Public Appendix Slip Sheets...x Public Appendix J.1 – 2017 Pro Forma Renewable Energy Credits...

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) 2017 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) 302-1935 E-mail: [email protected]

Dated: July 21, 2017

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) 2017 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN

In accordance with the Assigned Commissioner and Assigned Administrative Law

Judge’s Ruling Identifying Issues and Schedule of Review for 2017 Renewables Portfolio

Standard (“RPS”) Procurement Plans, dated May 26, 2017 (“ACR”), the E-Mail Ruling

Granting, in Part, IOUs1 Request for an Extension of Time to Produce the 2017 RPS

Procurement Plans, dated June 19, 2017, Southern California Edison Company (“SCE”)

respectfully submits its 2017 Renewables Portfolio Standard (“RPS”) Procurement Plan (“2017

RPS Plan”) to the California Public Utilities Commission (“Commission” or “CPUC”).2

SCE’s 2017 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

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 2016 Renewables Portfolio Standard Procurement Plan Under Seal.

3 SCE worked with Pacific Gas and Electric Company and San Diego Gas & Electric Company to make the format of the utilities’ plans as uniform as possible.

2

Confidential/Public Appendix C.2 – Physical Renewable Net Short Calculations

Based on SCE Assumptions

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

CPUC Assumptions

Confidential Appendix C.4 – Optimized Renewable Net Short Calculations Based on

SCE Assumptions

Confidential/Public Appendix D – Cost Quantification Table

Public Appendix E – RECs From Expiring Contracts

Public Appendix F.1 – Renewable Energy Sales Authorized Brokers and Exchanges

Confidential Appendix F.2 – Renewable Energy Sales

Public Appendix G.1 – 2017 Pro Forma Renewable Power Purchase Agreement

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

Agreement

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

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

Public Appendix I.1 – 2017 Procurement Protocol

Public Appendix I.2 – Redline of 2017 Procurement Protocol

Public Appendix J.1 – 2017 Pro Forma Renewable Energy Credits Sales Agreement

Public Appendix J.2 – Redline of 2017 Pro Forma Renewable Energy Credits Sales

Agreement

Public Appendix J.3 – SCE Cover Sheet to EEI Master Power Purchase and Sale

Agreement

Public Appendix J.4 – EEI Master Power Purchase and Sale Agreement

Public Appendix J.5 – Collateral Annex to the EEI Master Power Purchase and Sale

Agreement

Public Appendix J.6 – Paragraph 10 to the Collateral Annex to the EEI Master Power

Purchase and Sale Agreement

3

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) 302-1935 E-mail: [email protected]

July 21, 2017

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) 2017 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 21st day of July, 2017, at Rosemead, California.

/s/ Janos Kakuk By: Janos Kakuk

SOUTHERN CALIFORNIA EDISON COMPANY

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

(U 338-E)

2017 Written Plan

July 21, 2017

PUBLIC VERSION

2017 Written Plan Table Of Contents

Section Page

-i-

I. EXECUTIVE SUMMARY OF 2017 RPS PLAN ...........................................................................1

II. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND ........................................................................................................................................5

A. SCE’s Renewables Portfolio ................................................................................................5

B. SCE’s Forecast of Renewable Procurement Need ...............................................................5

C. SCE’s Plan for Achieving RPS Procurement Goals ............................................................9

D. SCE’s Portfolio Optimization Strategy ..............................................................................11

E. SCE’s Management of its Renewables Portfolio ...............................................................13

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues .................................................................................................14

1. Lessons Learned and Past and Future Trends ........................................................14

a) Possible Future Trend Toward Departing Load ...........................................................................................................15

b) Need for REC Sales ...................................................................................17

III. PROJECT DEVELOPMENT STATUS UPDATE .......................................................................18

IV. POTENTIAL COMPLIANCE DELAYS ......................................................................................18

A. Curtailment ........................................................................................................................18

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio .........................................................................................................19

C. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and Transmission ............................................................20

D. A Heavily Subscribed Interconnection Queue ...................................................................21

E. Developer Performance Issues ...........................................................................................22

V. RISK ASSESSMENT ....................................................................................................................22

VI. QUANTITATIVE INFORMATION .............................................................................................23

2017 Written Plan Table Of Contents (Continued)

Section Page

-ii-

A. RNS Calculations ...............................................................................................................23

B. Response to RNS Questions ..............................................................................................24

1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? ...................................................................................................24

2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. ...............................................................25

3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ...................................................................................................25

4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? ..................................................26

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? ......................................................................................27

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. ............................................................................................27

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. .................................................................................................................27

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. ..............................................28


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. ............................................................................................29

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? ......................................................................................................................29

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? ..................................................................................29

VII. MINIMUM MARGIN OF PROCUREMENT ..............................................................................30

VIII. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES .....................................................................................................................31

A. Bid Solicitation Protocol ....................................................................................................31

B. LCBF Methodology ...........................................................................................................32

IX. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..............................................32

X. ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING ............................................................................................................................33

XI. AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS .......................................................................................................................................35

A. Justification of SCE’s Request for Pre-Approval of a Limited Amount of Short-Term RPS-Eligible Transactions .............................................35

1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future .................................................35

2. California Customers Need an Open Market for RECs ......................................................................................................................36

3. REC Sales Will Create Customer Value ................................................................38


Section Page

-iv-

a) Selling is better than banking up to the established limits ........................................................................................38

b) Published Research From Independent Entities Forecasting Decline and/or Stabilization of Renewable Energy Costs ..................................................39

c) REC Sales Stabilize Rates By Realizing Near Term Value........................................................................................39

d) 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 ............................................................................................39

B. SCE’s Preferred and Alternate Proposals ..........................................................................40

1. Preferred/Pre-Approved Approach ........................................................................40

a) General Description of Pre-approval Mechanism .................................................................................................40

b) Reasons That Pre-Approval of REC Sales Transactions Is the Preferred Approach .....................................................41

2. Alternate/Tier 1 Advice Letter Approach ..............................................................43

C. SCE’s Proposed Limits on REC Sales ...............................................................................43

D. Acceptable REC pricing ....................................................................................................43

E. Proposed Transactional Methods .......................................................................................43

1. Competitive Solicitations .......................................................................................43

2. Bilateral Transactions ............................................................................................44

3. Brokers ...................................................................................................................44

4. Exchanges ..............................................................................................................45

a) Exchange Cleared Transactions .................................................................46

F. Proposed Timeline for REC Sales .....................................................................................46


Section Page

-v-

XII. EXPIRING CONTRACTS ............................................................................................................46

XIII. COST QUANTIFICATION ..........................................................................................................47

XIV. IMPERIAL VALLEY ....................................................................................................................47

XV. IMPORTANT CHANGES FROM 2016 RPS PLAN ...................................................................47

A. Important Changes in 2017 Procurement Protocol ............................................................48

1. Only REC Sales Will Be Part of this Solicitation ..................................................48

B. Important Changes in 2017 Pro Forma and REC Sales Agreement ..........................................................................................................................48

C. Important Changes in 2017 Least Cost, Best Fit Methodology ......................................................................................................................49

1. Capacity benefit for Solar and Wind resources .....................................................49

XVI. SAFETY CONSIDERATIONS .....................................................................................................49

XVII. STANDARD CONTRACT OPTION ............................................................................................51

A. Procurement Need ..............................................................................................................52

B. Standard Contract ...............................................................................................................52

XVIII. GREEN TARIFF SHARED RENEWABLES PROGRAM ..........................................................53

A. Community Renewables - Background .............................................................................54

B. Community Renewables - Modifications to the 2017 Procurement Protocol, 2017 Pro Forma Standard Contract Option, and LCBF Methodology .......................................................................................56

1. 2017 Procurement Protocol – CR Modifications ...................................................57

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


Section Page

-vi-

XIX. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .................................................61

A. Bilateral Transactions ........................................................................................................61

B. Energy Storage Procurement .............................................................................................61


-vii-

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

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

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

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

CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE

PUBLIC APPENDIX E RECS FROM EXPIRING CONTRACTS

PUBLIC APPENDIX F.1 RENEWABLE ENERGY SALES AUTHORIZED BROKERS AND EXCHANGES

CONFIDENTIAL APPENDIX F.2 RENEWABLE ENERGY SALES

PUBLIC APPENDIX G.1 2017 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT

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


-viii-

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

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

PUBLIC APPENDIX I.1 2017 PROCUREMENT PROTOCOL

PUBLIC APPENDIX I.2 REDLINE OF 2017 PROCUREMENT PROTOCOL

PUBLIC APPENDIX J.1 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX J.2 REDLINE OF 2017 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX J.3 SCE COVER SHEET TO EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX J.4 EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX J.5 COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX J.6 PARAGRAPH 10 TO THE COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

1

I.

EXECUTIVE SUMMARY OF 2017 RPS PLAN

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

Ruling Identifying Issues and Schedule of Review for 2017 Renewables Portfolio Standard (“RPS”)

Procurement Plans, dated May 26, 2017 (“ACR”), and the E-Mail Ruling Granting, in Part, IOUs1

Request for an Extension of Time to Produce the 2017 RPS Procurement Plans, dated June 19, 2017,

Southern California Edison Company’s (“SCE’s”) 2017 RPS Procurement Plan (“2017 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.

This 2017 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 not to conduct a 2017 RPS solicitation procuring new

RPS resources, and to sell Renewable Energy Credits (“RECs”). SCE’s 2017 RPS Plan includes its

2017 Procurement Protocol, 2017 Pro Forma Renewable Power Purchase Agreement, 2017 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 2016 RPS solicitation documents.

Further, this 2017 RPS Plan addresses other issues set forth in the ACR, statute, and other

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

2017 RPS Plan includes discussion of the following additional topics:

• Project development status update;

• Potential compliance delays and risks; 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

• Quantitative information discussing SCE’s renewable compliance;

• Minimum margin of procurement;

• Consideration of price adjustment mechanisms;

• Economic curtailment;

• Pre-approval process to sell RECs, or, in the alternative, Tier 1 Advice Letter process to

sell RECs;

• Expiring contracts;

• Cost quantification tables;

• Imperial Valley issues;

• Safety considerations;

• Standard Contract Option using the streamlined Renewable Auction Mechanism

(“RAM”) procurement tool;

• Green Tariff Shared Renewables (“GTSR”) program, in particular the enhanced

Community Renewables (“ECR” or “CR” by SCE) 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%, 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,2 D.11-

12-052 implementing the three portfolio content categories of renewable energy products that may 2 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.

3

be used to satisfy RPS targets,3 D.12-06-038 establishing new compliance rules 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

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 will be August 28, 2017).4

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

3 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 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.

4 D.17-06-026, Ordering Paragraph 23, p. 56.

4

the deadline for filing motions to update such plans”5 (which are due on September 22, 2017).6 If

SCE decides to make the early election in 2017, it will file a motion to update this plan on

September 22, 2017.

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 2017 RPS Plan,

SCE does not propose to hold a 2017 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 future, SCE proposes to sell RECs, as described in Section XI below and in

Appendix F.1 and F.2.

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 reliability need 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 2017 RPS Plan, SCE will request offers from parties interested in purchasing

Category 1 REC products from SCE. Also, SCE will bid into other parties’ solicitations seeking

Category 1 REC products. SCE does not forecast a net short position potential until 2030 with the

5 D.17-06-026, Ordering Paragraph 24, p. 56. 6 E-Mail Ruling Granting, in Part, IOUs Request for an Extension of Time to Produce the 2017 RPS

Procurement Plans, dated June 19, 2017.

5

use of bank. Therefore, in order to maximize value for customers, SCE will sell vintage 2017

through 2020 Category 1 products, consistent with its proposal in this 2017 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.7 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.

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 auctions, the Renewable Market Adjusting Tariff

(“ReMAT”), the utility-owned generation and independent power producer (“IPP”) portions of

SCE’s Solar Photovoltaic Program (“SPVP”), the GTSR program,8 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.

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

7 SCE retired RECs amounting to 20.6% of its retail sales for the first compliance period. 8 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.

6

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

BioMAT), among other factors.

Appendices C.1 through C.4 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.

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”).9

As 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.10

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.11 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 9 SCE’s forecasts only extend through 2030; therefore, SCE’s forecasted RNS information is only included

through 2030. 10 The required information on RECs from expiring contracts is included in Appendix E. 11 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.

7

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

60% 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 70% in

the third compliance period and approximately 69% 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).12 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.13 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.14 At present, because dedicated resources procured to serve Green Rate customers have

not yet begun service, SCE transferred RECs from other RPS-eligible resources in its Interim Green

Rate Pool to serve Green Rate subscriptions, until dedicated Green Rate resources are operational.

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.15

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

Appendices C.2 and C.4, and the Commission’s assumptions, as reflected in Appendices C.1 and

C.3, is that SCE uses its most recent bundled retail sales forecast for all years while the

12 No customers are presently being served under the Community Renewables Rate. As a result, SCE only

counted Green Rate customers here. 13 See CAL. PUB. UTIL. CODE § 2833(s). 14 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.

15 CAL. PUB. UTIL. CODE § 2833(u).

8

Commission’s assumptions use SCE’s most recent bundled retail sales forecast for 2017 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. This is consistent with the adopted standardized planning

assumptions laid-out in the February 28, 2017 Assigned Commissioner’s Ruling in the Integrated

Resource Planning (“IRP”) docket, R.16-02-007.16 SCE uses its own bundled 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 103.1 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.

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

16 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 I.16-02-007 for the February 28, 2017 Assigned Commissioner’s Ruling for the purpose of any long term planning that occurs in 2017, as discussed at p. 4.

9

bank under SCE’s assumptions. Under the 50% by 2030 target and using SCE’s assumptions, SCE

forecasts a net short position starting in 2027 without the use of bank (as shown in Appendix C.2).

But with the use of bank, SCE forecasts a net long position at the end of 2030 (as shown in

Appendix C.4). Using the Commission’s assumptions, SCE forecasts a net short position starting in

2024 without the use of bank (as shown in Appendix C.1) and a net short position starting in 2030

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

for additional RPS-eligible energy.17

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, SCE served 28.2% of its retail

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

until 2027 without the use of bank and after 2030 with the use of bank. Therefore, SCE does not

intend to hold a RPS Solicitation in 2017 and, instead, will look to sell RECs consistent with its

proposal in this 2017 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 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.

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

development. Lancaster and Apple Valley as well as a Monte Carlo simulation of additional CCA load beginning in 2019 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.

10

SCE will seek to sell RECs of 2017-2020 vintage to allow SCE to optimize its renewables

portfolio and provide value for all bundled and unbundled 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 the procurement in SCE’s current renewables portfolio is from contracts executed

prior to June 1, 2010 or contracts for Category 1 products. 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 and whether SCE elects early adoption of the new

compliance rules in D.17-06-026.

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

11

curve.18 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 H.1.

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

options to help meet the State’s RPS targets, including ReMAT, BioMAT, local capacity

requirements solicitations, all source solicitations, PRP, QF standard contracts, and bilateral

negotiations for competitive 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

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 H.1. The primary quantitative metric used for evaluating

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

18 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.

12

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

evaluating proposals.

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

energy products,19 project deferrals, and solicitation deferrals (as it did by not holding a 2012 or a

2016 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.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.21 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.

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

19 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.

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

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

13

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”), the PPA is managed by

SCE’s Energy Contracts Management group. 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

14

counterparty.22 In the event an amendment is elected, the IOU should negotiate in good faith.23 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.24 The details of D.88-10-032

provide further guidance to the IOUs to restrict modifications to PPAs with viable projects,25 and

reject modifications that would result in creating an essentially new project.26

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.27

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.28

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

22 See D.88-10-032 at p. 16. 23 Id. at Conclusion of Law 8. 24 Id. at p. 16, Conclusions of Law 13-14. 25 Id. at p. 17, Conclusion of Law 4, Appendix A at pp. 4-5. 26 Id. at p. 26, Conclusion of Law 17. 27 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. 28 For example, the Commission has indicated specific IOU actions regarding amendments to certain terms

in tariff-based agreements.

15

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 within the SCE service territory to join

Lancaster and Apple Valley in developing a Community 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 more 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 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 Intent (“BNI”), an initial Resource Adequacy (“RA”) filing, or the start of CCA service.29

In expectation of growing CCA departing load in the near future, SCE prepared a Monte Carlo

29 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.

16

simulation of CCA departing load starting in 2019 and has accordingly adjusted its procurement plan

at this time.30 As these actual load departures materialize, SCE will consider how these departures

impact its RPS compliance, including its need for additional resources.

Moreover, 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.”31 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.32

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

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

Examples include: BioRAM, ReMAT, 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 necessary special

purpose RPS programs without unfairly burdening bundled service customers.

30 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, and the Monte Carlo simulation for departing load beginning in 2019.

31 CAL. PUB. UTIL. CODE §§ 365.1, 366. 32 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.

17

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, SCE has more renewable energy

to meet its goals 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 renewable procurement

need.”33

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 is not always 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.34

Finally, given the SB 350 changes in compliance rules confirmed in D.17-06-

026, IOUs will have more 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.

33 Final 2016 RPS Plan, dated January 23, 2017, p. 14. 34 As explained in more detail in section XI and confidential Appendix F.2.

18

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

Five primary factors will 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. 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

19

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

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

(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. 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 is difficult to predict.

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

20

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 result 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.

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.”35 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

35 CAISO 2015-2016 Transmission Plan, at p. 6.

21

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

that are necessary for the delivery of renewable energy. While some 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 transmission projects included in the CAISO’s 2016-2017 draft 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.36

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 renewable projects

seeking interconnection to the CAISO controlled grid representing more than 20,000 MW of

capacity.37

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

36 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. 37 See https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueue.pdf.

22

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. For example, 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). 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.

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,

23

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

The quantitative analysis provided in Appendices C.1 through C.4 reflects these considerations.

VI.

QUANTITATIVE INFORMATION

A. RNS Calculations

As discussed in Section II.B, Appendices C.1 through C.4 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 and C.2 include physical RNS

calculations and Appendices C.3 and C.4 include optimized RNS calculations.

Appendices C.2 and C.4 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 2017 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 60% 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.38 38 After contracts from such programs are signed, they are risk-adjusted in the same manner as other


24

Appendices C.1 and C.3 provide SCE’s physical and optimized RNS through 2030 using the

Commission’s RNS Methodology. Appendices C.1 and C.3 use the same assumptions as in

Appendices C.2 and C.4 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 2017 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 2015-2027.39

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.

39 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.

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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, increased consideration of

CCA by municipalities may lead to more notifications of CCA formation, which could lead to a

longer RPS position 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 2017 and 2020. Wind 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

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projects in that location.40 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 in 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

both contributed to a higher project success rate.

40 See Southern California Edison Company’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), Application 07-06-031 (February 1, 2012).

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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, 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, and solicitation deferrals in order to adjust its renewable

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

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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

believes it appropriately accounts for these risk factors in its forecasted RNS as described in prior

sections.

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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 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 the procurement in SCE’s current renewables portfolio is from either contracts

executed prior to June 1, 2010 or contracts for Category 1 products. 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

30

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 only conduct solicitations for sales of vintage 2017 through

2020 Category 1 products in 2017. 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 60% 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.”41 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

41 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).

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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

SCE proposes to hold a 2017 RPS solicitation, only for sales of vintage 2017 through 2020

renewable energy for Category 1 RECs. SCE will use the proposed 2017 Procurement Protocol,

included here as Appendix I.1, for these sales and for future RPS solicitations beyond 2017. The

Procurement Protocol includes, among other things:

• 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

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• SCE’s 2017 Pro Forma Renewable Power Purchase Agreement (“Pro Forma”), attached

as Appendix G.1; and

• 2017 REC Sales Confirmation (“2017 REC Sales Agreement”).

A discussion of the important changes in the proposed solicitation documents from SCE’s

2016 solicitation documents is included in Section XV.

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 H.1 (the “LCBF Methodology”) describes this process,

including capacity valuation and the renewable integration cost adder, among other factors.

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 Environmental Justice communities through California’s Environmental Protection

Agency’s CalEnviroScreen 3.0.

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

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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.

X.

ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING

Although SCE has observed very few instances of negative pricing in the day-ahead

market,42 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 deliveries in excess of their day-

ahead awards, this practice helps to limit customer exposure to negative prices. This practice is

42 ~ 0.05% of hours in sampled nodes in the day-ahead market – the vast majority of which occur at

generally congested interties such as Palo Verde.

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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 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

day-ahead and in real-time, even if SCE ultimately pays the 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 Pre-Approval of 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 mechanism whereby these transactions are

pre-approved by the Commission. This proposal would improve upon current Commission

processes that make renewable resource procurement more difficult, burdensome, and time

consuming than non-renewable resources. If the Commission does not agree that SCE’s customers

and the market, in general, will benefit from pre-approved transactions, SCE requests a Tier 1

Advice Letter approval process for its REC sales consistent with D.14-11-042.

