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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: Carol.Schmidfrazee@sce.com
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: Carol.Schmidfrazee@sce.com
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
2017 Written Plan Table Of Contents (Continued)
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
2017 Written Plan Table Of Contents (Continued)
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
2017 Written Plan Table Of Contents (Continued)
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
2017 Written Plan Table Of Contents (Continued)
Section Page
-vi-
XIX. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .................................................61
A. Bilateral Transactions ........................................................................................................61
B. Energy Storage Procurement .............................................................................................61
2017 Written Plan Table Of Contents (Continued)
-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
2017 Written Plan Table Of Contents (Continued)
-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
projects with executed contracts that are not yet online.
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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
existing resources than expected, lower risk-adjusted project success rates for contracted generation
that is not yet online, lower load requirements due to departing load, and higher levels of curtailment
than expected. SCE assesses its renewable procurement position with such adverse assumptions to
ensure that, even in an adverse case scenario, SCE would still expect to meet its RPS targets after
making the sale. It is not SCE’s intent to purchase renewable energy products solely for the purpose
of selling them at a later date.
At this time, SCE considers holding an excessive amount of bank in the long-term to
be an inefficient use of resources. Rather, SCE generally allocates any near-term forecasted RECs
above the PQR to years of forecasted shortfall. Additionally, as described in Section XI.C, SCE will
setup limits for REC sales using a margin of safety for compliance.
8. Provide Voluntary Margin of Over-procurement (“VMOP”) on both a
short-term (10 years forward) and long-term (10-20 years forward) basis. This
should include a discussion of all risk factors and quantitative justification for
the amount of VMOP.
SCE currently does not use a VMOP methodology on either a short-term or long-term
basis. While there are different risks that have different impacts in the short and long-term, SCE
believes it appropriately accounts for these risk factors in its forecasted RNS as described in prior
sections.
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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
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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.
39
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
45
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.
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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
20162017 Written Plan
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
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TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
Section Page
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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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
Section Page
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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
20162017 Written Plan
TABLE OF CONTENTS (CONTINUED)
Table Of Contents (Continued)
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
2017 Written Plan Table Of Contents (Continued)
-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.3 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.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”).
Appendix A - Page 11
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
Appendix A - Page 12
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.
Appendix A - Page 13
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.
Appendix A - Page 14
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.
Appendix A - Page 15
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.
Appendix A - Page 16
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.
Appendix A - Page 17
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
projects with executed contracts that are not yet online.
Appendix A - Page 18
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).
Appendix A - Page 19
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.
Appendix A - Page 20
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)
Appendix A - Page 21
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.
Appendix A - Page 22
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
Appendix A - Page 23
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.
Appendix A - Page 24
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.
Appendix A - Page 25
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
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, 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.
Appendix A - Page 26
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.
Appendix A - Page 27
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.
Appendix A - Page 28
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.
Appendix A - Page 29
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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.
Appendix A - Page 30
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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.
Appendix A - Page 31
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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
Appendix A - Page 32
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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.
Appendix A - Page 33
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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.
Appendix A - Page 34
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.
Appendix A - Page 35
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
Appendix A - Page 36
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.
Appendix A - Page 37
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.
Appendix A - Page 38
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.
Appendix A - Page 39
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.
Appendix A - Page 40
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;
Appendix A - Page 41
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.
Appendix A - Page 42
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.
Appendix A - Page 43
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).
Appendix A - Page 44
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
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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
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, 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
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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.
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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
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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).
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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;
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• 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.
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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.
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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
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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.
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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).
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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.
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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
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
51 Id.
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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
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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.
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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.
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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
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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
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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.
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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 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.
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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).
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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.
Appendix A - Page 79
70
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.
Appendix A - Page 80
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.
Appendix A - Page 81
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.
Appendix A - Page 82
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.
Appendix A - Page 83
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.
Appendix A - Page 84
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.
Appendix A - Page 85
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.
Appendix A - Page 86
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.
Appendix A - Page 87
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.
Appendix A - Page 88
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.
Appendix A - Page 89
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.
Appendix A - Page 90
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.
Appendix A - Page 91
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.
Appendix A - Page 92
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
Appendix A - Page 93
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
PS-E
ligib
le P
rocu
rem
ent a
n dG
ener
atio
n N
et C
ost
[Sum
of R
ows
2 th
roug
h 11
]
13B
undl
ed R
etai
l Sal
es
(kW
h)70
,616
,552
,902
72
,964
,152
,898
74
,994
,454
,104
78
,863
,139
,433
79
,505
,151
,004
80
,956
,160
,306
78
,048
,183
,506
75
,141
,421
,957
73
,777
,490
,034
75
,596
,657
,918
74,4
80,0
94,9
0275
,828
,582
,966
75,3
22,3
45,8
6873
,621
,347
,624
14In
crem
enta
l Rat
e Im
pact
[Row
12
divi
ded
by R
ow 1
3]1.
