilateral negotiations for

renewable energy purchases or sales subject to the Commission’s review and approval of completed

transactions.

B. Energy Storage Procurement

Public Utilities Code Section 2837 requires the IOUs’ RPS Procurement Plans to incorporate

any energy storage targets and policies that are adopted by the Commission as a result of its

implementation of Assembly Bill (“AB”) 2514. To implement AB 2514, the Commission adopted

D.13-10-040, which implemented an energy storage procurement framework and design.

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The Commission also directed SCE to procure 580 MW of energy storage by 2020, with projects

installed and delivering by 2024.118

SCE considers eligible energy storage systems to help meet its energy storage target through

several different programs including conducting an Energy Storage RFO, the Aliso Canyon Energy

Storage RFO and other programs that may incorporate energy storage facilities. Further details on

SCE’s energy storage procurement can be found in SCE’s Energy Storage Plan.119

118 See D.13-10-040 at pp. 15, 26. 119 See Southern California Edison Company’s (U 338-E) Application for Approval of its 2016 Energy

Storage Procurement Plan (filed biennially). The Application can be located here: http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/14A8421BD056DFC488257F69006CF6CF/$FILE/A.16-03-XXX_2016%20ESPP_SCE%20Energy%20Storage%20Procurement%20Plan%20Application.pdf.

PUBLIC APPENDIX A

Redline of 2017 Written Plan

(U 338-E)

2017 Final2018 Written Plan

January 17,August 20, 2018

PUBLIC VERSION

20172018 Written Plan Table Of Contents

Section Page

-i-

I. EXECUTIVE SUMMARY OF 20172018 RPS PLAN ...................................................................1

II. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND ......................................................................................................................................57

A. SCE’s Renewables Portfolio ..............................................................................................57

B. SCE’s Forecast of Renewable Procurement Need .............................................................68

C. SCE’s Plan for Achieving RPS Procurement Goals ......................................................1016

D. SCE’s Portfolio Optimization Strategy ..........................................................................1218

E. SCE’s Management of its Renewables Portfolio ...........................................................1420

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues .............................................................................................1522

1. Lessons Learned and Past and Future Trends ....................................................1522

a) Possible Future Trend Toward Departing Load .......................................................................................................1622

b) Need for REC Sales ...............................................................................1824

III. PROJECT DEVELOPMENT STATUS UPDATE ...................................................................1925

IV. POTENTIAL COMPLIANCE DELAYS ..................................................................................1925

A. Curtailment ....................................................................................................................2026

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio .....................................................................................................2127

C. Permitting, Siting, Approval, and Construction ofRenewable Generation Projects and Transmission .......................................................2228

D. A Heavily Subscribed Interconnection Queue ...............................................................2329

E. Developer Performance Issues .......................................................................................2329

F. Load Uncertainty Including Faster Implementation of Transportation Electrification And Departing Load ..........................................................30

V. RISK ASSESSMENT ................................................................................................................2430


Section Page

-ii-

VI. QUANTITATIVE INFORMATION .........................................................................................2431

A. RNS Calculations ...........................................................................................................2431

B. Response to RNS Questions ..........................................................................................2632

1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? ..................................................................................................................2632

2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. .................................................................2633

3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ........................................2733

4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? ..............................................2834

5. As projects in development move towards their commercial operation date, are there any changes to the expected RPS deliveries? If so, how do these changes impact the RNS? ..................................................................................2835

6. What is the appropriate amount of RECs above the procurement quantity requirement (“PQR”) to maintain? Please provide a quantitative justification and elaborate on the need for maintaining banked RECs above the PQR. ........................................................................................2935

7. What are your strategies for short-term management (10 years forward) and long-term management (10-20 years forward) of RECs above the PQR? Please discuss any plans to use RECs above the PQR for future RPS compliance and/or to sell RECs above the PQR. .............................................................................................................2935

8. Provide Voluntary Margin of Over-procurement (“VMOP”) on both a short-term (10 years forward) and long-term (10-20 years forward) basis. This should include a discussion of all risk factors and quantitative justification for the amount of VMOP. ..........................................3036


Section Page

-iii-

9. Please address the cost-effectiveness of different methods for meeting any projected VMOP procurement need, including application of forecast RECs above the PQR. ........................................................................................3037

10. Are there cost-effective opportunities to use banked RECs above the PQR for future RPS compliance in lieu of additional RPS procurement to meet the RNS? ..................................................................................................................3137

11. How does your current RNS fit within the regulatory limitations for portfolio content categories? Are there opportunities to optimize your portfolio by procuring RECs across different portfolio content categories? ..........................................................................................................3137

VII. MINIMUM MARGIN OF PROCUREMENT ..........................................................................3238

VIII. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES .................................................................................................................3339

A. Bid Solicitation Protocol ................................................................................................3339

B. LCBF Methodology .......................................................................................................3440

IX. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..........................................3441

X. ECONOMIC CURTAILMENT, FREQUENCY, COSTS ANDFORECASTING .............................................................................................................................3542

XI. AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS ...................................................................................................................................3744

A. Justification of SCE’s Request for a Tier 1 Advice Letter Approval Process for a Limited Amount of Short-Term RPS-Eligible Transactions .............................................................................................3744

1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future ........................................................3744

2. California Customers Need an Open Market for RECs ..................................................................................................................3844

3. REC Sales Will Create Customer Value ............................................................3946


Section Page

-iv-

a) Selling is better than banking up to the established limits ....................................................................................3946

b) Published Research From Independent Entities Forecasting Decline and/or Stabilization of Renewable Energy Costs ..................................................40

c) REC Sales Stabilize Rates By Realizing Near Term Value ............................................................................................4047

dc) SB 350 Allows for IOUs’ Use Of More ShortTerm-term Products, Which Could Help Lower Costs for Customers, While Requiring Other LSEs to Use More Long Term-termProducts..................................................................................................4148

B. SCE’s Proposal ..............................................................................................................4249

1. Tier 1 Advice Letter Approach ..........................................................................4249

2. Tier 3 Approval Process .....................................................................................4451

C. SCE’s Proposed Limits on REC Sales ...........................................................................4451

D. Acceptable REC pricing ................................................................................................4451

E. Proposed Transactional Methods ...................................................................................4451

1. Competitive Solicitations ...................................................................................4552

2. Bilateral Transactions ........................................................................................4552

3. Brokers ...................................................................................................................45

F. Proposed Timeline for REC Sales .................................................................................4752

G. Alternate Approach Is Adopted In PCIA OIR Proceeding ................................................53

XII. EXPIRING CONTRACTS ............................................................................................................47

XIII. COST QUANTIFICATION ........................................................................................................4753

XIVXIII.IMPERIAL VALLEY .............................................................................................................4753

XVXIV.IMPORTANT CHANGES FROM 20162017 RPS PLAN......................................................4754


Section Page

-v-

A. Important Changes in 2017 Procurement Protocol ............................................................48 2018 Pro Forma .................................................................................................................54

1. Only REC Sales Will Be Part of this Solicitation ..................................................48

B. Important Changes in 2017 Pro Forma and REC Sales Agreement ..........................................................................................................................48 the Written Plan .................................................................................................................55

C. Important Changes in 2017 Least Cost, Best Fit Methodology ......................................................................................................................49

1. Capacity benefit for Solar and Wind resources .....................................................49 Removal of Time-of-Use and Expiring Contracts Information ............................................................................................................55

2. Addition of Information on Electrification of Transportation ........................................................................................................56

3. Revisions to REC Sales Strategy ...........................................................................56

4. Removal of Information on Expiring Contracts ....................................................57

XVIXV.SAFETY CONSIDERATIONS ...............................................................................................5057

XVIIXVI.STANDARD CONTRACT OPTION ...................................................................................5158

A. Procurement Need ..........................................................................................................5259

B. Standard Contract ...........................................................................................................5259

XVIIIXVII.GREEN TARIFF SHARED RENEWABLES PROGRAM...............................................5360

A. Community Renewables - Background .........................................................................5461

B. Community Renewables - Modifications to the 20172018Procurement Protocol, 20172018 Pro Forma Standard Contract Option, and LCBF Methodology ....................................................................5764

1. 20172018 Procurement Protocol – CR Modifications............................................................................................................................5765


Section Page

-vi-

2. 2017 Pro Forma, Standard Contract Option – CR Rider and Amendment Modifications ....................................................................58

3. LCBF – CR Modifications .....................................................................................59

C. Green Rate and Community Renewables – Annual Reporting............................................................................................................................60

D. SCE’s Request to Terminate the GTSR Program ..........................................................6165

D. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar Programs ........................................................................................65

E. SCE’s GTSR Replacement Program .................................................................................66

XIXXVIII.OTHER RPS PLANNING CONSIDERATIONS AND ISSUES....................................................................................................................................................6166

A. Bilateral Transactions ....................................................................................................6166

B. Energy Storage Procurement .........................................................................................6166

C. TOU Rate Periods ..............................................................................................................62


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CONFIDENTIAL/PUBLIC APPENDIX A REDLINE OF 2017 WRITTEN PLAN

CONFIDENTIAL/PUBLIC APPENDIX B PROJECT DEVELOPMENT STATUS UPDATE

CONFIDENTIAL/PUBLIC APPENDIX C.1 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH GAM

CONFIDENTIAL/PUBLIC APPENDIX C.2 PHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS,WITHGAM

CONFIDENTIAL APPENDIX C.3 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH GAM

CONFIDENTIAL APPENDIX C.4 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH GAM

CONFIDENTIAL/PUBLIC APPENDIX DC.5 COST QUANTIFICATION TABLEPHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH PCIA

CONFIDENTIAL/PUBLIC APPENDIX EC.6 RECS FROM EXPIRING CONTRACTSPHYSICAL RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH PCIA

PUBLICCONFIDENTIAL APPENDIX FC.17 OPTIMIZED RENEWABLEENERGY SALES AUTHORIZED BROKERS NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS, WITH PCIA

CONFIDENTIAL APPENDIX C.8 OPTIMIZED RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS, WITH PCIA

CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE

CONFIDENTIAL APPENDIX F.2E RENEWABLE ENERGY SALES

PUBLIC APPENDIX GF.1 20172018 PRO FORMA


-viii-

RENEWABLE POWER PURCHASE AGREEMENT

PUBLIC APPENDIX GF.2 REDLINE OF 2017 PRO FORMARENEWABLE POWER PURCHASE AGREEMENT

PUBLIC APPENDIX HG.1 SCE’S 2018 LEAST-COST BEST-FIT METHODOLOGY

PUBLIC APPENDIX HG.2 REDLINE OF SCE’S 2017 LEAST-COST BEST-FIT METHODOLOGY

PUBLIC APPENDIX IH.1 20172018 PROCUREMENT PROTOCOL

PUBLIC APPENDIX IH.2 REDLINE OF 2017 PROCUREMENT PROTOCOL

PUBLIC APPENDIX JI.1 2018 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX J.2 REDLINE OF 2017 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX JI.32 SCE COVER SHEET TO EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX JI.43 EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX JI.54 COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX JI.65 PARAGRAPH 10 TO THE COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

1

I.

EXECUTIVE SUMMARY OF 20172018 RPS PLAN

In accordance with the Assigned Commissioner and Assigned Administrative Law Judge’s

Ruling Identifying Issues and Schedule of Review for 20172018 Renewables Portfolio Standard

(“RPS”) Procurement Plans, dated May 26, 2017June 21, 2018 (“ACR”), and the E Mail Ruling

Granting, in Part, IOUs1 Request for an Extension of Time to Produce the 20172018 RPS

Procurement Plans, dated June 19, 2017, and the Decision Accepting Draft 2017 RPS Procurement

Plans, Decision No. (“D.”) 17-12-007, dated December 18, 2017,July 9, 2018, Southern California

Edison Company’s (“SCE’s”) 20172018 RPS Procurement Plan (“20172018 RPS Plan”) details SCE’s

plan for satisfying the State’s RPS goals in a manner that minimizes costs and maximizes value for

SCE’s customers. On August 20, 2018, SCE filed its 2018 RPS Plan in the R.18 07 003 docket. On

August 28, 2018, Administrative Law Judge (“ALJ”) Robert Mason, issued an E Mail Ruling ordering

SCE to refile its 2018 RPS Plan in the R.15 02 020 docket. So, SCE now resubmits this 2018 RPS Plan

in the R.15 02 020 docket.

This 20172018 RPS Plan discusses SCE’s renewables portfolio, the process SCE uses for

forecasting its renewable procurement need, SCE’s forecasted renewable procurement position

through 2030, SCE’s portfolio optimization strategy and management of its renewables portfolio,

lessons learned from SCE’s experience with renewable procurement, past and future trends, and

additional policy and procurement issues. Additionally, SCE explains its plans for achieving

California’s RPS targets, including SCE’s plan on whether or not to conduct a 2017 RPS solicitation

procuringin 2018 (“2018 RPS Solicitation”) to procure new RPS eligible resources, and its plan to sell

Renewable Energy Credits (“RECs”). SCE’s 2017 RPS Plan includes its 2017

There is no final decision in the Power Charge Indifference Adjustment (“PCIA”) OIR,

Rulemaking (“R.”) 17-06-026, at this time. SCE will present one methodology regarding a 2018 RPS

1 The IOUs are the Investor -Owned Utilities, which include Pacific Gas and Electric Company (“PG&E”), Southern California Edison Company (“SCE”), and San Diego Gas & Electric Company (“SDG&E”).

2

Solicitation for REC Sales assuming two different outcomes to that proceeding.2 SCE also requests an

opportunity to update the REC Sales methodology in this 2018 RPS Plan 60 days after the issuance of

a final decision in the PCIA OIR, if the ultimate outcome of the PCIA OIR differs from the two

outcomes upon which SCE based its REC sales strategy presented here. SCE’s 2018 RPS Plan

includes its 2018 Procurement Protocol, 20172018 Pro Forma Renewable Power Purchase

Agreement, 20172018 Pro Forma RECs Sales Agreement, and a description of SCE’s least-cost

best-fit (“LCBF”) evaluation methodology, including consideration of workforce development and

disadvantaged communities, and a summary of the important changes from SCE’s 20162017 RPS

solicitation documents.

Further, this 20172018 RPS Plan addresses other issues set forth in the ACR, statute, and other

California Public Utilities Commission (“Commission” or “CPUC”) decisions. Specifically, SCE’s

20172018 RPS Plan includes discussion of the following additional topics:

Project development status update;

Potential compliance delays and risks;

Quantitative information discussing SCE’s renewable compliance;

Minimum margin of procurement;

Consideration of price adjustment mechanisms;

Economic curtailment;

One REC sales methodology assuming two different potential outcomes of the PCIA OIR,

including the same Tier 1 and Tier 3 Advice Letter processes to sell RECs;for

Commission review of REC sales as in the 2017 RPS Plan;

2 SCE is aware of the California Public Utilities Commission’s (“Commission’s”) plan to provide further guidance to the IOUs in managing their legacy portfolios in a PCIA Phase 2 proceeding. If a final PCIA Phase 2 decision warrants change to our then existing 2018 RPS Solicitation for REC Sales, we will request a change to the 2018 RPS Plan after the issuance of that decision. In the meantime, SCE understands that all actions taken consistent with a Commission-adopted 2018 RPS Plan, prior to any change associated with a PCIA Phase 2 final decision, are per se reasonable consistent with the Assembly Bill (“AB”) 57 procurement framework.

3

Expiring contracts;

Cost quantification tables;

Imperial Valley issues;

Safety considerations;

Standard Contract Option using the streamlined Renewable Auction Mechanism (“RAM”)

procurement tool;

The potential termination of the Green Tariff Shared Renewables (“GTSR”) program, in

particular the enhanced Community Renewables (“ECR” or “CR” by SCE) program

and its replacement with another program; and

Other RPS planning considerations and issues.

SCE takes the RPS program’s regulatory framework into account. Senate Bill (“SB”) 2 (1x),

which took effect on December 10, 2011, increased the overall target percentage of procurement from

renewable resources from 20% to 33%, by 2020, and departed from the prior structure of annual RPS

goals and moved to multi-year compliance periods, with interim procurement targets established for

each multi-year compliance period. The Commission has issued several decisions implementing SB 2

(1x), including Decision (“D.”) 11-12-020 setting RPS procurement quantity requirements,23

D.11-12-052 implementing the three portfolio content categories of renewable energy products that

may be used to satisfy RPS targets,34 D.12-06-038 establishing new compliance rules for the RPS

23 As implemented by the Commission in D.11-12-020, pp. 2-3, the RPS procurement quantity requirements applicable to all retail sellers are as follows: (1) 20% of overall retail sales for the first compliance period from 2011-2013; (2) 21.7% of 2014 retail sales, plus 23.3% of 2015 retail sales, plus 25% of 2016 retail sales for the second compliance period from 2014-2016; (3) 27% of 2017 retail sales, plus 29% of 2018 retail sales, plus 31% of 2019 retail sales, plus 33% of 2020 retail sales for the third compliance period from 2017-2020; and (4) 33% of retail sales in each year thereafter.

34 The first portfolio content category (“Category 1”) includes products from renewable generators with a first point of interconnection to the Western Electricity Coordinating Council (“WECC”) transmission system within the boundaries of a California Balancing Authority Area (“CBA”), or with a first point of interconnection with the electricity distribution system used to serve end users within the boundaries of a CBA, or where the renewable generation is dynamically transferred to a CBA, or scheduled into a CBA on an hourly basis without substituting electricity from another source. The second portfolio content category (“Category 2”) includes firmed and shaped products. The third portfolio content category (“Category 3”) includes all other renewable electricity products, including unbundled RECs. Retail sellers are subject to a

(Continued)

4

program, and D.14--12-023 setting enforcement rules for the RPS program. The Commission has not

yet established a cost limitation for RPS-related procurement expenditures for each electrical

corporation.

On October 7, 2015, Governor Brown signed SB 350 which, among other significant changes

to the RPS program, increases the State’s RPS goals to 50% by 2030. In 2016, the Commission issued

D.16-12-040 implementing compliance periods and Procurement Quantity Requirements (“PQR”) for

compliance with the revised requirements of California RPS mandated by SB 350. On June 29, 2017,

the Commission issued D.17-06-026 revising compliance requirements for the California RPS in

accordance with SB 350. D.17-06-026 focused on changes affecting the role of long -term contracts in

RPS procurement and the methodology for determining how excess procurement in one compliance

period may be applied to later compliance periods. D.17-06--06-026 adopted SB 350 requirements

that California Load Serving Entities (“LSEs”) must enter into ownership or contractual arrangements

of 10 years or more for eligible renewable resources for 65% of their PQR for all compliance periods

beginning January 1, 2021.5 D.17-06-026 also requires retail sellers to give notice of their election for

early compliance with long-term contracting requirements in Pub. Util. Code §399.13(b) by a letter

sent to the Director of Energy Division within 60 days from the effective date of the decision (which

iswas August 28, 2017).46

On August 28, 2017, SCE sent a letter to the Director of Energy Division giving notice of its

election for early compliance with long-term contracting requirements in Pub. Util. Code §399.13.57

D.17-06-026 also requires that any “retail seller making the early election in 2017 must file a motion to

Continued from the previous pageminimum portfolio content category target (varying by compliance period) for Category 1 products and a maximum portfolio content category target (varying by compliance period) for Category 3 products. The remainder may be satisfied by Category 2 products.

5 D.17-06-026, pp. 8-10.46 D.17-06-026, Ordering Paragraph 23, p. 56. 57 On the same day, Energy Division, through an email from Brent Tarnow, acknowledged receipt of SCE’s

notice.

5

update its 2017 renewable portfolio standard procurement plan to reflect the election not later than the

deadline for filing motions to update such plans”6 (which are due on September 22, 2017).78 .As

required by D.17-06-026, on September 22, 2017, SCE filed a motion to update its 2017 RPS Plan to

reflect its election for early compliance and to reflect compliance with requirements in D.17-01-006

that it include its current TOU rate periods in its 2017 RPS Plan. In particular, SCE’s calculation of its

renewable net short position has changed as a result of its early election. Accordingly, SCE updated

the discussion of the renewable net short amount in the Written Plan and the calculations of the new

renewable net short in Appendices C.1, C.2, C.3, C.4, and F.2 as a result of the early election through

the motion to update the 2017 RPS PlanD.17-12-007, dated December 14, 2017, granted SCE’s

motion to update in Ordering Paragraph No. 13.9

While SCE has elected early compliance with long-term contracting requirements in SB 350,

not all LSEs have done so. Beginning in 2021, all LSEs will need to comply with the 65% of PQR

long-term contracting requirements in SB 350. In anticipation of this change in 2021, SCE requests

authority to make REC sales for the balance of a particular contract or of 10 years in order to maximize

the value of its RECs for its bundled service customers.

On June 6, 2018, the Commission issued D.18-05-026 implementing SB 350 provisions on

penalties and waivers in the RPS program. D.18-05-026 maintained the existing RPS penalty scheme

and integrated changes made by SB 350 into the current RPS waiver scheme. Ordering Paragraph No.

3 of D.18-05-026 requires that:

6 D.17-06-026, Ordering Paragraph 24, p. 56.78 ED.17-Mail Ruling Granting, in Part, IOUs Request for an Extension of Time to Produce the 2017 RPS

Procurement Plans, dated June 19, 2017.06-026, Ordering Paragraph 24, p. 56.9 D.17-12-007, Ordering Paragraph 13, p. 73.

6

Beginning with the 2018 Renewables Portfolio Standard Procurement Plan cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually demonstrate that transportation electrification is accounted for in their procurement plans by explicitly referencing forecasted transportation electrification in their Renewables Portfolio Standard procurement plans; providing a detailed description of the data and method used to support their forecast; and explaining how they considered the California Energy Commission’s Integrated Energy Policy Report transportation electricity demand forecast in creating their own forecast.10

Accordingly, SCE is adding a discussion of its forecast of transportation electrification in Section II.B,

which discusses how SCE forecasts RPS need.

SCE’s renewable procurement planning may change as a result of the Commission’s further

implementation of SB 350’s changes to the RPS program, adoption of new RPS legislation, a

procurement expenditure limitation mechanism, or other changes to the RPS program.

SCE’s analysis of its renewable procurement need is discussed herein. SCE does not have a

need for renewable energy at this time to satisfy its RPS program targets. In this 20172018 RPS Plan,

SCE does not proposeproposes to not hold a 20172018 RPS solicitation for the procurement of eligible

renewable resources. Instead, because SCE projects that it will not need new eligible renewable

resources for the foreseeable futureIf SCE’s preferred scenario as set forth in the Integrated Resource

Plan (“IRP”) proceeding11 is adopted, then SCE may seek to hold a solicitation to procure

non-Greenhouse Gas (“GHG”) emitting resources, including renewable energy, under the IRP docket.

In this RPS docket, SCE proposes to sell RECs, as described in Section XI below and in Appendix F.1

and F.2.E.