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

Foreseeable Future

The IOU’s are well positioned to meet the Compliance Period (“CP”) 3 2020 33%

RPS target with existing projects and projects under development (risk-adjusted).43 PG&E forecasts

it will not need incremental physical RPS need until 2026,44 and SDG&E forecasts 45% renewable

energy by 2020.45 Because of this excess REC volume, neither SCE, PG&E nor SDG&E held 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,

43 2016 Q4 CPUC RPS Report to Legislature. 44 2016 PG&E RPS Plan. 45 2016 SDG&E RPS Plan.

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filed REC sales agreements entered into through its RFO, via a Tier 1 Advice Letter for Commission

approval.46

The Commission’s 2016 Biennial RPS program update47 showed that most of the

CCAs and ESPs are significantly below their 2020 33% RPS requirements. Most of these smaller

RPS 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.48 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,49

46 See, PG&E’s Advice Letter No. 5095-E. 47 http://www.cpuc.ca.gov/RPS_Reports_Docs p. 6, Table 1. 48 CAL. PUB. UTIL. CODE § 399.16(c). 49 D.17-06-026.

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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 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 (SB350) 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 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 RPS energy,50 and some ESPs and/or CCAs may

need RECs to meet compliance requirements in the near future.51 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.

50 Section XI.A.1 above. 51 Id.

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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

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.

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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.

c) REC Sales Stabilize Rates By Realizing Near Term Value

SCE has a bank until year 203052 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 its customers. SCE is significantly long on its compliance position in the near term. Then, the

bank gets shorter. In year 2030,53 SCE has no need for new RPS resources with the use of bank, but

is not as significantly long on RPS resources. If SCE can generate some revenues through near term

REC sales, it will help smooth out SCE’s RPS compliance positions over the years. In turn, these

REC sales would smooth out the rate impacts over 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.

d) 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

Senate Bill 35054 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,

52 Section II.B. 53 Id. 54 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416

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starting no later than 2021. The previous long-term contracting requirement for retail sellers was

smaller - .25% of 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. 55 Any retail

seller making such an election must, however, meet 65% long-term contracting requirement.56.

Short-term contracts would facilitate the following types of projects/products to count toward RPS

targets:

• 7 year renewable qualifying facility must-take contracts

• 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 Preferred and Alternate Proposals

1. Preferred/Pre-Approved Approach

a) General Description of Pre-approval Mechanism

Similar to the pre-approval mechanism in the IOUs’ Bundled Procurement

Plans,57 SCE recommends a pre-approval for a limited transaction sale volume. SCE has included

the following key elements in its plan: a REC Sales PPA, details of proposed transaction methods,58 55 Id. at Ordering Paragraphs 15-24, at pp. 54-56. 56 Id. at Conclusion of Law 6, at p. 42. 57 Public Utilities Code Section 454.5 (c) and (d) allows for a utilities’ procurement plan to eliminate the

need for after-the-fact reasonableness through review of upfront achievable standards and criteria coupled with verification of appropriate contract administration through the Quarterly Compliance Reports.

58 Consistent with D.14-11-042.

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and a detailed discussion of terms, volume limits, and pricing floor as a part of the REC sales

framework.

Table XI-1 summarizes the key elements of SCE’s REC sales framework:

Table XI-1 SCE’s REC Sales Framework

Parameter Proposal

Transaction mediums59 Exchanges, RFO Process, Electronic Solicitations, Brokers, Bilateral (strong showing60)

Terms < 5 years

Sales Volume Limits61 Based on load/gen forecast and uncertainty around it, changing RPS legislation and anticipated pricing

Pricing62 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) filing

b) Reasons That Pre-Approval of REC Sales Transactions Is the Preferred

Approach

Appendix F.2, in Section I.A, discusses confidential data suggesting that given

the supply/demand imbalance of RECs in California, a faster approval process is absolutely

necessary to avoid market inefficiencies.

59 Explained in more detail in section XI.E below. 60 A strong showing could include competing price offers, broker or online quotes, published indices,

comparisons to recent solicitations. 61 Sales Volume Limits methodology is explained in detail in Appendix F.2, section II. 62 Price Floor methodology is explained in detail in Appendix F.2, section III.

42

Additionally, on June 16, 2017, PG&E submitted Advice 5095-E, seeking

approval of five power purchase and sale agreements for a total of ~2.1 TWh. These sales were

between PG&E and five counterparties, with significant amount of sales to ESPs and CCAs (Direct

Energy, 3 Phase Renewables Inc., Peninsula Clean Energy Authority, EDF and Exelon [which is a

parent company to ESP Constellation NewEnergy Inc.]).63 These sales substantiate that there will be

a significant imbalance of RECs in California for Compliance Period 3.

REC sales transactions are fairly simple and REC products are easy to

understand. Given the short term length of these transactions, the valuation and selection process

should be straightforward. If bids are of similar terms, SCE will simply rank the bids by REC

premium for shortlisting. Finally, pre-approval will significantly increase REC market efficiency:

• It will provide a greater opportunity to maximize value for SCE’s

customers as there is more certainty for transactions

• It will allow SCE to transact quickly with buyers due to changing market

circumstances

• It will allow buyers to timely meet compliance obligations especially

when a transaction takes place towards the end of a compliance period.64

For example, if parties have an immediate need for RECs, the parties

would have limited time to procure the contracted-for RECs. Having pre-

approval allows the parties to begin delivering RECs as soon as possible

which is especially important at the end of a year and at the end of a

compliance period. Having to wait for approval may make it very difficult

or impossible to enter into contracts at the end of a year for a bundled

product (energy and RECs) from that same year.

63 Advice 5095-E, Section 1.4(b), p. 5. 64 Section XI.D, Appendix F.2.

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2. Alternate/Tier 1 Advice Letter Approach

SCE proposes a Tier 1 Advice Letter Approach for approval of REC sales as an

alternative to pre-approval. SCE’s proposed alternate approach is similar to its preferred approach

described above. The alternate approach includes terms, volume limits, and pricing floor as part of

the preferred approach for the REC sales framework as summarized in Table XI-1 above. The

difference between the preferred approach and the alternate approach is that instead of having

Commission pre-approval of all REC sales transactions meeting the criteria, SCE will submit a Tier

1 Advice Letter filing for each of its REC sales. A Tier 1 Advice Letter will include each 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). Also, 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.

C. SCE’s Proposed Limits on REC Sales

Appendix F.2, Section II describes and provides an example calculation of SCE’s proposed

volume limits.

D. Acceptable REC pricing

Appendix F.2, Section III sets out confidential upfront pricing standards 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

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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 see where the market is in terms of prices willing to be paid for RECs. SCE may also bid in

to 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 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 a reasonableness showing including a showing that the price achieved

represents a reasonable market price.

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

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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 in order for the transactions to be deemed reasonable prior to

contract execution.65 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.

4. Exchanges

An exchange is a central marketplace with established rules and regulations where

buyers and sellers meet to trade standardized products at prices that are both visible and

representative (i.e. the price is known and available to any interested market participant and the

posted price and quantity are determinative of the final transaction costs). Exchanges differ from

brokers in that exchanges take title to the product being transacted, such that the exchange becomes

the counterparty for both the buyer and the seller. While no exchange-traded product currently

exists for RECs, having the standing authority to transact over an exchange would have two key

benefits should such a product develop. First, the identities of the counterparties are not revealed

prior to transaction, thus providing anonymity for those parties that might wish to remain

anonymous. Second, because of an exchange’s structure and margining rules, credit risk would be

reduced substantially relative to transacting with a counterparty in the Over-The-Counter markets.

Given that exchanges provide unique benefits in terms of price transparency, anonymity, and credit,

it would likely become an attractive transaction mechanism should an exchange-traded product

develop.

Currently, SCE is not aware of an exchange that lists California RECs as a product.

To the extent an exchange develops the capability to list California RECs and if SCE wants to utilize

65 See Appendix F.1 for SCE’s proposed list of pre-approved brokers.

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exchanges in the future, it will obtain prior Energy Division approval by filing a Tier 2 Advice

Letter.

a) Exchange Cleared Transactions

An exchange may also permit participants to “clear” certain conforming

transactions that were not executed through the exchange initially. In this process, the parties to an

Over-The-Counter transaction agree to submit the transaction to the exchange. For a fee, the

exchange (e.g., New York Mercantile Exchange (“NYMEX”) via NYMEX ClearPort or

Intercontinental Exchange (“ICE”) via ICE Clear) agrees to take title to the transaction and assumes

responsibility for protecting both the buyer and seller from financial loss.

To access both NYMEX and ICE, SCE and other market participants use

intermediaries called clearing firms. A clearing firm is a company approved to clear trades through

the exchange, and is responsible for the financial commitments of its customers that clear through

the firm. Clearing firms charge a fee for performing the clearing function. These fees are small

relative to the nominal value of the transactions. If given the authority to utilize exchanges to

transact in RECs, SCE will select a clearing firm on a transaction-by-transaction basis from the list

that is incorporated into Appendix F.1.

F. Proposed Timeline for REC Sales

SCE’s Procurement Protocol in Appendix I.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 2017 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.

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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, as well as actual RPS-eligible generation

for every year from 2003 through 2016. Appendix D also includes a forecast of future expenditures

SCE may incur every year from 2017 through 2030, as well as a forecast of expected generation for

every year from 2017 through 2030.

XIV.

IMPERIAL VALLEY

In SCE’s last RPS solicitation (the 2015 RPS solicitation), SCE received 279 proposals.

XV.

IMPORTANT CHANGES FROM 2016 RPS PLAN

SCE has made significant changes to the Written Plan to recognize that SCE, at present, has

no need for eligible renewable resources. As a result, SCE does not propose to hold a 2017 RPS

solicitation. Instead, SCE seeks permission to sell SCE RECs of 2017-2020 vintage, as discussed in

Section XI above.

SCE’s 2017 RPS Plan includes changes to: (1) SCE’s 2016 Procurement Protocol; (2) SCE’s

2016 Pro Forma; (3) SCE’s 2016 Pro Forma REC Sales Agreement; and (4) SCE’s LCBF

Methodology. Those changes are summarized below. SCE has included redlines of its 2017

Procurement Protocol, 2017 Pro Forma, 2017 Pro Forma REC Sales Agreement, and LCBF

Methodology against the versions of those documents included in SCE’s 2016 RPS Plan as

Appendices I.2, G.2, J.2 and H.2, respectively. SCE has made relatively few changes to these

documents from the 2016 documents. The most significant changes to the other 2016 documents are

summarized below.

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A. Important Changes in 2017 Procurement Protocol

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.66 A redline of the 2017 Pro Forma showing all of the changes from the 2016

RPS Pro Forma is attached as Appendix I.2. Additionally, changes related specifically to the

Standard Contract Option are mentioned in Section XVII.B. For SCE’s Community Renewables

solicitation (“CR-RAM”) SCE will use the Community Renewables Rider (“CR Rider”) to the 2017

Standard Contract Option, which SCE submitted to the Commission via Advice Letter 3422-E for its

Community Renewables PPAs.

Important changes in 2017 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).

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).

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).

66 SCE also made changes to the Green Rate provisions that mirror the CR-Rider.

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Other non-substantive changes made to the 2017 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 2017 Pro Forma.

The changes to the 2017 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.

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”).

C. Important Changes in 2017 Least Cost, Best Fit Methodology

1. Capacity benefit for Solar and Wind resources

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.17-06-02767 to calculate Resource Adequacy benefit, as further discussed in

Appendix H.1.

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

67 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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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 2017 Pro Forma provides that the seller must

operate the generating facility in accordance with “Prudent Electrical Practices.”68 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. . . .”69

Consistent with SCE’s focus on safety, SCE’s 2017 Pro Forma also provides that, prior to

commencement of any construction activities on the project site, the seller must provide to SCE a

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.70

SCE also has a safety section in its 2017 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 2017 Pro Forma.71

68 See 2017 Pro Forma (attached as Appendix G.1) at Section 3.12(a). 69 Id. at Exhibit A. 70 Id. at Section 3.11(e). 71 See 2017 Procurement Protocol (attached as Appendix I.1) at Section 9.03.

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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.72 The Commission also authorized the IOUs to use an

optional streamlined RAM procurement tool in future RPS solicitations.73 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.74

Although SCE will not have a 2017 RPS solicitation, the Standard Contract Option PPA is

used as part of the Community Renewables procurement. 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,75 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 will only be

available to projects with a first point of interconnection to the CAISO, and not to dynamically

scheduled projects.76

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.

72 See D.14-11-042 at pp. 91-92, pp. 102-104. 73 Id. at pp. 91-92. 74 Id. at p. 92. 75 Id. 76 SCE’s 2017 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 2017 Pro Forma will be required for dynamically scheduled projects.

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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.”77 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

XVIII. 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.78 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 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 2017 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 2017 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.

77 D.14-11-042 at p. 92. 78 Id. at p. 93.

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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, SCE made changes to the SCE 2017 Pro Forma that are applicable to the Standard

Contract Option. Please see Section XV(B).

XVIII.

GREEN TARIFF SHARED RENEWABLES PROGRAM

On September 28, 2013, Governor Brown signed SB 43 into law.79 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.

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.80 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”81

(referred to as “environmental justice” or “EJ” projects by SCE). To implement this statutory

79 SB 43 was codified in California Public Utilities Code Section 2831 et seq. 80 See D.15-01-051 at Ordering Paragraph 7. 81 CAL. PUB. UTIL. CODE § 2833(d)(1).

54

provision, the Commission established EJ and residential reservations for each IOU, including 45

MW to SCE.82

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.83 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 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

solicitations.84 The Commission limited initial procurement to new solar facilities between 0.5 MW

and 3 MW,85 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.86 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

82 See D.15-01-051 at Ordering Paragraph 7 and D.15-01-051 at pp. 4-5. 83 Id. at pp. 3-4. 84 Id. Ordering Paragraph 1. 85 Id. at pp. 36-37, p. 39, Conclusion of Law 17. 86 See D.16-05-006, Conclusions of Law 2 and 4.

55

requirements.87 CR projects must be located within SCE’s service territory88 and must satisfy the

eligibility requirements associated with the RAM procurement tool.89

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;90 (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;91 (v) Advice 3432-E, which is the 20 Year Forecast of

GTSR bill credits and charges;92 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

because projects eligible for SCE’s CR-MAT program will also be eligible for SCE’s CR-RAM

program.93

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;94 (ii) Advice 3496-E, 2017 annual marketing,

education and outreach plan and budget for the GTSR program;95 (iii) Advice 3525-E, which is

87 Id. at Ordering Paragraph 5. 88 See D.15-01-051 at pp. 21-23, Conclusion of Law 14. 89 See D.16-05-006 at p. 35, Conclusion of Law 4. 90 Advice 3180-E was approved by the Energy Division, effective as of February 23, 2015. 91 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution

E-4734. 92 SCE submitted Advice 3432-E that was approved by the Energy Division, effective as of July 11, 2016. 93 SCE submitted Advice 3422-E that was approved by the Energy Division, effective as of June 15, 2016. 94 Advice 3461-E was approved by the Energy Division, effective as of September 25, 2016. 95 Advice 3496-E was approved by the Energy Division, effective as of November 27, 2016.

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SCE’s GTSR program rate component 2017 Updates;96 (iv) Advice 3525-E-A, supplemental filing

to make modifications to Advice 3525-E;97 (v) Advice 3536-E, which implements the California

alternate rates for energy for the GTSR Program;98 (vi) Advice 3557-E, which updated the CR-RAM

Rider and RFO Instructions for CR-RAM Two;99 (vii) Advice 3614-E, which is the update to the 20

Year Forecast of GTSR bill credits and charges;100 and (viii) Petition for Modification (PFM) for

D.15-01-051 to change the AmLaw 100101 securities opinion requirement.102

B. Community Renewables - Modifications to the 2017 Procurement Protocol, 2017 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

96 Advice 3525-E was approved by the Energy Division, effective as of January 1, 2017. 97 Advice 3525-E-A was approved by the Energy Division, effective as of January 1, 2017. 98 SCE submitted Advice 3536-E on December 21, 2016, which has not been approved as of the date of this

filing. 99 Advice 3557-E was approved by the Energy Division, effective as of March 12, 2017. 100 SCE submitted Advice 3614-E on June 5, 2017, which has not been approved as of the date of this filing. 101 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United

States based on gross revenue. 102 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.

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and two in 2018. SCE will use the latest approved RPS Pro Forma Standard Contract Option and

CR Rider and Amendment with each RFO.

1. 2017 Procurement Protocol – CR Modifications

The 2017 Procurement Protocol includes additional 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.16-05-006.103 The Procurement Protocol also

contains specific instructions applicable to CR and CR-EJ projects only, including:

• 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, 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.

103 See D.15-01-051 at pp. 21-23, Conclusion of Law 7; D.16-05-006 at Ordering Paragraph 1.

58

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 and CR-RAM Two (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.16-05-006.104 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.

In D.15-01-051, the Commission adopted a securities opinion requirement to protect

customers from the cost of securities litigation related to any securities claim that could arise from a

CR project, which required a developer of a CR project to hire an AmLaw 100 firm to issue a

securities opinion addressed to the IOU offtaker.105 Pursuant to Ordering Paragraph 12 of D.16-05-

006, Energy Division and Legal Division held a workshop on October 13, 2016, in which parties

could discuss and develop a petition to modify the AmLaw 100 securities opinion requirement in

D.15-01-051.

104 See Advice 3461-E and Advice 3557-E. 105 D.15-01-051 at pp. 71, 175, Conclusion of Law 29.

59

As a result of that workshop, the IOUs filed a PFM of D.15-01-051 and provided an

alternate objective standard that would make more law firms eligible to issue the securities opinion,

which would lower transactional costs to CR project developers. The IOUs sought to replace the

AmLaw 100 requirement with a three-part standard – the lawyer primarily responsible for issuing

the opinion has sufficient experience in securities law, the lawyer has an active license to practice

law in California, and the law firm issuing the opinion carries $10 million in professional liability

insurance coverage. On July 17, 2017, the Commission issued D.17-07-007 to modify D.15-01-051

to replace the AmLaw 100 requirement with the three-part standard, and to direct the IOUs to update

their CR-RAM riders with the new securities opinion requirements.106

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”);107 (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.108

106 D.17-07-007. The IOUs will file Tier 1 advice letters within 15 days of the effective date of the decision

to reflect the new securities opinion requirements in the CR-RAM rider. 107 See D.16-05-006 at Ordering Paragraph 3. 108 Id. at Ordering Paragraph 2.

60

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”).109 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.110 SCE filed its

interim Annual GTSR 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”).111 The GTSR Annual Tracking

Report was filed on September 1, 2016 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.112

109 See D.15-01-051 at pp. 141-42, Ordering Paragraph 10. 110 Id. at pp. 141-42. 111 See Advice 3218-E at p. 24. 112 Id. at p. 24 and Attachment D.

61

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.