28 ¢
/kW
h1.
32 ¢
/kW
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 ¢
/kW
h2.
15 ¢
/kW
h2.
58 ¢
/kW
h*T
he a
ctua
l cos
t of U
OG
Sm
all H
ydro
in 2
013
was
$53
,529
,737
, not
$53
,101
,662
as
repo
rted
in th
e 20
14 R
PS
Pro
cure
men
t Pla
n.*T
he a
ctua
l cos
t of U
OG
Sm
all H
ydro
in 2
014
was
$54
,486
,018
, not
$52
,517
,116
as
repo
rted
in th
e 20
15 R
PS
Pro
cure
men
t Pla
n.
1Ex
ecut
ed B
ut N
ot C
PUC
-App
rove
d R
PS-E
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
ioga
s$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$03
Bio
mas
s$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$04
Geo
ther
mal
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
5S
mal
l Hyd
ro$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$06
Sol
ar P
V$0
$0$2
,465
,72 5
$5,8
10,2
84$1
8,52
5,93
6$1
8,62
8,13
3$1
8,61
9,87
0$1
8,61
9,31
4$1
8,56
9,72
2$1
8,41
6,98
9$1
8,12
0,18
6$1
7,82
5,20
9$1
7,38
7,40
2$1
7,00
4,75
97
Sol
ar T
herm
al$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$08
Win
d$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$09
UO
G S
mal
l Hyd
ro
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
10U
OG
Sol
ar$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$011
Unb
undl
ed R
EC
s$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$012
Sal
es R
even
ue$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0To
tal E
xecu
ted
But
Not
CPU
C-A
ppro
ved
RPS
-Elig
ibl e
Proc
urem
ent a
nd G
ener
atio
n C
ost
[Sum
of R
ows
2 th
roug
h 11
]
14B
undl
ed R
etai
l Sal
es(k
Wh)
56,4
98,6
36,9
0255
,383
,811
,902
55,0
71,2
16,3
5255
,197
,786
,629
55
,364
,709
,155
55
,738
,273
,501
56
,416
,183
,627
57
,061
,703
,555
57
,401
,844
,487
57
,879
,854
,587
15In
crem
enta
l Rat
e Im
pact
[Row
13
divi
ded
by R
ow 1
4]0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h0.
03 ¢
/kW
h
16Ex
ecut
ed C
PUC
-App
rove
d R
PS-E
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
17B
ioga
s$5
,931
,021
$7,1
17,8
86$6
,849
,050
$6,1
73,1
10$6
,173
,273
$6,2
58,8
47$6
,272
,614
$6,4
05,0
79$6
,482
,894
$5,8
05,3
41$2
,426
,236
$1,3
54,0
38$1
,363
,609
$1,3
77,3
4418
Bio
mas
s$3
3,02
3,12
5$5
6,88
7,99
7$5
8,38
7,45
9$6
0,11
9,33
5$6
1,51
4,09
0$6
1,01
2,40
9$4
1,58
2,98
4$4
2,48
3,54
3$4
3,38
7,96
8$4
4,52
9,62
5$4
5,39
0,34
2$4
6,36
4,54
6$4
7,13
8,77
0$4
8,14
7,07
719
Geo
ther
mal
$362
,836
,646
$389
,567
,961
$356
,266
,486
$342
,171
,149
$345
,486
,010
$349
,542
,831
$346
,859
,810
$346
,953
,627
$351
,563
,455
$343
,742