If in future years SCE holds a solicitation, SCE would use a solicitation process that is intended

to capitalize on the maturing renewables market and target the most viable proposals that fit SCE’s

compliance and reliability needneeds and provide the most value to customers. In order to submit a

proposal, SCE will require that projects have: (1) a Phase II Interconnection Study (or an equivalent or

more advanced interconnection status or exemption); and (2) an “application deemed complete” (or

equivalent) status within the applicable land use entitlement process. Because of uncertainty

10 D.18-05-026, Ordering Paragraph 3, p. 32.11 R.16-02-007.

7

surrounding SCE’s long-term load forecast due to potential changes in its load profile (i.e., the effects

of electric transportation, local solar photovoltaic (“PV”) generation, and departing load), SCE would

request that all bidders submit one offer for a term of 10 years or less for each project.

In this 20172018 RPS Plan, SCE will request offers from parties interested in purchasing REC

products from SCE. In its 2017 RPS Plan, SCE planned to request offers from parties interested in

purchasing Category 1 REC products from SCE. Also, SCE willonly. In this 2018 RPS Plan, SCE

expands its proposal for the REC products that it may sell in order to maximize its flexibility to sell a

variety of REC products. Also, SCE may bid into other parties’ solicitations seeking Category 1 REC

products. Assuming the adoption of the IOUs’ Green Allocation Mechanism (“GAM”) proposal in the

PCIA OIR, SCE forecasts a net short position after 2027 with the use of bank. Assuming that no REC

allocation methodology is adopted in the PCIA proceeding, SCE does not forecast a net short position

potential until 2030 with the use of bankthrough 2030 and beyond with the use of bank. Although the

Commission has issued both a proposed decision and an alternate decision in the PCIA OIR, at this

time, the outcome of that proceeding is unknown. Additional uncertainty exists regarding other

factors such as the future departing load levels, especially as it relates to the formation of additional

Community Choice Aggregators (“CCAs”) (see Section II.F.1.A below for a discussion on CCAs).

Therefore, in order to maximize value for customers, SCE willmay sell vintage 2017 through 2020

Category 1REC products, consistent with its proposal in this 20172018 RPS Plan.

II.

ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND

A. SCE’s Renewables Portfolio

For the first compliance period from 2011 through 2013, SCE served 20.6% of its retail sales

from RPS-eligible resources.8 In 2014, SCE served 23.4% of its retail sales from RPS-eligible

resources. In 2015, SCE served 24.3% of its retail sales from RPS-eligible resources. In 2016, SCE

served 28.2% of its retail sales from RPS-eligible resources.

8 SCE retired RECs amounting to 20.6% of its retail sales for the first compliance period.

8

Table II-1 below shows SCE’s percentage of retail sales for its RPS-eligible resources:

Table II-1 Percentage of SCE’s Retail Sales from RPS-Eligible Resources

Compliance Period Year(s) % of Retail Sales from RPS Eligible Resources

First 2011-2013 20.6

Second 2014-2016 25.3

2017 2017 31.6

To date, SCE’s RPS-eligible deliveries and executed renewable procurement contracts have

resulted from SCE’s RPS solicitations, SCE’s Renewables Standard Contract program, the Assembly

Bill 1969 feed-in tariffs, RAM and Bioenergy Renewable Auction Mechanism (“BioRAM”) auctions,

the Renewable Market Adjusting Tariff (“ReMAT”),912, the Bioenergy Market Adjusting Tariff

(“BioMAT”), the utility-owned generation and independent power producer (“IPP”) portions of

SCE’s Solar Photovoltaic Program (“SPVP”), the GTSR program,1013 SCE’s Preferred Resources

Pilot (“PRP”) program, qualifying facility (“QF”) contracts, utility-owned small hydro projects, and

bilateral opportunities.

SCE did not hold an RPS Solicitation in 2016 but did sign two contracts from the 2015 RPS

Solicitation for 253 MW, 12 ReMAT contracts for approximately 23 MW, three Bio-RAM contracts

for approximately 67 MW, two GTSR contracts for 40 MW, and three QF standard offer contracts for

approximately 11 MW in 2016 and through June 2017. either 2016 or 2017. However, in 2017 and so

far in 2018, SCE has signed the following renewable contracts:


1013 Only RECs associated with unsubscribed GTSR energy deliveries may be used for SCE’s RPS compliance. See D.15-01-051 at pp. 43-44; Ordering Paragraph 12.

9

Three ReMAT contracts for 7.5 MW

Two QF standard offer contracts for approximately 0.6 MW; and

Five BioMAT contracts for approximately 8.2 MW

B. SCE’s Forecast of Renewable Procurement Need

SCE determines its expected renewable procurement need by comparing its forecasted RPS

targets to its forecasted energy deliveries from contracted projects. The forecasted energy deliveries

include SCE’s probabilistic risk-adjusted forecast of generation from contracted projects that are not

yet online. SCE also considers generation from pre-approved procurement programs (i.e., ReMAT,

BioMAT), among other factors.

Appendices C.1 through C.48 include SCE’s forecast of its renewable procurement position

and need – i.e., SCE’s renewable net short (“RNS”) – based on the RPS targets adopted by the

Commission in D.11-12-020 for all years through 2020 as well as the RPS targets adopted by the

Commission in D.16-12-040 for the years 2021 through 2030. Table II-2 below summarizes the types

of information presented in Appendices C.1 through C.8.

Table II-2 Summary of Information Included in Appendices C.1-C.8

Appendix PCIA Outcome Nature of Calculation

Assumptions Used

C.1 GAM Physical RNS Commission’s Assumptions with adoption of GAM

C.2 GAM Physical RNS SCE’sassumptions with adoption of GAM

C.3 GAM Optimized RNS Commission’s assumptions with adoption of GAM

C.4 GAM Optimized RNS SCE’sassumptions with adoption of GAM

C.5 No Allocation of RECs in PCIA Physical RNS Commission’s Assumptions with No Allocation of RECs

C.6 No Allocation of RECs in PCIA Physical RNS SCE’sassumptions with

10

No Allocation of RECs

C.7 No Allocation of RECs in PCIA Optimized RNS Commission’s Assumptions with No Allocation of RECs

C.8 No Allocation of RECs in PCIA Optimized RNS SCE’sAssumptions with No Allocation of RECs

These Appendices use the standardized reporting template included in the Administrative Law

Judge’s Ruling on Renewable Net Short, R.11-05-005, dated May 21, 2014 (“RNS Ruling”).11,14 Asas

required in the Revised Energy Division Staff Methodology for Calculating the Renewable Net Short

(“Revised RNS Methodology”) attached to the RNS Ruling, Appendices C.1 and C.2 include physical

RNS calculations. Appendices C.3 and C.4 include optimized RNS calculations.12 Appendices C.1

and C.3 include physical and optimized RNS calculations using all required assumptions for the

Commission’s Revised RNS Methodology. Appendices C.2 and C.4 include physical and optimized

RNS calculations using SCE’s assumptions. More information regarding Appendices C.1 through C.4

and responses to the RNS questions set forth in the RNS Ruling are included in Section VI. .

All forecasts include projects under contract and assume that contracted projects which are

currently online will deliver 100% of their expected amount of renewable energy. All forecasts also

include generation from pre-approved procurement programs (i.e., ReMAT, BioMAT) at a 100%

success rate before contracts are signed.1315 Additionally, all forecasts incorporate current expected

online dates for all projects that are not yet online.

Furthermore, all forecasts account for potential issues that could delay RPS compliance,

project development status, minimum margin of procurement, and other potential risks through the use

11 14 SCE’s forecasts only extend through 2030;2030, therefore, SCE’s forecasted RNS information is only included through 2030.

12 The required information on RECs from expiring contracts is included in Appendix E.1315 After contracts from such programs are signed, they are risk-adjusted in the same manner as other

projects with executed contracts that are not yet online.

11

of SCE’s probabilistic risk-adjusted success rates for energy deliveries from contracted projects that

are not yet online. These probabilistic risk-adjusted success rates are intended to reflect a number of

dynamic factors and are periodically adjusted based on new information. The forecasts include

individual project-specific, risk-adjusted success rates for large, near-term projects and a flat 6070%

success rate for the remaining projects, which is based on these projects’ overall weighted -average

success rate. The overall probabilistic risk-adjusted success rate for energy deliveries from SCE’s

portfolio of contracts with projects that are not yet online varies from approximately 7078% in the

third compliance periodCompliance Period (“CP”) 3 and approximately 6976% thereafter.

Additionally, SCE adjusted its load forecast to remove customer load served under the Green

Tariff portion of the GTSR program (called the “Green Rate” by SCE).1416 This is because the GTSR

program is a separate program from the RPS program, and therefore customer load under the Green

Rate load should not be included.1517 For this reason, Green Rate subscriptions are also deducted from

SCE’s generation forecasts to remove energy deliveries associated with the load served under the

Green Rate.1618 At present, becausePrior to dedicated resources procured to serve Green Rate

customers have not yet begunbeginning service, SCE transferred RECs from other RPS-eligible

resources in its Interim Green Rate Pool to serve Green Rate subscriptions, until. In March 2018, one

dedicated Green Rate resources are operationalresource became operational. SCE expects to begin

transferring RECs from this dedicated Green Rate resource in 2019 for 2018 customer subscriptions.

SCE also reduced its bundled retail sales forecast used to calculate its RPS goals by the amount of

energy used to serve Green Rate customer load, as permitted by the GTSR program.1719

1416 No customers are presently being served under the Community Renewables Rate. As a result, SCE only counted Green Rate customers here.

1517 See CAL. PUB. UTIL. CODE § 2833(s). 1618 Because no customers are presently being served under the Community Renewables Rate, SCE did not

make any assumptions about how many customers would be served in the future, under the Community Renewables Rate.

1719 CAL. PUB. UTIL. CODE § 2833(u).

12

SCE's load forecast also accounts for future Transportation Electrification (“TE”) load

growth.20 SCE developed its own internal model to forecast electric vehicle (“EV”) adoption and

considers TE load as a positive load contributor.

As a nascent and dynamic market, EV adoption is affected by multiple drivers such as

manufacturer supply, policies set by federal, state, and local governments, and EV technology

advancement. SCE models light-duty EV through a Generalized Bass Diffusion model. Once vehicle

population numbers are determined for each year, SCE calculates the total annual load by multiplying

the number of forecasted EVs by the weighted average KWh usage per vehicle. Multiple factors are

considered to determine hourly, daily, and annual EV charging load shapes. SCE then incorporates

the EV load forecast into its demand forecast used in this 2018 RPS Plan.

The difference between the RNS forecasts using SCE’s assumptions, as reflected in

Appendices C.2 and2, C.4, C.6, and C.8 and the Commission’s assumptions, as reflected in

Appendices C.1 and1, C.3, C.5, and C.7 is that SCE uses its most recent bundled retail sales forecast

for all years while the Commission’s assumptions use SCE’s most recent bundled retail sales forecast

for 20172018 through 2021 and the CEC’s 2016 California Energy Demand Updated (“CEDU”)

Forecast for 2022-2027 with extension beyond 2027 calculated based on the average annual rate of

change in the CEDU Forecast for the period 2015-2027.2022 and the annual load forecasts through

2030 reflected in the 2017 Integrated Energy Policy Report with adjustments for updates to certain

CCA load forecasts. This is consistent with the adopted standardized planning assumptions laid-out in

the February 28, 2017June 18, 2018 Assigned CommissionerAdministrative Law Judge’s Ruling in

the Integrated Resource Planning (“IRP”)IRP docket, R.16-02-007.1821 SCE uses its own bundled

20 TE refers to only light-duty electric vehicles (“EV”) here.1821 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail

sales for the first five years and should use the LTPP standardized planning assumptions thereafter. SeeRNS Ruling, Attachment A at p. 25. The Commission adopted the standardized planning assumptions in IR.16-02-007 forin the February 28, 2017June 18, 2018 Assigned CommissionerAdministrative Law Judge’s Ruling for the purpose of any long term planning that occurs in 2017, as discussed at p. 4.filing2018 IRPs.

13

retail sales forecast for renewable procurement planning because it is SCE’s best forecast of bundled

retail sales.

As shown in Appendices C.1 through C.4, SCE’s procurement quantity requirement for the

first compliance period was approximately 44.8 billion kilowatt-hours (“kWh”) and its RPS-eligible

procurement was about 46.2 billion kWh. The net surplus, less non-bankable procurement, results in

the net long position of around 1.4 billion kWh at the end of the first compliance period.

Appendices C.1 through C.4 also demonstrate that, using either SCE’s or the Commission’s

assumptions, SCE forecasts a procurement quantity requirement for the second compliance period of

approximately 52.4 billion kWh and RPS-eligible procurement of about 56.8 billion kWh. The net

surplus, less non-bankable procurement, contributes to the cumulative net long position of around 5.6

billion kWh at the end of the second compliance period.

For the third compliance period, using either SCE’s or the Commission’s assumptions, SCE

forecasts a procurement quantity requirement of approximately kWh and RPS-eligible

procurement of about 102.7 billion kWh. The net surplus, less non-bankable procurement, contributes

to the cumulative net long position of around kWh at the end of the third compliance

period.

Table II-3 below summarizes information on SCE’s RNS position assuming adoption of

GAM:

SCE forecasts a net short position in the year 2030 with the use of bank under the

Commission’s assumptions. But SCE forecasts a net long position in the year 2030 with the use of

bank under SCE’s assumptions. Under the 50% by 2030 target and using

Table II-3 SCE’s RNS Position assuming adoption of GAM

Compliance Period

Assumptions Used

PQRBillionKilowatt-hours(KWh)

RPS-eligibleProcurement BillionKilowatt-hours

End Bank Balance / <Shortfall> Billion Kilowatt-hours(KWh)22

22 For rows associated with CP 3-6 in this column, the bank balance assumes bank allocation to CCAs.

14

(KWh)

1 (2011-2013) SCE’sassumptions with adoption of GAM

44.8 46.2 1.4


52.4 56.8 5.6


90.9


77.6


62.5 54.3 12.2


71.2 47.0 -12.0


44.8 46.2 1.4


52.4 56.8 5.6


90.9


77.6


72.1 54.3 -3.8


78.4 47.0 -31.5

Assuming adoption of GAM with SCE’s assumptions, SCE forecasts a net short position

starting in 20272024 without the use of bank (as shown in Appendix C.2). But with the use of bank,

SCE forecasts a net long position atthrough the end of 2030CP 5 (2025-2027) (as shown in Appendix

C.4). Using the Commission’s assumptions, SCE forecasts a net short position starting in 20242023

15

without the use of bank (as shown in Appendix C.1) and a net shortlong position starting in

2030through the end of CP 4 (2021-2024) with the use of bank (as shown in Appendix C.3).

Accordingly, SCE currently does not have a near-term need for additional RPS-eligible energy.19

assuming adoption of GAM.23

Using either Commission or SCE assumptions, SCE’s ability to meet its RPS requirements

may be constrained by any form of bank restrictions adopted under GAM.

Table II-4 below summarizes information on SCE’s RNS position assuming adoption of no

allocation of RECs in the PCIA:

Table II-4 SCE’s RNS Position assuming no allocation of RECs in PCIA

Compliance Period

Assumptions Used PQRBillion Kilowatt-hours (KWh)

RPS-eligible Procurement Billion Kilowatt-hours (KWh)

End Bank Balance / <Shortfall> Billion Kilowatt-hours (KWh)


44.8 46.2 1.4


52.4 56.8 5.6


101.3


108.2


62.5 77.2 79.9


71.2 66.8 75.5


44.8 46.2 1.4


52.4 56.8 5.6


101.3

1923 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”) development. Lancaster and Apple Valley based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 20192020 are currently accounted for in SCE assumptions for departing load. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time.SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division. See section II.F, subsection 1, pp. 22-24, for a detailed explanation of SCE’s CCA outlook.

16


108.2


72.1 77.2 63.9


78.4 66.8 52.2

Assuming adoption of no allocation of RECs in PCIA with SCE’s assumptions, SCE forecasts

a net short position starting in 2029 without the use of bank (as shown in Appendix C.6). But with the

use of bank, SCE forecasts a net long position through the end of CP 6 (2028-2030) and beyond (as

shown in Appendix C.8). Using the Commission’s assumptions, SCE forecasts a net short position

starting in 2027 without the use of bank (as shown in Appendix C.5) and a net long position through

the end of CP 6 (2028-2030) and beyond with the use of bank (as shown in Appendix C.7).

Accordingly, SCE currently does not have a need for additional RPS-eligible energy assuming

adoption of no allocation of RECs in PCIA.24

C. SCE’s Plan for Achieving RPS Procurement Goals

Through its RPS procurement activities, SCE considers contracts for renewable energy that

will help achieve the State’s RPS goals, as well as provide needed energy to serve SCE’s customers at

rates competitive with the market. As mentioned above, in 2016,2017, SCE served 28.231.6% of its

retail sales from RPS-eligible resources. SCE does not forecast a net short in its RPS compliance

position until 20272029 without the use of bank and after 2030 with the use of bank under the current

no REC allocation PCIA scenario. Therefore, SCE does not intend to hold a 2018 RPS Solicitation in

2017 and, instead, willthis 2018 RPS Plan. If SCE’s preferred scenario as set forth in the IRP is

adopted, then SCE may seek to hold a solicitation to procure non-GHG emitting resources, including

renewable energy, under the IRP. In addition, because of SCE’s long position, SCE may look to sell

24 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”) development based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 2020 are currently accounted for in SCE assumptions for departing load. See section II.F, subsection 1, pp. 22-24 for a detailed explanation of SCE’s CCA outlook. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division.

17

RECs consistent with its proposal in this 20172018 RPS Plan. Among additional factors, SCE makes

these decisions taking into account: (1) the renewable energy procured through SCE’s prior RPS

solicitations and other procurement mechanisms, (2) probabilistic risk adjustment of expected

generation from executed contracts with projects that are not yet online, (3) future RPS solicitations

and other procurement mechanisms that are expected to take place, (4) departing load uncertainty

(including the outcome of the PCIA OIR proceeding) and (5) the cost of procuring renewable energy

via solicitation as compared to the cost of procuring in the market. As discussed above, SCE does not

have a need for renewable energy to meet its RPS targets at this time. Therefore, SCE will not conduct

a 2017 RPS solicitation.

SCE willmay seek to sell RECs of 2017-2020 vintage to allow SCE to optimize its renewables

portfolio and provide value for all bundled and unbundleddeparting load customers. SCE may

conduct a solicitation of offers, negotiate bilaterally, or bid into other parties’ solicitations to sell such

products to maximize value to customers and optimize the RPS portfolio. Section XI contains a more

thorough discussion of the REC sales strategy.

All of theThe procurement in SCE’s current renewables portfolio is primarily from contracts

executed prior to June 1, 2010 or contracts for Category 1 products. with a small amount of Category 3

RECs.25 SCE forecasts that it will meet its RPS targets primarily through long-term Category 1

products because they provide the most flexibility for SCE’s customers. However, SCE’s forecast

may evolve in this regard based on the Commission’s implementation of SB 350.

SCE considers its RPS position in light of how long it takes to bring new projects online,

SCE’s forecasted position, and how many solicitations SCE anticipates being able to complete in order

to meet SCE’s compliance requirements. SCE then makes a pro rata allocation of its need over the

remaining anticipated solicitations. Additionally, SCE generally executes contracts for deliveries in

excess of its renewable procurement need to account for the risk of project failure and other relevant

25 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering their product to CAISO. SCE has not contracted for Category 3 products.

18

risks. This pro rata strategy allows SCE to adjust to changes in the RPS program, including the

potential for increased RPS targets, and to respond to changes in load forecasts and/or expected

generation from operating and previously contracted renewable resources.

SCE determines the value of resources with specific deliverability characteristics (such as

peaking, dispatchable, baseload, firm, and as-available) through its LCBF analysis. SCE uses its

LCBF methodology to compare project profiles, including duration of term, location, technology,

online date, viability, deliverability, and price, to estimate the value of each project to SCE’s

customers and its relative value in comparison to other proposals using both quantitative and

qualitative factors. SCE also considers resource diversity with respect to proposals featuring differing

technologies, generation profiles, and fuel sources, and performs a qualitative appraisal of the various

benefits and drawbacks of projects when considering over-generation and the duck curve.2026 This

process ensures that the projects that provide the most value align with SCE’s procurement needs.

SCE’s LCBF approach is described in more detail in Section VIII.B and Appendix HG.1.

In addition to RPS solicitations, SCE continues to utilize a variety of other procurement

optionsmethods to help meet the State’s RPS targets, including mandated programs such as

ReMAT,2127 BioMAT, QF standard contracts and other opportunities such as local capacity

requirements solicitations, all source solicitations, PRP, QF standard contracts, and bilateral

negotiations for competitive procuring renewable energy products.

2026 The California Independent System Operator (“CAISO”) describes the Duck Curve in Fast Facts at - http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf. In essence, the CAISO points out that as intermittent resources, and particularly solar resources, have a larger role, there is more available generation at mid-day, thus reducing the demand for other generation resources. This is the belly of the duck. Once the sun goes down, there is a need for other quick-ramping resources to become available to serve the growing demand for other generation resources. This is the head of the duck.


19

D. SCE’s Portfolio Optimization Strategy

The objective of SCE’s renewables portfolio optimization strategy is to minimize costs to its

customers while ensuring that RPS goals are met or exceeded. The first step in SCE’s portfolio

optimization strategy is developing a forecast of SCE’s renewable procurement position and need, i.e.,

SCE’s RNS. This includes a calculation of SCE’s net position and SCE’s bank. SCE carefully

evaluates its renewable procurement need by assessing bundled retail sales, the performance and

variability of existing generation, the likelihood new generation will achieve commercial operation,

expected online dates, technology mix, expected curtailment, and the impact of pre-approved

procurement programs, among other factors. Annual variability of existing resources can either

increase or decrease SCE’s need and bank from year-to-year. However, over longer periods of time,

SCE expects generation levels to be relatively consistent.

SCE uses its LCBF methodology to evaluate renewable procurement opportunities as further

described in Section VIII.B and Appendix HG.1. The primary quantitative metric used for evaluating

bundled renewable energy is Net Market Value (“NMV”). SCE also relies on a number of qualitative

factors such as resource diversity and transmission area, among other factors such as impacts on

Disadvantaged Communities (“DACs”), when evaluating proposals.

Because SCE’s need assessment results in a long position, SCE may use sales of renewable

energy products,2228 project deferrals, and solicitation deferrals (as it did by not holding a 20122012,

2016 or a 20162017 RPS solicitation) in order to reduce customer cost while aligning procurement

with its forecasted need. Additionally, SCE actively administers its renewable procurement contracts

to manage customer cost.2329

2228 SCE procures renewable energy in compliance with the preferred loading order and when it expects to have a renewable procurement need. SCE does not purchase RPS-eligible energy for the express purpose of selling it at a later date.