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 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

2024.113

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.114

113 See D.13-10-040 at pp. 15, 26. 114 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)

20162017 Written Plan

January 23,July 21, 2017

PUBLIC VERSION


TABLE OF CONTENTS

Table Of Contents

Section Page

-i-

I. EXECUTIVE SUMMARY OF 20162017 RPS PLAN ...................................................................1

II. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND ........................................................................................................................................5

A. SCE’s Renewables Portfolio ................................................................................................5

B. SCE’s Forecast of Renewable Procurement Need .............................................................75

C. SCE’s Plan for Achieving RPS Procurement Goals ........................................................119

D. SCE’s Portfolio Optimization Strategy ..........................................................................1311

E. SCE’s Management of its Renewables Portfolio ...........................................................1513

F. Lessons Learned, Past and Future Trends, and Additional Policy/Procurement Issues .............................................................................................1714

1. Lessons Learned and Past and Future Trends ....................................................1714

a) Possible Future Trend Toward Departing Load .......................................................................................................1715

b) One Offer Must Have a Term Length of 10 Years or Less..............................................................................................19 Need for REC Sales ...................................................................................17

2. Additional Policy/Procurement Issues ...................................................................20

a) SCE Will Consider the Need for RPS Resources to Meet Local Reliability Need in the Western LA Basin and Goleta Areas ..........................................................................................................20

III. PROJECT DEVELOPMENT STATUS UPDATE ...................................................................2318

IV. POTENTIAL COMPLIANCE DELAYS ..................................................................................2318

A. Curtailment ....................................................................................................................2418

B. Increasing Proportion of Intermittent Resources in SCE’s Renewables Portfolio .....................................................................................................2519

Appendix A - Page 2


TABLE OF CONTENTS (CONTINUED)

Table Of Contents (Continued)

Section Page

-ii-

C. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and Transmission ........................................................2620

D. A Heavily Subscribed Interconnection Queue ...............................................................2721

E. Developer Performance Issues .......................................................................................2822

V. RISK ASSESSMENT ................................................................................................................2922

VI. QUANTITATIVE INFORMATION .........................................................................................2923

A. RNS Calculations ...........................................................................................................2923

B. Response to RNS Questions ..........................................................................................3124

1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? ..................................................................................................................3124

2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. .................................................................3125

3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ........................................3225

4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? ..............................................3326

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? ..................................................................................3327

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. ........................................................................................3427

Appendix A - Page 3




Section Page

-iii-

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. .............................................................................................................3427

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. ..........................................3528

9. Please address the cost-effectiveness of different methods for meeting any projected VMOP procurement need, including application of forecast RECs above the PQR. ........................................................................................3629

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? ..................................................................................................................3629

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? ..........................................................................................................3729

VII. MINIMUM MARGIN OF PROCUREMENT ..........................................................................3730

VIII. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES .................................................................................................................3931

A. Bid Solicitation Protocol ................................................................................................3931

B. LCBF Methodology .......................................................................................................4032

IX. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..........................................4032

X. ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING ........................................................................................................................4133

Appendix A - Page 4




Section Page

-iv-

XI. CALIFORNIA TREE MORTALITY EMERGENCY PROCLAMATION ........................................................................................................................43 AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS .......................................................................................................................................35

A. Justification of SCE’s Request for Pre-Approval of a Limited Amount of Short-Term RPS-Eligible Transactions .............................................35

1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future ............................................................35

2. California Customers Need an Open Market for RECs ......................................................................................................................36

3. REC Sales Will Create Customer Value ................................................................38

a) Selling is better than banking up to the established limits ........................................................................................38

b) Published Research From Independent Entities Forecasting Decline and/or Stabilization of Renewable Energy Costs ..................................................39

c) REC Sales Stabilize Rates By Realizing Near Term Value ................................................................................................39

d) 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 ....................................................39

B. SCE’s Preferred and Alternate Proposals ..........................................................................40

1. Preferred/Pre-Approved Approach ........................................................................40

a) General Description of Pre-approval Mechanism .................................................................................................40

b) Reasons That Pre-Approval of REC Sales Transactions Is the Preferred Approach .....................................................41

2. Alternate/Tier 1 Advice Letter Approach ..............................................................43

Appendix A - Page 5




Section Page

-v-

C. SCE’s Proposed Limits on REC Sales ...............................................................................43

D. Acceptable REC pricing ....................................................................................................43

E. Proposed Transactional Methods .......................................................................................43

1. Competitive Solicitations .......................................................................................43

2. Bilateral Transactions ............................................................................................44

3. Brokers ...................................................................................................................44

4. Exchanges ..............................................................................................................45

a) Exchange Cleared Transactions .................................................................46

F. Proposed Timeline for REC Sales .....................................................................................46

XII. EXPIRING CONTRACTS ............................................................................................................46

XIII. COST QUANTIFICATION ..........................................................................................................47

XIV. IMPERIAL VALLEY ....................................................................................................................47

XV. IMPORTANT CHANGES FROM 20152016 RPS PLAN ...........................................................47

A. Important Changes in 20162017 Procurement Protocol ....................................................48

1. Considering Proposals only for Category 1 Products ............................................48

2. Commercial On-Line Date Beginning on January 1, 2021 or Later ......................48

3. Offering 10 Year Term Lengths or Less ................................................................49

4. Solicitation Schedule is To Be Determined ...........................................................49

5. Only REC Sales Will Be Part of this Solicitation ......................................................5048

6. Workforce Development ........................................................................................50

7. Disadvantaged Communities .................................................................................50

B. Important Changes in 20162017 Pro Forma 51 and REC Sales Agreement .................................................................................................................48

Appendix A - Page 6




Section Page

-vi-

C. Important Changes in 20162017 Least Cost, Best Fit Methodology ..................................................................................................................5149

1. Workforce Development ........................................................................................51 Capacity benefit for Solar and Wind resources .....................................................49

2. Disadvantaged Communities .................................................................................51

3. Selection Criteria for Community Renewables .....................................................51

XVI. SAFETY CONSIDERATIONS .................................................................................................5249

XVII. STANDARD CONTRACT OPTION ........................................................................................5351

A. Procurement Need ..........................................................................................................5452

B. Standard Contract ...........................................................................................................5552

C. Project Size Restrictions ....................................................................................................56

D. Project Categories ..............................................................................................................56

E. Restriction on Subdivided Projects ....................................................................................57

F. Locational Restrictions ......................................................................................................57

G. Valuation and Selection .....................................................................................................57

H. Interconnection Studies ......................................................................................................58

I. Commercial Operation Deadline .......................................................................................58

J. Commission Approval Process ..........................................................................................59

XVIII. GREEN TARIFF SHARED RENEWABLES PROGRAM ......................................................5953

A. Community Renewables - Background .........................................................................6054

B. Community Renewables - Modifications to the 20162017 Procurement Protocol, 20162017 Pro Forma Standard Contract Option, and LCBF Methodology ....................................................................6156

1. 20162017 Procurement Protocol – CR Modifications............................................................................................................................6257

Appendix A - Page 7




Section Page

-vii-

2. 20162017 Pro Forma, Standard Contract Option – CR Rider and Amendment Modifications .........................................................6358

3. LCBF – CR Modifications .................................................................................6359

C. Green Rate and Community Renewables – Annual Reporting........................................................................................................................6460

XIX. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .............................................6461

A. Bilateral Transactions ....................................................................................................6461

B. Energy Storage Procurement .........................................................................................6461

Appendix A - Page 8




viii-viii-

CONFIDENTIAL/PUBLIC APPENDIX A

REDLINE OF 20162017 WRITTEN PLAN

CONFIDENTIAL/PUBLIC APPENDIX B PROJECT DEVELOPMENT STATUS UPDATE

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

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

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

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

CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE

PUBLIC APPENDIX E RECS FROM EXPIRING CONTRACTS

PUBLIC APPENDIX F.1 2016 PROCUREMENT PROTOCOLRENEWABLE ENERGY SALES AUTHORIZED BROKERS AND EXCHANGES

PUBLICCONFIDENTIAL APPENDIX F.2 REDLINE OF 2016 PROCUREMENT PROTOCOLRENEWABLE ENERGY SALES

PUBLIC APPENDIX G.1 20162017 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT

PUBLIC APPENDIX G.2 REDLINE OF 20162017 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT

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

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

PUBLIC APPENDIX JI.1 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT2017 PROCUREMENT PROTOCOL

Appendix A - Page 9


-ix-

PUBLIC APPENDIX I.2 REDLINE OF 2017 PROCUREMENT PROTOCOL

PUBLIC APPENDIX J.1 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX J.2 REDLINE OF 2017 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT

PUBLIC APPENDIX J.2 3 SCE COVER SHEET TO EEI MASTER POWER PURCHASE AND SALE AGREEMENT



PUBLIC APPENDIX J.5 COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

PUBLIC APPENDIX J.56 PARAGRAPH 10 TO THE COLLATERAL ANNEX TO THE EEI MASTER POWER PURCHASE AND SALE AGREEMENT

Appendix A - Page 10

CONFIDENTIAL - DRAFT

1

I.

EXECUTIVE SUMMARY OF 20162017 RPS PLAN

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

Ruling Identifying Issues and Schedule of Review for 20162017 Renewables Portfolio Standard

(“RPS”) Procurement Plans, dated May 17, 201626, 2017 (“ACR”), and the E-Mail Ruling Granting,

in Part, IOUs1 Request for an Extension of Time to Produce the 20162017 RPS Procurement Plans,

dated June 8, 2016, and the Decision Accepting Draft 2016 Renewables Portfolio Standard

Procurement Plans, Decision No. (“D.”) 16-12-044, dated December 22, 2016,19, 2017, Southern

California Edison Company’s (“SCE’s”) Final 20162017 RPS Procurement Plan (“20162017 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.

This 20162017 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, and discusses SCE possibly conducting a 2016including SCE’s plan not to

conduct a 2017 RPS solicitation procuring new RPS resources, and to sell Renewable Energy Credits

(“RECs”). SCE’s 20162017 RPS Plan includes its 20162017 Procurement Protocol and 2016, 2017

Pro Forma Renewable Power Purchase Agreement, 2017 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 20152016 RPS solicitation documents.

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

Further, this 20162017 RPS Plan addresses other issues set forth in the ACR, statute, and other

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

20162017 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;

• California Tree Mortality Emergency Proclamation;Pre-approval process to sell RECs, or,

in the alternative, Tier 1 Advice Letter process to sell RECs;

• Expiring contracts;

• Cost quantification tables;

• Imperial Valley issues;

• Safety considerations;

• Standard Contract Option using the streamlined Renewable Auction Mechanism (“RAM”)

procurement tool;

• Green Tariff Shared Renewables (“GTSR”) program, in particular the enhanced

Community Renewables (“ECR” or “CR” by SCE) program; and

• Other RPS planning considerations and issues.

SCE takes the RPS program’s regulatory framework into account in planning for possible

renewable procurement in 2016 and beyond. 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%, 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


3

period. The Commission has issued several decisions implementing SB 2 (1x), including Decision

(“D.”) 11-12-020 setting RPS procurement quantity requirements,2 D.11-12-052 implementing the

three portfolio content categories of renewable energy products that may be used to satisfy RPS

targets,3 D.12-06-038 establishing new compliance rules 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. TheIn 2016, the Commission

has not yet issued a decision on the implementation of SB 350’s higher RPS targets and other changes

to the RPS program. However, SCE has included SB 350’s higher RPS targets in this 2016 RPS Plan

assuming that the Commission will use the same methodology adopted in D.11-12-020 to set interim

RPS targets.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 2 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.

3 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 renewable energy credits (“RECs”). Retail sellers are subject to a minimum 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.


4

procurement in one compliance period may be applied to later compliance periods. 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 will be August 28, 2017).4 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”5 (which are due on September 22, 2017).6 If SCE decides to make

the early election in 2017, it will file a motion to update this plan on September 22, 2017.

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 20162017 RPS Plan,

SCE does not propose to hold a 2016 RPS solicitation. SCE will seek permission from the

Commission to procure any amounts, other than amounts separately mandated by the Commission

(i.e. Feed-In Tariff and Tree Mortality Renewable Auction Mechanism (“BioRAM”), during the time

period covered by the 2016 solicitation cycle.) 2017 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 future, SCE proposes to sell RECs, as described in Section XI below and

in Appendix F.1 and F.2.

To the extentIf in future years SCE conductsholds a 2016 RPS solicitation after seeking

permission from the Commission and receiving appropriate authorization, SCE will, SCE would use a

4 D.17-06-026, Ordering Paragraph 23, p. 56. 5 D.17-06-026, Ordering Paragraph 24, p. 56. 6 E-Mail Ruling Granting, in Part, IOUs Request for an Extension of Time to Produce the 2017 RPS

Procurement Plans, dated June 19, 2017.


5

solicitation process that is intended to capitalize on the maturing renewables market and target the

most viable proposals that fit SCE’s reliability need 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), unless the resource is located in the

Western LA Basin4 or the Goleta area,5 which have a compelling local reliability need; 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), if SCE conducts a 2016 solicitation after seeking permission from the

Commission and receiving appropriate authorization, SCE willSCE would request that all bidders

submit one offer for a term of 10 years or less for each project. SCE will also solicit Category 1

products only. Additionally, SCE will only consider proposals from projects with initial delivery

dates to SCE of January 1, 2021 or later, unless the resource is located in the Western LA Basin or the

Goleta area where there is a demonstrated local reliability need.

If SCE holds a 2016 RPS solicitation after seeking permission from the Commission and

receiving appropriate authorization, SCE will alsoIn this 2017 RPS Plan, SCE will request offers from

parties interested in purchasing Category 1 or 3REC products from SCE. Also, SCE will bid into other

parties’ solicitations seeking Category 1 REC products. SCE does not forecast a net short position

potential until 2023.2030 with the use of bank. Therefore, in order to maximize value for customers,

SCE maywill sell vintage 20162017 through 2020 Category 1 or 3 products if purchasers present

reasonably priced offers. SCE would not sell Category 1 or 3 products if doing so would compromise

SCE’s renewable positionproducts, consistent with its proposal in this 2017 RPS Plan.

4 In D.16-05-053, the Commission found that SCE still needed to procure 169.4 megawatts (“MW”) of

preferred resources in the Western LA Basin as part of the local capacity resource need that SCE attempted to fill as part of its Local Capacity Requirements Request for Offers (“LCR RFO”).

5 SCE has a significant need for new generation to fill local capacity need in the Goleta area which has insufficient transmission and generation to support continued electric service during a significant emergency event, like a wildfire or mud slide.


6

II.

ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND

A. SCE’s Renewables Portfolio

For the first compliance period from 2011 through 2013, SCE served 20.720.6% of its retail

sales from RPS-eligible resources.67 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.

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

utility-owned generation and independent power producer (“IPP”) portions of SCE’s Solar

Photovoltaic Program (“SPVP”), the GTSR program,78 SCE’s Preferred Resources Pilot (“PRP”)

program, qualifying facility (“QF”) contracts, utility-owned small hydro projects, and bilateral

opportunities.

SCE has completed actions pursuant to the California Tree Mortality Emergency Proclamation

(“Proclamation”) issued by Governor Brown on October 30, 2015 and Senate Bill (“SB”) 8598, as

discussed in Section XI below. Those actions included implementation of: (1) the BioRAM

solicitation seeking 64 megawatts (“MW”) of capacity from biomass facilities burning trees from

High Hazard Zones (“HHZ”) for wildfires; and (2) implementation of the Bioenergy Market Adjusting

Tariff (“BioMAT”) seeking power from small (3 MW or smaller) biomass facilities burning trees from

67 SCE retired RECs amounting to 20.6% of its retail sales for the first compliance period. 78 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. 8 On August 30, 2016, the California Legislature passed Senate Bill (“SB”) 859, and Governor Edmund G.

Brown, Jr., signed it into law on September 14, 2016.2 SB 859 developed a new requirement for electrical corporations to procure their respective shares of 125 Megawatts (“MW”) from existing biomass facilities using prescribed amounts of dead and dying trees located in high hazard zones (“HHZ”) as feedstock. In Resolution E-4805, dated October 21, 2016, at page 8, the Commission identified SCE’s share of the additional 125 MW as 44 MW.


7

HHZ. On November 22, 2016, SCE submitted three BioRAM contracts totaling 66.7 MW from its

BioRAM solicitation for Commission approval in Advice Letter 3517-E. On December 23, 2016, the

Director of Energy Division approved SCE’s Advice Letter 3517-E, effective December 22, 2016.

This procurement resulting from BioRAM, as well as any BioMAT procurement that occurs, will be

RPS-eligible deliveries.Between January 2014 and December 2015, SCE executed 26 RAM contracts

for approximately 409 MW, 14 ReMAT contracts for approximately 27 MW, 41 SPVP IPP contracts

for approximately 64 MW, one GTSR contract for 20 MW, two PRP contracts for 2 MW, and three QF

standard offer contracts for approximately 38 MW.9 During this period, SCE also executed: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.

• 8 contracts for approximately 1,556 MW from its 2013 RPS solicitation;

• one bilateral contract for 132 MW;

• one sales agreement for 2016 deliveries; and

• 18 contracts for approximately 2,096 MW from its 2014 RPS solicitation.

SCE launched its 2015 RPS solicitation on January 29, 2016 and has executed two RPS

contract with a total combined contract capacity of 253 MW and two GTSR contracts with a total

combined contract capacity of 40 MW. SCE is still actively negotiating contracts for renewable

energy from that solicitation.

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 9 Of these, six of the RAM contracts totaling 98 MW, four of the ReMAT contracts totaling 5 MW, and

eleven of the SPVP IPP contracts for 16 MW subsequently terminated. This information is up to date as of June 30, 2016.


8

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

BioMAT), among other factors.

Appendices C.1 through C.4 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. Because of the new 50% by 2030 target

established in SB 350, Appendices C.1 through C.4 also include a 50% target for 2030 and use the

same methodology2020 as well as the RPS targets adopted by the Commission in D.1116-12-020 to

set targets040 for the years 2021 through 2030.

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”).109 As

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.1110 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 thatwhich 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.1211 Additionally, all forecasts incorporate current expected

109 SCE’s forecasts only extend through 2030; therefore, SCE’s forecasted RNS information is only included

through 2030. 1110 The required information on RECs from expiring contracts is included in Appendix E. 1211 After contracts from such programs are signed, they are risk-adjusted in the same manner as other



9

online dates for all projects that are not yet online. SCE is in the process of completing its 2015 RPS

solicitation.

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 60%

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 around 89% for the second

compliance period to approximately 7970% in the third compliance period and approximately 7469%

thereafter.

Additionally, SCE adjusted its load and generation forecasts for RPS-eligible energyforecast

to remove customer load served under the Green Tariff portion of the GTSR program (called the

“Green Rate” by SCE).12 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.13 This is

because RECsFor 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 do not

count toward RPS compliance.14 Green Rate subscriptions are incorporated into all forecasts

12 No customers are presently being served under the Community Renewables Rate. As a result, SCE only

counted Green Rate customers here. 13 No customers are presently being served under the Community Renewables Rate. As a result, SCE only

counted Green Rate customers hereSee CAL. PUB. UTIL. CODE § 2833(s). 14 See CAL. PUB. UTIL. CODE § 2833(s).


10

assuming that 100% of current Green Rate subscriptions continue indefinitely.15.14 At present,

because dedicated resources procured to serve Green Rate customers have not yet begun service, SCE

transferred RECs from other RPS-eligible generation fromresources in its Interim Green Rate Pool to

serve Green Rate subscriberssubscriptions, until dedicated Green Rate resources are operational, as an

offset to existing renewable generation. 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.1615

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

Appendices C.2 and C.4, and the Commission’s assumptions, as reflected in Appendices C.1 and C.3,

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 2016 through 2020 and the

standardized planning assumptions that were used in the 2014 Long-Term Procurement Plan

(“LTPP2017 through 2021 and the CEC’s 2016 California Energy Demand Updated (“CEDU”)

Forecast for 2021 through 20242022-2027 with extension beyond 20242027 calculated based on the

average annual rate of change between 2020-2024.17in the CEDU Forecast for the period 2015-2027.

This is consistent with the adopted standardized planning assumptions laid-out in the February 28,

2017 Assigned Commissioner’s Ruling in the Integrated Resource Planning (“IRP”) docket,

R.16-02-007.16 SCE uses its own bundled retail sales forecast for renewable procurement planning

because it is SCE’s best forecast of bundled retail sales.

1514 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.

1615 CAL. PUB. UTIL. CODE § 2833(u). 1716 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. In Appendices C.1 and C.3, SCE uses its own bundled retail sales forecastThe Commission adopted the standardized planning assumptions in I.16-02-007 for 2025 through 2030 because there is no LTPP forecast for those years.the February 28, 2017 Assigned Commissioner’s Ruling for the purpose of any long term planning that occurs in 2017, as discussed at p. 4.


11

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 46.446.2 billion kWh. The net surplus, less non-bankable procurement,

results in the net long position of around 1.61.4 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.

UsingFor 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 103.5103.1 billion kWh for the third compliance period. 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.

SCE forecasts a net short position in later yearsthe year 2030 with the use of bank under both

SCE’s assumptions and 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

SCE’s assumptions, SCE forecasts a net short position starting in 20242027 without the use of bank

(as shown in Appendix C.2) and a net short position starting in 2028. But with the use of bank, SCE

forecasts a net long position at the end of 2030 (as shown in Appendix C.4). Using the Commission’s

assumptions, SCE forecasts a net short position starting in 20222024 without the use of bank (as

shown in Appendix C.1) and a net short position starting in 20272030 with the use of bank (as shown

in Appendix C.3). Accordingly, SCE currently does not have a short-term renewable procurement

need, but it does anticipate a longer term need for additional RPS--eligible energy.1817 1817 This conclusion assumes no incremental departing load from Community Choice Aggregation

(“CCA”) development. City of Lancaster is the only CCALancaster and Apple Valley as well as a Monte Carlo simulation of additional CCA load beginning in 2019 are currently accounted for in SCE assumptions

(Continued)


12

C. SCE’s Plan for Achieving RPS Procurement Goals

Through its 2016-2017 RPS procurement activities, SCE intends to considerconsiders

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. SCE’s 2016-2017 RPS

procurement activities will takeAs mentioned above, in 2016, SCE served 28.2% of its retail sales

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

2027 without the use of bank and after 2030 with the use of bank. Therefore, SCE does not intend to

hold a RPS Solicitation in 2017 and, instead, will look to sell RECs consistent with its proposal in this

2017 RPS Plan. Among additional factors, SCE makes these decisions taking into account: (1) the

renewable energy procured through SCE’s prior RPS solicitations, including the 2015 RPS

solicitation, 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 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. However, SCE does not propose to conduct a 2016 RPS solicitation. SCE will seek

permission from the Commission to procure any amounts, other than amounts separately mandated by

the Commission (i.e. Feed-In Tariff and BioRAM), during the time period covered by the 2016

solicitation cycle. If SCE does launch such a solicitation after seeking permission from the

Commission and receiving appropriate authorization, SCE will only consider proposals from projects

with initial delivery dates to SCE of January 1, 2021 or later, unless the resource is located in the

Western LA Basin or the Goleta area. As in the 2014 and 2015 RPS solicitations, in order to fill its

Continued from the previous page 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.


