sce 2019 final rps plan-confidential vol. 1, pleading...this 2019 final rps procurement plan is...
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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 18-07-003
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E)
2019 FINAL RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN
VOLUME 1
PUBLIC VERSION
JANET S. COMBS CAROL A. SCHMID-FRAZEE
Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1337 Facsimile: (626) 302-1935 E-mail: [email protected]
Dated: January 29, 2020
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 18-07-003
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E)
2019 FINAL RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLAN
Pursuant to the Assigned Commissioner and Assigned Administrative Law Judge’s
Ruling Identifying Issues and Schedule of Review for 2019 Renewables Portfolio Standard
(“RPS”) Procurement Plans, dated April 19, 2019 (“ACR”), the Administrative Law Judge’s
Ruling Modifying Schedule, dated May 7, 2019 (“ALJ’s Ruling”), and Decision No. 19-12-042,
Ordering Paragraph (“OP”) No. 2,1 Southern California Edison Company (“SCE”) respectfully
submits its 2019 Final Renewables Portfolio Standard (“RPS”) Procurement Plan (“2019 RPS
Plan”) to the California Public Utilities Commission (“Commission” or “CPUC”).2
SCE’s 2019 RPS Plan consists of a Written Plan and Appendices thereto.3
The Appendices include:
1 D.19-12-042 was issued on December 30, 2019. D.19-12-042, OP 2, requires that SCE file its 2019
Final RPS Procurement Plan within 30 days of the issuance of the decision on December 30, 2019, This 2019 Final RPS Procurement Plan is filed on January 29, 2019, which is 30 days from the issuance of D.19-12-042.
2 SCE is concurrently filing a Motion for Leave to File its Confidential Draft 2019 Renewables Portfolio Standard Procurement Plan Under Seal.
3 SCE worked with PG&E and SDG&E to make the format of the utilities’ plans as uniform as possible.
2
Confidential/Public Appendix A – Redline of Draft 2019 Written Plan
Public Appendix B – Project Development Status Update
Confidential/Public Appendix C.1 – Renewable Net Short Calculations Based on
CPUC Assumptions
Confidential/Public Appendix C.2 – Renewable Net Short Calculations Based on
CPUC Assumptions
Confidential/Public Appendix D – Cost Quantification Table
Confidential Appendix E – Renewable Energy Sales
Confidential Appendix E.1 – Redline of Renewable Energy Sales
Public Appendix F – 2019 Pro Forma Renewable Power Purchase Agreement
Public Appendix G.1 – SCE’s 2019 Least-Cost Best-Fit Methodology
Public Appendix G.2 – Redline of SCE’s 2018 Least-Cost Best-Fit Methodology
Public Appendix H.1 – 2019 Procurement Protocol
Public Appendix H.2 – Redline of 2018 Procurement Protocol
Public Appendix I – 2019 Pro Forma Renewable Energy Credits Sales Agreement
Public Appendix I.1 – Redline of 2019 Pro Forma Renewable Energy Credits Sales
Agreement
Public Appendix J – New REC Sales Procurement Protocol
Public Appendix K – Informational Only TOD Factors
3
Respectfully submitted, JANET S. COMBS CAROL A. SCHMID-FRAZEE
/s/ Carol A. Schmid-Frazee By: Carol A. Schmid-Frazee
Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1337 Facsimile: (626) 302-1935 E-mail: [email protected]
January 29, 2020
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) 2019 Final 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 29th day of January 2020, at Rosemead, California.