2329 Contract amendments have the potential to decrease contract prices or provide other benefits to customers.

20

SCE evaluates various potential risks when considering whether to engage in sales of

renewable energy products including the risk of not meeting its RPS targets.2430 This evaluation

includes, without limitation, a calculation of SCE’s renewable procurement position and RPS bank

with a set of adverse assumptions. Among others, these assumptions include lower performance of


that is not yet online, and higher levels of curtailment than expected. SCE assesses its renewable

procurement position with these adverse assumptions to ensure that SCE would still expect to meet its

RPS targets after making the sale. SCE’s overall approach appropriately balances the risks and costs

of selling renewable energy products with the risks and costs of maintaining an RPS bank.

Finally, SCE continues to analyze the effects of procurement of RPS-eligible resources on

other procurement programs in order to consider portfolio impacts. The Commission and the

California Independent System Operator (“CAISO”) considered flexibility requirements in the

Resource Adequacy (“RA”) proceeding to help manage the intermittency created on the grid by

certain renewable resources. The CAISO launched a stakeholder process to discuss new obligations

for flexible capacity and how flexibility requirements will be allocated to load-serving entities. The

adopted proposal for allocating flexibility requirements directly allocates the identified requirements

based on the amount of intermittent generation contracted by the load-serving entity. This creates a

direct link between RPS procurement and flexibility requirements as the amount of wind and solar

resources in the portfolio impacts the magnitude of the flexibility requirement allocated to the

load-serving entity. A portfolio-wide optimization strategy needs to assess the composition of SCE’s

renewables portfolio, as resources such as geothermal and other baseload resources may potentially

reduce flexibility requirements.

2430 SCE also considers statutory and regulatory restrictions on banking of excess procurement.

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E. SCE’s Management of its Renewables Portfolio

After SCE executes an RPS power purchase agreement (“PPA”), the PPA is managed by

SCE’s Energy Contracts Management group manages the PPA. Each PPA is assigned a contract

manager who serves as the primary point of contact to address all obligations and milestones under the

PPA. To the extent allowable, many PPAs will require some form of modification prior to attaining

commercial operation. Modifications may include financing consents, updates to facility descriptions,

amendments that reduce costs to the seller and/or SCE without increasing revenues, true-up of PPA

milestones and timelines as interconnection and permitting information is updated, and other

miscellaneous changes to accommodate adjustments during the project development process.

Generally, PPAs require few modifications after attaining commercial operation. At this juncture in

the contract lifecycle, contract administration efforts become more focused on monitoring the

contractual performance and payment obligations. However, disputes, settlements, outages, changes

to delivery obligations or other issues may arise and are also managed by the same contract managers.

In evaluating modifications or amendments to a PPA, SCE applies guidance from

D.88-10--032. Although D.88-10-032 was enacted as a set of guidelines for the administration of QF

contracts, SCE has been using it when administering all forms of PPAs. At a high level,

D.88--10--032 gave the IOUs the option to determine whether to enter into- an amendment with any

counterparty.2531 In the event an amendment is elected, the IOU should negotiate in good faith.2632

The decision also provides that in response to requests for contract modifications, an IOU is to seek

concessions that are commensurate with the change being sought.2733 The details of D.88-10-032

provide further guidance to the IOUs to restrict modifications to PPAs with viable projects,2834 and

reject modifications that would result in creating an essentially new project.2935

2531 See D.88-10-032 at p. 16. 2632 Id. at Conclusion of Law 8. 2733 Id. at p. 16, Conclusions of Law 13-14. 2834 Id. at p. 17, Conclusion of Law 4, Appendix A at pp. 4-5. 2935 Id. at p. 26, Conclusion of Law 17.

22

As appropriate, SCE also considers the standards of review for PPA amendments set forth in

D.14-11-042, including assessment of SCE’s renewable procurement need, NMV, contract price,

project viability, consistency with Commission decisions, and other required updated information.3036

SCE seeks approval by the Commission of all PPA modifications either through its annual

Energy Resource Recovery Account (“ERRA”) application or through advice letters or applications,

depending on the type of PPA and nature of the amendment, and based on guidance from Commission

decisions regarding specific modifications to PPAs.3137

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues

1. Lessons Learned and Past and Future Trends

SCE’s experience in renewable contracting has enabled SCE to negotiate successfully

and bring projects online with a variety of counterparties on a diverse array of technologies. SCE is

committed to recognizing the unique characteristics of each situation and working toward balanced

and mutually -acceptable agreements. To this end, SCE continues to refine both its RPS solicitation

process and its pro forma PPA as a result of lessons learned from SCE’s extensive experience in

contracting for renewable resources and working with developers. Over the course of the last several

years, SCE has also incorporated or accounted for several trends in its renewable procurement

planning and solicitation process. SCE discusses important lessons learned and significant past and

future trends below. Additionally, as SCE has noted in past RPS Procurement Plans, more stringent

eligibility requirements, such as the requirement that projects have a Phase II Interconnection Study

(or an equivalent or more advanced interconnection status or exemption) and an “application deemed

complete” (or equivalent) status within the applicable land use entitlement process in order to submit a

proposal, have resulted in higher viability project proposals. SCE intends to continue these

requirements in any future solicitations for all projects.

3036 See D.14-11-042 at pp. 80-82. The standards of review do not apply to amendments that are minor or non-material. Id. at p. 80.

3137 For example, the Commission has indicated specific IOU actions regarding amendments to certain terms in tariff-based agreements.

23

a) Possible Future Trend Toward Departing Load

SCE expects additional cities and eligible public entities within the SCE service

territory to join Lancaster and Apple Valley in developing a Communitybegin CCA service. SCE had

its first departing CCA load starting in May 2015 in the form of Lancaster Choice Energy (“LCE”).

Apple Valley Choice Aggregation (“CCA”) program in their local jurisdiction. In addition to the two

existing CCAs, Pico Rivera and San Jacinto have executed SCE applications to begin CCA service

starting by September, 2017 and April, 2018 respectively. Several moreEnergy (“AVCE”) began

operations at the beginning of April 2017, followed by Pico Rivera Innovative Municipal Energy

(“PRIME”) in October 2017, Clean Power Alliance (“CPA” or Los Angeles County) Phase I

implementation in February 2018, San Jacinto Power (“SJP”) in April 2018, Rancho Mirage Energy

Authority (“RMEA”) in May 2018, and CPA Phase 2 in June 2018. Desert Communities Energy

(“DCE”) was expected to begin service in August 201838 followed by three additional phases of CPA

covering much of Los Angeles and Ventura counties in 2019. Additional cities, counties, and

governmental aggregations within the SCE service territory have either initiated contact, requested

load data from SCE, or passed a municipal ordinance related to their interest and intention to

developing CCAs. These entities have the potential to represent a significant departure of load from

SCE’s bundled procurement service. As additional large departures come to fruition, they will have

proportionally significant impacts on SCE’s progress towards meeting its RPS compliance goals by

reducing SCE’s potential RPS need.

Departing load should not impact SCE’s planned procurement activities unless

and until new load-serving entities (“LSEs”) formalize their departure through a Binding Notice of

38 At a July 25, 2018 DCE Board Meeting, DCE voted to indefinitely delay their previously-planned August 2018 implementation date. Their new implementation date (if any) is not currently known. SCE will not know about DCE’s final decision on all of the implementation plan changes -- especially for 2019 -- in time for us to make appropriate changes to our load forecast for this filing. It should be noted, however, that DCE’s forecast peak load was only 385 megawatts in 2018, and DCE’s delay in pursuing CCA implementation does not materially affect the overall point that SCE is significantly long regarding RPS targets for the foreseeable future.

24

Intent (“BNI”), an initial Resource Adequacy (“RA”)RA filing, or the start of CCA service.32, or

formal submission of an April RA forecast for the following year pursuant to California Public

Utilities Code Section 380.39 In expectation of growing CCA departing load in the near future, SCE

prepared a Monte Carlo simulation of CCA departing load starting in 20192020 and has accordingly

adjusted its procurement plan at this time.3340 As these actual load departures materialize, SCE will

consider how these departures impact its RPS compliance, including its need for additional

resources.Moreover, ifthe size of the RPS bank and the need to sell RECs to newly forming CCAs. If

a sufficiently large amount of SCE’s current bundled service customers depart bundled service, SCE

may be significantly over-procured to meet its RPS compliance goals. In this case, the existing Power

Charge Indifference Adjustment (“PCIA”) mechanism might be insufficient to protect the remaining

bundled customers from rate impacts due to these departures and thus fail to meet the Commission

standard of maintaining “bundled customer indifference.”34 The Commission should reconsider how

to equitably and appropriately allocate the costs and benefits of RPS procurement performed on behalf

of those customers among all customers, bundled and unbundled, in R.17-06-026, which was recently

issued on July 10, 2017. The Commission should be prepared to make necessary changes to ensure

that remaining bundled customers are indeed indifferent to departing load.35, depending somewhat on

the outcome of the PCIA OIR. If the outcome of that proceeding is that the IOUs do not allocate a

portion of their RECs (i.e., GAM is not adopted) then, as mentioned above, SCE’s position will remain

long through 2030 and beyond with the use of bank.

3239 SCE’s internal criteria for a qualifying governmental entity to be included in the CCA departing load forecast with full certainty for bundled procurement forecast purposes.

3340 SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its PRG, including Energy Division. SCE’s current scenario analysis for departing load includes Lancaster, Apple Valley, PicoRivera, CPA Phase One, San Jacinto, Rancho Mirage, CPA Phase Two, DCE, CPA Phases Three to Five, and the Monte Carlo simulation for departing load beginning in 2019.2020.

34 CAL. PUB. UTIL. CODE §§ 365.1, 366.35 See, e.g. CAL. PUB. UTIL. CODE §366.2(d)(AB 117, 2002) requiring all customers to bear a fair share of

utility procurement costs incurred on their behalf to avoid cost shifting.

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Finally, as the potential for departures from bundled service increases, the

Commission should consider the cost impacts of mandated special purpose above-market, RPS

procurement. Examples include: BioRAM, ReMAT,3641 and BioMAT. Because only the IOUs

undertake this procurement and only bundled service customers fund such programs, as customers

depart from bundled service, the remaining bundled service customers will be disproportionately

affected by the costs of these programs. To ensure equitable allocation of these costs, particularly as

increases in departing load materialize, it will be important to develop a way to support

necessarymandated special purpose RPS programs without unfairly burdening bundled service

customers.

b) Need for REC Sales

SCE is well positioned to meet its RPS compliance obligation both in the near

term and in the future. As described in confidential Appendix F.2,E, SCE has more renewable

energy to meet its goalscompliance responsibilities than it needs for the forseeable future.

Additionally, SCE can create short term customer value and introduce some rate stability by engaging

in limited amount short term sales transactions as explained in details in confidential Appendix F.2. A

sales strategy is already a part of SCE’s approved portfolio optmization strategy. As described in

SCE’s approved 2016 RPS plan “If SCE’s need assessment results in a long position or it would

otherwise optimize SCE’s renewables portfolio or maximize value to its customers, SCE may use sales

of renewable energy products, project deferrals, and solicitation deferrals (as it did by not holding a

2012 RPS solicitation) in order to move its renewable procurement back in line with its forecasted


26

renewable procurement need.”37sales transactions.. The Commission adopted SCE’s REC sales

strategy in its Draft 2017 RPS Plan, with some minor modifications, in D.17-12-007.42

In addition to providing benefits to SCE’s customers, an open market for

short term REC sales may provide for a low cost option for RPS compliance for other LSEs in

California. Long -term contracting ismay not alwaysbe an option for smaller LSEs given the higher

costs and long -term commitments. In absence of that option, an open market can provide for a lower

-cost option for short -term REC purchases.3843

Finally, given the SB 350 changes in compliance rules confirmed in

D.17-06--026, IOUs will have moresome flexibility to fulfill their compliance requirements through a

combination of long term contracts and short -term products, reducing the overall costs for their

customers. Given this change, SCE will seek portfolio optimization opportunities to make those

tradeoffs between long -term contracts and short -term purchases. An active REC sales strategy will

be a key part of SCE’s portfolio optimization strategy.

III.

PROJECT DEVELOPMENT STATUS UPDATE

Appendix B contains a status update on the development of RPS-eligible projects currently

under contract, but not yet delivering generation. SCE received some of the information in this status

update from its counterparties. The status of these projects impacts SCE’s renewable procurement

position and procurement decisions. For instance, SCE adjusts its renewable procurement position

during the development stage of a project once it is determined whether the project will or will not

meet its contractual obligations through its forecasted probabilistic risk-adjusted success rates.

37 Final 2016 RPS Plan, dated January 23, 2017, p. 14.42 D.17-12-007, Ordering Paragraph 8, pp. 71-72.3843 As explained in more detail in section XI and confidential Appendix FE.2.

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IV.

POTENTIAL COMPLIANCE DELAYS

FiveSix primary factors willmay challenge SCE’s achievement of the RPS goals: (1)

curtailment; (2) the increasing proportion of intermittent resources in SCE’s renewables portfolio; (3)

permitting, siting, approval, and construction of both renewable generation projects and transmission;

(4) a heavily subscribed interconnection queue; and (5) developer performance issues; and (6) load

uncertainty associated with possible departing load and increasing electrification of transportation.

SCE discusses each of these potential issues that could cause compliance delays below and describes

the steps it has taken to mitigate the effects of these challenges.

As discussed in Section II.B, in forecasting its renewable procurement position and need, SCE

accounts for potential issues that could delay RPS compliance, project development status, minimum

margin of procurement, and other potential risks through the use of probabilistic risk-adjusted success

rates for energy deliveries from contracted projects that are not yet online. SCE considers the factors

discussed below in this process.

A. Curtailment

As more renewable generation comes online, congestion at the transmission and distribution

levels can become more common. Several of SCE’s contracted wind projects in the Tehachapi region

in Kern County, California, for example, have had to curtail deliveries to maintain system reliability in

this area. Similarly, many projects in the Antelope and Devers areas have been required to curtail in

order to accommodate outages needed for system maintenance and upgrades. The increase in

California’s RPS goal from 33% to 50% will result in more intermittent resources on the grid and

increased deliveries from RPS-eligible resources, likely resulting in more curtailment of renewable

output due to over-generation.

SCE has been working on multiple fronts to mitigate the risk of curtailment. SCE has

continued working to increase the level of coordination with generators during the construction

phases of major transmission projects in the Tehachapi, Lugo, and Devers areas, with a particular

focus on minimizing the duration of outages that will require curtailments and scheduling work

28

during periods of low production for renewable resources. Further, SCE is developing strategies to

utilize economic curtailment rights to enable CAISO to more efficiently achieve generation

reductions when and where needed to alleviate congestion in the course of normal operations, and

during transmission outages and periods of over generation. This practice will enable the CAISO to

fold renewable resources more directly into market optimization runs.

SCE has had some success reducing curtailment at the distribution level, in part by

completing needed system upgrades, but also by giving SCE switching center operators better tools

to monitor real time production levels during outages. This increased visibility enables operators

to take more targeted action when generators exceed pro rata limitations, and to more effectively

manage aggregate limits in the event not all resources are generating their full pro rata share. SCE

will continue to look for opportunities to mitigate the impacts of curtailment on meeting RPS goals.

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio

Over the last several years, a number of large wind projects in SCE’s renewables portfolio

have achieved commercial operation. These projects include (among others,) the Alta Wind and

Caithness Shepherds Flat projects totaling nearly 2,400 MW) have achieved commercial operation.

Additionally, SCE signed contracts with Broadview and El Cabo projects for an additional 600 MW

expected to be on line in the next year as well as the El Cabo and Broadview wind projects which

came online in 2017 and total 622 MW. While these resources contribute significantly toward

SCE’s renewables portfolio, they have also made forecasting SCE’s renewable procurement position

and need more complex. Wind generation output is difficult to predict. Actual production from

wind generators varies significantly from hour to hour, month to month, and year to year, thereby

exposing SCE to large fluctuations in renewable energy deliveries. Although not as unpredictable as

wind generation, solar production also varies over time depending on weather conditions and

project performance, among other factors. As wind and solar projects come to represent an ever

larger proportion of SCE’s renewables portfolio, these effects will be magnified, particularly with

California’s RPS target increasing to 50%, which will resulthas resulted in more wind and solar

projects in SCE’s renewables portfolio.

29

Given the number of intermittent resources expected to achieve commercial operation in

the coming years, SCE is preparing to successfully integrate new wind and solar resources. For

example, SCE is working on ways to improve forecasting accuracy by collecting actual generation

data from new wind and solar resources and analyzing forecasted output versus actual production

after the fact. SCE is also seeking to maintain a balanced portfolio, while keeping customer cost in

mind, in order to ensure there is sufficient diversity of renewable resource types to manage

intermittency risk going forward.

C. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and

Transmission

The lack of sufficient transmission infrastructure and the process for permitting and approval

of new transmission lines continues to be a challenge to reaching the State’s renewable energy targets.

Lack of adequate transmission infrastructure and the lengthy process of siting, permitting, and

building new transmission continues to impede bringing new renewable resources online.

As stated in the CAISO’s 2015-2016 Transmission Plan, “[t]he transition to greater reliance on

renewable generation has created significant transmission challenges because renewable resource

areas tend to be located in places distant from population centers.”3944 Through its transmission

planning process, the CAISO utilizes renewable resource portfolios from the Commission and the

CEC to identify transmission projects that will support the development of renewable resources in

areas where they are most likely to occur. This “least regrets” approach helps to address an element of

uncertainty that generation developers may have regarding the approval of transmission projects that

are necessary for the delivery of renewable energy. While someSome transmission projects have

already been approved or are progressing through the Commission approval process, challenges still

remain regarding the completion of those transmission projects. In SCE’s service area, there are

several major transmissionand are progressing and may help in alleviating transmission constraints

3944 CAISO 2015-2016 Transmission Plan, at p. 6.

30

once the projects are completed. However, more projects includedhave been identified in the

CAISO’s 2016-2017 draft-2018 Transmission Plan that SCE is pursuing which will contribute to

supporting the State’s RPS goals. These projects include the Lugo-Eldorado series cap and terminal

equipment upgrade, the Alberhill 500 kV Method of Services project, the Mesa 500 kV Substation

Loop-In, and the Lugo-Mohave series capacitors project.40as necessary to maintain safe, reliable

delivery of energy while meeting the State’s clean energy goals.45

The long and complicated permitting process for renewable generation facilities is also a

barrier to meeting RPS goals. Moreover, environmental concerns, legal challenges, and public

opposition can impact the timeline for bringing renewable generation projects online.

D. A Heavily Subscribed Interconnection Queue

A heavily subscribed CAISO interconnection queue is also a major barrier to achieving the

State’s RPS goals. As of June 3, 2016, the CAISO reported more than 100 active renewableThe June

2018 CAISO Interconnection Queue reports 140 solar and wind projects seeking interconnection to

the CAISO controlled grid representing more than 20,00024,000 MW of capacity.4146

The large number of interconnection requests, particularly from renewable generators,

presents significant challenges for SCE, the CAISO, and renewable generators. Generators that have

completed their studies, but not signed generation interconnection agreements, contribute to the

uncertainty around available system capacity. When capacity is reserved for generators that have not

signed interconnection agreements, other potentially more viable later-queued generators can appear

to trigger upgrades that may not be necessary. Although protocols exist to allow for the removal of

40 CAISO Draft 2016-2017 Transmission Plan, at p. 314. CAISO’s draft 2016-2017 Transmission Plan is available at: https://www.caiso.com/Documents/Draft2016-2017TransmissionPlan.pdf.

45 A copy of the CAISO Transmission Plan can be found at: http://www.caiso.com/Documents/BoardApproved-2017-2018_Transmission_Plan.pdf

4146 See https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueue.pdfhttp://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx.

31

languishing generators from interconnection queues, these protocols are difficult to implement

because they can lead to litigation.

E. Developer Performance Issues

Achieving California’s renewable energy goals also depends on the successful performance of

renewable developers in meeting contractual obligations, timely completing construction milestones,

and achieving commercial operation. Hurdles encountered during these activities require developers

to alter their milestone schedules. This can result in delays, lengthy contract amendment negotiations,

and contract terminations. For example, severalRecently, developer performance has become less of

an issue as the renewables market has matured and RFP requirements such as a Phase II

Interconnection Study have been implemented. However, there have been developer performance

issues in some cases especially among the mandated carve-out feed-in-tariff programs such as CREST

and, more recently, ReMAT. Several of SCE’s contracts have terminated due to developer

performance issues (e.g., poor site selection, failure to timely secure the necessary permits, and

inability to complete the CAISO new resource implementation processes in a timely manner). ThisAs

stated above, this is especially true in SCE’s smaller and mandated procurement programs. In these

programs, requirements showing the viability of a project, such as the requirement of a Phase II

Transmission Study or equivalent, are not an eligibility criteria. Projects that have achieved this level

of development typically have significant dollars invested and secured project-backing. As a result, in

most cases potential fatal flaws in project location, technology, or environmental factors have been

identified and resolved.

To the extent that delays, termination events, and under-performance occur, the amount of

delivered energy on which SCE can rely to reach the State’s goals is reduced.

F. Load Uncertainty Including Faster Implementation of Transportation Electrification

And Departing Load

There are two key factors that create load uncertainty which could impact SCE’s ability to

achieve its RPS goals. First, as discussed in Section II.B above, SCE’s load forecast accounts for

currently-anticipated future transportation electrification load growth. However, if future TE load

32

growth is more accelerated or in excess of SCE’s current forecasts, SCE’s ability to reach its RPS

target may be negatively impacted because it may not have sufficient RPS-eligible resources to serve a

significantly larger load than it presently forecasts. Given predicted levels of future departing load to

CCAs, however, even TE adoption materially in excess of SCE’s current forecasts is unlikely to

change the overall fact that SCE will be significantly long on RPS for the foreseeable future. That

said, it is also possible that SCE may experience significant returns of CCA (or other alternate

ESP-served) load, which could negatively impact its ability to achieve its RPS targets.

V.

RISK ASSESSMENT

SCE describes risks that may result in compliance delays in Section IV. As explained in

Section II.B, in forecasting its renewable procurement position and need, SCE accounts for potential

issues that could delay RPS compliance, project development status, minimum margin of

procurement, and other potential risks through the use of probabilistic risk-adjusted success rates for

energy deliveries from contracts that are executed but not yet online. SCE considers these risk factors

in this process. Additionally, SCE takes into account historic generation from existing resources,

including lower than expected generation, variable generation, and resource availability, among other

factors, when forecasting expected generation from its contracted renewable projects. The

quantitative analysis provided in Appendices C.1 through C.48 reflects these considerations.

VI.

QUANTITATIVE INFORMATION

A. RNS Calculations

As discussed in Section II.B, Appendices C.1 through C.48 include SCE’s RNS calculations

using the standardized reporting template included in the RNS Ruling under the RPS program rules.

As required by the Commission’s RNS Methodology, Appendices C.11, C.2, C.5, and C.26 include

physical RNS calculations and Appendices C.3 and3, C.44, C.7, and C.8 include optimized RNS

calculations.