13

longer term need, SCE would be flexible in its contracting in the 2016 solicitation. For example, SCE

may contract with a seller for energy deliveries beginning in 2021 or later but will provide the

opportunity for sellers to sell power directly to the market or to a third party until the delivery term

begins under the contract with SCE. Also, if SCE conducts a 2016 RPS solicitation after seeking

permission from the Commission and receiving appropriate authorization, it may includeTherefore,

SCE will not conduct a 2017 RPS solicitation.

SCE will seek to sell RECs of 2017-2020 vintage to allow SCE to optimize its renewables

portfolio and provide value for all bundled and unbundled customers. SCE may conduct a solicitation

of offers for SCE to sell RECs of 2016-2020 vintage to allow SCE to optimize its renewables portfolio.

Finally, if SCE decides to hold a 2016 RPS solicitation after seeking permission from the Commission

and receiving appropriate authorization, one of the two required Community Renewables solicitations

may be part of the 2016 RPS solicitation., 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 the procurement in SCE’s current renewables portfolio is from contracts executed prior

to June 1, 2010 or contracts for Category 1 products. SCE forecasts that it will meet its RPS targets

primarily through long-term Category 1 products because they providedprovide 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 and the treatment of shorter term contracts and banking rules.whether SCE

elects early adoption of the new compliance rules in D.17-06-026.

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 SCE’sits 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


14

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 its need forthe 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.1918 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 H.1.

In addition to RPS solicitations, SCE will continuecontinues to utilize a variety of other

procurement options to help meet the State’s RPS targets, including ReMAT, BioMAT, BioRAM,

local capacity requirements solicitations, all source solicitations, PRP, QF standard contracts, and

bilateral negotiations for competitive renewable energy products.

Given SCE’s long position in the near term, SCE may solicit offers from interested parties to

purchase RECs or other renewable energy products from SCE, as part of any 2016 RPS solicitation

that SCE may hold after seeking permission from the Commission and receiving appropriate

authorization. The RECs would be of 2016-2020 vintage. Additionally, SCE may conduct a future

solicitation or negotiate bilaterally to sell such products to maximize value to its customers and

optimize its RPS portfolio. 1918 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.


15

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 H.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, when evaluating

proposals.

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

energy products,2019 project deferrals, and solicitation deferrals (as it did by not holding a 2012 or a

2016 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.2120

2019 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.

2120 Contract amendments have the potential to decrease contract prices or provide other benefits to customers.


16

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.2221 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, even in the worst case 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.

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 will needneeds to assess the composition

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

potentially reduce flexibility requirements.

2221 SCE also considers statutory and regulatory restrictions on banking of excess procurement.


17

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. 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.2322

In the event an amendment is elected, the IOU should negotiate in good faith.2423 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.2524 The details of D.88-10-032 provide further guidance

to the IOUs to restrict modifications to PPAs with viable projects,2625 and reject modifications that

would result in creating an essentially new project.2726 2322 See D.88-10-032 at p. 16. 2423 See idId. at Conclusion of Law 8. 2524 See idId. at p. 16, Conclusions of Law 13-14. 2625 See idId. at p. 17, Conclusion of Law 4, Appendix A at pp. 4-5. 2726 See idId. at p. 26, Conclusion of Law 17.


18

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.2827

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.2928

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 several of its 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

2827 See D.14-11-042 at pp. 80-82. The standards of review do not apply to amendments that are minor or

non-material. See idId. at p. 80. 2928 For example, the Commission has indicated specific IOU actions regarding amendments to certain

terms in tariff-based agreements.


19

to continue these requirements should SCE conduct a 2016 RPS solicitationin any future solicitations

for all projects, except those that are located in the Western LA Basin or Goleta area.

a) Possible Future Trend Toward Departing Load

Various parties have made statements in public forums, including in public

comments in Commission proceedings,30 about their interest and intentionSCE expects additional

cities within the SCE service territory to join Lancaster and Apple Valley in developing a Community

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 more 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

service. In addition, the City of Lancaster recently formed a CCA and most customers in the City of

Lancaster departed utility bundled procurement service in SCE’s service area. If futureAs additional

large departures were to come to fruition, they couldwill 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

Intent (“BNI”).31 SCE has not received any BNIs for new CCAs since the City of Lancaster formed its

CCA, and, therefore, is not altering, an initial Resource Adequacy (“RA”) filing, or the start of CCA

service.29 In expectation of growing CCA departing load in the near future, SCE prepared a Monte

Carlo simulation of CCA departing load starting in 2019 and has accordingly adjusted its procurement 30 A.14-05-024, Comments of Marin Clean Energy, Sonoma Clean Power, The City of Lancaster, The City

and County of San Francisco, The County of Los Angeles, Lean Energy US, Clean Coalition, and Communities for a better environment Comments on the Draft Workshop Report, p. 2, filed June 20, 2016.

31 SCE Tariff Rules, Rule 23.2(A)(1). 29 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.


20

plan at this time.3230 However, if such As these actual load departures materialize, SCE will consider

how these departures impact its RPS compliance, including its need for additional resources.

Moreover, 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.”3331 If the existing PCIA is found to be insufficient to protect bundled service customers

from rate impacts, theThe 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 a future proceeding.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.3432

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

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

Examples include: BioRAM, ReMAT, 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 necessary special purpose

3230 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, and the Monte Carlo simulation for departing load beginning in 2019.

3331 CAL. PUB. UTIL. CODE §§ 365.1, 366. 3432 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.


21

RPS programs without unfairly burdening bundled service customers. SCE provides its significant

proposed changes to its RPS Plan in Section XV below.

b) One Offer Must Have a Term Length of 10 Years or LessNeed for REC

Sales

If SCE conducts a 2016 RPS solicitation after seeking permission from the

Commission and receiving appropriate authorization, SCE will allow bidders to propose terms of any

length. However, SCE will require bidders to provide at least one proposal per project with a term

length of 10 years or less. Given SCE’s long RPS position and uncertainty regarding departing load,

SCE prefers shorter delivery terms. Signing shorter term contracts now means that SCE’s customers

are not contractually bound to as many longer-term contracts. As a result, if SCE’s bundled load

decreases and concomitantly its renewable position becomes significantly longer, SCE’s bundled

customers would have to pay for fewer longer term renewable contracts. This is especially important

given the possibility of CCA load departure. Also, renewable technologies are continuing to evolve

and improve, and prices may continue to decline given the continued efficiencies bidders are receiving

through their projects. Shorter terms allow SCE to better take advantage of these technological

advances through quicker contract cycles. Finally, shorter-term contracts support the continued

operation of existing RPS resources that may not be able to support longer-term (20 year) extensions.

SCE made a similar request in its original 2015 RPS Procurement Plan. The

Commission denied this request in D.15-12-025 indicating that requiring projects to offer a 10-year

PPA length would unnecessarily constrain the market.35 SCE’s 2015 RPS Procurement Plan showed

that SCE had a need for new eligible renewable resources. In this 2016 RPS Procurement Plan,

primarily due to a reduced load forecast and SCE’s procurement from its 2015 RPS solicitation, SCE

has no need for new eligible renewable resources. In addition, there is a possibility that SCE’s need

could be further reduced by more CCA formation in its service area. Since D.15-12-025 was issued, 35 D.15-12-025, pp. 95-96.


22

the City of Lancaster formed its CCA and departed utility service. As a result, there is a greater value

now for SCE to enter into shorter-term contracts. It will not constrain the market for project

developers to offer 10-year contracts, as all developers will be competing on the same basis. In fact, it

will expand the number of bids that SCE might consider because there will be more 10-year contracts

for SCE to choose from.

2. Additional Policy/Procurement Issues

a) SCE Will Consider the Need for RPS Resources to Meet Local Reliability

Need in the Western LA Basin and Goleta Areas

On February 13, 2013, the Commission issued D.13-02-015, the LTPP Track 1

decision, which authorized SCE to procure between 1,400 and 1,800 MW of electrical capacity in the

Western Los Angeles sub-area of the Los Angeles basin local reliability area (“Western LA Basin”)

and 215 MW to 290 MW of electrical capacity in the Moorpark sub-area to meet local capacity

requirements (“LCR”) by 2021 due to the expected retirement of once-through cooling units. Pursuant

to D.13-02-015, SCE was required to procure minimum amounts of gas-fired generation, preferred

resources (including renewable resources), and energy storage in the Western LA Basin. There were

no technology-specific requirements in the Moorpark sub-area. SCE commenced its LCR Request for

Offers (“RFO”) on September 12, 2013. The LCR RFO was open to all technologies that could meet

SCE’s LCR needs, including renewable resources.

On March 13, 2014, the Commission issued D.14-03-004, the LTPP Track 4

decision, which authorized SCE to procure an additional 500 to 700 MW of capacity in the Western

LA Basin sub-area due to the retirement of the San Onofre Nuclear Generating Station. Combined,

D.13-02-015 and D.14-03-004 authorized SCE to procure between 1,900 and 2,500 MW of capacity in

the Western LA Basin.

On November 21, 2014 and November 26, 2014, respectively, SCE filed

applications, A.14-11-012 and A.14-11-016, respectively, requesting approval of the results of its


23

LCR RFOs for the Western LA Basin and the Moorpark, Goleta area. D.15-11-041 approved the

results of the LCR RFO for the Western LA Basin and found no need for further procurement.

However, D.16-05-053, the decision denying the applications for rehearing, modified D.15-11-041 to

require SCE to meet the preferred resource minimum procurement authorization established in

D.14-03-004. As a result, SCE is required to procure an additional 169.4 MW of preferred resources

in the Western LA Basin, which SCE can procure through Commission authorized procurement

mechanisms. Consistent with D.16-05-053, SCE’s 2016 RPS Procurement Protocol solicits projects

in the Western LA Basin to participate in the 2016 RPS solicitation, if it is conducted. Additionally,

projects located in the Western LA Basin that are interconnected to SCE’s distribution system served

by the Johanna and Santiago substations may also meet SCE’s PRP goal.36

D.16-05-053 approved the contracts submitted for approval in the Moorpark

sub-area and found no further need for LCR procurement in that sub-area. But, the Commission left

the docket open to consider the need for the Ellwood generation and linked storage contract to

maintain reliability in in the Goleta area.37 That said, there remains a need for new resources to

support operation of the electric system in the Goleta area in an emergency situation because of a lack

of either generation or transmission resources in the area.38 SCE submits that it should act to fill this

need as soon as possible. If SCE goes forward with a 2016 RPS solicitation after seeking permission

from the Commission and receiving appropriate authorization, SCE will solicit renewable resources in

the Goleta area to participate in this solicitation.

Because of the critical need for local reliability resources in the Western LA

Basin and the Goleta area, SCE will not require projects in those areas to have a Phase II

Interconnection Study and will seek to contract with such resources starting before January 1, 2021.

To the extent SCE receives proposals for projects in the Western LA Basin and

Goleta area that are not selected in SCE’s RPS solicitation based on LCBF selection criteria, SCE will 36 See D.14-03-004. More information on the PRP is available at http://on.sce.com/preferredresources. 37 D.16-05-053, pp. 26-32. 38 Id. at pp. 28-29.


24

consider the value of these proposals using the LCR selection process and criteria. Only projects that

provide RA benefits and are able to obtain a CAISO Net Qualifying Capacity assignment will be

considered for purposes of meeting SCE’s LCR in the Western LA Basin and Goleta area. SCE may,

in its sole discretion, decide to enter into bilateral contracts with some of these projects based on their

LCR value. If SCE does enter into any such contracts, it will submit them for Commission approval

through a separate application or advice letter, as appropriate.

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, SCE has more renewable energy to

meet its goals 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 renewable procurement need.”33

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 is not always 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.34

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

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

combination of long term contracts and short term products, reducing the overall costs for their 33 Final 2016 RPS Plan, dated January 23, 2017, p. 14. 34 As explained in more detail in section XI and confidential Appendix F.2.


25

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.39 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 forecastforecasted probabilistic

risk--adjusted success rates.

IV.

POTENTIAL COMPLIANCE DELAYS

Five primary factors will 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. 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

39 The 2015 RPS solicitation contracts and contracts executed after the filing of SCE’s original 2015 RPS Plan

on August 4, 2015 are not included.


26

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.

While the upcoming West of Devers (“WOD”) upgrade project is necessary in order to provide

sufficient transmission capacity to meet the 33% by 2020 and 50% by 2030 RPS goals, curtailment

during WOD construction is expected. This expectation of curtailment was disclosed to renewable

resources seeking to interconnect to WOD-impacted areas before interconnecting them to the system.

However, many of these resources elected to interconnect prior to the completion of the WOD

upgrade. Delays in the completion of the WOD upgrade project would increase the amount of

curtailment as more resources are added. SCE is evaluating different construction sequence

alternatives to minimize the curtailment of renewables. The completion of the WOD project will

provide additional transmission capacity that could be utilized to accommodate future generation to

meet the 50% RPS goal. 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 and possible exacerbation of

the problems discussed above. .

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


27

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

(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. While these resources have

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

forecasting SCE’s renewable procurement position and need more complex. Wind generation 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 result 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.


28

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.”4035 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 some 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

transmission projects included in the CAISO’s 2015-2016-2017 draft Transmission Plan that SCE is

pursuing thatwhich will contribute to supporting the State’s RPS goals. These projects include the

Tehachapi Renewable Transmission Project, WOD, Delaney – Colorado River 500 kV line,

Devers-Mirage 230 kV line, Lugo – Eldorado 500 kV Line reroute, Lugo-Eldorado series cap and

terminal equipment upgrade, the Sycamore – Penasquitos 230 kV lineAlberhill 500 kV Method of

4035 CAISO 2015-2016

Transmission Plan, at p. 6.


29

Services project, the Mesa 500 kV Substation Loop-In, and the Lugo-Mohave series capacitors

project.4136

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 renewable projects

seeking interconnection to the CAISO controlled grid representing more than 20,000 MW of

capacity.4237

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, 41 Id.36 CAISO Draft 2016-2017 Transmission Plan, at p. 276 314. CAISO’s 2015-draft 2016-2017

Transmission Plan is available at: https://www.caiso.com/Documents/Board-Approved2015-Draft2016-2017TransmissionPlan.pdf.

4237 See https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueue.pdf.


30

and contract terminations. For example, 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). 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.To proactively address developer

performance issues, SCE continues to reach out to and communicate with project developers on a

regular basis, discuss options and the status of project development, and provide guidance and

direction as appropriate. In response to lessons learned in previous solicitations, SCE has also made

several modifications to its solicitation materials. The two most relevant updates to solicitation

requirements were implemented in the 2014 RPS solicitation in the form of a Phase II Interconnection

Study requirement and the Commission-mandated “application deemed complete” requirement with

respect to project permitting. These two requirements have significantly contributed to greater

viability in the pool of projects bid into the solicitations. In particular, projectsThis 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, which in most cases has already identified

and resolved potential fatal flaws in project location, technology, or environmental factors have been

identified and resolved.

In any 2016 RPS solicitation, SCE will implement an exception to the requirement of a Phase

II Interconnection Study for resources located in the Western LA Basin and the Goleta areas where

there is a local reliability need. For resources in these areas, a Phase I Interconnection Study will be

sufficient to encourage as many projects as possible to submit bids. SCE will carefully consider the

viability of projects in these areas that do not have a Phase II Interconnection Study.

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.


31

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.4 reflects these considerations.

VI.

QUANTITATIVE INFORMATION

A. RNS Calculations

As discussed in Section II.B, Appendices C.1 through C.4 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 and C.2 include physical RNS

calculations and Appendices C.3 and C.4 include optimized RNS calculations.

Appendices C.2 and C.4 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 20162017 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;


32

• 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 60% 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.4338

Appendices C.1 and C.3 provide SCE’s physical and optimized RNS through 2030 using the

Commission’s RNS Methodology. Appendices C.1 and C.3 use the same assumptions as in

Appendices C.2 and C.4 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 2016 through 2020 and the standardized

planning assumptions that were used in the 2014 LTPP for 2021 through 20242017

through 2021 and the CEC's 2016 CEDU Forecast for 2022-2027 with extension beyond

20242027 calculated based on the average annual rate of change between 2020-2024.44in

the CEDU Forecast for the period 2015-2027.39

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.

4338 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. 4439 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. In Appendices C.1 and C.3, SCE used its own bundled retail sales forecast for 2025 through 2030 because there is no LTPP forecast for those years.


33

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

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 of CCA formation, which could lead to a longer RPS

position 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.


34

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 20162017 and 2020. Wind 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.4540 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.

4540 See Southern California Edison Company’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), Application 07-06-031 (February 1, 2012).


35

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 in 2015.2016. 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 both 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.

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


36

sales, 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. 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.

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, 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

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


37

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 its response to question 6 above,

SCE does not target a minimum amount or range of RECs above the PQR for banking. SCE takes into

account project specific success rates to determine an adequate margin of procurementSection 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

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.


38

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 the procurement in SCE’s current renewables portfolio is from either contracts

executed prior to June 1, 2010 or contracts for Category 1 products. 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 350.350

and D.17-06-026. SCE does see opportunities to optimize its portfolio and achieve customer value

through procurementsales across the three portfolio content categories. However, givenGiven SCE’s

current position of no RPS need in the near term, SCE will only solicit Category 1 products if it

conducts a 2016 RPS solicitation after seeking permission from the Commission and receiving

appropriate authorization. Category 1 products will not only help ensure that SCE meets its RPS

goals, but also help SCE satisfy its need for energy to serve its customers in a cost effective manner.

Additionally, throughconduct solicitations for sales of vintage 2017 through 2020 Category 1 products

in 2017. Through soliciting near term REC sales, SCE may find opportunities to create value for its


39

customers. SCE believes that by providing flexibility in its procurement strategy, SCE can minimize

costs to 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 60%

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.”4641 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

4641 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).


40

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 does not proposeproposes to hold a 20162017 RPS solicitation, only for sales of vintage

2017 through 2020 renewable energy for Category 1 RECs. SCE will seek permission from the

Commission to procure any amounts, other than amounts separately mandated by the Commission

(i.e. Feed-In Tariff and BioRAM), during the time period covered by the 2016 solicitation cycle.) If

SCE launches a 2016 RPS solicitation after seeking and receiving permission from the Commission to

do so, SCE will use the proposed 20162017 Procurement Protocol, included here as Appendix F.1.I.1,

for these sales and for future RPS solicitations beyond 2017. The Procurement Protocol includes,

among other things:

• SCE’s requirements for initial delivery dates and preferred contract term lengths;

• Deliverability characteristics and locational preferences;

• SCE’s preference for LCR and PRP 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;


41

• A schedule of key dates related to the 2016 RPS solicitation; and

• SCE’s 20162017 Pro Forma Renewable Power Purchase Agreement (“Pro Forma”),

attached as Appendix G.1; and

• 2016 Pro Forma Master Renewable Energy Credit Purchase Agreement (“2016 REC

Purchase Agreement”), which will be supplied with supplementary materials later. 2017

REC Sales Confirmation (“2017 REC Sales Agreement”).

A discussion of the important changes in the proposed solicitation documents from SCE’s

2016 solicitation documents from SCE’s 2015 solicitation documents is included in Section XV.

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

costbenefit 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 H.1 (the “LCBF Methodology”) describes this process, including capacity

valuation and the renewable integration cost adder, among other factors.

In accordance with the ACR, SCE is also consideringconsiders 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 Environmental Justice communities through

California’s Environmental Protection Agency’s CalEnviroScreen 2.0.3.0.


42

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 its 2016 RPS solicitation if approved after seeking permission from the

Commissionfuture 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.

X.

ECONOMIC CURTAILMENT, FREQUENCY, COSTS AND FORECASTING

Although SCE has observed very few instances of negative pricing in the day-ahead

market,4742 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.

4742 ~ 0.05% of hours in sampled nodes in the day-ahead market – the vast majority of which occur at

generally congested interties such as Palo Verde.