,366
$236
,461
,770
$144
,112
,056
$143
,631
,784
$52,
724,
533
20S
mal
l Hyd
ro$1
2,54
6,06
4$1
0,45
5,36
2$1
0,39
5,11
2$6
,825
,855
$3,6
24,8
20$3
,550
,630
$3,4
15,5
29$3
,416
,926
$3,2
67,1
66$3
,278
,505
$3,2
85,3
44$3
,260
,202
$3,1
76,0
72$3
,187
,417
21S
olar
PV
$850
,798
,257
$865
,463
,207
$983
,090
,925
$1,1
38,6
34,3
38$1
,161
,827
,959
$1,1
74,2
58,8
23$1
,178
,396
,549
$1,1
81,7
03,6
61$1
,188
,528
,646
$1,1
91,2
83,0
95$1
,176
,423
,580
$1,1
61,6
38,8
86$1
,138
,948
,748
$1,1
16,5
53,4
7322
Sol
ar T
herm
al$1
17,5
07,0
25$1
18,8
63,7
19$1
04,1
37,4
37$9
0,95
2,13
6$6
7,67
6,83
5$6
5,97
6,15
0$6
5,78
1,35
3$6
5,56
9,54
1$6
5,52
9,86
3$6
5,24
4,90
2$5
7,76
5,21
1$5
5,06
2,66
5$5
3,59
7,23
5$5
0,53
0,16
423
Win
d$7
42,7
41,1
95$8
41,8
36,0
95$8
69,2
25,3
23$8
83,4
68,8
70$8
61,9
74,8
11$8
43,7
28,6
04$8
44,7
17,6
54$8
46,6
48,5
35$8
46,2
53,2
38$8
44,9
77,5
95$8
44,4
49,3
25$8
44,5
17,4
99$8
31,4
04,2
00$8
17,5
44,9
0024
UO
G S
mal
l Hyd
ro$2
6,68
2,67
4$2
7,33
6,47
3$2
8,02
2,96
3$2
8,74
3,77
7$2
9,50
0,63
2$3
0,29
5,33
0$3
1,12
9,76
3$3
2,00
5,91
7$3
2,92
5,87
9$3
3,89
1,83
9$3
4,90
6,09
7$3
5,97
1,06
8$3
7,08
9,28
8$3
8,26
3,41
925
UO
G S
olar
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
$49,
132,
021
26U
nbun
dled
RE
Cs
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
27S
ales
Rev
enue
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
$0$0
Tota
l CPU
C-A
ppro
ved
RPS
-Elig
ible
Pro
cure
men
t an d
Gen
erat
ion
Cos
t[S
um o
f Row
s 17
thro
ugh
27]
29B
undl
ed R
etai
l Sal
es(k
Wh)
56,4
98,6
36,9
01.7
155
,383
,811
,901
.64
55,0
71,2
16,3
51.5
855
,197
,786
,629
55,3
64,7
09,1
5555
,738
,273
,501
56,4
16,1
83,6
2757
,061
,703
,555
57,4
01,8
44,4
8757
,879
,854
,587
30In
crem
enta
l Rat
e Im
pact
[Row
28
divi
ded
by R
ow 2
9]4.
58 ¢
/kW
h4.
67 ¢
/kW
h4.
66 ¢
/kW
h4.
66 ¢
/kW
h4.
67 ¢
/kW
h4.
63 ¢
/kW
h4.
34 ¢
/kW
h4.
10 ¢
/kW
h4.
02 ¢
/kW
h3.
76 ¢
/kW
hTo
tal I
ncre
men
tal R
ate
Impa
c[R
ow 1
5 +
30; F
orm
attin
g ca
n ca
use
Row
31
to d
iffer
slig
htl
from
the
sum
of R
ow 1
5 an
d 30
]
$1,9
03,0
09,1
26
3.79
¢/k
Wh
Join
t IO
U C
ost Q
uant
ifica
tion
Tabl
e 2
(For
ecas
t Cos
ts a
nd R
even
ues,
$)
4.70
¢/k
Wh
4.71
¢/k
Wh
4.67
¢/k
Wh
$2,5
67,2
88,2
76
$17,
004,
759
$2,5
74,3
18,8
50$2
,587
,071
,130
$2,5
81,8
85,2
90$2
,450
,239
,926
$2,3
41,4
12,9
82$2
,305
,481
,727
$2,1
77,4
60,3
48
$18,
120,
186
$17,
825,
209
4.38
¢/k
Wh
4.13
¢/k
Wh
$17,
387,
402
4.05
¢/k
Wh
28$2
,201
,198
,028
$2,3
66,6
60,7
21$2
,465
,506
,777
314.