33

Appendices C.22, C.4, C.6, and C.48 include SCE’s physical RNS and optimized RNS through

2030, based on the following SCE assumptions:

SCE’s most recent bundled retail sales forecast for 20172018 through 2030 which excludes

Green Rate customer subscriptions;

Transfers of energy deliveries from SCE’s interim pool of RPS eligible resources to the

Green Rate program to serve Green Rate customers until dedicated Green Rate resources

come online; and conversely, transfers of energy deliveries from dedicated Green Rate

resource that are not used by Green Rate customers;

Contracted projects that are currently online will deliver 100% of their expected amount of

renewable energy;

Probabilistic risk-adjusted success rates for energy deliveries from contracted projects that

are not yet online. SCE’s forecasts include individual project-specific, risk-adjusted

success rates for large, near-term projects and a flat 6070% success rate for the remaining

projects, which is based on these projects’ overall weighted average success rate; and

100% success rate for projects originating from pre-approved programs such as ReMAT

and BioMAT before contracts from such programs are signed.4247

Appendices C.11, C.3, C.5, and C.37 provide SCE’s physical and optimized RNS through

2030 using the Commission’s RNS Methodology. Appendices C.1 and1, C.33, C.5, and C.7 use the

same assumptions as in Appendices C.2 and2, C.44, C.6, and C.8 except that:

Instead of using SCE’s most recent bundled retail sales forecast for all years, they use

SCE’s most recent bundled retail sales forecast for 20172018 through 2021 and the

CEC's 2016 CEDU Forecast for 2022-2027 with extension beyond 2027 calculated

based on the average annual rate of change in the CEDU Forecast for the period

2015-2027.432022 and the annual load forecasts through 2030 reflected in the 2017

4247 After contracts from such programs are signed, they are risk-adjusted in the same manner as other projects with executed contracts that are not yet online.

34

Integrated Energy Policy Report with adjustments for updates to certain CCA load

forecasts.48

At this time, SCE does not propose including a voluntary margin of over-procurement

(“VMOP”) in its renewable procurement planning. SCE will account for RPS need forecasting risks

through the identification and forecast of RECs above its RPS procurement quantity requirements

based on its forecast RPS portfolio.

B. Response to RNS Questions

SCE provides the following responses to the RNS questions included in Appendix D to the

RNS Ruling.

1. How do current and historical performance of online resources in your RPS

portfolio impact future projection of RPS deliveries and your subsequent RNS?

SCE considers weather and specific resource conditions, including maintenance issues,

degradation of output, and contractual issues that have impacted historic performance and may cause

the output of a facility to be different than what SCE anticipates for the future. SCE takes these

considerations into account when it is forecasting its RNS. In particular, if SCE determines any of

these conditions will impact a facility’s future generation, such generation will be increased or

decreased in the forecast for as long as SCE expects the situation to persist. SCE reviews these

conditions on a regular basis and updates its generation forecast accordingly.

2. Do you anticipate any future changes to the current bundled retail sales forecast?

If so, describe how the anticipated changes impact the RNS.

There are many factors that can impact SCE’s bundled retail sales forecast. Those

factors include, but are not limited to, demographic and macroeconomic drivers, electricity prices,

impact from utilities’ energy conservation programs, federal and state codes and standards, the

4348 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail sales for the first five years and should use the LTPP standardized planning assumptions thereafter. SeeRNS Ruling, Attachment A at p. 25.

35

California Solar Initiative Program, future customer adoption of distributed generation, future electric

vehicle use, and other electrification load growth. In addition, increased consideration of CCA by

municipalities may lead to more notifications ofin recent years, rapid acceleration of actual and

predicted CCA formation, which could lead have led to amaterially longer forecast RPS

positionpositions for SCE. SCE expects its bundled retail sales forecast to change over time as SCE

incorporates the best available information on the various drivers into its forecast. SCE’s overall

bundled retail sales forecast and resulting forecast RPS RNS will change depending on the net impact

of all of these factors. It is not possible for SCE to predict the future changes to its bundled retail sales

forecast due to the complex nature of the modeling efforts involved. Accordingly, the bundled retail

sales forecast that SCE uses at any given point in time is SCE’s best prediction of bundled retail sales.

As the bundled retail sales forecast goes up or down, it will increase or decrease SCE’s projected RNS

accordingly.

3. Do you expect curtailment of RPS projects to impact your projected RPS

deliveries and subsequent RNS?

SCE currently forecasts a very small but increasing level of curtailment in solar

between 20172018 and 2020. Wind remains less predictable but is forecasted to have little to no

curtailment during this time period. SCE currently uses its forecasted curtailment in 2020 as its

forecast for future years. Some details around how SCE makes its curtailment forecast are included

below.

For projects in development in the Tehachapi Wind Resource Area (“TWRA”), SCE

includes an estimate of curtailed generation based on analysis submitted in SCE’s testimony regarding

the Tehachapi Renewable Transmission Project (“TRTP”) in its generation forecasts for projects in

that location.4449 While potentially conservative, this analysis takes into account expected new

4449 See Southern California Edison CompanySCE’s Testimony in Response to the Assigned Commissioner’s Ruling on the Tehachapi Renewable Transmission Project (“TRTP”), Application 07-06-031 (January 10, 2012); Southern California Edison Company’s Supplemental Testimony in Response to the Assigned Commissioner’s Ruling on the Tehachapi Renewable Transmission Project (TRTP)TRTP, Application 07-06-031 (February 1, 2012).

36

interconnections in the TWRA, hourly generation profiles for wind and solar, and expected increases

in transmission capacity as TRTP construction progresses. The amount of generation actually

curtailed will be a function of real-time load, generation bids for dispatch, actual generation output that

differs from cleared bids for dispatch, and the amount of transmission capacity available.

Additionally, to the extent that other projects have been curtailed, or in the event SCE

revises its curtailment estimates for resources in Tehachapi or elsewhere in California, those

curtailment estimates may be incorporated into forecasts of generation in the future.

4. Are there any significant changes to the success rate of individual RPS projects

that impact the RNS?

SCE reviews the status of contracted projects that are not yet online every quarter to

assess the likelihood that each project will be successfully constructed and deliver energy. For the

larger contracted projects that terminated in the last year, SCE had gradually dropped their likelihood

of success over time such that when the projects eventually terminated, there was not a significant

impact to SCE’s forecast RNS. Overall, SCE has seen a number of large, near-term projects continue

to make strides towards completion, resulting in a collectively higher anticipated success rate for these

large, near-term projects than was allocated to similar projects inprior to 2016. As mentioned in

Section IV.E above, the requirement of a Phase II Interconnection Study or better along with an

application deemed complete with the appropriate environmental review agency have bothhas

contributed to a higher project success rate.

5. As projects in development move towards their commercial operation date, are

there any changes to the expected RPS deliveries? If so, how do these changes

impact the RNS?

As projects move closer to their commercial operation dates, there may be a number of

reasons to change the expected RPS-eligible deliveries, including schedule changes from phased

projects, commercial operation date changes, and availability of updated forecasted production

information. These factors may either increase or decrease the RNS.

37

6. What is the appropriate amount of RECs above the procurement quantity

requirement (“PQR”) to maintain? Please provide a quantitative justification

and elaborate on the need for maintaining banked RECs above the PQR.

SCE does not target a minimum amount or range of RECs above the PQR for banking.

Instead, SCE includes the expected success rate for projects in development and incorporates the

above risk factors in its forecast, which creates an adequate margin of procurement.

While SCE intends to maintain a bank, determining the appropriate level of RECs

above the PQR is dependent on a number of factors: the forecast level and uncertainty of bundled retail

sales, the outcome of the PCIA proceeding, possible disallowance of RECs by the CEC during RPS

verification, fuel source mix in the renewables portfolio, performance of existing resources, project

success rates, delay or acceleration of online dates, performance of new facilities once they are

operational, the level of the existing portfolio that is re-contracted, and curtailment, among other

factors. Annual variability of these factors can either increase or decrease the bank from year-to-year.

7. What are your strategies for short-term management (10 years forward) and

long-term management (10-20 years forward) of RECs above the PQR? Please

discuss any plans to use RECs above the PQR for future RPS compliance and/or

to sell RECs above the PQR.

When sufficiently long during short-term periods, SCE has used sales of renewable

energy products, project deferrals, portfolio optimization, and solicitation deferrals in order to adjust

its renewable procurement back in line with its forecasted RNS. If SCE forecasted short-term

shortfalls, SCE would satisfy the need through additional procurement. For example, SCE could

re-contract with existing projects, initiate an RPS solicitation, procure through pre-approved

procurement programs, or make short-term purchases with Commission approval. Additionally, SCE

diligently manages contracts to ensure all contractual obligations are met. SCE uses these activities

for renewables portfolio optimization.

Specifically regarding the sale of RECs, when SCE has a long position in the near term,

SCE evaluates whether a sale of renewable energy products is appropriate. This evaluation includes a

38

calculation of SCE’s renewable procurement position and RPS bank under a set of adverse


resources than expected, lower risk-adjusted project success rates for contracted generation that is not

yet online, lower load requirements due to departing load, and higher levels of curtailment than

expected. SCE assesses its renewable procurement position with such adverse assumptions to ensure

that, even in an adverse case scenario, SCE would still expect to meet its RPS targets after making the

sale. It is not SCE’s intent to purchase renewable energy products solely for the purpose of selling

them at a later date.

At this time, SCE considers holding an excessive amount of bank in the long-term to be

an inefficient use of resources. Rather, SCE generally allocates any near-term forecasted RECs above

the PQR to years of forecasted shortfall. Additionally, as described in Section XI.C, SCE will setup

limits for REC sales using a margin of safety for compliance.

8. Provide Voluntary Margin of Over-procurement (“VMOP”) on both a

short-term (10 years forward) and long-term (10-20 years forward) basis. This

should include a discussion of all risk factors and quantitative justification for the

amount of VMOP.

SCE currently does not use a VMOP methodology on either a short-term or long-term

basis. While there are different risks that have different impacts in the short and long-term, SCE

believes it appropriately accounts for these risk factors in its forecasted RNS as described in prior

sections.

9. Please address the cost-effectiveness of different methods for meeting any

projected VMOP procurement need, including application of forecast RECs

above the PQR.

SCE procures what it believes is needed to meet its RPS targets, allocating any

near-term forecasted RECs above the PQR to years of forecasted shortfall. SCE’s forecasted need is

far enough in the future that SCE believes it can fill that need through additional procurement on a

39

ratable basis. SCE believes it appropriately accounts for risk through the risk factors identified in its

response to question 6 above, and currently does not utilize a VMOP.

In the event that SCE implements a VMOP methodology in the future, SCE would use

the same methods to procure its projected VMOP procurement need as it uses to procure towards its

RPS targets, including procurement of Category 1 products.

10. Are there cost-effective opportunities to use banked RECs above the PQR for

future RPS compliance in lieu of additional RPS procurement to meet the RNS?

There are a few alternatives for the potential use of banked RECs above the PQR,

including applying them in the future compliance periods, engaging in sales for the amount of bank,

and a combination of sales of Category 1 products and procurement of other products. As noted above

in response to question 7, SCE does not hold an excessive amount of bank for the sole purpose of

selling it later. SCE generally allocates any near-term forecasted RECs above the PQR to years of

forecasted shortfall. SCE conducts various portfolio optimization strategies also described in its

response to question 7 to manage its renewables portfolio.

11. How does your current RNS fit within the regulatory limitations for portfolio

content categories? Are there opportunities to optimize your portfolio by

procuring RECs across different portfolio content categories?

All of theThe procurement in SCE’s current renewables portfolio is primarily from

either contracts executed prior to June 1, 2010 or contracts for Category 1 products. with a small

amount of Category 3 RECs.50 Accordingly, SCE’s procurement fits within the minimum target for

Category 1 products and the maximum target for Category 3 products established by SB 2 (1x) and

D.11-12-052, as well as the targets established in SB 350 and D.17-06-026. SCE does see

opportunities to optimize its portfolio and achieve customer value through sales across the three

portfolio content categories. Given SCE’s current position of no RPS need in the near term, SCE will

50 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering their product to CAISO. SCE has not contracted for Category 3 products.

40

onlymay conduct solicitations for sales of vintage 2017 through 2020 Category 1REC products in

2017.2018. Through soliciting near term REC sales, SCE may find opportunities to create value for its

customers.

VII.

MINIMUM MARGIN OF PROCUREMENT

SCE’s renewable procurement efforts will be guided by its forecast of its renewable

procurement needs, as described in Section II.B and provided in Appendices C.1 through C.4. In its

forecast of its renewable procurement position and need, SCE currently accounts for the risks of

project failure and delay associated with contracted projects that are not yet online. To this end, SCE

uses individual project-specific, risk-adjusted success rates for large, near-term projects and a flat

6070% success rate for the remaining projects, which is based on these projects’ overall weighted

average success rate. This probabilistic risk adjustment methodology for discounting expected energy

deliveries from projects under development is modeled to represent project development success rates

as well as any contingency that would make meeting the State’s RPS goals less likely (e.g., delays due

to transmission, curtailment, material shortages, load growth beyond that which is forecasted, or less

than expected output from resources). Additionally, this methodology provides an appropriate

minimum margin of procurement “necessary to comply with the renewables portfolio standard to

mitigate the risk that renewable projects planned or under contract are delayed or cancelled.”4551 SCE

will reassess its position on a periodic basis and, as such, expects that success rates may need to be

modified in the future to reflect changes to SCE’s portfolio.

The Commission should rely on retail sellers to calculate their minimum margins of

procurement and should not attempt to impose a one-size-fits-all approach. As many of the projects in

SCE’s portfolio become operational, SCE will face different risks, including integration of these

resources. The risks associated with project failure will be replaced by less significant risks of projects

4551 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).

41

generating below full capacity. Similarly, SCE expects that the portfolio risk picture is not the same

for each retail seller. For example, risks may vary depending on whether a portfolio contains a high

proportion of contracts that are online (as discussed above) or depending on the various technologies

being used (e.g., geothermal technology, which is a baseload resource, versus wind or solar

technologies, which are more intermittent as described in Section IV.B). For these reasons, each retail

seller should continue to have the authority to revise its approach to calculating the minimum margin

of procurement through the RPS procurement planning process and each retail seller should have the

flexibility to calculate this margin based on its unique portfolio make-up and procurement needs.

VIII.

BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES

A. Bid Solicitation Protocol

SCE proposes toDepending on the outcome of the PCIA OIR proceeding, SCE may hold a

20172018 RPS solicitation, only for sales of vintage 2017 through 2020 renewable energy for

Category 1 RECs. SCE will use the proposed 20172018 Procurement Protocol, included here as

Appendix IH.1, for these sales and for future RPS solicitations beyond 2017.2018. The Procurement

Protocol includes, among other things, the following items, some of which are not relevant for SCE’s

contemplated REC sales solicitation but are relevant for purchase solicitations in future years:

SCE’s requirements for initial delivery dates and preferred contract term lengths;

Deliverability characteristics and locational preferences;

SCE’s preference for LCR projects;

Encouragement for Women-Owned, Minority-Owned, Disabled Veteran-Owned,

Lesbian-Owned, Gay-Owned, Bisexual-Owned, and/or Transgender-Owned Business

Enterprises (“Diverse Business Enterprises”) to participate in SCE’s RPS solicitation and

information on how sellers can help SCE to achieve General Order (“GO”) 156 goals;

Requirements for each proposal submission;

A description of the type of products SCE is soliciting;

A schedule of key dates related to the RPS solicitation; and

42

SCE’s 20172018 Pro Forma Renewable Power Purchase Agreement (“Pro Forma”),

attached as Appendix GF.1; and

20172018 REC Sales Confirmation (“20172018 REC Sales Agreement”).

A discussion of the important changes in the proposed solicitation documents from SCE’s

20162017 solicitation documents is included in Section XVXIV.

B. LCBF Methodology

In its LCBF evaluation process, SCE performs a quantitative assessment of each proposal and

subsequently ranks them based on each proposal’s benefit and cost relationship. The result of the

quantitative analysis is a rank order of all complete and conforming proposals’ net levelized benefit

that help define the preliminary shortlist. Following the quantitative analysis, SCE will conduct an

assessment of the top proposals’ qualitative attributes. These qualitative attributes, including factors

such as local reliability, resource diversity, and nominal contract payments, are considered to either

eliminate or add projects to the final shortlist based on qualitative attributes, or to determine

tie-breakers, if any. Once a project is added to the shortlist, SCE may enter into a PPA with the

project. By taking many quantitative and qualitative factors into consideration, SCE ensures that it

will select projects best suited for its portfolio in order to meet customer needs and attain the State’s

RPS goals. Appendix HG.1 (the “LCBF Methodology”) describes this process, including capacity

valuation and the renewable integration cost adder, among other factors.

There is one element of the current LCBF Methodology about which SCE raised concerns in

its Opening Comments on LCBF Reform, dated July 22, 2016. That is the use of Time of Delivery

(“TOD”) factors for evaluation and payment purposes. As discussed in more detail in Appendix G.1,

TOD factors are unlikely to serve as an incentive for production of power when it is most needed in the

future as solar and wind renewable resources have limited flexibility in their time of power production.

While SCE does not eliminate the use of TOD factors in its LCBF valuation in this Written Plan, it will

continue to argue for their elimination in future consideration of LCBF Reform.

SCE also considers as qualitative factors in its LCBF valuation, the impact of a project on: (1)

employment or Workforce Development; and (2) disadvantaged communities, which are identified as

43

Environmental Justice communities through California’s Environmental Protection Agency’s

CalEnviroScreen 3.0.

As stated previously in this written plan, IOUs will have some flexibility to fulfill their

compliance requirements through a combination of long term contracts and short-term products,

reducing the overall costs for their customers. Given this change, SCE will seek portfolio optimization

opportunities to make those tradeoffs between long-term contracts and short-term purchases. An

active REC sales strategy will be a key part of SCE’s portfolio optimization strategy. As part of its

LCBF analysis of REC sales, SCE will establish a floor price,

and would not look to engage in a sales transaction below that floor price. In Appendix E, SCE

proposes the methodology to establish a REC sales price floor.

IX.

CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS

As in the past three RPS solicitations that SCE has held, SCE does not plan to solicit price

structures based on indices in future RPS solicitations. Sellers can, however, bid escalation factors

in their prices. Proposals with adjustable pricing based on indices were more common when the

renewable industry was starting out. Uncertainties over relatively new technologies made it

reasonable to tie pricing to certain commodity indices, inflation rates, or other indices that made

sense given the technology. However, the industry is more sophisticated now, supply chains are

becoming more stable, and price adjustment mechanisms based on indices are not needed. Sellers

and SCE want price certainty, and SCE does not want to be subjected to extraordinary high (or

unsustainably low) pricing due to fluctuations in a commodity or other indices. Additionally, the

ability to bid price adjustments based on indices increases complexity for sellers in the proposal

process and for SCE in the evaluation process. Developers are not requesting price adjustment

mechanisms and the contract price risk uncertainty associated with them does not warrant their

consideration.

44

X.

ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING

Although SCE has observed very few instances of negative pricing in the day ahead

market,4652 negative prices have been observed on a more regular basis in the real time market.

SCE identifies several factors contributing to increases in instances of negative prices.

Over-generation typically occurs in off peak hours when baseload and must take renewable

generation is high and demand is low, which can cause negative market price hours. On peak

negative prices tend to be localized, transient, and related to congestion caused by a particular

transmission bottleneck.

It is generally difficult to forecast negative prices. SCE continues to manage potential

instances of negative pricing, and the associated impact to SCE customers, through several

different strategies. As a general practice, SCE schedules variable energy resources, such as solar

and wind facilities, into the day ahead market whenever possible. Because resources that are

awarded day ahead schedules are only exposed to negative prices in real time for actual deliveries

in excess of their bid in, day ahead awards, this practice helps to limit customer exposure to

negative prices. This practice is consistent with least cost dispatch principles, which govern SCE’s

approach to marketing its entire portfolio of contracted and utility owned resources.

Additionally, SCE plans to economically bid resources with economic curtailment rights into

the day ahead and real time markets. Resources with these curtailment rights will then be

curtailed as needed based on CAISO’s economic dispatch. In some SCE PPAs, there is a pre defined

amount of pre paid energy per year that may be economically curtailed, subject to some

restrictions, without requiring SCE to pay for the energy that could have been delivered but for the

curtailment instruction. As noted above, this amount is commonly referred to as a “curtailment

cap.” Once the curtailment cap is reached, SCE must pay the contract price for energy that could

4652 ~ 0.05 ~1.96% of hours in sampled nodes in the day ahead market – the vast majority of which occurat generally congested interties such as Palo Verde.

45

have been delivered but for the curtailment instruction. In other SCE PPAs, SCE has the right to

curtail based on economic factors, but must always pay the contract price for energy that could

have been delivered but for the curtailment instruction. These types of curtailment rights are

commonly referred to as “take or pay.” In instances where SCE has either exceeded the

curtailment cap or only has “take or pay” economic curtailment rights to begin with, if SCE were

not to curtail deliveries in excess of any schedules awarded at positive prices, customers would pay

the contract price for that excess delivered energy and incur the costs associated with negative

pricing in such intervals. SCE’s economic bids will therefore serve to further limit customer

exposure to negative prices both in day ahead and in real time, even if SCE ultimately pays the full

contract price for curtailed energy.

In future RPS solicitations, SCE plans to not require sellers to bid the pre-paid economic

curtailment option with the curtailment cap. SCE will retain the right to curtail at its discretion, but

will pay for curtailments directly resulting from SCE marketing decisions. As in prior years, SCE will

not pay for curtailments in response to an emergency, or due to CAISO or transmission provider

instructions.

XI.

AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS

A. Justification of SCE’s Request for a Tier 1 Advice Letter Approval Process for a Limited

Amount of Short-Term RPS-Eligible Transactions

SCE requests authorization to enter into a limited quantity of short-term renewable energy

transactions for Category 1 REC only products through a Tier 1 Advice Letter Approval Process. This

proposal would improve upon current Commission processes.SCE will propose and detail one REC

sales strategy assuming two different outcomes to the PCIA proceeding within Appendix E.

46

1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The

Foreseeable Future

The IOUs areSCE is well positioned to meet the Compliance Period (“CP”)CP 3 2020

33% RPS target with existing projects and projects under development (risk-adjusted).47 PG&E

forecasts it will not need incremental physical RPS need until 2026,48 and SDG&E forecasts 45%

renewable energy by 2020.49 Because of this excess REC volume, neither SCE, PG&E nor SDG&E

held Therefore SCE did not hold an RPS procurement solicitation for the 2016 cycle. In both its 2016

and 2017 RPS Plans, PG&E provides a solicitation protocol for a streamlined process for short-term

REC sales contracts under five years, with a pro forma sales agreement, citing Commission

authorization in D.14-11-042. The Commission accepted PG&E’s solicitation protocol in

D.16-12-044. PG&E recently launched a 2017 Request For Offers (“RFO”) for the short-term sales of

bundled RECs and, on June 16, 2017, filed REC sales agreements entered into through its RFO, via a

Tier 1 Advice Letter for Commission approval.50and 2017 cycles. Also, if the Commission adopts the

GAM proposal in the PCIA OIR proceeding, SCE forecasts that it will have excess RECs at least

through 2023 without the use of its REC bank and through CP 5 (2025-2027) with the use of the REC

bank for compliance purposes. If the Commission does not adopt REC allocation PCIA methodology

in the PCIA OIR proceeding, SCE forecasts that it will have excess RECs at least through 2029

without the use of its REC bank and through CP 6 (2028-2030) and beyond with the use of the REC

bank for compliance purposes.