43

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 deliveries in excess of their

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 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 day-ahead and in real-time,

even if SCE ultimately pays the contract price for curtailed energy.

If SCE conducts a 2016 RPS solicitation after seeking permission from the Commission and

receiving appropriate authorization, SCE willIn 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


44

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.

CALIFORNIA TREE MORTALITY EMERGENCY PROCLAMATION

AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS

The ACR requested that SCE address three fundamental issues regarding the Proclamation.

SCE’s discussion of each issue is below:

A. Justification of SCE’s Request for Pre-Approval of 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 mechanism whereby these transactions are

pre-approved by the Commission. This proposal would improve upon current Commission processes

that make renewable resource procurement more difficult, burdensome, and time consuming than

non-renewable resources. If the Commission does not agree that SCE’s customers and the market, in

general, will benefit from pre-approved transactions, SCE requests a Tier 1 Advice Letter approval

process for its REC sales consistent with D.14-11-042.

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

Foreseeable Future

The IOU’s are well positioned to meet the Compliance Period (“CP”) 3 2020 33% RPS

target with existing projects and projects under development (risk-adjusted).43 PG&E forecasts it will

not need incremental physical RPS need until 2026,44 and SDG&E forecasts 45% renewable energy by

43 2016 Q4 CPUC RPS Report to Legislature. 44 2016 PG&E RPS Plan.


45

2020.45 Because of this excess REC volume, neither SCE, PG&E nor SDG&E held 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.46

The Commission’s 2016 Biennial RPS program update47 showed that most of the

CCAs and ESPs are significantly below their 2020 33% RPS requirements. Most of these smaller RPS

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.48 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

45 2016 SDG&E RPS Plan. 46 See, PG&E’s Advice Letter No. 5095-E. 47 http://www.cpuc.ca.gov/RPS_Reports_Docs p. 6, Table 1. 48 CAL. PUB. UTIL. CODE § 399.16(c).


46

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,49 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 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 (SB350) 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 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 RPS energy,50 and some ESPs and/or CCAs may need

49 D.17-06-026. 50 Section XI.A.1 above.


47

RECs to meet compliance requirements in the near future.51 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.

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

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

51 Id.


48

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.

c) REC Sales Stabilize Rates By Realizing Near Term Value

SCE has a bank until year 203052 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 its

customers. SCE is significantly long on its compliance position in the near term. Then, the bank gets

shorter. In year 2030,53 SCE has no need for new RPS resources with the use of bank, but is not as

significantly long on RPS resources. If SCE can generate some revenues through near term REC

sales, it will help smooth out SCE’s RPS compliance positions over the years. In turn, these REC sales

would smooth out the rate impacts over 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.

52 Section II.B. 53 Id.


49

d) 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

Senate Bill 35054 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 - .25% of 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. 55 Any retail seller

making such an election must, however, meet 65% long-term contracting requirement.56. Short-term

contracts would facilitate the following types of projects/products to count toward RPS targets:

• 7 year renewable qualifying facility must-take contracts

• 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.

54 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416 55 Id. at Ordering Paragraphs 15-24, at pp. 54-56. 56 Id. at Conclusion of Law 6, at p. 42.


50

B. SCE’s Preferred and Alternate Proposals

1. Preferred/Pre-Approved Approach

a) General Description of Pre-approval Mechanism

Similar to the pre-approval mechanism in the IOUs’ Bundled Procurement

Plans,57 SCE recommends a pre-approval for a limited transaction sale volume. SCE has included the

following key elements in its plan: a REC Sales PPA, details of proposed transaction methods,58 and a

detailed discussion of terms, volume limits, and pricing floor as a part of the REC sales framework.

Table XI-1 summarizes the key elements of SCE’s REC sales framework:

57 Public Utilities Code Section 454.5 (c) and (d) allows for a utilities’ procurement plan to eliminate the need

for after-the-fact reasonableness through review of upfront achievable standards and criteria coupled with verification of appropriate contract administration through the Quarterly Compliance Reports.

58 Consistent with D.14-11-042.


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Table XI-1 SCE’s REC Sales Framework

Parameter Proposal

Transaction mediums59 Exchanges, RFO Process, Electronic Solicitations, Brokers, Bilateral (strong showing60)

Terms < 5 years

Sales Volume Limits61 Based on load/gen forecast and uncertainty around it, changing RPS legislation and anticipated pricing

Pricing62 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) filing

b) Reasons That Pre-Approval of REC Sales Transactions Is the Preferred

Approach

Appendix F.2, in Section I.A, discusses confidential data suggesting that given

the supply/demand imbalance of RECs in California, a faster approval process is absolutely necessary

to avoid market inefficiencies.

Additionally, on June 16, 2017, PG&E submitted Advice 5095-E, seeking

approval of five power purchase and sale agreements for a total of ~2.1 TWh. These sales were

between PG&E and five counterparties, with significant amount of sales to ESPs and CCAs (Direct

Energy, 3 Phase Renewables Inc., Peninsula Clean Energy Authority, EDF and Exelon [which is a

59 Explained in more detail in section XI.E below. 60 A strong showing could include competing price offers, broker or online quotes, published indices,

comparisons to recent solicitations. 61 Sales Volume Limits methodology is explained in detail in Appendix F.2, section II. 62 Price Floor methodology is explained in detail in Appendix F.2, section III.


52

parent company to ESP Constellation NewEnergy Inc.]).63 These sales substantiate that there will be a

significant imbalance of RECs in California for Compliance Period 3.

REC sales transactions are fairly simple and REC products are easy to

understand. Given the short term length of these transactions, the valuation and selection process

should be straightforward. If bids are of similar terms, SCE will simply rank the bids by REC

premium for shortlisting. Finally, pre-approval will significantly increase REC market efficiency:

• It will provide a greater opportunity to maximize value for SCE’s customers

as there is more certainty for transactions

• It will allow SCE to transact quickly with buyers due to changing market

circumstances

• It will allow buyers to timely meet compliance obligations especially when

a transaction takes place towards the end of a compliance period.64 For

example, if parties have an immediate need for RECs, the parties would

have limited time to procure the contracted-for RECs. Having pre-approval

allows the parties to begin delivering RECs as soon as possible which is

especially important at the end of a year and at the end of a compliance

period. Having to wait for approval may make it very difficult or

impossible to enter into contracts at the end of a year for a bundled product

(energy and RECs) from that same year.

2. Alternate/Tier 1 Advice Letter Approach

SCE proposes a Tier 1 Advice Letter Approach for approval of REC sales as an

alternative to pre-approval. SCE’s proposed alternate approach is similar to its preferred approach

described above. The alternate approach includes terms, volume limits, and pricing floor as part of the

preferred approach for the REC sales framework as summarized in Table XI-1 above. The difference 63 Advice 5095-E, Section 1.4(b), p. 5. 64 Section XI.D, Appendix F.2.


53

between the preferred approach and the alternate approach is that instead of having Commission

pre-approval of all REC sales transactions meeting the criteria, SCE will submit a Tier 1 Advice Letter

filing for each of its REC sales. A Tier 1 Advice Letter will include each 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). Also, 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.

C. SCE’s Proposed Limits on REC Sales

Appendix F.2, Section II describes and provides an example calculation of SCE’s proposed

volume limits.

D. Acceptable REC pricing

Appendix F.2, Section III sets out confidential upfront pricing standards 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. Provide a table listing existing RPS-eligible biomass contracts. The table should

include the contracts’ expiration date, contract capacity, facility name, location, and

contract price.Competitive Solicitations

Facility Name Location Contract Capacity

(MW)

Contract Price

($/MWh)48

Estimated

Expiration Date49


54

Chinese Station Jamestown 18.0 02/28/2022

Rio Bravo – Fresno Fresno 24.3 02/28/2022

Rio Bravo – Rocklin Lincoln 24.4 02/28/2022

Continued from the previous page 48 Some contracts may contain annual escalation factors. Prices shown in the table are levelized over the term

of the contract. 49 Contracts terminate 5 years after initial commercial operation. At the time that SCE prepared this response

none of the three BioRAM biomass facilities had begun initial commercial operation under a contract with SCE. For the purposes of this response, all BioRAM projects are based on an initial commercial operation date of 3/1/2017 but the actual commercial operation date is likely to be other than 3/1/2017.

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 see where the market is in terms of prices willing to be paid for RECs. SCE may also bid in to

solicitations held by third parties seeking RECs.

2. Describe the benefits that biomass contracts provide to your renewable

portfolio.Bilateral Transactions

The primary benefit that biomass contracts provide to SCE’s renewable portfolio is that they

help deliver RPS energy. Outside of the RPS benefit, biomass contracts do not offer other unique

benefits because biomass facilities are not typically dispatchable nor located in load centers. In fact,

biomass facilities in remote mountainous areas could create a problem if the plant output exceeds the

system capacity of small networks.


55

As SCE stated in its Petition for Modification of Decision 10-12-048, “the purpose of the

Proclamation is to protect the general public from life safety risks associated with wildfires, to prevent

watershed-wide environmental degradation, and to facilitate the removal of dead trees that threaten

power lines and other critical infrastructure.”50 Accordingly, these biomass facilities do not offer a

unique benefit to SCE’s customers but instead are being considered as one method to address a

state-wide emergency associated with tree mortality that could lead to wildfires, environmental

degradation, and impacted transportation infrastructure that could affect all California residents to

some degree and could affect mountainous communities directly. In addition, wildfires and falling

trees near electric transmission lines51 could affect electric system reliability that would also affect all

electric customers in California.

Biomass facilities provide energy, capacity, and RPS credits but provide no other benefits to

IOU electric customers that would justify paying a premium for this energy. However, as identified

above, biomass facilities offer benefits to all citizens of California. As a result, any solution to address

removal and disposal of HHZ material should fairly distribute above-market costs to all California

citizens. Allocating above-market costs solely to IOU bundled electric customers, including SCE’s

bundled service customers, is not an equitable cost allocation.

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 prior to a solicitation being launched. These and other

situations may lead to SCE selling RECs bilaterally rather than through a competitive process. Such

50 Rulemaking 08-08-009, Petition for Modification of Decision 10-12-048 filed jointly by Pacific Gas and

Electric Company and Southern California Edison Company, April 19, 2016, at p. 5. D. 16-12-006, dated December 6, 2016, at OP 2, p.14, denied this Petition for Modification and, at pp.14-15, OP 4, required the IOUs to file cost allocation applications seeking this relief. But, D.16-12-006, also, at OP 4 on pp.14-15, allowed the IOUs to file a motion for the Commission to accept A.16-11-005, filed on November14, 2016, as fulfilling this requirement and the IOUs did so on December 15, 2016.

51 SCE already maintains a vegetation management program that seeks to remove trees that threaten the electric transmission and distribution lines and also that could increase the risk of fire caused by contact with electric system equipment.


56

sales would be subject to a reasonableness showing including a showing that the price achieved

represents a reasonable market price.

3. When considering authorizing of additional Proclamation-related procurement, what

alternatives (e.g. contract extensions) to additional RAM auctions should be

considered? Describe the advantages and disadvantages for each alternative in

relation to addressing the Proclamation.Brokers

The most significant issues related to addressing the Proclamation is to assure that the above

market costs associated with addressing the Proclamation are shared fairly among all citizens of

California. In that regard, SCE offers two concepts to allow California to fairly address the

Proclamation.

First, the costs and benefits of any BioRAM solicitation should be shared ratably among all

electric service providers including municipal utilities, investor owned utilities, and other LSEs.

Equitably sharing all costs and benefits among all California electric consumers would fairly allocate

those costs and benefits that the IOUs are being required to provide as a benefit to all of California.52

The advantage would be that costs and benefits would be spread to all electric consumers in California

which could increase the pool of customers paying for these above-market costs. The disadvantage is

that this would expand the customer base to municipal utilities which is outside of the scope of the

Proclamation and outside of the jurisdiction of the Commission. This proposal could not be adopted

without further action by the Governor and/or the Legislature.

A second, and possibly more expedient solution would be for various federal, state, and local

governmental agencies to fund the cost of disposing of this HHZ material. If public agencies were

responsible for the cost of acquiring and disposing of HHZ material, then there may be no

above-market electricity costs associated with their disposal. Moreover, if the most efficient disposal

method is not through burning HHZ fuel, that method could be chosen. One method that may be

52 To completely share costs, the Commission should consider a minimum fixed customer charge that would

also recover costs from net energy metering customers.


57

available would be sale of the wood to third parties interested in using it. If public agencies decided

that burning the HHZ material is the best option, the cost would be paid through public funds. The

benefit of this proposal to the Proclamation is that it would allow public agencies to have complete

control of the process to identify HHZ materials to be harvested and the quantity of HHZ material that

is harvested. The disadvantage related to the Proclamation is that this approach relies on public funds

that may be difficult to acquire.

Another consideration for the Tree Mortality issue is that the Commission should carefully

consider the disconnect between the amount of HHZ material that is available to be harvested versus

the amount of HHZ material that can be reliably harvested in order to support continuous or near

continuous utilization of biomass facilities. The Commission should consider solicitation of seasonal

BioRAM contracts that would be in effect only during the months that reliable levels of HHZ material

can be available to the biomass facility. HHZ material availability is influenced by several factors

including snowpack, forest fires, distance from the HHZ material to the biomass facility, and so on.

Future BioRAM solicitations should consider these seasonal factors and not attempt to force a

baseload annual contract to a fuel source that is only available during certain seasons. Considering the

seasonal availability of HHZ material will significantly impact how the Commission addresses the

Proclamation. Finally, contracts to meet the needs of a Proclamation to address HHZ material removal

should not pay above-market costs once the emergency described in the Proclamation has ended. As a

result, special consideration should be made to adopt short-term contracts, adopt termination rights for

buyer or seller, or adopt market-based contract pricing in the event that HHZ material is not available

or if the tree mortality issue becomes a non-emergency.

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


58

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 in order for the transactions to be deemed reasonable prior to contract execution.65

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.

4. Exchanges

An exchange is a central marketplace with established rules and regulations where

buyers and sellers meet to trade standardized products at prices that are both visible and representative

(i.e. the price is known and available to any interested market participant and the posted price and

quantity are determinative of the final transaction costs). Exchanges differ from brokers in that

exchanges take title to the product being transacted, such that the exchange becomes the counterparty

for both the buyer and the seller. While no exchange-traded product currently exists for RECs, having

the standing authority to transact over an exchange would have two key benefits should such a product

develop. First, the identities of the counterparties are not revealed prior to transaction, thus providing

anonymity for those parties that might wish to remain anonymous. Second, because of an exchange’s

structure and margining rules, credit risk would be reduced substantially relative to transacting with a

65 See Appendix F.1 for SCE’s proposed list of pre-approved brokers.


59

counterparty in the Over-The-Counter markets. Given that exchanges provide unique benefits in

terms of price transparency, anonymity, and credit, it would likely become an attractive transaction

mechanism should an exchange-traded product develop.

Currently, SCE is not aware of an exchange that lists California RECs as a product. To

the extent an exchange develops the capability to list California RECs and if SCE wants to utilize

exchanges in the future, it will obtain prior Energy Division approval by filing a Tier 2 Advice Letter.

a) Exchange Cleared Transactions

An exchange may also permit participants to “clear” certain conforming

transactions that were not executed through the exchange initially. In this process, the parties to an

Over-The-Counter transaction agree to submit the transaction to the exchange. For a fee, the exchange

(e.g., New York Mercantile Exchange (“NYMEX”) via NYMEX ClearPort or Intercontinental

Exchange (“ICE”) via ICE Clear) agrees to take title to the transaction and assumes responsibility for

protecting both the buyer and seller from financial loss.

To access both NYMEX and ICE, SCE and other market participants use

intermediaries called clearing firms. A clearing firm is a company approved to clear trades through the

exchange, and is responsible for the financial commitments of its customers that clear through the

firm. Clearing firms charge a fee for performing the clearing function. These fees are small relative to

the nominal value of the transactions. If given the authority to utilize exchanges to transact in RECs,

SCE will select a clearing firm on a transaction-by-transaction basis from the list that is incorporated

into Appendix F.1.

F. Proposed Timeline for REC Sales

SCE’s Procurement Protocol in Appendix I.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 2017 RPS Plan.


60

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.

XIII.

COST QUANTIFICATION

The spreadsheet attached as Appendix D includes actual expenditures per year for

RPS-eligible generation for every year from 2003 through 2015,2016, as well as actual RPS-eligible

generation for every year from 2003 through 2015.2016. Appendix D also includes a forecast of

future expenditures SCE may incur every year from 20162017 through 2030, as well as a forecast of

expected generation for every year from 20162017 through 2030.

XIV.

IMPERIAL VALLEY

In SCE’s last RPS solicitation (the 2015 RPS solicitation), SCE received 279 proposals.

XV.

IMPORTANT CHANGES FROM 20152016 RPS PLAN

SCE has made significant changes to the Written Plan to recognize that SCE, at present, has no

need for eligible renewable resources. As a result, SCE does not propose to hold a 20162017 RPS

solicitation. Instead, SCE will seekseeks permission from the Commission to procure any amounts,

other than amounts separately mandated by the Commission (i.e. Feed-In Tariff and BioRAM), during

the time period covered by the 2016 solicitation cycle.) Any 2016 RPS solicitation held by SCE after

seeking and receiving permission from the Commission may include a request for offers to purchase

from SCE RECs of 2016-2020 vintage and will include one of the two required Community


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Renewables solicitations. SCE’s Written Plan also includes new materials to comply with the ACR

concerning: (1) the Proclamation regarding Tree Mortality, (2) Workforce Development, and (3)

Disadvantaged Communitiesto sell SCE RECs of 2017-2020 vintage, as discussed in Section XI

above.

SCE’s 20162017 RPS Plan includes changes to: (1) SCE’s 2016 Procurement Protocol; (2)

SCE’s 2016 Pro Forma; (3) SCE’s 2016 Pro Forma REC Sales Agreement; and (34) SCE’s LCBF

Methodology. Those changes are summarized below. SCE has included redlines of its 20162017

Procurement Protocol, 20162017 Pro Forma, 2017 Pro Forma REC Sales Agreement, and LCBF

Methodology against the versions of those documents included in SCE’s 20152016 RPS Plan as

Appendices FI.2, G.2, J.2 and IH.2, respectively. SCE has made relatively few changes to these

documents from the 20152016 documents. The most significant changes to the other 2016 documents

are summarized below.

A. Important Changes in 20162017 Procurement Protocol

1. Considering Proposals only for Category 1 Products

In the 2015 RPS solicitation, SCE solicited long-term Category 1, Category 2, and

Category 3 products. As provided in SCE’s 2016 Procurement Protocol, SCE will only consider

proposals for Category 1 products from both new and existing generation facilities if it launches a

2016 RPS solicitation.

SCE has made this change given its relatively long RPS position in the near term. SCE

believes that projects providing Category 1 product are best suited to deliver energy in the long-term

and be flexible on start dates and term length.

2. Commercial On-Line Date Beginning on January 1, 2021 or Later

SCE does not propose to hold a 2016 RPS solicitation. SCE will seek permission from

the Commission to procure any amounts, other than amounts separately mandated by the Commission

(i.e. Feed-In Tariff and BioRAM), during the time period covered by the 2016 solicitation cycle.) If


62

SCE conducts a 2016 RPS solicitation after seeking and receiving permission from the Commission,

SCE wants to focus the efforts of both SCE and sellers on proposals that are likely to be most valuable

to customers. To this end, SCE intends to solicit Category 1 products with delivery terms

commencing on or after January 1, 2021, except in the Western LA Basin and Goleta area. SCE has no

need for near-term eligible renewable resources at this time. Therefore, if SCE conducts a 2016 RPS

solicitation after seeking and receiving permission from the Commission, SCE will require sellers to

offer projects with a start date of January 1, 2021 or later, unless they are located in the Western LA

Basin or Goleta area where there is currently a specific local reliability need. The proposed 2021 start

date helps to align deliveries with SCE’s need, while establishing an online date that is not so far into

the future as to make it unrealistic for sellers to bid projects that are near “shovel ready.”

3. Offering 10 Year Term Lengths or Less

As discussed above, SCE does not propose to hold a 2016 RPS solicitation. SCE will

seek permission from the Commission to procure any amounts, other than amounts separately

mandated by the Commission (i.e. Feed-In Tariff and BioRAM), during the time period covered by the

2016 solicitation cycle.) If SCE launches a 2016 RPS solicitation after seeking and receiving

permission from the Commission, SCE will allow sellers to offer terms of any length. However, SCE

will also require that sellers propose at least one offer with a term length of 10 years or less for each

project. With the changing RPS rules that may result with the implementation of SB 350 along with

the uncertainties around future load growth, distributed energy resources, departing load, electric

vehicles and industry technology advances, it is prudent to solicit contracts with shorter term lengths.