70 ¢
/kW
h
$2,6
06,2
20,5
90$2
,586
,910
,451
$2,5
83,7
55,6
45
4.61
¢/k
Wh
4.70
¢/k
Wh
$18,
525,
936
$18,
628,
133
$1,3
04,6
27,5
83$1
,230
,556
,730
13$0
$0$2
,465
,725
$5,8
10,2
84$1
8,61
9,87
0$1
8,61
9,31
4$1
8,56
9,72
2$1
8,41
6,98
9
Join
t IO
U C
ost Q
uant
ifica
tion
Tabl
e 1
(Act
ual N
et C
osts
, $)
$1,6
19,6
86,3
18$1
,409
,111
,050
12$9
07,1
27,3
88$9
66,6
07,4
75$9
68,0
03,0
63$9
32,4
20,5
51$9
76,8
69,4
95$1
,138
,144
,451
$1,0
32,7
15,7
11$1
,172
,088
,308
$1,6
60,7
14,5
99
Act
ual R
PS-E
ligib
le P
rocu
rem
ent /
Gen
erat
ion
and
Sale
s (k
Wh)
1Te
chno
logy
Typ
e (P
rocu
rem
ent /
Gen
erat
ion
and
Sale
s)20
0320
0420
0520
0620
0720
0820
0920
1020
1120
1220
1320
1420
1520
162
Bio
gas
722,
946,
872
777,
312,
732
771,
018,
454
752,
792,
686
587,
082,
098
546,
962,
524
493,
557,
888
513,
205,
916
505,
975,
841
499,
348,
085
484,
856,
973
449,
602,
910
410,
920,
238
317,
624,
690
3B
iom
ass
365,
097,
000
373,
917,
000
351,
063,
000
353,
889,
000
365,
332,
000
363,
224,
000
417,
625,
000
437,
916,
000
351,
018,
000
114,
694,
000
00
00
4G
eoth
erm
al7,
079,
544,
959
7,88
2,15
3,15
27,
823,
442,
082
7,48
1,22
8,81
07,
611,
424,
731
7,73
9,37
0,19
77,
675,
040,
864
7,63
3,51
1,17
17,
178,
640,
942
6,42
1,87
8,83
36,
536,
991,
410
6,74
5,45
5,45
26,
687,
895,
884
5,40
6,19
1,07
15
Sm
all H
ydro
236,
744,
651
246,
952,
691
325,
458,
412
348,
497,
816
196,
112,
961
182,
554,
690
138,
319,
853
220,
027,
751
301,
898,
312
193,
824,
909
111,
406,
134
28,1
89,9
0817
,624
,603
65,9
33,5
086
Sol
ar P
V0
00
00
01,
372,
324
51,3
89,2
1353
,432
,781
73,8
22,9
8624
7,18
5,88
41,
839,
819,
140
3,82
5,64
5,62
66,
241,
358,
790
7S
olar
The
rmal
756,
941,
166
739,
291,
464
622,
099,
854
613,
049,
994
666,
864,
846
730,
264,
176
839,
801,
580
879,
081,
877
889,
065,
595
868,
991,
935
680,
234,
418
751,
904,
813
833,
904,
840
773,
651,
852
8W
ind
2,36
6,58
2,60
92,
313,
238,
518
2,27
5,71
3,06
72,
232,
844,
707
2,37
4,03
2,23
82,
383,
541,
034
3,03
8,79
8,46
54,
142,
352,
867
5,41
7,62
5,93
36,
286,
303,
872
7,51
0,59
6,68
57,
442,
425,
300
6,06
2,73
4,88
47,
391,
812,
341
9U
OG
Sm
all H
ydro
535,
123,
742
466,
007,
745
545,
840,
580
599,
902,
056
362,
302,
038
344,
846,
249
426,
458,
028
461,
590,
000
618,
139,
310
434,
380,
326
269,
814,
338
274,
950,
708
234,
845,
891
394,
208,
307
10U
OG
Sol
ar0
00
00
438,
489
2,79
8,91
24,
846,
187
54,5
32,1
5198
,598
,314
68,9
10,1
7698
,184
,960
117,
952,
073
107,
120,
236
11U
nbun
dled
RE
Cs
00
00
00
00
00
00
00
Tota
l CPU
C-A
ppro
ved
RPS
-Elig
ible
Pro
cure
men
t /
Gen
erat
ion
and
Sale
s[S
um o
f Row
s 2
thro
ugh
11]
2B
ioga
s0
00
00
00
00
00
00
03
Bio
mas
s0
00
00
00
00
00
00
04
Geo
ther
mal
00
00
00
00
00
00
00
5S
mal
l Hyd
ro0
00
00
00
00
00
00
06
Sol
ar P
V0
056
,015
,812
141,
096,
951
527,
389,
466
527,
470,
374
524,
356,
128
521,
508,
322
517,
064,
699
509,
617,
300
498,
553,
127
487,
595,
694
472,
713,
568
459,
412,
411
7S
olar
The
rmal
00
00
00
00
00
00
00
8W
ind
00
00
00
00
00
00
00
9U
OG
Sm
all H
ydro
00
00
00
00
00
00
00
10U
OG
Sol
ar0
00
00
00
00
00
00
011
Unb
undl
ed R
EC
s0
00
00
00
00
00
00
012
RP
S-E
ligib
le S
ales
00
00
00
00
00
00
00
Tota
l Exe
cute
d B
ut N
ot C
PUC
-App
rove
d R
PS-E
ligib
le
Del
iver
ies
[Sum
of R
ows
2 th
roug
h 11
]
15B
ioga
s71
,342
,361
88,5
64,6
8185
,482
,666
77,6
89,0
9376
,466
,889
76,4
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
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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
Private Investors 2010 2010
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
Private Investors 1994 2005
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)
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