The Commission’s 2016 Biennial RPS program update51 showed that most of the

CCAs and ESPs are significantly below their 2020 33% RPS requirements. Most of these smaller RPS

47 2016 Q4 CPUC RPS Report to Legislature.48 2016 PG&E RPS Plan.49 2016 SDG&E RPS Plan.50 See, PG&E’s Advice Letter No. 5095-E.51 http://www.cpuc.ca.gov/RPS_Reports_Docs p. 6, Table 1.

47

obligated entities procure the majority of their RPS-eligible resources through short-term transactions

made at the end of a compliance period. All retail sellers must procure a minimum level of Category 1

RECs; the minimum level increases over multi-year compliance periods.52 For CP 3, the minimum

requirement for Category 1 procurement is 75%, which is higher than previous compliance periods.

Also, there is a maximum limit on the amount of Category 3 procurement that may be used in each

compliance period, which decreases over the same time frame. As a result, the smaller ESPs and

CCAs cannot solely depend on short term Category 3 RECs acquired towards the end of compliance.

Additionally, any newly formed CCAs during this timeframe (2017-2020) will have to

meet the same requirements for RPS compliance as described above. Most of these requirements will

have to be met using existing facilities, since development of new projects (i.e., siting, licensing,

construction, contracting) is a time consuming process that may not be able to be completed in time to

meet the 33% RPS compliance requirement by 2020. Accordingly, it is important for all market

participants to have access to purchase Category 1 RECs from existing facilities to avoid market

distortions.

2. California Customers Need an Open Market for RECs

When entities only rely on long -term contracting and new projects to meet compliance

requirements, the costs of meeting RPS goals are higher. This cost increase comes from an inability to

make adjustments to the portfolio quickly using short term products. Until recently,53 the RPS rules

did not allow for much flexibility in meeting RPS requirements if using a bank. LSEs with large

procurement needs and therefore large uncertainties could not reasonably rely on the use of short -term

products to meet their requirements. This was especially true as the market was forming; when and

there was not significant depth in the short -term markets. Large LSEs instead used the banking rules

to build portfolios to account for uncertainties in project development, load forecasts and production.

This led to the development of banked positions that also resulted in an inability to use short -term

52 CAL. PUB. UTIL. CODE § 399.16(c).53 D.17-06-026.

48

products to meet any future needs due to RPS retirement rules. New legislation (SB 350) adopted in

2016 removed these barriers and created a more level playing field for all LSEs.

A combination of long -term and short -term procurement will allow LSEs to build

more costs cost-effective portfolios for customers. Long -term procurement can focus on bringing

new projects online. Short -term procurement can focus on balancing the portfolio to meet compliance

requirements at the lowest possible cost. This combination of long-term and short-term procurement

will also allow for a free exchange of RECs between different entities who may have over/under

procured for their compliance needs.

The Commission’s RPS compliance reports demonstrate the state’s progress in

meeting its aggressive RPS procurement targets, driven by the investments made by the three large

IOUs in California. Currently all IOUs are long for RPS energy,54 and some ESPs and/or CCAs may

need RECs to meet compliance requirements in the near future, as well as meeting their additional

sustainability goals that many have set forth - above and beyond their compliance requirements.55

Allowing for the free trade of these long positions between LSEs will allow for a lower cost outcome

for all customers. An open market will provide for a lower cost and flexible option for meeting RPS

requirements.

In addition, all retail sellers must procure a minimum level of Category 1 RECs; the

minimum level increases over multi-year compliance periods.56 For CP 3, the minimum requirement

for Category 1 procurement is 75%, which is higher than previous compliance periods. Also, there is

a maximum limit on the amount of Category 3 procurement that may be used in each compliance

period, which decreases over the same time frame. As a result, entities cannot solely depend on s

Category 3 RECs acquired towards the end of a compliance period. Any newly formed entity during

the CP 3 timeframe (2018-2020) will have to meet the same requirements for RPS compliance as

54 Section XI.A.1 above. 55 Id.56 CAL. PUB. UTIL. CODE § 399.16(c).

49

described. Most of these requirements will have to be met using existing facilities, since development

of new projects (i.e., siting, licensing, construction, contracting) is a time-consuming process that will

likely not be able to be completed in time to meet the 33% RPS compliance requirement by 2020.

Accordingly, it is important for all market participants to have access to purchase RECs sourced from

existing facilities to avoid potential market distortions and compliance shortfalls.

In addition, as discussed in Section I above, beginning in 2021, SB 350, as

implemented in D.17-06-026, requires that all entities must meet 65% of their RPS target with eligible

renewable resources having long-term contracts or ownership arrangements of 10 years or more.

Accordingly, it is important for all market participants to have access to purchase long-term RECs

sourced from existing facilities either for the duration of a contract for a specific facility or for 10 years

for non-project specific contracts to avoid potential market distortions.

3. REC Sales Will Create Customer Value

a) Selling is better than banking up to the established limits

When SCE considers whether to engage in sales of renewable energy products,

SCE compares the value obtained from selling RECs to the costs of having to procure additional

renewable energy in the future. SCE analyzes the impact to its renewable needs and the costs to

customers through the use of the NMV calculation. SCE compares the NMV for the sales transaction

against the NMV of proposals submitted to SCE in recent solicitations and other procurement. If the

NMV for long-term renewable procurement is higher than the NMV for the sales transaction, it would

be more cost -effective for SCE to maintain its existing RPS bank for future compliance periods and

not to make renewable energy sales. Conversely, if the NMV from recent solicitations is lower than

the NMV for the sales transaction, SCE has an opportunity to optimize its renewables portfolio and

realize value for its customers by selling renewable energy products.

In addition to the NMV considerations discussed above, SCE evaluates

potential risks when determining its renewables portfolio optimization strategy, including the risk of

not meeting its RPS targets. When SCE has a long position in the near and intermediate term, SCE

evaluates whether a sale of renewable energy products is appropriate. This evaluation includes a

50

calculation of SCE’s renewable procurement position and RPS bank with a set of adverse


resources than expected, lower risk-adjusted project success rates for contracted generation that is not

yet online, and higher levels of curtailment than expected. SCE assesses its renewable procurement

position with such adverse assumptions to ensure that, even in a sub-optimal scenario, SCE would still

expect to meet its RPS targets after making the sale. SCE’s overall approach appropriately balances

the risks and costs of selling renewable energy products with the risks and costs of maintaining an RPS

bank.

b) Published Research From Independent Entities Forecasting Decline and/or

Stabilization of Renewable Energy Costs

Appendix F.2, at Section I, contains Confidential Data regarding SCE's most

recent RPS solicitations and published BNEF research illustrating a declining trend in the cost of

renewable energy.

b) c) REC Sales Stabilize Rates By Realizing Near Term Value

Assuming adoption of the IOUs’ GAM proposal, SCE has a bank until year

203056the end of CP 5 (2025-2027)57 for meeting RPS compliance established by SB 2 (1x) and

D.11-12-052, as well as the targets established in SB 350 and D.17-06-026. Assuming no allocation of

RECs in the PCIA methodology, SCE has a bank until CP 6 (2028-2030) and beyond58 for meeting

RPS compliance established by SB 2 (1x) and D.11-12-052, as well as the targets established in SB

350 and D.17-06-026. As a result, short term REC sales can help create near term value and in turn

create near term rate relief for itsSCE customers. SCE isholds a significantly long on itsposition to

meet compliance positionneeds in the near term. Then, the bank gets shorter. In year 2030,57In future

compliance periods, the length of this position is subject to fluctuation, depending on the final

5657 Section II.B. 58 Id.

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outcome of the PCIA OIR. For example, assuming adoption of GAM in CP 5 (2025-2027),59 SCE

hasforecasts no need for new RPS resources with the use of bank, but is not as significantly long on

RPS resourcesby CP 6 SCE’s bank is not long on RECs. Adoption of no allocation of RECs in the

existing PCIA methodology results in SCE being significantly longer on RECs with the use of bank. If

SCE can generate some revenues through near term REC sales, it will help smooth out SCE’s RPS

compliance positions over thethese coming years. In turn, these REC sales would smooth out the rate

impacts over the years to SCE’s customers because RECs from more expensive contracts would be

sold and replaced with cheaper renewable energy for compliance for future years, taking advantage of

declining renewable prices as discussed in Appendix F.2, Section I.

c) d) SB 350 Allows for IOUs’ Use Of More Short Term-term Products, Which

Could Help Lower Costs for Customers, While Requiring Other LSEs to Use

More Long Term-term Products

Senate BillSB 3505860 requires that 65% of total renewable portfolio that a retail

seller counts toward the RPS target for each compliance period must be from long-term contracts,

starting no later than 2021. The previous long-term contracting requirement for retail sellers was

smaller - 0.25% of prior period’s total retail sales.

Starting in 2017, any retail seller can elect to use the new SB 350 rules,

allowing 35% of RECs towards the RPS targets to come from short-term contracts. 5961 Any retail

seller making such an election must, however, meet 65% long-term contracting requirement.6062.

Short-term contracts would facilitate the following types of projects/products to count toward RPS

targets:

7 Seven-year renewable qualifying facility must-take contracts

5759 Id.5860 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416.5961 Id. at Ordering Paragraphs 15-24, at pp. 54-56. 6062 Id. at Conclusion of Law 6, at p. 42.

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Existing projects (including in-state) that can still produce and do not want

to repower and have a long-term contract terminating

New projects that are merchant prior to a long-term contract

Short Term-term Bundled RECs

Unbundled REC contracts

Given the changes in legislation, IOUs will now have more flexibility to fulfill

their compliance requirements through a combination of long -term contracts and short -term

products, including but not limited to the examples above, reducing the overall costs for their

customers.

B. SCE’s Proposal

1. Tier 1 Advice Letter Approach

SCE proposes a Tier 1 Advice Letter Approach for approval of REC sales. SCE’s

proposed approach includes terms, volume limits, and a pricing floor as part of the preferred approach

for the REC sales framework as summarized in Table XI-15 below.

53

Table XI-15SCE’s REC Sales Framework

Parameter Proposal

Transaction mediums61 63 Exchanges, RFO Process, Electronic Solicitations, Brokers, Bilateral (strong showing6264)

Terms < 5Remaining term of applicable contract or up to 10 years for non-project specific contracts

Sales Volume Limits63 65 Based on load/gen forecast and uncertainty around it, changing RPS legislation and anticipated pricing

Pricing64 66 Price Floor based on market pricing

PRG Consultation Quarterly, at PRG meetings

Approval Process

Pre-approval through 2017 RPS Plan filing; Report through Quarterly Compliance Report (QCR) filingTier 1 if sold through solicitation process or a bilateral utilizing standard contract without modification after results of a solicitation are known. All others, Tier 3.

Consistent with D.17-12-007, Ordering Paragraph No. 8,6567 SCE will submit a Tier 1

Advice Letter filing for each of its REC sales from solicitations resulting from this 20172018 RPS

Plan or for bilaterally negotiated REC sales using the pro forma REC Sales Agreement attached to this

Written Plan as Appendixes JAppendices I.1-JI.65 and executed after SCE receives bids for a sales

61 Explained in more detail in section XI.E below.63 Explained in more detail in section XI.E below.6264 A strong showing could include competing price offers, broker or online quotes, published indices,

comparisons to recent solicitations. 63 Sales Volume Limits methodology is explained in detail in Appendix F.2, section II.65 Sales Volume Limits methodology is explained in detail in Appendix E, section II.64 Price Floor methodology is explained in detail in Appendix F.2, section III.66 Price Floor methodology is explained in detail in Appendix E, Section III.6567 D.17-12-007, pp. 71-72.

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solicitation resulting from this Written Plan.. For REC Sales PPAs resulting from solicitations, a Tier

1 Advice Letter will include eachall REC Sales PPA with REC Sales PPAs to be submitted as a group

for the results of each concurrent solicitation (consistent with D.14-11-042). For bilaterally negotiated

REC Sales PPAs using the pro forma REC Sales Agreement in Appendices JI.1-JI.165 of this Written

Plan and executed after SCE receives bids for a sales solicitation resulting from this 20172018 RPS

Plan, a separate Tier 1 Advice Letter will include each bilaterally negotiated REC Sales PPA. With

the simplicity of the evaluation and selection process, a Tier 1 advice letter approval process is more

appropriate and more efficient than the current Tier 3 advice letter approval process for such REC

sales.

2. Tier 3 Approval Process

Consistent with D. 17-12-007, SCE may also engage in bilateral REC sales

transactions that do not utilize the pro forma REC Sales Agreement attached as Appendices JI.1-JI.65

to this Written Plan or that are not executed after SCE received bids for a sales solicitation resulting

from this 20172018 RPS Plan.6668 These bilateral REC sales transactions are subject to the

Commission’s review and approval of completed transactions through a Tier 3 Advice Letter

process.6769

C. SCE’s Proposed Limits on REC Sales

Appendix F.2,E, Section II describes and provides an example calculation of SCE’s proposed

volume limits. SCE will take into account any impact from the PCIA proceeding as it relates to how it

may impact its REC position in future years. Assuming the current PCIA methodology (or something

comparable) is adopted in the PCIA proceeding, SCE would expect to have substantially more RECs

compared to if the GAM proposal is adopted. As such, SCE would likely have a much higher

maximum sales volume limit if the current PCIA methodology is maintained.

6668 See, D.17-12-007, pp. 71-72, Ordering Paragraph 8. 6769 Id.

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D. Acceptable REC pricing

Appendix F.2,E, Section III sets out SCE’s confidential upfront pricing standardsstandard for

REC sales.

E. Proposed Transactional Methods

SCE proposes several methods for which it seeks approval to transact RECs. Below is a

description of some of these methods. SCE will consider several factors to determine the most

effective method for the sales of RECs including, but not limited to, liquidity of the product and other

market dynamics, price competitiveness, number of counterparties transacting in the product, and

quantities required by SCE. These factors change over time; thus, SCE may seek to transact at various

times using different methods.

1. Competitive Solicitations

SCE proposes to maximize value to its customers through competitive solicitations that

encourage participants to offer the highest possible price when purchasing RECs. When buying

renewable energy, SCE has seen much higher costs being offered through mandated procurement,

non-competitive programs. Typically, these programs may focus on specific technologies or project

size. Conversely, SCE’s RPS Solicitations have consistently brought the lowest renewable prices

through the competitive bidding process. Similarly, higher prices may be realized through a

competitive solicitation when SCE sells RECs. Additionally, a competitive solicitation will allow

SCE to seediscover where the market is, in terms of the prices buyers are willing to be paidpay for

RECs. SCE may also bid in tointo solicitations held by third parties seeking RECs.

2. Bilateral Transactions

In certain instances, SCE may accept bilateral offers to purchase RECs. For example,

if there are a small number of interested parties in the REC market or deadlines are approaching where

an interested party needs to purchase RECs, to meet a unique need, prior to a solicitation being

launched. These and other situations may lead to SCE selling RECs bilaterally rather than through a

competitive process. Such sales would be subject to review through a Tier 1 Advice Letter process, if

they utilize the pro forma REC Sales Agreement submitted in Appendices J.1-J.6 to this Written Plan

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and occur after SCE receives bids for a sales solicitation resulting from this 2017 RPS Plan. If such

sales do not utilize the pro forma REC Sales Agreement submitted in Appendices J.1-J.6 to this

Written Plan or do not occur after SCE receives bids for a sales solicitation resulting from this 2017

RPS Plan, such sales would be subject to review through a Tier 3 Advice Letter process.

3. Brokers

Brokers provide a forum for market participants to trade anonymously with one

another. Voice brokers announce bid and ask prices, but not counterparty names, to market

participants and match up buyers and sellers based on price. Electronic brokers perform the same

function electronically. Brokers, therefore, facilitate trading by creating price transparency and

liquidity in the market. As such, the price that brokers provide is known and available to any

interested market participant and representative of the market at the time of the transaction. Where

practical and possible, SCE obtains multiple broker quotes to ensure SCE pays or receives the market

price. Unlike exchanges, brokers do not take title to the product being transacted and, therefore, do not

provide credit support for them. Once a broker matches up market participants, their identities are

revealed to each other, but not to the market. The market participants must either be enabled to

transact (for example, through a master agreement), establish new agreements, or clear the transaction

through an exchange. For providing these matching services, brokers charge each party a fee. These

fees are small relative to the nominal value of the transactions.

Brokers are an excellent means through which to transact standard (e.g. GHG

allowances) and non-standard (e.g. LCFS credits, GHG Offsets) products that may or may not be

traded on exchanges. SCE is seeking authorization to use pre-approved brokers for REC transactions

as part of this filing.68 If SCE wants to add or use other brokers in the future, it will obtain prior

Energy Division approval by filing a Tier 2 Advice Letter. That said, sales through Brokers would be

subject to review through a Tier 1 Advice Letter process, if they utilize the pro forma REC Sales

68 See Appendix F.1 for SCE’s proposed list of pre-approved brokers.

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Agreement submitted in Appendices J.1-J.6 to this Written Plan and occur after SCE receives bids for

a sales solicitation resulting from this 2017 RPS Plan. If such sales do not utilize the pro forma REC

Sales Agreement submitted in Appendices J.1-J.6 to this Written Plan or do not occur after SCE

receives bids for a sales solicitation resulting from this 2017 RPS Plan, such sales would be subject to

review through a Tier 3 Advice Letter process.

F. Proposed Timeline for REC Sales

SCE’s Procurement Protocol in Appendix IH.1 sets out its proposed timeline for any REC

Sales done through an RFO, and all other types of REC sales transactions would occur following

Commission approval of SCE’s 20172018 RPS Plan.

XII.

EXPIRING CONTRACTS

For SCE’s RPS-eligible contracts expiring in the next ten years, Appendix E includes the name

of the facility, technology, contract expiration date, nameplate capacity, expected annual generation,

location, contract type, and portfolio content category classification. SCE used the template for

reporting on RECs from expiring contracts as provided in the RNS Ruling.

G. Alternate Approach Is Adopted In PCIA OIR Proceeding

Within the PCIA OIR proceeding, proposals other than an updating of the benchmarks using

the current PCIA methodology or the Joint Utilities’ PAM or GAM proposals have also been put

forward. These include a PCIA with updated benchmarks, (proposed by AReM/DACC),

Monetization in Market with a True-Up (proposed by TURN), Portfolio Securitization (proposed by

CalCCA), and different auction mechanisms (Commercial Energy and CalCCA). SCE expects to hold

a net long REC position with any of the current alternate proposals and would likely still propose to

sell RECs using the rationale and methods proposed above. However, SCE requests an opportunity to

update this 2018 RPS Plan with modifications to its REC sales approach 60 days from the issuance of

a final decision in R.17-06-026, if the Commission chooses an approach different from using the

current PCIA methodology or the Joint Utilities’ PAM or GAM proposals.

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XII.XIII.

COST QUANTIFICATION

The spreadsheet attached as Appendix D includes actual expenditures per year for

RPS eligible generation for every year from 2003 through 2016,2017, as well as actual RPS eligible

generation for every year from 2003 through 2016.2017. Appendix D also includes a forecast of

future expenditures SCE may incur every year from 20172018 through 2030, as well as a forecast of

expected generation for every year from 20172018 through 2030.

XIII.XIV.

IMPERIAL VALLEY

In SCE’s last RPS solicitation (the 2015 RPS solicitation), SCE received 279 proposals.

Since SCE has not held an RPS solicitation

since 2015, SCE will not include this section in future RPS Plans, as it is not necessary when no

solicitations are being held.

XIV.XV.

IMPORTANT CHANGES FROM 20162017 RPS PLAN

SCE has made significant changes to the Written Plan to recognize that SCE, at present, has no

need for more eligible renewable resources. As a result, SCE does not propose to hold a 2017 RPS

solicitation. Instead2018 RPS solicitation. If SCE’s preferred scenario as set forth in the IRP


(“GHG”) emitting resources, including renewable energy, through the IRP proceeding. Instead, in this

RPS proceeding, SCE seeks permission to sell SCE RECs of 2017-2020 vintage, as discussed in

Section XI above.

70 R.16-02-007.

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SCE’s 20172018 RPS Plan includes changes to: (1) SCE’s 20162017 Procurement Protocol;

(2) SCE’s 20162017 Pro Forma; (3) SCE’s 2016 Pro Forma REC Sales Agreement; and (43) SCE’s

LCBF Methodology. Those changes are summarized below. SCE has included redlines of its

20172018 Procurement Protocol, 2017 Pro Forma, 2017 Pro Forma REC Sales Agreement, and

LCBF Methodology against the versions of those documents included in SCE’s 20162017 RPS Plan

as Appendices IH.2, GF.2, J.2 and HG.2, respectively. SCE has made relatively few changes to these

documents from the 2016 documents2017 documents. SCE did not include a redline of the 2017 Pro

Forma REC Sales Agreement because the 2018 Pro Forma REC Sales Agreement is identical to the

2017 Pro Forma REC Sales Agreement. The most significant changes to the other 20162017

documents are summarized below.

A. Important Changes in 2017 Procurement Protocol 2018 Pro Forma

1. Only REC Sales Will Be Part of this Solicitation

As discussed above, SCE plans to solicit offers for SCE to sell RECs of 2017-2020

vintage as part of any 2017 RPS solicitation that it may hold. The 2017 RPS Procurement Protocol, in

Article 1, includes solicitation of proposals to sell RECs of 2017-2020 vintage which may be part of

any 2017 RPS solicitation.

B. Important Changes in 2017 Pro Forma and REC Sales Agreement

The changes to the Pro Forma were mostly minor or clean-up items, with important changes

summarized below.69 A redline of the 20172018 Pro Forma showing all of the changes from the

20162017 RPS Pro Forma is attached as Appendix IF.2. Additionally, changes related specifically to

the Standard Contract Option are mentioned in Section XVIIXVI.B. For SCE’s Community

Renewables solicitation (“CR-RAM”) SCE will use the Community Renewables Rider (“CR Rider”)

to the 20172018 Standard Contract Option, which SCE submitted to the Commission via Advice

Letter 3422-E for its Community Renewables PPAs.