4. Solicitation Schedule is To Be Determined

Typically, SCE’s RPS Procurement Protocol includes a proposed schedule for the RPS

solicitation. However, in 2016, SCE does not propose to hold a 2016 RPS solicitation. So, the 2016

Procurement Protocol, at Section 3.01, shows dates only “to be determined.” If SCE seeks permission


63

from the Commission to hold a 2016 RPS solicitation, it will provide a revised Section 3.01 to the

2016 RPS Procurement Protocol with dates filled in with its request.

1. 5. Only REC Sales Will Be Part of this Solicitation

As discussed above, SCE plans to solicit offers for SCE to sell RECs of

2016-2017-2020 vintage as part of any 20162017 RPS solicitation that it may hold. The 20162017

RPS Procurement Protocol, in Article 1, includes solicitation of proposals to sell RECs of

2016-2017-2020 vintage which may be part of any 20162017 RPS solicitation.

6. Workforce Development

The ACR, at p. 14, stated that “the 2016 RPS Procurement Plans shall include a

description of a proposed approach for assessing and differentiating the ability of different bids to

contribute to employment growth.” The 2016 RPS Procurement Protocol, at Section 3.2(g)(i),

includes a requirement that each bid address its ability to contribute to employment growth. As

discussed in Section XV.C.1 below and in Appendix H.1, SCE’s LCBF methodology will assess this

information as one of the qualitative factors considered for each bid.

7. Disadvantaged Communities

The ACR, at p. 15, quoted from Public Utilities Code Section 399.13(a)(7) requiring

the utilities to “give preference to renewable energy projects that provide environmental and economic

benefits to communities afflicted with poverty or high unemployment, or that suffer from high

emission levels of toxic air contaminants, criteria air pollutants, and greenhouse gases.” The ACR

then stated that “the 2016 RPS Procurement Plans shall include a description of their methodology for

preferring projects that provide the benefits described in 399.13(a)(7).” The 2016 RPS Procurement

Protocol, at Section 3.2(g)(i), includes a requirement that each bid address its impact, if any, on such

disadvantaged communities, identified in the Environmental Justice communities through California’s

Environmental Protection Agency’s CalEnviroScreen 2.0. As discussed in Section XV.C.2 below and


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in Appendix H.1, SCE’s LCBF methodology will assess this information as one of the qualitative

factors considered for each bid.

B. Important Changes in 20162017 Pro Forma and REC Sales Agreement

The changes to the Pro Forma were eithermostly minor or clean-up items.53, with important

changes summarized below.66 A redline of the 20162017 Pro Forma showing all of the changes from

the 20152016 RPS Pro Forma is attached as Appendix FI.2. Additionally, changes related specifically

to the Standard Contract Option are mentioned in Section XVII.B. If SCE goes forward with a 2016

RPS solicitation it will include aFor SCE’s Community Renewables solicitation. (“CR-RAM”) SCE

will use the Community Renewables Rider (“CR Rider”) to the 20152017 Standard Contract Option,

which SCE submitted to the Commission via Advice Letter 3422-E for its Community Renewables

PPAs.

SCE will provide its 2016 Pro Forma Master Renewable Energy Credit Purchase Agreement

with supplementary materials later in the 2016 RPS review process.

Important changes in 2017 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).

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).

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).

5366 SCE also made changes to the Green Rate provisions that mirror the CR-Rider.


65

Other non-substantive changes made to the 2017 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 2017 Pro Forma.

The changes to the 2017 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.

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”).

C. Important Changes in 20162017 Least Cost, Best Fit Methodology

1. Workforce DevelopmentCapacity benefit for Solar and Wind resources

SCE will review information submitted by the bidders describing the impact of their

project on employment growth as one of the qualitative factors that it considers in its evaluation of

each biduse 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.17-06-02767 to calculate Resource Adequacy benefit, as further discussed in Section II.A.1(f) of

Appendix H.11.

67 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.


66

2. Disadvantaged Communities

SCE will review information submitted by the bidders describing the impact of their

project on disadvantaged communities as one of the qualitative factors that it considers in its

evaluation of each bid, as further discussed in Section II.A.1(f) of Appendix H.1.

3. Selection Criteria for Community Renewables

If SCE holds a 2016 RPS solicitation after seeking and receiving permission from the

Commission, one of its two required Community Renewables solicitations will be part of the 2016

RPS solicitation. As a result, SCE added to its LCBF Methodology in Section III.A of Appendix H.1

a discussion of the bid evaluation and selection process for Community Renewables.

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 20162017 Pro Forma provides that the seller must

operate the generating facility in accordance with “Prudent Electrical Practices.”5468 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

5468 See 20162017 Pro Forma (attached as Appendix G.1) at Section 3.12(a).


67

reasonably have been expected to accomplish the desired result consistent with good business

practices, reliability and safety. . . .”5569

Consistent with SCE’s focus on safety, SCE’s 20162017 Pro Forma also provides that, prior to

commencement of any construction activities on the project site, the seller must provide to SCE a

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.5670

SCE also has a safety section in its 20162017 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 20162017 Pro Forma.5771

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.5872 The Commission also authorized the IOUs to use an optional

streamlined RAM procurement tool in future RPS solicitations.5973 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.6074

As in the 2015Although SCE will not have a 2017 RPS solicitation, SCE plans to include a

“the Standard Contract Option” using the RAM PPA is used as part of the Community Renewables

procurement tool in any 2016 RPS solicitation that it may conduct. Consistent with the Commission’s

intent to provide the IOUs with flexibility to optimize their portfolios based on their procurement

5569 See idId. at Exhibit A. 5670 See idId. at Section 3.11(e). 5771 See 20162017 Procurement Protocol (attached as Appendix FI.1) at Section 9.03. 5872 See D.14-11-042 at pp. 91-92, pp. 102-104. 5973 See idId. at pp. 91-92. 6074 See idId. at p. 92.


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needs while providing a streamlined procurement tool,6175 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. Sellers will have the option to participate in the

Standard Contract Option by checking a box in the RPS proposal form. The Standard Contract Option

will only be available to projects with a first point of interconnection to the CAISO, and not to

dynamically scheduled projects.6276

Subject to SCE’s selection of the proposal and agreement that a standard contract is

appropriate for the proposal, sellers will be offered a standard contract in the form of the 2016 Pro

Forma with no negotiations. 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.”6377 In a 2016 RPS solicitation, SCE will use the

Standard Contract Option to satisfy its RPS and energy needs. SCE will alsoSCE will use the Standard

Contract Option for Community Renewables procurement needs as discussed in Section XVIII.

6175 See idId. 6276 SCE’s 20162017 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 20162017 Pro Forma will be required for dynamically scheduled projects.

6377 D.14-11-042 at p. 92.


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Community Renewables has a Rider that modifies the Standard Contract Option, which is detailed in

Section XVIII. 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.6478 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 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 20162017 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 20162017 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 2016,2017, SCE made changes to the SCE 2017 Pro Forma that are applicable to the

Standard Contract Option to: (i) the Commercial Operation Date, and (ii) extensions to the

6478 See idId. at p. 93.


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Commercial Operation Date. These changes were made to correct an error in the previously approved

2015 Pro Forma Standard Contract Option provisions, which incorrectly stated that the Commercial

Operation Date must be no later than 24 months from CPUC Approval rather than 36 months from

CPUC Approval. Please see Section XV(B).

C. Project Size Restrictions

The Commission eliminated the RAM project size restrictions for the streamlined RAM

procurement tool and authorized the IOUs to establish project size requirements based on their

specific procurement needs at the time of the solicitation.65 SCE does not propose to include any

project size restrictions for the Standard Contract Option in a 2016 RPS solicitation. SCE will allow

sellers to propose projects of any size, but not less than the minimum of 500 kilowatts for the 2016

solicitation.

While SCE will allow sellers with projects of any size to select the Standard Contract Option,

SCE must also agree that the Standard Contract Option is appropriate for the seller’s proposed project.

For proposals that state a preference for a standard contract, SCE reserves the right to discuss with a

seller the need to negotiate certain terms and conditions when appropriate. Although project size is not

the only example of a parameter that might trigger such a situation, very large projects do often carry

more complicated issues that warrant careful construction of a negotiated PPA. The Standard Contract

Option will only be used if both SCE and the seller agree that it is appropriate for the specific project.

D. Project Categories

The Commission retained the RAM product category requirement (peaking, non-peaking,

baseload), but did not mandate that the IOUs procure a specific amount from each product category.66

While SCE does not intend to set specific targets for each product category, SCE will consider all the

product categories and they will be indicators of SCE’s desire to balance the resources in its diverse 65 See id. at p. 94. 66 See D.14-11-042 at p. 95.


71

renewables portfolio. SCE intends to conduct its selection process for both the negotiated track and

the Standard Contract Option using LCBF criteria.

E. Restriction on Subdivided Projects

In D.14-11-042, the Commission eliminated the prohibition against subdivided projects

participating in RAM, and required the IOUs to define the terms they will use to either include or

exclude subdivided projects.67 SCE sees no need to impose a restriction on subdivided projects in its

Standard Contract Option for the 2016 RPS solicitation, particularly given that it is not imposing a size

restriction.

F. Locational Restrictions

The Commission removed the requirement that RAM projects be located in the service

territories of the IOUs, and permitted the IOUs to procure anywhere within the CAISO control area,

including dynamically scheduled resources, to increase the available pool of resources.68 SCE’s

Standard Contract Option for the 2016 RPS solicitation will be applicable to projects with a first point

of interconnection to the CAISO control area, but will not include dynamically scheduled resources.

Dynamically scheduled resources generally require some changes to SCE’s RPS pro forma PPA.

G. Valuation and Selection

The Commission found it reasonable to require the IOUs to use the same valuation

methodologies used in their RPS solicitations for the RAM procurement tool.69 SCE will use its

LCBF evaluation process for valuation and selection of Standard Contract Option projects. In order to

be selected, the value of a Standard Contract Option project must be within the range established by

the SCE’s 2016 RPS solicitation shortlist based on SCE’s LCBF methodology as described in

67 See id. at p. 96. 68 See id. at pp. 97-98. 69 See D.14-11-042 at pp. 98-99.


72

Appendix H.1. This approach results in all projects being valued utilizing the same methodology, and

lends fairness to the process while increasing competition among sellers.

H. Interconnection Studies

In D.14-11-042, the Commission required that projects participating in the RAM procurement

tool process have a Phase II Interconnection Study (or the equivalent).70 Consistent with that decision,

SCE will apply the same Phase II Interconnection Study requirement to Standard Contract Option and

non-Standard Contract Option projects in its 2016 RPS solicitation, except for projects located in the

Western LA Basin and Goleta area where there is local reliability need. In those areas, a Phase I

Interconnection Study will be required.

I. Commercial Operation Deadline

For new projects, the Commission imposed a commercial operation deadline requirement for

the RAM procurement tool of 36 months with a six month extension for regulatory delays.71 The

Commission also exempted existing projects from going through the RAM viability screens, which

include: (1) site control; (2) development experience; (3) commercial technology; and (4)

interconnection application.72 SCE will include the 36 month commercial operation deadline with a

six month extension for regulatory delays in its Standard Contract Option for new projects. Moreover,

SCE does not intend to apply any separate RAM viability screens to Standard Contract Option

projects. However, SCE does believe it is appropriate to apply the same eligibility requirements that

apply to all other existing projects participating in the 2016 RPS solicitation to Standard Contract

Option projects. In particular, existing projects with interconnection agreements that terminate before

the start of the new RPS PPA should be required to demonstrate that they will have a new

interconnection agreement in place at the start of the new RPS PPA. Those existing projects with

70 Id. at p. 100. 71 See id. at p. 101. 72 See id.


73

interconnection agreements that continue during the new RPS PPA should be required to demonstrate

that they are not making any modifications that would prevent them from delivering under their

existing interconnection agreements. Existing projects should not be permitted to circumvent

solicitation eligibility requirements by selecting the Standard Contract Option.

J. Commission Approval Process

In D.14-11-042, the Commission permitted the IOUs to seek approval of RAM procurement

tool projects through the Tier 2 advice letter process or to request approval of another approval process

in their RPS Procurement Plans.73 As noted above, SCE proposes to seek approval of Standard

Contract Option projects through the Tier 2 advice letter process.

XVIII.

GREEN TARIFF SHARED RENEWABLES PROGRAM

On September 28, 2013, Governor Brown signed SB 43 into law.7479 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.

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.7580 SB 43 also provides

that 100 MW of the statewide limitation for the GTSR program shall be reserved for facilities that are

73 See id. 7479 SB 43 was codified in California Public Utilities Code Section 2831 et seq. 7580 See D.15-01-051 at Ordering Paragraph 7.


74

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” 7681

(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.7782

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.7883 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 in the 2016 RPS solicitation. This is because the Green Rate

program currently has a limited number 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

solicitations.7984 The Commission limited initial procurement to new solar facilities between 0.5 MW

and 3 MW,8085 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.8186 Additionally, now that the CAISO has resolved Distributed Energy Resource 7681 CAL. PUB. UTIL. CODE § 2833(d)(1). 7782 See D.15-01-051 at Ordering Paragraph 7 and D.15-01-051 at pp. 4-5. 7883 See idId. at pp. 3-4. 7984 See idId. Ordering Paragraph 1. 8085 See idId. at pp. 36-37, p. 39, Conclusion of Law 17. 8186 See D.16-05-006, Conclusions of Law 2 and 4.


75

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.87 CR projects

must be located within SCE’s service territory8288 and must satisfy the eligibility requirements

associated with the RAM procurement tool.8389

SCE has 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;8490 (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; 8591 (v) Advice 3432-E, which is the 20 Year Forecast of

GTSR bill credits and charges;8692 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 because

projects eligible for SCE’s CR-MAT program will also be eligible for SCE’s CR-RAM program. 8793

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;94 (ii) Advice 3496-E, 2017 annual

87 Id. at Ordering Paragraph 5. 8288 See D.15-01-051 at pp. 21-23, Conclusion of Law 14. 8389 See D.16-05-006 at p. 35, Conclusion of Law 4. 8490 Advice 3180-E was approved by the Energy Division, effective as of February 23, 2015. 8591 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution

E-4734. 8692 SCE submitted Advice 3432-E on July 11, 2016, which has not beenthat was approved as ofby the

dateEnergy Division, effective as of this filing.July 11, 2016. 93 SCE submitted Advice 3422-E that was approved by the Energy Division, effective as of June 15, 2016. 94 Advice 3461-E was approved by the Energy Division, effective as of September 25, 2016.


76

marketing, education and outreach plan and budget for the GTSR program;95 (iii) Advice 3525-E,

which is SCE’s GTSR program rate component 2017 Updates;96 (iv) Advice 3525-E-A, supplemental

filing to make modifications to Advice 3525-E;97 (v) Advice 3536-E, which implements the

California alternate rates for energy for the GTSR Program;98 (vi) Advice 3557-E, which updated the

CR-RAM Rider and RFO Instructions for CR-RAM Two;99 (vii) Advice 3614-E, which is the update

to the 20 Year Forecast of GTSR bill credits and charges;100 and (viii) Petition for Modification (PFM)

for D.15-01-051 to change the AmLaw 100101 securities opinion requirement.102

B. Community Renewables - Modifications to the 20162017 Procurement Protocol,

20162017 Pro Forma Standard Contract Option, and LCBF Methodology

SCE has 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 willplanned to

include a Community Renewables solicitation in any 2016 RPS solicitation that it holdswould hold

after seeking and receiving Commission permission. If SCE doesintended that if it did not go forward

with a 2016 RPS solicitation, it willwould move forward separately with a second Community

Renewables Solicitation., which SCE launched on April 7, 2017.

95 Advice 3496-E was approved by the Energy Division, effective as of November 27, 2016. 96 Advice 3525-E was approved by the Energy Division, effective as of January 1, 2017. 97 Advice 3525-E-A was approved by the Energy Division, effective as of January 1, 2017. 98 SCE submitted Advice 3536-E on December 21, 2016, which has not been approved as of the date of this

filing. 99 Advice 3557-E was approved by the Energy Division, effective as of March 12, 2017. 87100 SCE submitted Advice 34223614-E on June 15, 2016,5, 2017, which has not been approved as of the

date of this filing. 101 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United States

based on gross revenue. 102 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.


77

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

with each RFO.

1. 20162017 Procurement Protocol – CR Modifications

The 20162017 Procurement Protocol includes additional requirements applicable only

to CR and CR-EJ projects. CR and CR-EJ projects must agree to participate in the RAM tool via the

20162017 Pro Forma Standard Contract Option and CR Rider and Amendment, consistent with the

Commission’s direction in D.15-01-051 and D.16-05-006.88103 The Procurement Protocol also

contains specific instructions applicable to CR and CR-EJ projects only, including:

• 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,

at least 50% (by number of customers) and at least 1/6th of the demonstrated

88103 See D.15-01-051 at pp. 21-23, Conclusion of Law 7, and7; D.16-05-006 at Ordering Paragraph 1.


78

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. 20162017 Pro Forma, Standard Contract Option – CR Rider and Amendment

Modifications

In Advice Letter 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 “CurrentPrevious CR-RAM Rider”). The Current CR-RAM Rider

willPrevious 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 containscontained only minor changes from

the 2015 RPS Pro Forma Standard Offer Contract. The Current CR-RAM Rider includedPrevious

CR-RAM Rider has since been updated for CR-RAM One and CR-RAM Two (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.16-05-006.104 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 any the 2016 RPS solicitation that it may decide to hold. If

104 See Advice 3461-E and Advice 3557-E.


79

SCE does not decide to hold a 2016 RPS solicitation, it will hold a second CR solicitation.future

CR-RAM RFOs.

In D.15-01-051, the Commission adopted a securities opinion requirement to protect

customers from the cost of securities litigation related to any securities claim that could arise from a

CR project, which required a developer of a CR project to hire an AmLaw 100 firm to issue a securities

opinion addressed to the IOU offtaker.105 Pursuant to Ordering Paragraph 12 of D.16-05-006, Energy

Division and Legal Division held a workshop on October 13, 2016, in which parties could discuss and

develop a petition to modify the AmLaw 100 securities opinion requirement in D.15-01-051.

As a result of that workshop, the IOUs filed a PFM of D.15-01-051 and provided an

alternate objective standard that would make more law firms eligible to issue the securities opinion,

which would lower transactional costs to CR project developers. The IOUs sought to replace the

AmLaw 100 requirement with a three-part standard – the lawyer primarily responsible for issuing the

opinion has sufficient experience in securities law, the lawyer has an active license to practice law in

California, and the law firm issuing the opinion carries $10 million in professional liability insurance

coverage. On July 17, 2017, the Commission issued D.17-07-007 to modify D.15-01-051 to replace

the AmLaw 100 requirement with the three-part standard, and to direct the IOUs to update their

CR-RAM riders with the new securities opinion requirements.106

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

105 D.15-01-051 at pp. 71, 175, Conclusion of Law 29. 106 D.17-07-007. The IOUs will file Tier 1 advice letters within 15 days of the effective date of the decision to

reflect the new securities opinion requirements in the CR-RAM rider.


80

Limits”);89107 (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.90108

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”).91109 The GTSR

Report will beAnnual 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.110 SCE

filed its interim Annual GTSR 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”).111 The GTSR Annual Tracking Report

89107 See D.16-05-006 at Ordering Paragraph 3. 90108 Id. at Ordering Paragraph 2. 91109 See D.15-01-051 at pp. 32141-33, p. 41, pp. 68-69, and p. 143.42, Ordering Paragraph 10. 110 Id. at pp. 141-42. 111 See Advice 3218-E at p. 24.


81

was filed on September 1, 2016 and will includeincluded: (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.92112

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.

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 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

2024.93113

SCE conducted a 2014 Energy Storage RFO to help meet the target identified in D.13-10-040.

SCE signed three contracts from that RFO for a total of 16.3 MW. Additionally, SCE launched

anconsiders 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 in June 2016 and is currently evaluating the offers received.and other programs that may

92 See Advice 3218-E112 Id. at p. 24 and p.Attachment 32.D. 93113 See D.13-10-040 at ppp. 15 and p.15, 26.


82

incorporate energy storage facilities. Further details on SCE’s energy storage procurement can be

found in SCE’s Energy Storage Plan.114

SCE will allow proposals with energy storage in a 2016 RPS solicitation where the seller

controls the storage. Because of SCE’s limited RPS needs, SCE does not intend to solicit RPS projects

with energy storage where SCE controls the dispatch or charging of the storage units. Instead, SCE

will consider such energy storage offers in its 2016 Energy Storage solicitation.

114 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.


Document comparison by Workshare Compare on Thursday, July 20, 2017 9:56:22 AM Input:

Document 1 ID file://C:\Users\leisurgv\Desktop\02 Final 2016 RPS Plan (CONF).docx

Description 02 Final 2016 RPS Plan (CONF)

Document 2 ID file://C:\Users\leisurgv\Desktop\00 2017 RPS Plan (CONF).docx

Description 00 2017 RPS Plan (CONF) Rendering set Standard Legend:

Insertion Deletion Moved from Moved to Style change Format change Moved deletion Inserted cell Deleted cell Moved cell Split/Merged cell Padding cell Statistics:

Count Insertions 766Deletions 646Moved from 10Moved to 10Style change 0Format changed 0Total changes 1432


PUBLIC APPENDIX B

Project Development Status Update

Asof

June

30,201

7

ProjectS

tatus

ProjectID

ProjectN

ame

ContractStatus

Site

ControlStatus

Perm

itType

Perm

itStatus

Expe

cted

orAc

tual

perm

ittingcompletion

date

Tran

smission

secured?

Fina

ncing

secured?

Equipm

ent

secured?

InDe

velopm

ent

5748

LancasterW

ADB,

LLC

NoAp

provalNeede

dCU

PCo

mplete

4/21

/201

7Yes

InDe

velopm

ent

5762

CentralA

ntelop

eDryRa

nchB,

LLC

NoAp

provalNeede

dCU

PCo

mplete

6/16

/201

4Yes

InDe

velopm

ent

5816

Pano

cheVa

lleySolar,LLC

Approved

CUP

Complete

6/14

/201

6InDe

velopm

ent

5251

Mileston

eWildom

ar,LLC

NoAp

provalNeede

dCU

PYes

InDe

velopm

ent

5414

NEENAC

HSO

LAR

NoAp

provalNeede

dCU

PYes

InDe

velopm

ent

5261

Windh

ubSolarA

SolarP

roject

Approved

CUP,Co

nstructio

n&Bu

ilding

InDe

velopm

ent

5263

American

KingsS

olar,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5814

North

Rosamon

dSolar,LLC

Pend

ingAp

proval

CUP,Co

nstructio

n&Bu

ilding

Complete

2ndqtr2

017

Yes

InDe

velopm

ent

5882

SunStream

s,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

InDe

velopm

ent

5883

Willow

Sprin

gsSolar,LLC

Pend

ingAp

proval

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5884

Sunshine

ValleySolar,LLC

Pend

ingAp

proval

CUP,Co

nstructio

n&Bu

ilding

InDe

velopm

ent

5226

CalienteSprin

gs,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

InDe

velopm

ent

5819

LuzS

olar

Partne

rsLtd,V(SEG

SV)

(f/k/a50

19)

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5833

Jacumba

Solar,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Complete

1/31/2017

Yes

InDe

velopm

ent

5889

Blythe

SolarIII,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

3106

TerraGe

nDixieVa

lley,LLC(f/k/a30

11)

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5805

88FT

8MELLC(M

ount

SignalII)

Approved

CUP,IID

Encroachmen

tAgreemen

t,Co

nstructio

n&

Building

Complete

6/15

/201

5Yes

InDe

velopm

ent

5808

93LF

8MELLC(M

ount

SignalV)

Approved

CUP,IID

Encroachmen

tAgreemen

t,Co

nstructio

n&

Building

Complete

6/15

/201

5Yes

InDe

velopm

ent

5810

41MB8M

ELLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

6369

ElCabo

Wind,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Complete

Q220

17Yes

InDe

velopm

ent

6372

TuleWind

Approved

CUP,Co

nstructio

n&Bu

ilding

Complete

Q220

17Yes

InDe

velopm

ent

6380

VoyagerW

indI,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5245

REGa

skellW

est1

(REWalkerP

ass)

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5246

RETranqu

ility

8AzulLLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Complete

7/3/2017

Yes

InDe

velopm

ent

5811

RETranqu

illity

LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

InDe

velopm

ent

5788

LancasterS

olar

1Ap

proved

CUP

Complete

12/31/20

14Yes

InDe

velopm

ent

1243

RioBravoRo

cklin

Approved

CUP

Complete

6/7/19

85Yes

InDe

velopm

ent

1244

RioBravoFresno

Approved

CUP

Complete

12/17/19

84Yes

InDe

velopm

ent

5262

Antelope

DSR3,LLC

Approved

CUP

Yes

InDe

velopm

ent

5747

AVSPh

ase2

Approved

CUP

Yes

InDe

velopm

ent

5264

MaverickSolar,LLC

Approved

CUP,Co

nstructio

n,Bu

ilding,ITP&Pu

blic

Yes

InDe

velopm

ent

5886

ValentineSolar,LLC

Approved

CUP

Complete

6/21

/201

6Yes

InDe

velopm

ent

1245

MM

Tulare

Energy,LLC

Approved

N/A

Yes

InDe

velopm

ent

5258

GreenBe

anworks

C,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5268

GreenBe

anworks

D,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

5519

One

TenPartne

rs,LLC

Approved

CUP,Co

nstructio

n&Bu

ilding

Yes

InDe

velopm

ent

4226

DesertWater

Agen

cy(Sno

wCreek)

NoAp

provalNeede

dN/A

Yes

App

endi

x B

- Pa

ge 1

PUBLIC APPENDIX C.1

Physical Renewable Net Short Calculations Based on CPUC Assumptions

Phys

ical

Ren

ewab

le N

et S

hort

Cal

cula

tions

Bas

ed o

n C

PUC

Ass

umpt

io

Var

iabl

eC

alcu

latio

nIte

m

Def

icit

from

RPS

prio

r to

Repo

rtin

g 20

11

Act

uals

2012

Act

uals

2013

Act

uals

2011

-201

320

14

Act

ual

2015

Act

ual

2016

Act

ual

2014

-201

620

17

Fore

cast

2018

Fore

cast

2019

Fore

cast

2020

Fore

cast

2017

-202

020

21

Fore

cast

2022

Fore

cast

2023

Fore

cast

2024

Fore

cast

2025

Fore

cast

2026

Fore

cast

2027

Fore

cast

2028

Fore

cast

2029

Fore

cast

2030

Fore

cast

Fore

cast

Yea

rC

P1C

P21

23

4C

P35

67

89

1011

1213

14

Ann

ual R

PS R

equi

rem

ent

ABu

ndle

d R

etai

l Sal

es F

orec

ast (

LTPP

) 1

73,7

77

75,5

97

74,4

80

223,

854

75,8

29

75,3

22

73,6

21

224,

772

56,4

99

69,3

96

69,0

59

68,6

18

68,2

75

67,7

12

67,1

96

66,6

07

66,0

23

65,4

44

BRP

S Pr

ocur

emen

t Qua

ntity

Req

uire

men

t (%

)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

%

CA

*BG

ross

RPS

Pro

cure

men

t Qua

ntity

Req

uire

men

t (G

Wh)

14,7

55

15,1

19

14,8

96

44,7

71

16,4

55

17,5

50

18,4

05

52,4

10

19,6

62

25,3

29

26,4

50

27,4

47

28,4

71

29,3

19

30,2

38

31,1

06

31,8

89

32,7

22

DV

olun

tary

Mar

gin

of O

ver-

proc

urem

ent

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

EC

+DN

et R

PS P

rocu

rem

ent N

eed

(GW

h)14

,755

15

,119

14

,896

44

,771

16

,455

17

,550

18

,405

52

,410

19

,662

25

,329

26

,450

27

,447

28

,471

29

,319

30

,238

31

,106

31

,889

32

,722

RPS

-Elig

ible

Pro

cure

men

t

FaR

isk-

Adj

uste

d R

ECs

from

Onl

ine

Gen

erat

ion

15,5

85

15,7

64

16,4

45

47,7

94

17,7

34

18,3

16

21,1

39

57,1

89

23,6

87

24,3

01

23,4

50

23,0

59

94,4

96

22,3

27

22,0

48

21,7

59

21,6

52

21,5

42

21,1

90

19,5

62

18,0

80

17,6

80

16,1

66

Faa

Fore

cast

Fai

lure

Rat

e fo

r Onl

ine

Gen

erat

ion

(%)

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%

FbR

isk-

Adj

uste

d R

ECs

from

RPS

Fac

ilitie

s in

Dev

elop

men

t-

-

-

-

-

-

-

-

47

7

1,17

0

2,

420

4,45

8

8,

525

5,11

4

5,

120

5,10

1

5,

082

5,05

0

4,

995

4,91

1

4,

832

4,71

9

4,

617

Fbb

Fore

cast

Fai

lure

Rat

e fo

r RPS

Fac

ilitie

s in

Dev

elop

men

t (%

)N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

16.4%

18.8%

34.8%

30.7%

29.9%

31.4%

31.4%

31.3%

31.3%

31.3%

31.3%

31.2%

31.1%

31.1%

31.0%

FcPr

e-A

ppro

ved

Gen

eric

REC

s-

-

-

-

-

-

-

-

-

2

23

45

69

79

10

9

135

13

7

137

13

7

137

13

7

137

13

7

FeEx

ecut

ed R

EC S

ales

36

2

778

47

3

1,61

4

-

-

40

4

404

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

FFa

+Fb+

Fc-F

eTo

tal R

PS E

ligib

le P

rocu

rem

ent (

GW

h)

215

,223

14

,986

15

,972

46

,181

17

,734

18

,316

20

,735

56

,785

24

,163

25

,473

25

,892

27

,561

10

3,09

0

27

,520

27

,277

26

,995

26

,872

26

,729

26

,321

24

,610

23

,049

22

,535

20

,920

F0C

ateg

ory

0 RE

Cs

315

,170

14

,876

15

,771

45

,817

16

,492

15

,169

14

,915

46

,575

13

,715

12

,714

11

,602

10

,835

48

,866

10

,225

10

,188

10

,223

10

,153

10

,121

9,

910

9,71

2

9,

655

9,45

9

8,

157

F1C

ateg

ory

1 RE

Cs

352

110

20

1

364

1,

243

3,14

7

5,

820

10,2

10

10,4

48

12,7

57

14,2

67

16,6

82

54,1

54

17,2

16

16,9

81

16,6

37

16,5

82

16,4

71

16,2

75

14,7

62

13,2

57

12,9

40

12,6

26

F2C

ateg

ory

2 RE

Cs

3-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

F3C

ate g

ory

3 RE

Cs

3-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Gro

ss R

PS P

ositi

on (P

hysi

cal N

et S

hort

)

Ga

F-E

Ann

ual G

ross

RPS

Pos

ition

(GW

h)46

7

(133

)

1,

076

1,41

0

1,

280

766

2,

330

4,37

5

7,

858

1,94

8

54

5

(576

)

(1

,742

)

(2,9

98)

(5

,628

)

(8,0

56)

(9

,354

)

(11,

802)

Gb

F/A

Ann

ual G

ross

RPS

Pos

ition

(%)

20.6

%19

.8%

21.4

%20

.6%

23.4

%24

.3%

28.2

%25

.3%

48.7

%39

.3%

39.1

%39

.2%

39.1

%38

.9%

36.6

%34

.6%

34.1

%32

.0%

App

licat

ion

of B

ank

Ha

Exis

ting

Bank

ed R

ECs

abov

e th

e PQ

R0

467

32

5

01,

371

2,64

9

3,

382

1370

.833

327

,819

35

,139

36

,799

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

Hb

REC

s ab

ove

the

PQR

adde

d to

Ban

k46

7

(142

)

1,

046

1,37

1

1,

278

734

2,

249

4,26

0

7,

319

1,66

0

54

4

-

-

-

-

-

-

-

Hc

Non

-ban

kabl

e RE

Cs

abov

e th

e PQ

R-

9

30

39

2

32

81

11

5

539

28

8

1

-

-

-

-

-

-

-

HH

a+H

bG

ross

Bal

ance

of R

ECs

abov

e th

e PQ

R46

7

325

1,

371

1,37

1

2,

649

3,38

2

5,

631

5,63

1

35

,139

36

,799

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

IaPl

anne

d A

pplic

atio

n of

REC

s ab

ove

the

PQR

tow

ards

RPS

Com

plia

nce

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

IbPl

anne

d Sa

les

of R

ECs

abov

e th

e PQ

R-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

JH

-Ia-Ib

Net

Bal

ance

of R

ECs

abov

e th

e PQ

R46

7

325

1,

371

1,37

1

2,

649

3,38

2

5,

631

5,63

1

35

,139

36

,799

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

37

,343

J0C

ateg

ory

0 RE

Cs

31,

007

-

-

1,00

7

-

-

-

-

-

-

-

-

-

-

-

-

-

J1C

ateg

ory

1 RE

Cs

352

110

20

1

364

1,

243

3,01

8

-

4,

260

7,31

9

1,

660

544

-

-

-

-

-

-

-

J2C

ate g

ory

2 RE

Cs

3-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Expi

ring

Con

trac

ts

KRE

Cs

from

Exp

irin

g RP

S C

ontr

acts

-

592

1,

002

2,11

1

2,

959

6,66

5

3,

484

4,03

3

4,

383

4,48

4

4,

484

4,70

8

6,

146

7,45

9

7,

541

8,88

8

Net

RPS

Pos

ition

(Opt

imiz

ed N

et S

hort

)

LaG

a+Ia

-Ib-H

cA

nnua

l Net

RPS

Pos

ition

aft

er B

ank

Opt

imiz

atio

n (G

Wh)

467

(1

42)

1,04

6

1,

371

1,27

8

73

4

2,24

9

4,

260

7,31

9

1,

660

544

(5

76)

(1,7

42)

(2

,998

)

(5,6

28)

(8

,056

)

(9,3

54)

(1

1,80

2)

Lb(F

+Ia-

Ib-H

c)/A

Ann

ual N

et R

PS P

ositi

on a

fter B

ank

Opt

imiz

atio

n (%

)20

.6%

19.8

%21

.4%

20.6

%23

.4%

24.3

%28

.1%

25.2

%47

.8%

38.9

%39

.1%

39.2

%39

.1%

38.9

%36

.6%

34.6

%34

.1%

32.0

%

Not

e: F

ield

s in

gre

y ar

e po

tect

ed a

s C

onfid

entia

l und

er C

PUC

Con

fiden

tialit

y Ru

les

Not

e: V

alue

s ar

e sh

own

in G

Whs

Notes: 1

Bund

ledretailsalesforecastfor

2017

2021

isfrom

SCE'sQ

420

16bu

ndledretailsalesforecast;bu

ndledretailsalesforecastfor

2022

2027

isbasedon

theCE

C's2

016CaliforniaEnergy

DemandUpd

ated

(CED

U)Forecasta

sado

pted

bytheCP

UCforLTPPplanning

with

extensionbe

yond

2027

calculated

basedon

2Includ

esallcon

tractsexecuted

throughJune

30,201

7;ne

wgene

ratio

nforecastbasedon

individu

alprojectspe

cific

successrates

forlarge

near

term

projectsandflata

verage

successrateforrem

aining

projectsbasedon

theseprojects'overallweightedaveragesuccessrate

3Forecastof

deliveriesb

ypo

rtfolio

conten

tcategoriesisfor

executed

contractso

nly;do

esno

tinclude

program

gene

rics

App

endi

x C

.1 -

Page

1

PUBLIC APPENDIX C.2

Physical Renewable Net Short Calculations Based on SCE Assumptions

CONFIDENTIAL APPENDIX C.3

Optimized Renewable Net Short Calculations Based on CPUC Assumptions

(Redacted in Entirety)

CONFIDENTIAL APPENDIX C.4

Optimized Renewable Net Short Calculations Based on SCE Assumptions

(Redacted in Entirety)

PUBLIC APPENDIX D

Cost Quantification Table

Table 1 (Actual Costs, $) Items ActualRows 2 8 and 11 (years 2003 2016) Settlements data from 1/1/2003 to 12/31/2016, 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 2017

UOG Small Hydro is the annualized capital cost plus 2016 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 2016) Settlements data from 1/1/2003 to 12/31/2016, net of sales and GTSRTable 4 (Forecast Generation, kWh) Items ForecastRows 2 12 and 15 25 Forecast begins in year 2017

Calculated as forecasted generation in each year

Joint IOU Assumption Guidelines for Table Input

Act

ual R

PS-E

ligib

le P

rocu

rem

ent a

nd G

ener

atio

n N

et C

osts

1Ex

ecut

ed C

PUC

-App

rove

d R

PS-E

ligib

le C

ontr

acts

(P

urch

ases

and

Sal

es)

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2B

ioga

s$4

9,23

9,75

2$5

5,21

8,58

1$5

8,02

4,70

0$5

5,84

2,74

8$4

6,39

1,31

0$4

5,66

9,90

1$4

1,31

9,95

7$4

6,56

7,99

4$4

5,21

1,23

6$3

5,15

6,54

3$3

3,11

4,88

8$3

3,39

8,83

7$2

6,21

5,22

9$1

9,99

6,62

03

Bio

mas

s$3

0,22

9,21

4$3

0,64

1,34

0$2

9,26

6,68

7$2

9,36

4,74

8$3

1,99

5,80

3$3

2,87

0,62

7$3

7,67

6,12

1$3

9,93

4,58

6$3

2,64

1,65

9$8

,227

,073

$0$0

$0$0

4G

eoth

erm

al$5

33,7

87,2

87$5

68,5

28,0

10$5

69,1

45,2

47$5

40,2

76,5

90$5

64,1

91,7

71$6

82,9

23,9

53$5

91,0

94,3

90$6

01,0

71,8

79$5

59,7

44,5

74$4

15,4

42,0

81$4

33,4

20,4

93$4

88,8

51,4

82$4

06,3

26,0

46$3

21,1

70,2

915

Sm

all H

ydro

$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

$2,4

68,1

52$1

,579

,449

$5,2

25,7

936

Sol

ar P

V$2

,303

$1,0

77$5

74$1

11$0

$0$1

16,0

15$6

,014

,872

$6,2

63,2

15$1

0,23

6,56

5$2

9,30

6,57

7$2

01,1

63,0

17$4

06,4

97,5

64$6

28,9

52,5

237

Sol

ar T

herm

al$1

09,7

67,9

59$1

09,1

76,9

41$1

02,3

33,4

01$1

00,4

64,2

97$1

08,1

26,4

46$1

18,4

42,5

49$1

18,6

33,9

43$1

22,7

39,9

76$1

24,8

89,3

86$1

01,6

11,5

19$9

2,13

7,54

5$1

11,9

17,5

97$1

14,4

43,2

98$1

07,5

60,2

988

Win

d$1

50,5

01,1

68$1

68,9

06,4

14$1

64,0

98,2

93$1

58,6

44,7

62$1

85,5

60,1

85$2

11,1

57,9

17$1

97,3

06,6

48$2

98,8

46,8

15$4

47,5

81,9

05$5

53,1

58,0

34$7

32,7

98,0

17$7

33,0

90,3

66$5

97,2

32,8

83$7

59,4

47,7

089

UO

G S

mal

l Hyd

ro$1

8,91

9,06

9$2

0,78

3,33

0$2

2,00

4,72

4$2

5,47

6,77

3$2

8,92

1,41

9$2

9,62

4,91

2$3

2,85

2,29

3$3

5,08

4,44

9$4

6,52

3,88

0$5

4,40

3,39

6$5

3,52

9,73

7$5

4,48

6,01

8$2

4,93

8,05

9$2

2,10

0,74

210

UO

G S

olar

$0$0

$0$0

$0$2

37,3

24$1

,518

,688

$2,5

87,8

58$1

5,70

3,57

7$3

4,08

4,65

7$2

4,80

2,43

1$3

5,33

9,13

0$4

2,45

3,79

0$3

8,55

5,15

111

Unb

undl

ed R

EC

s$0

$0$0

$0$0

$0$0

$0$0

$0$0

$0$0

$0To

tal C

PUC

-App

rove

d R

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ligib

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n dG

ener

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n N

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ost

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of R

ows

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h 11

]

13B

undl

ed R

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l Sal

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(kW

h)70

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crem

enta

l Rat

e Im

pact

[Row

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divi

ded

by R

ow 1

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28 ¢

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32 ¢

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h1.

29 ¢

/kW

h1.

18 ¢

/kW

h1.

23 ¢

/kW

h1.

41 ¢

/kW

h1.

32 ¢

/kW

h1.

56 ¢

/kW

h1.

77 ¢

/kW

h1.

63 ¢

/kW

h1.

89 ¢

/kW

h2.

19 ¢

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h2.

15 ¢

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h2.

58 ¢

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ctua

l cos

t of U

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15 R

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cure

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1Ex

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d R

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ligib

le C

ontr

acts

(P

urch

ases

and

Sal

es)

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2B

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2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

17B

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s$5

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divi

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67 ¢

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h4.

66 ¢

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h4.

66 ¢

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h4.

67 ¢

/kW

h4.

63 ¢

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h4.