69 SCE also made changes to the Green Rate provisions that mirror the CR-Rider.

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Important changes in 20172018 Pro Forma:

1. In case of shortfall in the actual installed Contract Capacity or Installed DC Rating, Seller

can pay for the capacity shortfall, in addition to the option of applying Development

Security. This payment option helps protect Seller’s relationship with its Letter of

Credit issuing bank. This change is reflected in Section 3.06(f).Added that either party

may terminate in the event of a Force Majeure prior to the Commercial Operation Date

that extends beyond the Commercial Operation Deadline. Also, made clear that Force

Majeure does not include a curtailment at the direction of the Transmission Provider or

the CAISO when the curtailment is caused by outages or capacity reductions due to

maintenance construction or repair.

2. Added Seller indemnity obligations for: i) violation of Applicable Laws or CAISO Tariff;

ii) release of hazardous material; and iii) monetary penalties or fines against SCE by

the CPUC resulting from Sellers willful or negligent failure to provide SCE with the

full amount of RA.

3. 2. Interest payment on cash collateral is changed from monthly payment upon receiving

invoice to payment upon collateral return. This change saves administrative efforts for

both parties. This change is reflected in Section 8.04(a).Made changes related to late

payment interest calculations including changing the calculation of “Interest Rate” to

incorporate the average annual interest rates reported for all weekdays in the H.15

release published by the Federal Reserve.

3. Development Security posting deadline is changed from Effective Date to within five

Business Days following Effective Date. The change provides Seller reasonable time to

post the security. This change is reflected in Section 8.02(b).

4. Changed the Time of Delivery Periods and the Payment Allocation factors.

5. Modified language within certain sections of the agreement in order to address conformity

within SCE contracting language across all solicitations

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6. Other non-substantive changes made to the 20172018 Pro Forma reflect a re-organization

of certain credit terms and conditions in order to consolidate all of the credit related

provisions into a single article within the 20172018 Pro Forma.

TheNo changes were made to the 20172018 Pro Forma REC Sales Agreement were mostly minor

clean-up items to reflect formatting errors within the document. A redline of the 2017 Pro Forma

REC Sales Agreement showing all of the changes from the 2016 Pro Forma REC Sales Agreement is

attached as Appendix J.2. Important changes include the following.and the document remains the

same as in 2017.

1. The credit and collateral terms were updated to reflect a revised method for calculating

the buyer’s collateral requirements.

2. The confidentiality provisions were modified to allow the parties to disclose

confidential information to the Western Renewable Generation Information System

(“WREGIS”).

B. C. Important Changes in 2017 Least Cost, Best Fit Methodologythe Written Plan

1. Capacity benefit for Solar and Wind resourcesRemoval of Time-of-Use and

Expiring Contracts Information

SCE will use the Effective Load Carrying Capacity (“ELCC”) methodology with

approved ELCC values from Energy Division’s second proposed methodology, as set forth in

Appendix A of D.17-06-02770 to calculate Resource Adequacy benefit, as further discussed in

Appendix H.1.

In the 2017 RPS Plan, SCE included information on its Residential and

Non-Residential Time-of-Use (“TOU”) periods, in compliance with D.17-01-006, p. 67. In its 2017

Final RPS Plan, approved by the Commission in D.17-12-007, SCE stated that “Going forward, Base

TOU periods will be addressed in SCE’s General Rate Case Phase 2 proceedings and consequently

70 On June 29, 2017, the Commission issued the final decision (D-17-06-027) to adopt an Effective Load Carrying Capacity approach to determining the capacity value of wind and solar resources.

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will not be included in subsequent RPS Plans.”71 Accordingly, in conformance with its statement in its

2017 RPS Plan, SCE has not included information on its Residential and Non-Residential TOU

periods in this 2018 RPS Plan.

2. Addition of Information on Electrification of Transportation

D.18-05-026 implementing SB 350 provisions on penalties and waivers in the RPS

program requires that: “Beginning with the 2018 Renewables Portfolio Standard Procurement Plan

cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually demonstrate

that transportation electrification is accounted for in their procurement plans by explicitly referencing

forecasted transportation electrification in their Renewables Portfolio Standard procurement

plans…”72 Accordingly, SCE added a discussion of its forecast of transportation electrification in

Section II.B, which discusses how SCE forecasts RPS need.

3. Revisions to REC Sales Strategy

In June of 2017, the Commission opened the PCIA OIR. SCE did not have the

opportunity to consider the impacts of that proceeding on its REC sales strategy in its 2017 RPS Plan.

However, at this point, the Commission has created a full evidentiary record in the PCIA OIR, parties

have submitted their briefs and the Commission has published both a Proposed and an Alternate

Proposed Decision in that proceeding. So, in this 2018 RPS Plan, SCE will present a REC sales

methodology that conforms to two possible scenarios for the outcome of the PCIA OIR. If the final

decision in the PCIA OIR differs from the two possible scenarios for the outcome of the PCIA OIR

that SCE presents, SCE may seek to update its 2018 RPS Plan to revise its REC sales strategies in

conformance with the final PCIA OIR decision.

In addition, in this 2018 RPS Plan, SCE generally proposes sale of all PCCs of RECs,

rather than just PCC 1, as it proposed in the 2017 RPS Plan. This is to give SCE the flexibility to sell

71 2017 Final RPS Plan, pp.62-63.72 D.18-05-026, Ordering Paragraph No. 3, p. 32.

63

more types of RECs in the market. SCE also proposes to sell RECs for longer terms (if there is a

market for such sales) and makes changes to its price floor methodology.

4. Removal of Information on Expiring Contracts

The ACR for the 2018 RPS Plan did not require inclusion of information on expiring

contracts, as the ACR for the 2017 RPS Plan did. Accordingly, SCE did not include information on

expiring contracts in this 2018 RPS Plan.

XV.XVI.

SAFETY CONSIDERATIONS

SCE is strongly committed to safety in all aspects of its business. Renewable sellers are

responsible for the safe construction and operation of their generating facilities and compliance with

all applicable laws and safety regulations. SCE has taken several steps to address those issues over

which it has the most visibility and control – the delivery of renewable electricity products to SCE in a

reliable, safe, and operationally sound manner.

As with past RPS pro forma PPAs, SCE’s 20172018 Pro Forma provides that the seller must

operate the generating facility in accordance with “Prudent Electrical Practices.”7173 The detailed

definition of “Prudent Electrical Practices” includes “those practices, methods and acts that would be

implemented and followed by prudent operators of electric energy generating facilities in the Western

United States, similar to the Generating Facility, during the relevant time period, which practices,

methods and acts, in the exercise of prudent and responsible professional judgment in the light of the

facts known or that should reasonably have been known at the time the decision was made, could

reasonably have been expected to accomplish the desired result consistent with good business

practices, reliability and safety. . . .”7274

Consistent with SCE’s focus on safety, SCE’s 20172018 Pro Forma also provides that, prior to

commencement of any construction activities on the project site, the seller must provide to SCE a

7173 See 20172018 Pro Forma (attached as Appendix GF.1) at Section 3.12(a). 7274 Id. at Exhibit A.

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report from an independent engineer certifying that seller has a written plan for the safe construction

and operation of the generating facility in accordance with Prudent Electrical Practices.7375

SCE also has a safety section in its 20172018 Procurement Protocol providing that sellers must

possess a written plan for the safe construction and operation of the generating facility as set forth in

the 20172018 Pro Forma.7476

XVI.XVII.

STANDARD CONTRACT OPTION

In D.14-11-042, the Commission ended the RAM program, as authorized in D.10-12-048, after

the conclusion of the RAM 6 auction.7577 The Commission also authorized the IOUs to use an optional

streamlined RAM procurement tool in future RPS solicitations.7678 The Commission directed the

IOUs to include the streamlined procurement tool in their RPS Procurement Plans, at their discretion,

starting with the 2015 RPS Procurement Plans.7779

Although SCE will not have a 2017 RPS solicitation,Since the Standard Contract Option PPA

is used as part of the Community Renewables procurement.part of the RPS Solicitation, whether or not

it gets utilized will depend upon whether or not SCE holds a 2018 RPS Solicitation. Consistent with

the Commission’s intent to provide the IOUs with flexibility to optimize their portfolios based on their

procurement needs while providing a streamlined procurement tool,7880 the Standard Contract Option

will allow for rapid development of renewable projects by avoiding the contract negotiation process

and expediting the Commission approval process of executed PPAs. The Standard Contract Option

7375 Id. at Section 3.11(e). 7476 See 20172018 Procurement Protocol (attached as Appendix IH.1) at Section 9.03. 7577 See D.14-11-042 at pp. 91-92, pp. 102-104. 7678 Id. at pp. 91-92. 7779 Id. at p. 92. 7880 Id.

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will only be available to projects with a first point of interconnection to the CAISO, and not to

dynamically scheduled projects.7981

Once executed, the Standard Contract Option PPAs will be submitted to the Commission for

approval via a Tier 2 advice letter. This process uses the same approval process as in RAM, which was

one factor in SCE successfully procuring 787 MW of renewables over five years in six auctions.

In the sections below, SCE discusses the parameters of the Standard Contract Option and their

consistency with D.14-11-042.

A. Procurement Need

In D.14-11-042, the Commission stated that the IOUs should explain in their RPS Procurement

Plan filings how any proposed use of the streamlined RAM procurement tool could satisfy an

authorized procurement need, “including, for example, system Resource Adequacy needs, local

Resource Adequacy needs, RPS needs, reliability needs, LCR needs, GTSR needs, and any need

arising from Commission or legislative mandates.”8082 If SCE holds a procurement for Community

Renewables, SCE will use the Standard Contract Option for Community Renewables procurement

needs as discussed in Section XVIII. Community Renewables has a Rider that modifies the Standard

Contract Option, which is detailed in Section XVIIIXVII. SCE may also use the Standard Contract

Option to fulfill other authorized procurement needs in the future.

B. Standard Contract

The Commission required IOUs to seek Commission authorization for a revised standard

contract so that the RAM tool can continue to be a more streamlined contracting and approval

process.8183 SCE uses its current Pro Forma as the standard contract for the Standard Contract Option.

The RAM standard contract and SCE’s RPS pro forma PPAs are closely aligned. Changes to the RPS

7981 SCE’s 20172018 Pro Forma is structured with the assumption that the generating facility will have a first point of interconnection with the CAISO. Accordingly, changes to the 20172018 Pro Forma will be required for dynamically scheduled projects.

8082 D.14-11-042 at p. 92. 8183 Id. at p. 93.

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pro forma PPA that were approved for use in RPS solicitations were subsequently requested and

generally approved for use in the next RAM cycle, and vice versa. Additionally, both the RPS pro

forma PPA and the RAM standard contract have been drafted in a manner that allows for the simple

insertion of project specific information without any other modifications to the terms and conditions.

Specifically, project-specific parameters can be inserted into the 20172018 Pro Forma (e.g., project

size, technology, location, and other project specific attributes), and the resulting contract will be the

standard contract. Additional non-material ministerial changes to the 20172018 Pro Forma may also

be needed in the standard contracts; for example, to correct typographical errors or section references

or delete definitions that are not needed for particular projects.

It will be considerably more efficient for SCE, the Commission, the parties, and the market to

update one pro forma PPA each year, rather than having separate pro forma PPAs for Standard

Contract Option and non-Standard Contract Option projects. Further, one pro forma PPA eliminates

market distortions that might come from commercial differences that could skew sellers toward or

away from the Standard Contract Option.

For 2017,2018, SCE made changes to the SCE 2017 Pro Forma that are applicable to the

Standard Contract Option. Please see Section XVXIV(BA).

XVII.XVIII.

GREEN TARIFF SHARED RENEWABLES PROGRAM

On September 28, 2013, Governor Brown signed SB 43 into law.8284 SB 43 enacted the GTSR

program, a 600 MW statewide program that allows participating utilities’ customers – including local

governments, businesses, schools, homeowners, municipal customers, and renters – to meet up to

100% of their energy usage with generation from eligible renewable energy resources. As required by

SB 43, all of the IOUs filed applications with the Commission requesting approval of GTSR programs

consistent with the requirements and intent of the statute.

8284 SB 43 was codified in California Public Utilities Code Section 2831 et seq.

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On January 29, 2015, the Commission adopted D.15-01-051, implementing a GTSR program

framework and approving the IOUs’ applications with modifications. Among other things, the

Commission divided the GTSR program’s statewide limitation of 600 MW of customer participation

among the IOUs. Specifically, the Commission allocated 269 MW to SCE.8385 SB 43 also provides

that 100 MW of the statewide limitation for the GTSR program shall be reserved for facilities that are

no larger than 1 MW and that are located in areas previously identified by the California

Environmental Protection Agency as “the most impacted and disadvantaged communities”8486

(referred to as “environmental justice” or “EJ” projects by SCE). To implement this statutory

provision, the Commission established EJ and residential reservations for each IOU, including 45 MW

to SCE.8587

The GTSR program structure approved by the Commission consists of two elements: (1) a

green tariff option (called the “Green Rate” by SCE) allowing customers to purchase energy with a

greater share of renewables, and (2) an enhanced community renewables option (called the

“Community Renewables” or “CR” program by SCE) allowing customers to subscribe to renewable

energy from community-based projects.8688 With regard to the Green Rate, SCE has already procured

its 50 MW advance procurement requirement in its 2015 RPS solicitation. SCE does not anticipate

doing additional Green Rate procurement. This is because the Green Rate program currently has a

limited number of subscribed customers and SCE’s advance procurement is expected to satisfy initial

customer enrollment.

A. Community Renewables - Background

The Commission authorized RAM as a procurement mechanism for the CR program,

including the streamlined RAM procurement tool that can be used as part of the IOUs’ RPS

8385 See D.15-01-051 at Ordering Paragraph 7. 8486 CAL. PUB. UTIL. CODE § 2833(d)(1). 8587 See D.15-01-051 at Ordering Paragraph 7 and D.15-01-051 at pp. 4-5. 8688 Id. at pp. 3-4.

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solicitations.8789 The Commission limited initial procurement to new solar facilities between 0.5 MW

and 3 MW,8890 but modified this in D.16-05-006 to include all eligible renewable resources between

0.5 MW and 20 MW for CR projects and all eligible renewable resources between 0.5 MW and 1 MW

for CR-EJ projects.8991 Additionally, now that the CAISO has resolved Distributed Energy Resource

Provider issues, D.16-05-006 allows for aggregation of sub-500 kW resources to participate in the CR

program as long as they aggregate to at least 500 kW and meet all CAISO requirements.9092 CR

projects must be located within SCE’s service territory9193 and must satisfy the eligibility requirements

associated with the RAM procurement tool.9294

SCE filed several advice letters to implement the CR program, including: (i) Advice 3180-E

identifying the eligible census tracts for EJ projects in its service territory;9395 (ii) Advice 3218-E,

which is the IOUs’ Joint Procurement Implementation Advice Letter; (iii) Advice 3219-E, which is

SCE’s Customer-Side Implementation Advice Letter; (iv) Advice 3220-E, which is SCE’s Marketing

Implementation Advice Letter;9496 (v) Advice 3432-E, which is the 20 Year Forecast of GTSR bill

credits and charges;9597 and (vi) Advice 3422-E, which makes changes to SCE’s 2015 Pro Forma

Renewable Power Purchase and Sale Agreement , Standard Contract Option and RFO instructions,

needed to implement the CR program through the RAM procurement tool consistent with

8789 Id. at Ordering Paragraph 1. 8890 Id. at pp. 36-37, p. 39, Conclusion of Law 17. 8991 See D.16-05-006, Conclusions of Law 2 and 4. 9092 Id. at Ordering Paragraph 5. 9193 See D.15-01-051 at pp. 21-23, Conclusion of Law 14. 9294 See D.16-05-006 at p. 35, Conclusion of Law 4. 9395 Advice 3180-E was approved by Energy Division, effective as of February 23, 2015. 9496 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution

E-4734. 9597 Advice 3432-E was approved by Energy Division, effective as of July 11, 2016.

69

D.16-05-006 (the “CR-RAM RFO”), and also requested closure of SCE’s CR-MAT program because

projects eligible for SCE’s CR-MAT program will also be eligible for SCE’s CR-RAM program.9698

Post-implementation of the CR program, SCE has filed several advice letters and other

compliance filing to update the CR program, including: (i) Advice 3461-E, which updated the

CR-RAM Rider and RFO Instructions for CR-RAM One;9799 (ii) Advice 3496-E, 2017 annual

marketing, education and outreach plan and budget for the GTSR program;98100 (iii) Advice 3525-E,

which is SCE’s GTSR program rate component updates for 2017;99101 (iv) Advice 3525-E-A,

supplemental filing to make modifications to Advice 3525-E;100102 (v) Advice 3536-E, which

implements the California alternate rates for energy for the GTSR Program;101103 (vi) Advice 3557-E,

which updated the CR-RAM Rider and RFO Instructions for CR-RAM Two;102104 (vii) Advice

3614-E, which is the update to the 20 Year Forecast of GTSR bill credits and charges;103105 (viii)

Petition for Modification (“PFM”) for D.15-01-051 to change the AmLaw 100104106 securities opinion

requirement;105107 (ix) Advice 3638-E, modifying the securities opinion requirement in the CR-RAM

Rider pursuant to D.17-07-007;106108 (ixx) Advice 3694-E, which updated the CR-RAM Rider and

RFO Instructions for CR-RAM Three;107109 (xxi) Advice 3678-E, 2018 annual marketing, education

9698 Advice 3422-E was approved by Energy Division, effective as of June 15, 2016. 9799 Advice 3461-E was approved by Energy Division, effective as of September 25, 2016. 98100 Advice 3496-E was approved by Energy Division, effective as of November 27, 2016. 99101 Advice 3525-E was approved by Energy Division, effective as of January 1, 2017. 100102 Advice 3525-E-A was approved by Energy Division, effective as of January 1, 2017. 101103 Advice 3536-E was approved by Energy Division, effective as of October 26, 2017. 102104 Advice 3557-E was approved by Energy Division, effective as of March 12, 2017. 103105 Advice 3614-E was approved by Energy Division, effective as of June 5, 2017. 104106 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United

States based on gross revenue. 105107 SCE submitted the PFM on March 27, 2017; the CPUC issued D.17-07-007 on July 17, 2017,

implementing the requested changes in the PFM. See Section XVIII.B.2.106 108 Advice 3638-E was approved by Energy Division, effective as of July 28, 2017. 107 109 Advice 3694-E was approved by Energy Division, effective as of November 15, 2017.

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and outreach plan and budget for the GTSR program;108110 (xixii) Advice 3678-E-A, supplement to

Advice 3678-E;109111 (xiixiii) Advice 3710-E, GTSR program rate component update for 2018;110112

and (xiii(xiv) Advice 3710-E-A, supplement to Advice 3170-E.111;113 (xv) Advice 3737-E, which

updated the 20-year forecast of GTSR bill credits and charges;114 and (xvi) Advice 3790-E, which

updated the CR-RAM Rider and RFO Instructions for CR-RAM Four.115

B. Community Renewables - Modifications to the 20172018 Procurement Protocol,

20172018 Pro Forma Standard Contract Option, and LCBF Methodology

SCE incorporated CR-related modifications into its 2016 Procurement Protocol, created a CR

Rider and Amendment to the 2016 Pro Forma Standard Contract Option, and incorporated

modifications to its LCBF Methodology for CR and CR-EJ eligible projects. SCE planned to include

a Community Renewables solicitation in any 2016 RPS solicitation that it would hold after seeking

and receiving Commission permission. SCE intended that if it did not go forward with a 2016 RPS

solicitation, it would move forward separately with a second Community Renewables Solicitation,

which SCE launched on April 7, 2017.

SCE has incorporated additional CR-related modifications into its 2017 Procurement Protocol

and updated its CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option, which is

the latest approved contract option. CR-RAM will have one more RFO in 2017 and two in 2018. SCE

will use the latest approved RPS Pro Forma Standard Contract Option and CR Rider and Amendment

108 SCE submitted 110 Advice 3678-E on October 16, 2017, which has not been approved as of the date of this filing.was approved by Energy Division, effective as of November 15, 2017.

109 SCE submitted 111 Advice 3678-E-A on December 7, 2017, which has not beenwas approved by Energy Division, effective as of the date of this filing.November 15, 2017.

110 112 SCE submitted Advice 3710-E on November 30, 2017, which has not been approved as of the date of this filing.

111 113 SCE submitted Advice 3710-E-A on December 22, 2017, which has not been approved as of the date of this filing.

114 Advice 3737-E was approved by Energy Division, effective as of January 31, 2018.115 Advice 3790-E was approved by Energy Division, effective as of May 20, 2018.

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with each RFO.SCE subsequently launched its third and fourth Community Renewables Solicitations

on December 22, 2017 and May 23, 2018, respectively. As of CR-RAM 3, SCE has provided two

CR-RAM Rider options to offerors—one specifically for Distributed Energy Resources (“DERs”) and

the other for projects that do not aggregate resources.

1. 20172018 Procurement Protocol – CR Modifications

The 20172018 Procurement Protocol includes additionaldoes not include any

requirements applicable only to CR and CR-EJ projects. CR and CR-EJ projects must agree to

participate in the RAM tool via the 2017 Pro Forma Standard Contract Option and CR Rider and

Amendment, consistent with the Commission’s direction in D.15-01-051 and D.16-05-006.112 The

Procurement Protocol also contains specific instructions applicable to CR and CR-EJ projects only,

including:If SCE holds a CR-RAM Solicitation, SCE will file an Advice Letter and include a

CR-RAM specific protocol.

RAM Eligibility: CR and CR-EJ projects must comply with the eligibility

requirements of applicable to the RAM procurement tool.

Contract Capacity: CR projects must have a minimum project size of 0.5 MW and

a maximum project size of 20 MW; and CR-EJ projects must have a minimum

project size of 0.5 MW and a maximum project size of 1 MW.

Procurement Targets: 75 MW is identified as the minimum procurement target

(“Minimum Procurement Target”).

Community Interest: CR and CR-EJ projects must demonstrate fulfillment of the

community interest requirements pursuant to Decisions 15-01-051 and 16-05-006

within 60 days of notification of contract award or the awarded capacity may be

assigned to the next highest ranking LCBF CR or CR-EJ project offer. In addition,

112 See D.15-01-051 at pp. 21-23, Conclusion of Law 7; D.16-05-006 at Ordering Paragraph 1.

72

at least 50% (by number of customers) and at least 1/6th of the demonstrated

community interest in CR and CR-EJ projects must come from residential

customers.

Resources under 500 kW are allowed to participate in the CR-RAM RFOs as long

as they aggregate to at least 500 kW and follow all CAISO requirements of

Distributed Energy Resources Aggregated resources.

2. 2017 Pro Forma, Standard Contract Option – CR Rider and Amendment

Modifications

In Advice 3422-E, pursuant to D.16-05-006, SCE transferred the previously approved

CR and CR-EJ program, as well as the CR-MAT Rider and Amendment provisions to the RAM tool,

creating a CR-RAM Rider and Amendment to the approved 2015 RPS Pro Forma Standard Offer

Contract (the “Previous CR-RAM Rider”). The Previous CR-RAM Rider included a number of

modifications necessary to implement the requirements of D.16-05-006, and SCE intended for the

Previous CR-RAM Rider to work with the 2016 RPS Pro Forma Standard Offer Contract because it

contained only minor changes from the 2015 RPS Pro Forma Standard Offer Contract. The Previous

CR-RAM Rider has since been updated for CR-RAM One, CR-RAM Two, a new securities opinion

requirement under D.17-07-007, and CR-RAM Three (the “Current CR-RAM Rider”), which will

continue to work with the 2016 RPS Pro Forma Standard Offer Contract because it is the latest

approved RPS Pro Forma Standard Contract Option. The Current CR-RAM Rider includes a number

of modifications to the Previous CR-RAM Rider, to reflect clarifications and conforming changes and

changes necessary to implement the requirements of Ordering Paragraph 5 of D.16-05-006 and

Ordering Paragraph 2 of D.17-07-007.113 SCE intends to utilize the Current CR-RAM Rider, as

modified by any future supplemental advice letters or as required by the Commission (the “Approved

CR-RAM Rider”) to procure CR-eligible resources as part of future CR-RAM RFOs.

113 See Advice 3461-E, Advice 3557-E, Advice 3638-E, and Advice 3694-E.

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3. LCBF – CR Modifications

As with other RPS-eligible projects, CR and CR-EJ projects will be selected using the

LCBF methodology, subject to the additional selection criteria as follows: (i) SCE may decline to

award contracts to developers that bid a price in excess of 120 percent (for CR projects) and 200

percent (for CR-EJ projects) of the maximum executed contract price in either the RAM as-available

peaking category or the Green Rate program, whichever occurred most recently (“Procurement Price

Limits”);114 (ii) when Minimum Procurement Targets are exceeded, first, SCE must select the LCBF

CR-EJ projects with offer prices less than the Procurement Price Limit up to the EJ reservation amount

established in D.15-01-051, then SCE will evaluate all remaining projects against one another on a

LCBF basis and SCE must select those projects with offer prices less than the applicable Procurement

Price Limit, up to the Procurement Target.115

C. Green Rate and Community Renewables – Annual Reporting

In D.15-01-051, the Commission directed the IOUs to include certain additional information in

an annual GTSR Program progress report (the “Annual GTSR Progress Report”).116 The Annual

GTSR Progress Report discusses the following topics: (i) enrollment reporting, (ii) a summary

tracking the amount and cost of generation transferred between RPS and GTSR programs, (iii) GTSR

revenue and cost reporting, (iv) advisory group or advising network activities, (v) marketing report,

(vi) CCA Code of Conduct report, (vii) supplier diversity, (viii) California Alternate Rates for Energy

enrollment figures, (ix) reports of fraud or misleading advertisements received through meetings with

an advisory group or advising network, and (x) enrollment figures for low-income customers and

subscribers who speak a language other than English at home.117 SCE filed its interim Annual GTSR

114 See D.16-05-006 at Ordering Paragraph 3.115 Id. at Ordering Paragraph 2.116 See D.15-01-051 at pp. 141-42, Ordering Paragraph 10.117 Id. at pp. 141-42.

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Progress Report on August 17, 2015, and its first Annual GTSR Progress Report on March 15, 2016.

SCE filed the Annual GTSR Progress Report covering the topics for 2016 on March 15, 2017.

Advice 3218-E, the IOU’s Joint Procurement Implementation Advice Letter, indicated that the

IOUs would be filing an annual report that tracks the amount of generation transferred between the

RPS and GTSR programs (the “Annual Tracking Report”).118 SCE’s GTSR Annual Tracking Reports

for 2015 and 2016 were filed on September 1, 2016 and September 1, 2017, respectively, and

included: (i) progress toward GTSR procurement, including EJ and residential reservations, (ii)

information on the transfer of capacity between the GTSR and RPS programs, and the cost impacts of

that transfer and impact on the IOUs’ RNS, (iii) the need, if any, to bridge for any shortfall, (iv)

accounting of RECs, and (v) a list of contracts with price, and other relevant details.119

C. D. SCE’s Request to Terminate the GTSR Program

On December 22, 2017, SCE filed a Tier 3 Advice 3722-E requesting the Commission’s

approval to terminate the GTSR program on January 1, 2019,120116 and to seek approval to recover

outstanding GTSR costs through the 2018 ERRA Review of Operations Filing.121117 As of the date of

this filing, Advice 3722-E is pending Commission approval.

D. SCE will submit a new renewables rate proposal designed to accomplish the goals set forth in

SB 43. ’s Disadvantaged Communities (DAC) Green Tariff and Community Solar

Programs

On June 21, 2018, the Commission approved D.18-06-027, Alternate Decision Adopting

Alternatives to Promote Solar Distributed Generation in Disadvantaged Communities, which

implements three new programs to promote solar energy in disadvantaged communities. Two of the

programs, the new DAC-Green Tariff program and the Community Solar Green Tariff program, are

118 See Advice 3218-E at p. 24.119 Id. at p. 24 and Attachment D.120116 See D.15-01-051 at Ordering Paragraph 13. 121117 Advice 3722-E.

75

similar to the GTSR Green Rate and Enhanced Community Renewables programs, respectively. The

DAC - Green Tariff Program will be available only to low-income residential customers in DACs,

defined as those meeting the qualifications for CARE and FERA. The Community Solar Green Tariff

Program will be similar to the DAC - Green Tariff program. The major difference between the

DAC-Green Tariff program and the Community Solar Green Tariff program is that the Community

Solar Green Tariff program requires community involvement with the solar project through a local

sponsor and will result in a solar facility serving a nearby community. The program is similar to

Enhanced Community Renewables in that the developer contracts with the customer to service the

energy component of the bill and contracts with SCE for the energy not subscribed by the SCE

customer. Currently, SCE has not filed an Advice Letter nor received approval of Advice Letters for

implementation of the DAC-Green Tariff and Community Solar Green Tariff Programs. Any details

on the procurement would be premature without approval from the Commission of the implementation

Advice Letter. The Advice Letter is scheduled to be filed on August 20, 2018. Details of the

procurement will be addressed in that Advice Letter and can be incorporated in any updated RPS Plan.

E. SCE’s GTSR Replacement Program

In Advice 3722-E, in which it requested the Commission’s approval to terminate the GTSR

program, SCE stated it would propose a replacement program for GTSR. SCE is projected to file an

Application for the GTSR replacement program later this year and full details of the program will be

included in the Application.

XVIII.XIX.

OTHER RPS PLANNING CONSIDERATIONS AND ISSUES

A. Bilateral Transactions

As part of its overall procurement strategy, SCE may engage in bilateral negotiations for

renewable energy purchases or sales subject to the Commission’s review and approval of completed

transactions.

76

B. Energy Storage Procurement

Public Utilities Code Section 2837 requires the IOUs’ RPS Procurement Plans to incorporate

any energy storage targets and policies that are adopted by the Commission as a result of its

implementation of Assembly Bill (“AB”) 2514. To implement AB 2514, the Commission adopted

D.13-10-040, which implemented an energy storage procurement framework and design. The

Commission also directed SCE to procure 580 MW of energy storage by 2020, with projects installed

and delivering by 2024.122118

SCE considers eligible energy storage systems to help meet its energy storage target through

several different programs including conducting an Energy Storage RFO, the Aliso Canyon Energy

Storage RFO and other programs that may incorporate energy storage facilities. Further details on

SCE’s energy storage procurement can be found in SCE’s Energy Storage Plan.123119

C. TOU Rate Periods

D.17-01-006 states, on p. 67, that “each IOU should include its current TOU rate periods in its

annual RPS procurement plan and should make such information available on its website.” SCE

includes its Residential and Non-Residential TOU rate periods in its 2017 RPS Plan in the Tables

below. Going forward,124 Base TOU periods will be addressed in SCE’s General Rate Case Phase 2

proceedings and consequently will not be included in subsequent RPS Plans.

122118 See D.13-10-040 at pp. 15, 26. 123119 See Southern California Edison Company’s (U 338-E) Application for Approval of its 2016 Energy

Storage Procurement Plan (filed biennially). The Application can be located here: http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/14A8421BD056DFC488257F69006CF6CF/$FILE/A.16-03-XXX_2016%20ESPP_SCE%20Energy%20Storage%20Procurement%20Plan%20Application.pdfhttp://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/14A8421BD056DFC488257F69006CF6CF/$FILE/A.16-03-XXX_2016%20ESPP_SCE%20Energy%20Storage%20Procurement%20Plan%20Application.pdf.

124 SCE currently has a pending rate design window proposal to modify the Base TOU periods for all non-residential customers, A.16-09-003, to be effective February 2019. Base TOU periods for (default) residential TOU will be established by the Commission when it resolves the rate design window applications of the state’s three main investor-owned utilities in their forthcoming 1/1/2018 rate design window applications in R.12-06-013.

77

This information is also available at SCE’s website at: www.sce.com. Click on “Your Home”

and then “Rates” for the Residential TOU rate periods, and “Your Business” and then “Rates” for the

Non-Residential TOU rate periods.

Table XVIII-2 Residential TOU Periods - Weekdays

TOU PeriodSummer(June through September)

Winter(October through May)

On-peak 2:00 PM to 8:00 PM 2:00 PM to 8:00 PM

Off-peak8:00 AM to 2:00 PM and8:00 PM to 10:00 PM

8:00 AM to 2:00 PM and8:00 PM to 10:00 PM

Super-off-peak 10:00 PM to 8:00 AM 10:00 PM to 8:00 AM

Table XVIII-3 Residential TOU Periods - Weekends



Off-peak 8:00 AM to 10:00 PM 8:00 AM to 10:00 PM

Super-off-peak 10:00 PM to 8:00 AM 10:00 PM to 8:00 AM

Table XVIII-4 Non-Residential TOU Periods - Weekdays



On-peak 12:00 PM to 6:00 PM N/A

Off-peak11:00 PM to 8:00 AM 11:00 PM to 8:00 AM and

9:00 PM to 11:00 PM

Mid-peak 8:00 AM to 12:00 PM and 6:00 PM to 11:00 PM

8:00 AM to 9:00 PM

78

Table XVIII-5 Non-Residential TOU Periods – Weekends and Holidays



Off-peak All Day All Day

Document comparison by Workshare Compare on Tuesday, September 04, 2018 2:22:22 PM Input:

Document 1 ID file://H:\Carol Schmid-Frazee\2018 RPS Draft Plan\Compare\2017 Final RPS Plan (PUBLIC).docx

Description 2017 Final RPS Plan (PUBLIC)

Document 2 ID file://H:\Carol Schmid-Frazee\2018 RPS Draft Plan\Compare\002 2018 Draft RPS Plan for Refile (PUBLIC).docx

Description 002 2018 Draft RPS Plan for Refile (PUBLIC) Rendering set Standard

Legend:

InsertionDeletionMoved fromMoved toStyle change Format change Moved deletionInserted cell Deleted cell Moved cell Split/Merged cell Padding cell

Statistics:

Count Insertions 992Deletions 829Moved from 13Moved to 13Style change 0Format changed 0Total changes 1847

PUBLIC APPENDIX B

Project Development Status Update

As of June 28, 2018

Project Status Project ID Project Name Contract Status Site Control Status Permit Type Permit Status

Expected or Actualpermitting completion

dateTransmissionsecured?

Financingsecured?

Equipmentsecured?

In Development 5262 Antelope DSR 3, LLC Approved Construction Complete 3/16/2017 YesIn Development 5892 CED Wistaria Solar, LLC Pending Approval Construction Complete 2/7/2018 YesIn Development 5258 Green Beanworks C, LLC No Approval Needed Construction Complete 4/4/2017 YesIn Development 5268 Green Beanworks D LLC No Approval Needed Construction Complete 4/4/2017 YesIn Development 5816 Panoche Valley Solar, LLC Approved Construction Complete 6/14/2016 YesIn Development 5747 AVS Phase 2 Approved Construction YesIn Development 1250 Decade Energy Approved Construction YesIn Development 5264 Maverick Solar, LLC Approved Construction YesIn Development 1251 Two Fiets Approved Construction Complete N/A YesIn Development 5810 41MB 8ME LLC Approved Material Permits YesIn Development 5805 88FT 8ME LLC (Mount Signal II) Approved Material Permits YesIn Development 5414 NEENACH SOLAR No Approval Needed Construction Permit YesIn Development 5263 American Kings Solar, LLC Approved Material Permits YesIn Development 1252 Central CA Fuel Cell 2 Approved Construction Permit YesIn Development 5814 North Rosamond Solar, LLC Approved Material Permits Complete 3/16/2018 YesIn Development 1247 Organic Energy Solutions Approved Construction Permit Yes

In Development 5882 Sun Streams, LLC Approved Material Permits Complete N/A Yes

In Development 5884 Sunshine Valley Solar, LLC Approved Material Permits Complete N/A YesIn Development 5883 Willow Springs Solar, LLC Approved Material Permits Complete 3/19/2018 YesIn Development 5261 Windhub Solar A Solar Project Approved Material Permits YesIn Development 5889 Blythe Solar III, LLC Approved Construction Permit yes

PUBLIC APPENDIX C.1

Physical Renewable Net Short Calculations Based on CPUC Assumptions, with GAM

Physical Renewable Net Short Calculations Based on CPUC Assumptions

Variable Calculation Item

Deficit from RPS

prior to Reporting 2011

Actuals

2012

Actuals

2013

Actuals2011-2013

2014

Actual

2015

Actual

2016

Actual2014-2016

2017

Forecast

2018

Forecast

2019

Forecast

2020

Forecast2017-2020

2021

Forecast

2022

Forecast

2023

Forecast

2024

Forecast

2025

Forecast

2026

Forecast

2027

Forecast

2028

Forecast

2029

Forecast

2030

ForecastForecast Year CP1 CP2 1 2 3 CP3 4 5 6 7 8 9 10 11 12 13

Annual RPS Requirement

A Bundled Retail Sales Forecast (LTPP) 1 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 50,981 49,310 56,714 56,358 55,966 55,470 55,009 54,556 54,100 53,662

B RPS Procurement Quantity Requirement (%) 20.0% 20.0% 20.0% 21.7% 23.3% 25.0% 27.0% 29.0% 31.0% 33.0% 34.8% 36.5% 38.3% 40.0% 41.7% 43.3% 45.0% 46.7% 48.3% 50.0%

C A*B Gross RPS Procurement Quantity Requirement (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 17,741 17,998 21,721 22,543 23,338 24,018 24,754 25,478 26,130 26,831

D Voluntary Margin of Over-procurement - - - - - - - - - - - - - - - - - - - - - - -

E C+D Net RPS Procurement Need (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 17,741 17,998 21,721 22,543 23,338 24,018 24,754 25,478 26,130 26,831

RPS-Eligible Procurement

Fa Risk-Adjusted RECs from Online Generation 15,585 15,764 16,445 47,794 17,734 18,316 21,139 57,189 23,213 25,860 19,349 18,415 86,837 17,014 16,417 15,969 15,807 15,690 15,424 14,260 13,162 12,861 12,582

Faa Forecast Failure Rate for Online Generation (%) 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

Fb Risk-Adjusted RECs from RPS Facilities in Development - - - - - - - - - 10 1 ,493 2 ,436 3 ,939 3 ,095 3 ,038 2 ,987 2 ,958 2 ,929 2 ,888 2 ,829 2 ,771 2 ,692 2 ,621

Fbb Forecast Failure Rate for RPS Facilities in Development (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A 25.0% 21.4% 22.9% 22.4% 23.6% 23.6% 23.6% 23.6% 23.6% 23.6% 23.6% 23.6% 23.6% 23.6%

Fc Pre-Approved Generic RECs - - - - - - - - - 3 40 55 99 65 81 96 97 96 96 96 96 96 96

Fe Executed REC Sales 362 778 473 1 ,614 - - 404 404 - - - - - - - - - - - - - - -

F Fa+Fb+Fc-Fe Total RPS Eligible Procurement (GWh) 2 15,223 14,986 15,972 46,181 17,734 18,316 20,735 56,785 23,213 25,874 20,882 20,906 90,874 20,174 19,536 19,051 18,861 18,715 18,408 17,185 16,029 15,649 15,300

F0 Category 0 RECs 3 15,170 14,876 15,771 45,817 16,492 15,169 14,915 46,575 13,262 12,627 8 ,573 7 ,442 41,904 6 ,638 6 ,451 6 ,390 6 ,303 6 ,269 6 ,116 5 ,975 5 ,932 5 ,795 5 ,662

F1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,147 5 ,820 10,210 9 ,885 13,243 12,269 13,409 48,806 13,471 13,004 12,565 12,462 12,350 12,195 11,114 10,001 9 ,758 9 ,542

F2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - - - - - - -

F3 Category 3 RECs 3 - - - - - - - - 67 - - - 67 - - - - - - - - - -

Gross RPS Position (Physical Net Short)

Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1 ,076 1 ,410 1 ,280 766 2 ,330 4 ,375 2 ,433 1 ,538 (2 ,670) (3 ,682) (4 ,623) (5 ,611) (7 ,569) (9 ,449) (10,481) (11,531)

Gb F/A Annual Gross RPS Position (%) 20.6% 19.8% 21.4% 20.6% 23.4% 24.3% 28.2% 25.3% 39.6% 39.6% 33.6% 33.5% 33.4% 33.2% 31.2% 29.4% 28.9% 28.5%

Application of Bank

Ha Existing Banked RECs above the PQR 0 467 325 0 1,371 2 ,649 3 ,382 1370.8333 16,398 18,831 20,368 20,368 20,368 20,368 20,368 20,368 20,368 20,368

Hb RECs above the PQR added to Bank 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 2 ,433 1 ,538 - - - - - - - -

Hc Non-bankable RECs above the PQR - 9 30 39 2 32 81 115 - - - - - - - - - -

H Ha+Hb Gross Balance of RECs above the PQR 467 325 1 ,371 1 ,371 2 ,649 3 ,382 5 ,631 5 ,631 18,831 20,368 20,368 20,368 20,368 20,368 20,368 20,368 20,368 20,368

Ia Planned Application of RECs above the PQR towards RPS Compliance - - - - - - - - - - - - - - - - - - - - - - -

Ib Planned Sales of RECs above the PQR - - - - - - - - - - - - - - - - - - - - - - -

J H-Ia-Ib Net Balance of RECs above the PQR 467 325 1 ,371 1 ,371 2 ,649 3 ,382 5 ,631 5 ,631 18,831 20,368 20,368 20,368 20,368 20,368 20,368 20,368 20,368 20,368

J0 Category 0 RECs 3 1,007 - - 1 ,007 - - - - - - - - - - - - - -

J1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,018 - 4 ,260 2 ,433 1 ,538 - - - - - - - -

J2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - -

Expiring Contracts

K RECs from Expiring RPS Contracts -

Net RPS Position (Optimized Net Short)

La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 2 ,433 1 ,538 (2 ,670) (3 ,682) (4 ,623) (5 ,611) (7 ,569) (9 ,449) (10,481) (11,531)

Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.4% 20.6% 23.4% 24.3% 28.1% 25.2% 39.6% 39.6% 33.6% 33.5% 33.4% 33.2% 31.2% 29.4% 28.9% 28.5%

Note: Fields in grey are potected as Confidential under CPUC Confidentiality Rules

Note: Values are shown in GWhs

Notes:1 Bundled retail sales forecast for 2018 2022 is from SCE's 2017 Q4 base case bundled retail sales 2018 Q2 CCA update forecast; bundled retail sales forecast for 2023 2030 is from CEC's 2017 IEPR forecast adjusted per 6/18/18 CPUC ALJ Ruling2 Includes all contracts executed through June 30, 2018; new generation forecast based on individual project specific success rates for large near term projects and flat average success rate for remaining projects based on these projects' overall weighted average success rate3 Forecast of deliveries by portfolio content categories is for executed contracts only; does not include program generics

PUBLIC APPENDIX C.2

Physical Renewable Net Short Calculations Based on SCE Assumptions, with GAM

Physical Renewable Net Short Calculations Based on SCE Assumptions


Deficit from RPS


Actuals

2012

Actuals

2013

Actuals2011-2013

2014

Actual

2015

Actual

2016

Actual2014-2016

2017

Forecast

2018

Forecast

2019

Forecast

2020

Forecast2017-2020

2021

Forecast

2022

Forecast

2023

Forecast

2024

Forecast

2025

Forecast

2026

Forecast

2027

Forecast

2028

Forecast

2029

Forecast

2030



A SCE Bundled Sales Forecast 1 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 50,981 49,310 48,522 48,086 48,030 48,071 48,184 48,497 48,986 49,754













F0 Category 0 RECs 3 15,170 14,876 15,771 45,817 16,492 15,169 14,915 46,575 13,262 12,627 8 ,573 7 ,442 41,904 6 ,638 6 ,451 6 ,390 6 ,303 6 ,269 6 ,116 5 ,975 5 ,932 5 ,795 5 ,662

F1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,147 5 ,820 10,210 9 ,885 13,243 12,269 13,409 48,806 13,471 13,004 12,565 12,462 12,350 12,195 11,114 10,001 9 ,758 9 ,542

F2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - - - - - - -

F3 Category 3 RECs 3 - - - - - - - - 67 - - - 67 - - - - - - - - - -


Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1 ,076 1 ,410 1 ,280 766 2 ,330 4 ,375 2 ,433 1 ,538 467 (373) (1 ,313) (2 ,407) (4 ,498) (6 ,619) (8 ,011) (9 ,577)


Application of Bank


Hb RECs above the PQR added to Bank 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 2 ,433 1 ,538 467 - - - - - - -






J0 Category 0 RECs 3 1,007 - - 1 ,007 - - - - - - - - - - - - - -

J1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,018 - 4 ,260 2 ,433 1 ,538 467 - - - - - - -

J2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - -

Expiring Contracts



La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 2 ,433 1 ,538 467 (373) (1 ,313) (2 ,407) (4 ,498) (6 ,619) (8 ,011) (9 ,577)

Lb (Ga+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.4% 20.6% 23.4% 24.3% 28.1% 25.2% 39.6% 39.6% 39.3% 39.2% 39.0% 38.3% 35.7% 33.1% 31.9% 30.8%



Notes:1 From SCE's 2017 Q4 base case bundled retail sales 2018 Q2 CCA update forecast2 Includes all contracts executed through June 30, 2018; new generation forecast based on individual project specific success rates for large near term projects and flat average success rate for remaining projects based on these projects' overall weighted average success rate3 Forecast of deliveries by portfolio content categories is for executed contracts only; does not include program generics