34 ¢

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76 ¢

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4.70

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$2,6

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9

Join

t IO

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(Act

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$1,6

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66,6

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68,0

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32,4

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0520

0620

0720

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722,

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777,

312,

732

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098

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513,

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7,73

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864

7,63

3,51

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6,42

1,87

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6,74

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236,

744,

651

246,

952,

691

325,

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412

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497,

816

196,

112,

961

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554,

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138,

319,

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220,

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00

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01,

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756,

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166

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464

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264,

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065,

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234,

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2,36

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599,

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461,

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618,

139,

310

434,

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326

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814,

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00

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438,

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2B

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00

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00

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66,8

8975

,319

,925

75,5

24,3

7675

,313

,025

66,4

77,2

8528

,344

,159

17,2

84,5

3117

,232

,048

17,2

32,0

4816

Bio

mas

s28

9,68

5,35

949

1,91

7,80

049

1,91

7,80

049

3,36

2,90

749

1,91

7,80

048

3,20

4,11

535

4,04

5,66

735

5,09

0,28

635

4,04

5,66

735

4,04

5,66

735

4,04

5,66

735

5,09

0,28

635

4,04

5,66

735

4,04

5,66

717

Geo

ther

mal

5,75

1,76

4,26

35,

848,

706,

602

5,02

7,27

0,49

64,

596,

934,

579

4,56

2,83

2,49

64,

562,

832,

496

4,48

5,23

1,31

24,

419,

866,

528

4,40

7,90

2,65

64,

228,

587,

755

2,93

3,06

6,44

81,

684,

343,

118

1,67

9,66

6,44

856

6,41

3,96

218

Sm

all H

ydro

186,

070,

593

139,

991,

097

139,

352,

139

89,1

99,3

2442

,303

,885

41,1

47,9

2439

,530

,667

39,3

02,1

2736

,977

,744

36,8

58,9

4936

,858

,949

36,4

33,6

7035

,291

,170

35,2

91,1

7019

Sol

ar P

V8,

197,

820,

756

8,37

9,01

2,92

010

,440

,430

,843

13,0

36,1

65,9

2413

,542

,654

,729

13,5

42,3

54,3

6513

,459

,403

,162

13,3

81,1

92,3

9113

,268

,373

,443

13,0

74,7

30,3

2012

,788

,087

,042

12,5

02,3

39,3

2712

,121

,529

,025

11,7

39,0

76,2

2220

Sol

ar T

herm

al85

4,60

1,34

490

2,30

3,74

778

2,66

6,60

872

4,53

9,50

655

2,19

4,79

451

9,76

8,49

351

9,41

6,19

151

9,11

9,07

951

7,70

8,73

451

2,88

1,62

940

9,42

4,03

337

6,77

8,51

936

7,41

2,02

933

0,56

7,46

721

Win

d7,

840,

804,

134

9,18

1,59

7,99

29,

430,

454,

659

9,61

8,92

2,43

49,

271,

379,

923

9,04

4,08

9,22

59,

020,

656,

219

9,02

9,70

9,08

59,

005,

001,

231

8,96

2,42

5,26

08,

942,

463,

038

8,92

6,23

6,68

78,

765,

586,

884

8,64

3,52

8,86

522

UO

G S

mal

l Hyd

ro43

5,73

8,02

643

5,73

8,02

635

7,49

1,86

435

8,20

4,43

835

7,49

1,86

435

7,49

1,86

435

7,49

1,86

435

8,20

4,43

835

7,49

1,86

435

7,49

1,86

435

7,49

1,86

435

7,49

1,86

435

7,49

1,86

435

7,49

1,86

423

UO

G S

olar

120,

080,

000

120,

100,

000

120,

150,

000

120,

150,

000

119,

820,

000

120,

100,

000

120,

410,

000

120,

410,

000

120,

140,

000

119,

850,

000

119,

850,

000

119,

850,

000

119,

850,

000

119,

850,

000

24U

nbun

dled

RE

Cs

00

00

00

00

00

00

00

25R

PS

-Elig

ible

Sal

es0

00

00

00

00

00

00

0To

tal C

PUC

-App

rove

d R

PS-E

ligib

le D

eliv

erie

s[S

um o

f Row

s 27

thro

ugh

36]

Exec

uted

CPU

C-A

ppro

ved

RPS

-Elig

ible

Con

trac

ts

(Pur

chas

es a

nd S

ales

)20

2920

30

23,8

18,1

05,1

3522

,163

,497

,265

2024

2025

2026

2027

2028

28,2

98,4

18,3

0928

,142

,954

,365

27,7

13,3

48,7

2925

,969

,631

,200

24,3

75,8

48,0

02

2029

2030

521,

508,

322

517,

064,

699

509,

617,

300

498,

553,

127

487,

595,

694

472,

713,

568

459,

412,

411

2024

2025

2026

2027

2028

Join

t IO

U C

ost Q

uant

ifica

tion

Tabl

e 3

(Act

ual P

rocu

rem

ent /

Gen

erat

ion

and

Sale

s, k

Wh)

18,1

91,5

24,0

39

28,7

47,4

55,3

7229

,115

,168

,205

2019

13

2022

29,0

17,0

62,3

80

1212

,062

,980

,999

12,7

98,8

73,3

0212

,714

,635

,449

2023

2023

2020

2021

527,

470,

374

524,

356,

128

2628

,431

,505

,008

23,7

47,9

06,8

3825

,587

,932

,865

26,8

75,2

17,0

75

14

141,

096,

951

527,

389,

466

2017

2018

2019

00

56,0

15,8

12

13,0

33,7

72,9

14

120

1720

18

12,3

82,2

05,0

6912

,291

,201

,359

12,1

63,1

50,9

12

2020

2021

2022

Join

t IO

U C

ost Q

uant

ifica

tion

Tabl

e 4

(For

ecas

t Pro

cure

men

t /

Gen

erat

ion

and

Sale

s, k

Wh)

Exec

uted

But

Not

CPU

C-A

ppro

ved

RPS

-Elig

ible

Con

trac

ts

(Pur

chas

es a

nd S

ales

)

20,6

97,9

00,7

9614

,343

,920

,982

17,6

30,5

33,1

9115

,909

,996

,018

15,3

70,3

28,8

6514

,991

,843

,260

PUBLIC APPENDIX E

RECs from Expiring Contracts

Con

trac

tID

Nam

eC

ontr

act

Type

Nam

epla

teC

apac

ity(M

W)

Expe

cted

Ann

ual

Gen

erat

ion

(GW

h)

Con

trac

tEx

pira

tion

Dat

eTe

chno

logy

Loca

tion

Stat

usPC

CC

lass

ifica

tion

6213

The

BN

Y M

ello

n Tr

ust C

ompa

ny, N

.A.

SO

45.

9317

.77

9/30

/201

7W

ind

Pal

m S

prin

gs, C

AO

nlin

eP

CC

040

29LA

CO

Flo

od C

ontro

l Dis

trict

SO

44.

975

16.5

110

/16/

2017

Sm

all H

ydro

Azu

sa, C

AO

nlin

eP

CC

040

35Th

ree

Val

leys

MW

D (F

ulto

n R

oad)

SO

40.

21.

0510

/31/

2017

Sm

all H

ydro

Pom

ona,

CA

Onl

ine

PC

C 0

4037

Thre

e V

alle

ys M

WD

(Willi

ams)

SO

40.

351.

5610

/31/

2017

Sm

all H

ydro

La V

erne

, CA

Onl

ine

PC

C 0

3104

Orm

esa

Geo

ther

mal

IS

O4

6338

5.76

11/2

9/20

17G

eoth

erm

alH

oltv

ille, C

AO

nlin

eP

CC

060

53D

ifwin

d Fa

rms

Lim

ited

VS

O4

7.9

14.4

611

/30/

2017

Win

dP

alm

Spr

ings

, CA

Onl

ine

PC

C 0

6105

Terr

a-G

en 2

51 W

ind,

LLC

(M

onol

ith X

)S

O4

5.31

9.82

11/3

0/20

17W

ind

Teha

chap

i, C

AO

nlin

eP

CC

061

06Te

rra-

Gen

251

Win

d, L

LC (

Mon

olith

XI)

SO

44.

998.

2111

/30/

2017

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

6107

Terr

a-G

en 2

51 W

ind,

LLC

(M

onol

ith X

II)S

O4

6.72

10.1

511

/30/

2017

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

6108

Terr

a-G

en 2

51 W

ind,

LLC

(M

onol

ith X

III)

SO

45.

677.

6611

/30/

2017

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

5019

Luz

Sol

ar P

artn

ers

Ltd.

VS

O4

3562

.88

12/3

1/20

17S

olar

The

rmal

Bor

on, C

AO

nlin

eP

CC

040

26D

eser

t Wat

er A

genc

y (S

now

Cre

ek)

SO

40.

30.

52/

1/20

18S

mal

l Hyd

roP

alm

Spr

ings

, CA

Onl

ine

PC

C 0

3011

Terr

a-G

en D

ixie

Val

ley,

LLC

SO

467

.23

490

7/4/

2018

Geo

ther

mal

Fallo

n, N

VO

nlin

eP

CC

060

92R

idge

top

Ene

rgy,

LLC

(II)

SO

428

80.6

59/

11/2

018

Win

dM

ojav

e, C

AO

nlin

eP

CC

060

90A

lta M

esa

Pw

r Pur

ch C

ontra

ct T

rust

SO

427

62.9

12/3

0/20

18W

ind

Whi

te W

ater

, CA

Onl

ine

PC

C 0

3004

Del

Ran

ch C

ompa

ny (N

iland

#2)

NE

G42

308.

9812

/31/

2018

Geo

ther

mal

Nila

nd, C

AO

nlin

eP

CC

030

09E

lmor

e C

ompa

nyS

O4

4231

2.9

12/3

1/20

18G

eoth

erm

alN

iland

, CA

Onl

ine

PC

C 0

4051

Mon

teci

to W

ater

Dis

trict

SO

40.

130.

631/

16/2

019

Sm

all H

ydro

San

ta B

arba

ra, C

AO

nlin

eP

CC

030

25S

alto

n S

ea P

ower

Gen

erat

ion

Co

#3S

O4

49.8

322.

582/

13/2

019

Geo

ther

mal

Cal

ipat

ria, C

AO

nlin

eP

CC

050

20Lu

z S

olar

Par

tner

s Lt

d. V

IS

O4

3558

.98

2/20

/201

9S

olar

The

rmal

Bor

on, C

AO

nlin

eP

CC

050

21Lu

z S

olar

Par

tner

s Lt

d. V

IIS

O4

3554

.73

3/1/

2019

Sol

ar T

herm

alB

oron

, CA

Onl

ine

PC

C 0

3030

Cos

o E

nerg

y D

evel

oper

sS

O4

7537

3.26

3/12

/201

9G

eoth

erm

alLi

ttle

Lake

, CA

Onl

ine

PC

C 0

1225

Riv

ersi

de C

ount

y W

aste

Man

agem

ent D

ept

CR

ES

T1.

26.

575/

31/2

019

Bio

gas

Mor

eno

Val

ley,

CA

Onl

ine

PC

C 0

6366

Mog

ul E

nerg

y P

artn

ersh

ip I,

LLC

QFS

C4

116/

23/2

019

Win

dTe

hach

api,

CA

Onl

ine

PC

C 1

6063

Des

ert W

inds

I P

PC

Tru

stS

O4

4876

.28

10/3

1/20

19W

ind

Moj

ave,

CA

Onl

ine

PC

C 0

6114

Des

ert W

ind

III P

PC

Tru

stS

O4

40.5

74.4

610

/31/

2019

Win

dM

ojav

e, C

AO

nlin

eP

CC

040

30D

anie

l M. B

ates

SO

40.

351.

1711

/21/

2019

Sm

all H

ydro

Cal

iforn

ia H

ot S

prin

gs, C

AO

nlin

eP

CC

030

26C

E L

eath

ers

Com

pany

SO

442

310.

4812

/31/

2019

Geo

ther

mal

Nila

nd, C

AO

nlin

eP

CC

061

03V

icto

ry G

arde

n P

hase

IV P

artn

er -

6103

SO

46.

975

12.8

11/

1/20

20W

ind

Teha

chap

i, C

AO

nlin

eP

CC

012

21V

entu

ra R

egio

nal S

anita

tion

Dis

trict

RS

C5

1.57

9.19

82/

29/2

020

Bio

gas

San

ta P

aula

, CA

Onl

ine

PC

C 0

4039

Kaw

eah

Riv

er P

ower

Aut

horit

yS

O4

1754

.73/

15/2

020

Sm

all H

ydro

Lem

on C

ove,

CA

Onl

ine

PC

C 0

6102

Vic

tory

Gar

den

Pha

se IV

Par

tner

- 61

02S

O4

6.97

516

.43/

16/2

020

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

3028

Sal

ton

Sea

Pow

er G

ener

atio

n C

o #2

SO

420

108.

214/

4/20

20G

eoth

erm

alC

alip

atria

, CA

Onl

ine

PC

C 0

6104

Vic

tory

Gar

den

Pha

se IV

Par

tner

- 61

04S

O4

6.97

515

.54

4/10

/202

0W

ind

Teha

chap

i, C

AO

nlin

eP

CC

060

95D

utch

Ene

rgy

SO

48

20.5

54/

12/2

020

Win

dP

alm

Spr

ings

, CA

Onl

ine

PC

C 0

5050

Luz

Sol

ar P

artn

ers

Ltd.

VIII

SO

280

158.

885/

29/2

020

Sol

ar T

herm

alH

inkl

ey, C

AO

nlin

eP

CC

061

13D

eser

t Win

ds II

Pw

r Pur

ch T

rst

SO

475

201.

98/

16/2

020

Win

dM

ojav

e, C

AO

nlin

eP

CC

040

34C

entra

l Hyd

roel

ectri

c C

orp.

SO

411

.95

41.2

112

/7/2

020

Sm

all H

ydro

Lake

Isab

ella

, CA

Onl

ine

PC

C 0

6067

Sky

Riv

er P

artn

ersh

ip (W

ilder

ness

III)

SO

420

.925

44.1

32/

13/2

021

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

5051

Luz

Sol

ar P

artn

ers

Ltd.

IXS

O2

8017

0.04

4/17

/202

1S

olar

The

rmal

Hin

kley

, CA

Onl

ine

PC

C 0

6066

Sky

Riv

er P

artn

ersh

ip (W

ilder

ness

II)

SO

419

.843

.45/

30/2

021

Win

dTe

hach

api,

CA

Onl

ine

PC

C 0

6065

Sky

Riv

er P

artn

ersh

ip (W

ilder

ness

I)S

O4

36.7

7581

.71

7/21

/202

1W

ind

Teha

chap

i, C

AO

nlin

eP

CC

063

33M

ount

ain

Vie

w P

ower

Par

tner

s, L

LCE

RR

66.6

219.

99/

30/2

021

Win

dS

an G

orgo

nio

Pas

s, C

AO

nlin

eP

CC

012

42P

acifi

c U

ltrap

ower

Chi

nese

Sta

tion

Bio

RA

M25

.612

9.29

83/

31/2

022

Bio

gas

Jam

esto

wn,

CA

Onl

ine

PC

C 1

4004

Hi H

ead

Hyd

ro In

corp

orat

edN

EG

0.35

1.8

4/30

/202

2S

mal

l Hyd

roB

isho

p, C

AO

nlin

eP

CC

042

08Lo

wer

Tul

e R

iver

Irrig

atio

n D

istri

ctC

RE

ST

1.4

0.77

57/

31/2

022

Sm

all H

ydro

Por

terv

ille, C

AO

nlin

eP

CC

155

10U

SD

A F

ores

t Ser

vice

San

Dim

as T

echn

olog

yC

RE

ST

0.25

0.2

7/31

/202

2S

olar

PV

San

Dim

as, C

AO

nlin

eP

CC

164

56E

dom

Hill

s P

roje

ct 1

, LLC

QFS

C19

.55

51.4

9/30

/202

2W

ind

Pal

m S

prin

gs, C

AO

nlin

eP

CC

110

99In

land

Em

pire

Util

ities

Age

ncy

SO

10.

581.

1412

/27/

2022

Bio

gas

Chi

no, C

AO

nlin

eP

CC

030

21S

econ

d Im

peria

l Geo

ther

mal

Co.

NE

G37

222.

887/

4/20

23G

eoth

erm

alH

eber

, CA

Onl

ine

PC

C 0

App

endi

x E

- Pag

e 1

Con

trac

tID

Nam

eC

ontr

act

Type

Nam

epla

teC

apac

ity(M

W)

Expe

cted

Ann

ual

Gen

erat

ion

(GW

h)

Con

trac

tEx

pira

tion

Dat

eTe

chno

logy

Loca

tion

Stat

usPC

CC

lass

ifica

tion

2804

Ora

nge

Cou

nty

San

itatio

n D

istri

ctN

EG

120.

017/

26/2

023

Bio

gas

Hun

tingt

on B

each

, CA

Onl

ine

PC

C 0

6367

Win

dlan

d R

efre

sh 1

, LLC

RA

M20

7.45

518

.286

6/30

/202

4W

ind

Moj

ave,

CA

Onl

ine

PC

C 1

4222

Gol

eta

Wat

er D

istri

ctW

ATE

R0.

251.

22/

28/2

025

Sm

all H

ydro

Gol

eta,

CA

Onl

ine

PC

C 1

6355

Cor

am E

nerg

y LL

CR

AM

203

10.5

1212

/31/

2025

Win

dM

ojav

e, C

AO

nlin

eP

CC

163

97W

indl

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- Pag

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PUBLIC APPENDIX F.1

Renewable Energy Sales Authorized Brokers and Exchanges

Appendix F.1 - Page 1

Authorized Brokers and Exchanges Brokerages

Platform Platform Sponsors Date Launched Date Commission Approved

Amerex Private Investors 1991 2005 American Energy Risk Management Private Investors 1991 2006

Automated Power Exchange Private Investors 1998 BGC Financial, L.P. Private Investors 2008 2013

Black Barrel Energy, L.P.

Partners: (99.9%) OTC Global Holdings, L.P and (0.1%) OTC

Operating GP, LLC. (also owned by OTC Global Holdings, LP). These

entities are owned by Private Investors

2005 2009

Cantor Fitzgerald Private Investors 1945 2005 Castlebridge Partners LLC Private investors 1997 2005

CGS Brokerage LLC Private investors 2003 2014 Choice Environmental,

LLCPrivate Investors 2010 2010

Choice Natural Gas, LP Private Investors 1993 2005 Choice Power, LP Private Investors 1993 2005

Classic Energy, LLC Private Investors 2015 2015

Edge Energy, LLC Parent: OTC Global

Holdings, L.P., Owned by Private Investors

2009 2010

Energy Trade Management GP, LLC

Private Investors 2009 2010

Equus Energy Group, LLC


Evolution Markets Private Investors 2000 2005 Evolution Markets Futures LLC Subsidiary of Evolution Markets 2010 2013

The Finerty Group Private Investors 2011 2015 GFI Brokers LLC Private Investors 2000 2006

ICAP Energy, LLC Intercapital Corporation (London Exchange)

1994

ICAP United, Inc. Publicly Traded 2005 2009 INFA Energy Brokers Private Investors 2005 2006

Intercontinental Exchange (ICE) Brokers, Energy Companies 2000 2005 IVG Energy, Ltd Private Investors 2004 2006

Longevous Capital, LLC Trading Partners: FCStone, LLC and INTL Hanley, LLC

Owned by Private Investors

2010 2012

Natsource Transaction Services LLC


Saddleback Energy Private Investors 2002 2006 Spectron Private Investors 1988 2006

TFS Energy Futures LLC TFS Brokers 1995 2005 Trident Brokerage Services LLC Private Investors 2013 2014

Tullet Prebon Americas Corp Subsidiary of Tullet Prebon, plc 2004 2015

Valence Energy, LLC Parent: OTC Global

Holdings, L.P., Owned by Private Investors

2008 2009

Appendix F.1 - Page 2

Walden Energy, LLC Trading Partner: Hudson Capital Energy, LLC

Owned by Private Investors

2003 2012

ExchangesPlatform Date Launched Date Commission

Approved ICE 2000 2007

NASDAQ OMX 1971 2013 NYMEX 1882 2005

Clearing Firms Platform Date Launched Date Commission

Approved Citigroup Global Markets, Inc. 1892 2005

Macquarie Futures USA, Inc.

2006 2010

Newedge USA LLC 1987 2005 Natural Gas Exchange Inc. (NGX) 1994

CONFIDENTIAL APPENDIX F.2

Renewable Energy Sales (Redacted in Entirety)

Public Appendix Slip Sheets...x Public Appendix J.1 – 2017 Pro Forma Renewable Energy Credits...

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