Appendix C.2

CONFIDENTIAL APPENDIX C.3 REDACTED IN ENTIRETY

Optimized Renewable Net Short Calculations Based on CPUC Assumptions, with GAM


Optimized Renewable Net Short Calculations Based on SCE Assumptions, with GAM

PUBLIC APPENDIX C.5

Physical Renewable Net Short Calculations Based on CPUC Assumptions, with PCIA

Physical Renewable Net Short Calculations Based on CPUC Assumptions


Deficit from RPS


Actuals

2012

Actuals

2013

Actuals2011-2013

2014

Actual

2015

Actual

2016

Actual2014-2016

2017

Forecast

2018

Forecast

2019

Forecast

2020

Forecast2017-2020

2021

Forecast

2022

Forecast

2023

Forecast

2024

Forecast

2025

Forecast

2026

Forecast

2027

Forecast

2028

Forecast

2029

Forecast

2030



A Bundled Retail Sales Forecast (LTPP) 1 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 50,981 49,310 56,714 56,358 55,966 55,470 55,009 54,556 54,100 53,662













F0 Category 0 RECs 3 15,170 14,876 15,771 45,817 16,492 15,169 14,915 46,575 13,262 12,627 10,364 9 ,586 45,839 9 ,001 8 ,989 9 ,010 8 ,931 8 ,903 8 ,692 8 ,494 8 ,434 8 ,241 8 ,052

F1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,147 5 ,820 10,210 9 ,885 13,243 14,833 17,271 55,232 18,266 18,118 17,717 17,658 17,540 17,331 15,799 14,220 13,876 13,570

F2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - - - - - - -

F3 Category 3 RECs 3 - - - - - - - - 67 - - - 67 - - - - - - - - - -


Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1 ,076 1 ,410 1 ,280 766 2 ,330 4 ,375 9 ,614 9 ,222 5 ,140 4 ,183 3 ,242 2 ,142 (324) (2 ,687) (3 ,876) (5 ,072)


Application of Bank


Hb RECs above the PQR added to Bank 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 9 ,614 9 ,222 5 ,140 4 ,183 3 ,242 2 ,142 - - - -






J0 Category 0 RECs 3 1,007 - - 1 ,007 - - - - - - - - - - - - - -

J1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,018 - 4 ,260 9 ,614 9 ,222 5 ,140 4 ,183 3 ,242 2 ,142 - - - -

J2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - -

Expiring Contracts



La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 9 ,614 9 ,222 5 ,140 4 ,183 3 ,242 2 ,142 (324) (2 ,687) (3 ,876) (5 ,072)

Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.4% 20.6% 23.4% 24.3% 28.1% 25.2% 53.7% 55.2% 47.4% 47.4% 47.5% 47.2% 44.4% 41.8% 41.1% 40.5%



Notes:1 Bundled retail sales forecast for 2018 2022 is from SCE's 2017 Q4 base case bundled retail sales 2018 Q2 CCA update forecast; bundled retail sales forecast for 2023 2030 is from CEC's 2017 IEPR forecast adjusted per 6/18/18 CPUC ALJ Ruling2 Includes all contracts executed through June 30, 2018; new generation forecast based on individual project specific success rates for large near term projects and flat average success rate for remaining projects based on these projects' overall weighted average success rate3 Forecast of deliveries by portfolio content categories is for executed contracts only; does not include program generics

PUBLIC APPENDIX C.6

Physical Renewable Net Short Calculations Based on SCE Assumptions, with PCIA

Physical Renewable Net Short Calculations Based on SCE Assumptions


Deficit from RPS


Actuals

2012

Actuals

2013

Actuals2011-2013

2014

Actual

2015

Actual

2016

Actual2014-2016

2017

Forecast

2018

Forecast

2019

Forecast

2020

Forecast2017-2020

2021

Forecast

2022

Forecast

2023

Forecast

2024

Forecast

2025

Forecast

2026

Forecast

2027

Forecast

2028

Forecast

2029

Forecast

2030



A SCE Bundled Sales Forecast 1 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 50,981 49,310 48,522 48,086 48,030 48,071 48,184 48,497 48,986 49,754













F0 Category 0 RECs 3 15,170 14,876 15,771 45,817 16,492 15,169 14,915 46,575 13,262 12,627 10,364 9 ,586 45,839 9 ,001 8 ,989 9 ,010 8 ,931 8 ,903 8 ,692 8 ,494 8 ,434 8 ,241 8 ,052

F1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,147 5 ,820 10,210 9 ,885 13,243 14,833 17,271 55,232 18,266 18,118 17,717 17,658 17,540 17,331 15,799 14,220 13,876 13,570

F2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - - - - - - -

F3 Category 3 RECs 3 - - - - - - - - 67 - - - 67 - - - - - - - - - -


Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1 ,076 1 ,410 1 ,280 766 2 ,330 4 ,375 9 ,614 9 ,222 8 ,277 7 ,492 6 ,552 5 ,345 2 ,747 143 (1 ,407) (3 ,118)


Application of Bank


Hb RECs above the PQR added to Bank 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 9 ,614 9 ,222 8 ,277 7 ,492 6 ,552 5 ,345 2 ,747 143 - -






J0 Category 0 RECs 3 1,007 - - 1 ,007 - - - - - - - - - - - - - -

J1 Category 1 RECs 3 52 110 201 364 1 ,243 3 ,018 - 4 ,260 9 ,614 9 ,222 8 ,277 7 ,492 6 ,552 5 ,345 2 ,747 143 - -

J2 Category 2 RECs 3 - - - - - - - - - - - - - - - - - -

Expiring Contracts



La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1 ,046 1 ,371 1 ,278 734 2 ,249 4 ,260 9 ,614 9 ,222 8 ,277 7 ,492 6 ,552 5 ,345 2 ,747 143 (1 ,407) (3 ,118)

Lb (Ga+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.4% 20.6% 23.4% 24.3% 28.1% 25.2% 53.7% 55.2% 55.4% 55.6% 55.3% 54.4% 50.7% 47.0% 45.4% 43.7%



Notes:1 From SCE's 2017 Q4 base case bundled retail sales 2018 Q2 CCA update forecast2 Includes all contracts executed through June 30, 2018; new generation forecast based on individual project specific success rates for large near term projects and flat average success rate for remaining projects based on these projects' overall weighted average success rate3 Forecast of deliveries by portfolio content categories is for executed contracts only; does not include program generics


Optimized Renewable Net Short Calculations Based on CPUC Assumptions, with PCIA


Optimized Renewable Net Short Calculations Based on SCE Assumptions, with PCIA

PUBLIC APPENDIX D

Cost Quantification Table

Table 1 (Actual Costs, $) Items ActualRows 2 8 and 11 (years 2003 2017) Settlements data from 1/1/2003 to 12/31/2017, net of sales and GTSRRow 9 Annualized capital cost plus applicable O&M in each yearRow 10 LCOE multiplied by actual generation in each yearRow 13 Actual bundled retail sales data, net of GTSR salesRow 14 Total Cost / Bundled Retail SalesTable 2 (Forecast Cost, $) Items ForecastRows 2 12 and 17 27 Forecast begins in year 2018

UOG Small Hydro is the annualized capital cost plus 2017 O&Mescalated at 5% annuallyUOG Solar is LCOE multiplied by actual generation in each year

Rows 14 and 29 IOU’s most current bundled retail sales forecast, net of GTSR salesRow 31 Total Cost / Bundled Retail SalesTable 3 (Actual Generation, kWh) Items ActualRows 2 11 (years 2003 2017) Settlements data from 1/1/2003 to 12/31/2017, net of sales and GTSRTable 4 (Forecast Generation, kWh) Items ForecastRows 2 12 and 15 25 Forecast begins in year 2018

Calculated as forecasted generation in each year

Joint IOU Assumption Guidelines for Table Input

Actual RPS-Eligible Procurement and Generation Net Costs

1 Executed CPUC-Approved RPS-Eligible Contracts (Purchases and Sales) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

2 Biogas $49,239,752 $55,218,581 $58,024,700 $55,842,748 $46,391,310 $45,669,901 $41,319,957 $46,567,994 $45,211,236 $35,156,543 $33,114,888 $33,398,837 $26,215,229 $19,996,620 $4,429,9553 Biomass $30,229,214 $30,641,340 $29,266,687 $29,364,748 $31,995,803 $32,870,627 $37,676,121 $39,934,586 $32,641,659 $8,227,073 $0 $0 $0 $0 $27,282,0624 Geothermal $533,787,287 $568,528,010 $569,145,247 $540,276,590 $564,191,771 $682,923,953 $591,094,390 $601,071,879 $559,744,574 $415,442,081 $433,420,493 $488,851,482 $406,326,046 $321,170,291 $347,988,6785 Small Hydro $14,680,635 $13,351,784 $23,129,437 $22,350,522 $11,682,561 $17,217,269 $12,197,656 $19,239,880 $26,068,150 $18,236,862 $10,001,362 $2,468,152 $1,579,449 $5,225,793 $13,379,6086 Solar PV $2,303 $1,077 $574 $111 $0 $0 $116,015 $6,014,872 $6,263,215 $10,236,565 $29,306,577 $201,163,017 $406,497,564 $628,952,523 $874,001,6887 Solar Thermal $109,767,959 $109,176,941 $102,333,401 $100,464,297 $108,126,446 $118,442,549 $118,633,943 $122,739,976 $124,889,386 $101,611,519 $92,137,545 $111,917,597 $114,443,298 $107,560,298 $103,861,4578 Wind $150,501,168 $168,906,414 $164,098,293 $158,644,762 $185,560,185 $211,157,917 $197,306,648 $298,846,815 $447,581,905 $553,158,034 $732,798,017 $733,090,366 $597,232,883 $759,447,708 $704,543,0109 UOG Small Hydro $18,919,069 $20,783,330 $22,004,724 $25,476,773 $28,921,419 $29,624,912 $32,852,293 $35,084,449 $46,523,880 $54,403,396 $53,529,737 $54,486,018 $24,938,059 $22,100,742 $44,387,00610 UOG Solar $0 $0 $0 $0 $0 $237,324 $1,518,688 $2,587,858 $15,703,577 $34,084,657 $24,802,431 $35,339,130 $42,453,790 $38,555,151 $35,591,82711 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Total CPUC-Approved RPS-Eligible Procurement and Generation Net Cost

[Sum of Rows 2 through 11]

13 Bundled Retail Sales (kWh) 70,616,552,902 72,964,152,898 74,994,454,104 78,863,139,433 79,505,151,004 80,956,160,306 78,048,183,506 75,141,421,957 73,777,490,034 75,596,657,918 74,480,094,902 75,828,582,966 75,322,345,868 73,621,347,624 73,482,939,540

14 Incremental Rate Impact [Row 12 divided by Row 13] 1.28 ¢/kWh 1.32 ¢/kWh 1.29 ¢/kWh 1.18 ¢/kWh 1.23 ¢/kWh 1.41 ¢/kWh 1.32 ¢/kWh 1.56 ¢/kWh 1.77 ¢/kWh 1.63 ¢/kWh 1.89 ¢/kWh 2.19 ¢/kWh 2.15 ¢/kWh 2.58 ¢/kWh 2.93 ¢/kWh*The actual cost of UOG Small Hydro in 2013 was $53,529,737, not $53,101,662 as reported in the 2014 RPS Procurement Plan.*The actual cost of UOG Small Hydro in 2014 was $54,486,018, not $52,517,116 as reported in the 2015 RPS Procurement Plan.

1 Executed But Not CPUC-Approved RPS-Eligible Contracts (Purchases and Sales) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

2 Biogas $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $03 Biomass $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $04 Geothermal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $05 Small Hydro $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $06 Solar PV $0 $15,723,077 $15,937,950 $15,667,104 $15,662,949 $15,547,578 $15,429,560 $15,337,135 $15,187,521 $14,829,437 $14,479,420 $14,027,465 $13,641,7737 Solar Thermal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $08 Wind $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $09 UOG Small Hydro $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $010 UOG Solar $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $011 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $012 Sales Revenue $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Total Executed But Not CPUC-Approved RPS-Eligible Procurement and Generation Cost


14 Bundled Retail Sales(kWh) 49,310,425,343 48,522,202,739 48,086,062,437 48,029,858,612 48,070,977,237 48,184,364,630 48,496,557,067 48,986,242,781 49,754,212,825

15 Incremental Rate Impact [Row 13 divided by Row 14 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh 0.03 ¢/kWh

16 Executed CPUC-Approved RPS-Eligible Contracts (Purchases and Sales) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

17 Biogas $7,018,271 $12,135,084 $14,584,444 $14,491,800 $14,532,053 $14,544,844 $14,825,712 $14,970,087 $14,257,043 $10,829,679 $9,729,316 $9,666,781 $9,638,18918 Biomass $56,731,860 $58,227,368 $59,955,190 $61,345,702 $67,922,031 $41,582,984 $42,483,543 $43,387,968 $44,529,625 $45,390,342 $46,364,546 $47,138,770 $48,147,07719 Geothermal $399,310,823 $362,974,030 $318,394,879 $270,742,628 $247,738,683 $246,901,053 $247,837,084 $252,678,815 $244,441,286 $137,006,547 $44,378,241 $44,176,561 $44,177,50820 Small Hydro $11,008,618 $10,834,002 $6,857,314 $3,611,114 $3,544,307 $3,412,872 $3,427,189 $3,267,924 $3,278,917 $3,285,688 $3,250,132 $3,175,371 $3,187,06521 Solar PV $864,059,297 $963,733,838 $1,116,338,639 $1,155,410,686 $1,170,216,140 $1,174,487,661 $1,177,948,431 $1,184,822,395 $1,187,608,782 $1,172,965,390 $1,158,387,241 $1,135,890,985 $1,113,650,79022 Solar Thermal $124,226,825 $108,764,224 $91,231,077 $67,181,069 $65,976,150 $65,781,353 $65,569,541 $65,529,863 $65,244,902 $57,765,211 $51,431,658 $49,897,171 $48,794,49823 Wind $841,407,748 $843,298,666 $856,314,752 $860,798,210 $843,642,248 $844,717,654 $846,648,535 $846,253,238 $844,977,595 $844,449,325 $844,517,499 $831,404,200 $817,544,90024 UOG Small Hydro $25,019,964 $25,755,604 $26,528,026 $27,339,070 $28,190,666 $29,084,841 $30,023,725 $31,009,554 $32,044,674 $33,131,549 $34,272,769 $35,471,050 $36,729,24425 UOG Solar $43,228,800 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,272 $44,003,27226 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $027 Sales Revenue $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Total CPUC-Approved RPS-Eligible Procurement and Generation Cost


29 Bundled Retail Sales(kWh) 49,310,425,343 48,522,202,739 48,086,062,437 48,029,858,612 48,070,977,237 48,184,364,630 48,496,557,067 48,986,242,781 49,754,212,825

30 Incremental Rate Impact [Row 28 divided by Row 29 5.04 ¢/kWh 5.08 ¢/kWh 5.14 ¢/kWh 5.18 ¢/kWh 5.16 ¢/kWh 4.87 ¢/kWh 4.61 ¢/kWh 4.49 ¢/kWh 4.35 ¢/kWhTotal Incremental Rate Impact

[Row 15 + 30; Formatting can cause Row 31 to differ slightlyfrom the sum of Row 15 and 30]

$2,155,465,290

Joint IOU Cost Quantification Table 1 (Actual Net Costs, $)

$1,619,686,318$1,409,111,05012 $907,127,388 $966,607,475 $968,003,063 $932,420,551 $976,869,495 $1,138,144,451 $1,032,715,711 $1,172,088,308 $1,660,714,599 $1,903,009,126$1,304,627,583 $1,230,556,730

13 $0 $15,723,077 $15,937,950 $15,667,104 $15,429,560 $15,337,135 $15,187,521 $14,829,437

Joint IOU Cost Quantification Table 2 (Forecast Costs and Revenues, $)

4.64 ¢/kWh 4.52 ¢/kWh

$13,641,773

4.38 ¢/kWh

28 $2,372,012,206 $2,429,726,088 $2,534,207,593

31 5.17 ¢/kWh

$2,504,923,551 $2,485,765,550 $2,464,516,534 $2,236,334,674 $2,200,824,161 $2,165,872,543

$14,479,420 $14,027,465

5.21 ¢/kWh 5.19 ¢/kWh 4.91 ¢/kWh

$2,472,767,032 $2,485,923,116 $2,480,386,096 $2,348,827,003

5.07 ¢/kWh 5.11 ¢/kWh

$15,662,949 $15,547,578

Actual RPS-Eligible Procurement / Generation and Sales (kWh)1 Technology Type (Procurement / Generation and Sales) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 20172 Biogas 722,946,872 777,312,732 771,018,454 752,792,686 587,082,098 546,962,524 493,557,888 513,205,916 505,975,841 499,348,085 484,856,973 449,602,910 410,920,238 317,624,690 53,254,3573 Biomass 365,097,000 373,917,000 351,063,000 353,889,000 365,332,000 363,224,000 417,625,000 437,916,000 351,018,000 114,694,000 0 0 0 0 242,794,3584 Geothermal 7,079,544,959 7,882,153,152 7,823,442,082 7,481,228,810 7,611,424,731 7,739,370,197 7,675,040,864 7,633,511,171 7,178,640,942 6,421,878,833 6,536,991,410 6,745,455,452 6,687,895,884 5,406,191,071 5,621,420,3225 Small Hydro 236,744,651 246,952,691 325,458,412 348,497,816 196,112,961 182,554,690 138,319,853 220,027,751 301,898,312 193,824,909 111,406,134 28,189,908 17,624,603 65,933,508 195,578,5266 Solar PV 0 0 0 0 0 0 1,372,324 51,389,213 53,432,781 73,822,986 247,185,884 1,839,819,140 3,825,645,626 6,241,358,790 8,379,275,4917 Solar Thermal 756,941,166 739,291,464 622,099,854 613,049,994 666,864,846 730,264,176 839,801,580 879,081,877 889,065,595 868,991,935 680,234,418 751,904,813 833,904,840 773,651,852 761,837,2408 Wind 2,366,582,609 2,313,238,518 2,275,713,067 2,232,844,707 2,374,032,238 2,383,541,034 3,038,798,465 4,142,352,867 5,417,625,933 6,286,303,872 7,510,596,685 7,442,425,300 6,062,734,884 7,391,812,341 7,057,058,7449 UOG Small Hydro 535,123,742 466,007,745 545,840,580 599,902,056 362,302,038 344,846,249 426,458,028 461,590,000 618,139,310 434,380,326 269,814,338 274,950,708 234,845,891 394,208,307 546,129,42610 UOG Solar 0 0 0 0 0 438,489 2,798,912 4,846,187 54,532,151 98,598,314 68,910,176 98,184,960 117,952,073 107,120,236 98,887,04311 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 66,530,196

Total CPUC-Approved RPS-Eligible Procurement / Generation and Sales


2 Biogas 0 0 0 0 0 0 0 0 0 0 0 0 03 Biomass 0 0 0 0 0 0 0 0 0 0 0 0 04 Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 05 Small Hydro 0 0 0 0 0 0 0 0 0 0 0 0 06 Solar PV 0 303,718,810 306,447,112 301,478,444 301,647,185 299,995,091 298,496,667 296,133,043 292,030,415 285,880,837 279,756,576 271,430,514 263,966,1557 Solar Thermal 0 0 0 0 0 0 0 0 0 0 0 0 08 Wind 0 0 0 0 0 0 0 0 0 0 0 0 09 UOG Small Hydro 0 0 0 0 0 0 0 0 0 0 0 0 0

10 UOG Solar 0 0 0 0 0 0 0 0 0 0 0 0 0

11 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0 012 RPS-Eligible Sales 0 0 0 0 0 0 0 0 0 0 0 0 0

Total Executed But Not CPUC-Approved RPS-Eligible Deliveries


15 Biogas 83,524,602 120,625,462 138,104,469 136,475,931 135,979,931 135,478,051 136,743,077 137,052,225 127,958,416 89,481,376 78,245,142 77,683,180 77,339,26416 Biomass 491,917,800 491,917,800 493,362,907 491,917,800 535,158,471 354,045,667 355,090,286 354,045,667 354,045,667 354,045,667 355,090,286 354,045,667 354,045,66717 Geothermal 5,868,927,762 3,837,423,879 3,394,335,837 3,365,135,181 3,365,135,181 3,271,445,084 3,198,536,440 3,189,984,181 3,010,669,280 1,715,147,972 463,013,030 461,747,972 461,747,97218 Small Hydro 139,945,133 139,305,131 89,152,316 42,256,876 41,100,916 39,483,659 39,456,372 36,977,744 36,858,949 36,858,949 36,313,872 35,291,170 35,291,17019 Solar PV 8,359,243,681 10,169,922,341 12,789,638,657 13,717,809,477 13,766,263,864 13,681,349,642 13,601,469,583 13,486,006,312 13,288,695,459 12,996,975,373 12,706,316,026 12,318,720,177 11,930,252,63920 Solar Thermal 936,522,513 827,808,665 729,084,291 542,460,029 519,768,493 519,416,191 519,119,079 517,708,734 512,881,629 409,424,033 320,470,647 309,874,654 302,915,95021 Wind 9,107,950,942 9,090,288,738 9,143,645,458 9,256,015,962 9,044,089,225 9,020,656,219 9,029,709,085 9,005,001,231 8,962,425,260 8,942,463,038 8,926,236,687 8,765,586,884 8,643,528,86522 UOG Small Hydro 452,521,092 371,717,523 360,219,392 359,641,637 359,831,500 359,915,731 360,244,859 359,757,595 359,571,328 359,596,203 360,948,298 363,042,292 359,996,46623 UOG Solar 120,080,000 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,311 122,231,31124 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0 025 RPS-Eligible Sales 0 0 0 0 0 0 0 0 0 0 0 0 0

Total CPUC-Approved RPS-Eligible Deliveries[Sum of Rows 27 through 36]

1 2018 2019

12,382,205,069 12,291,201,35912,163,150,912

2021 2022 2023

Joint IOU Cost Quantification Table 4 (Forecast Procurement / Generation and Sales, kWh)

Executed But Not CPUC-Approved RPS-Eligible Contracts (Purchases and Sales)

13,033,772,914 23,022,765,70320,697,900,79614,343,920,982 17,630,533,19115,909,996,01815,370,328,865 14,991,843,260

299,995,091 298,496,667

26 27,362,600,09225,560,633,525 25,171,240,850 27,259,774,638

14

301,478,444 301,647,185

2018 2019 2020

0 303,718,810 306,447,112

Joint IOU Cost Quantification Table 3 (Actual Procurement / Generation and Sales, kWh)

18,191,524,039

27,504,021,55528,033,944,204

2020

13

2023

27,889,558,892

12 12,062,980,999 12,798,873,302 12,714,635,449

2024

2024

2021 2022

2030

296,133,043 292,030,415 285,880,837 279,756,576 271,430,514 263,966,155

2025 2026 2027 2028 2029

Executed CPUC-Approved RPS-Eligible Contracts (Purchases and Sales) 2030

22,287,349,304

2025 2026 2027 2028 2029

27,208,765,000 26,775,337,299 25,026,223,922 23,368,865,299 22,808,223,307

CONFIDENTIAL APPENDIX E REDACTED IN ENTIRETY

Renewable Energy Sales