/s/ David LeBlond By: David LeBlond
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770
(U 338-E)
Final 2019 Written Plan
January 29, 2020
PUBLIC VERSION
2019 Final Written Plan Table Of Contents (Continued)
Section Page
i
I. SUMMARY OF KEY UPDATES...................................................................................................1
A. Important Changes in the Written Plan ................................................................................1
1. Inclusion of Informational-Only Time-of-Use Factors ............................................1
2. Revisions to REC Sales Strategy .............................................................................2
B. Important Changes in 2019 Pro Forma ...............................................................................3
C. Important Changes in 2019 Pro Forma REC Sales Agreement ..........................................3
D. Important Changes to Discussion of Disadvantaged Communities Green Tariff and Community Solar Green Tariff ...........................................................................4
II. EXECUTIVE SUMMARY OF 2019 DRAFT RPS PLAN .............................................................5
III. SUMMARY OF RECENT LEGISLATIVE AND/OR REGULATORY CHANGES .......................................................................................................................................7
IV. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND..........................................10
A. Portfolio Supply and Demand ............................................................................................10
B. Alignment with Load Curves .............................................................................................16
C. Responsiveness to Policies, Regulations, and Statutes ......................................................16
D. Portfolio Diversity .............................................................................................................18
E. Lessons Learned .................................................................................................................22
1. Possible Future Trend Toward Departing Load.....................................................22
2. Need for REC Sales ...............................................................................................24
V. PROJECT DEVELOPMENT STATUS UPDATE .......................................................................25
VI. POTENTIAL COMPLIANCE DELAYS ......................................................................................25
A. Curtailment ........................................................................................................................26
B. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and Transmission .................................................................................................27
C. A Heavily Subscribed Interconnection Queue ...................................................................27
2019 Final Written Plan Table Of Contents (Continued)
Section Page
ii
D. Developer Performance Issues ...........................................................................................28
E. Load Uncertainty Including Faster Implementation of Transportation Electrification And Departing Load ...................................................................................29
VII. RISK ASSESSMENT ....................................................................................................................29
VIII. QUANTITATIVE INFORMATION .............................................................................................30
A. RNS Calculations ...............................................................................................................30
B. Response to RNS Questions ..............................................................................................31
1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? ...........................................................................................31
2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. .................................................................................................................31
3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ....................................................32
4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? .......................................................................33
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? ....................................33
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. ...............................................................................34
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. ......................................................................................................34
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. .......................................35
2019 Final 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. .......................................................35
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? ..............................................................................36
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? ..................................................................................36
IX. MINIMUM MARGIN OF PROCUREMENT ..............................................................................37
X. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES .......................38
A. Solicitation Protocol for REC Sales ...................................................................................38
B. Procurement Protocol.........................................................................................................39
C. LCBF Criteria ....................................................................................................................39
1. Workforce Development ........................................................................................40
2. Disadvantaged Communities .................................................................................40
XI. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..............................................40
XII. CURTAILMENT, FREQUENCY, COSTS AND FORECASTING ............................................41
XIII. COST QUANTIFICATION ..........................................................................................................43
XIV. SAFETY CONSIDERATION .......................................................................................................43
XV. COMMENTS ON COORDINATION WITH INTEGRATED RESOURCE PLANNING PROCEEDING .........................................................................................................44
XVI. AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS .........................................44
A. Justification of SCE’s Request for Pre-Approval Or Tier 3 Approval Process for Certain RPS-Eligible Transactions .................................................................44
1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future ........................................................................45
2019 Final Written Plan Table Of Contents (Continued)
Section Page
iv
2. California Customers Need an Open Market for RECs .........................................45
3. REC Sales Will Create Customer Value ................................................................47
a) Selling is better than banking up to the established limits .........................47
b) REC Sales Stabilize Rates By Realizing Near Term Value ......................48
c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could Help Lower Costs for Customers, While Requiring Other LSEs to Use More Long-term Products......................................................................................................48
d) SCE Was Directed to Sell BioRAM RECs ................................................49
B. REC Sales Framework .......................................................................................................50
1. REC Sales Framework ...........................................................................................50
2. Tier 3 Approval Process .........................................................................................52
C. SCE’s Proposed Limits on REC Sales ...............................................................................52
D. Acceptable REC pricing ....................................................................................................52
E. Proposed Transactional Methods .......................................................................................52
1. Competitive Solicitations and Electronic Solicitations ..........................................52
2. Bilateral Transactions ............................................................................................53
F. Proposed Timeline for REC Sales .....................................................................................53
XVII. STANDARD CONTRACT OPTION ............................................................................................53
A. Procurement Need ..............................................................................................................54
B. Standard Contract ...............................................................................................................55
XVIII. GREEN ENERGY TARIFF PROGRAMS ...................................................................................56
A. Green Tariff Shared Renewable and Community Renewable Programs ...........................56
1. Community Renewables - Background .................................................................57
2019 Final Written Plan Table Of Contents (Continued)
Section Page
v
2. Community Renewables - Modifications to the 2019 Procurement Protocol, 2019 Pro Forma Standard Contract Option, and LCBF Methodology ..........................................................................................................60
a) 2019 Procurement Protocol – CR Modifications .......................................61
3. SCE’s Request to Terminate the GTSR Program and Required Modifications to GTSR ..........................................................................................61
4. Adjustment to RPS Load Forecast for GTSR and CR Program ............................61
B. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar Programs ...................................................................................................................62
1. Adjustment to RPS Load Forecast for DAC-GT and CSGT Programs ................................................................................................................63
C. New Green Energy Programs ............................................................................................64
XIX. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .................................................64
A. Bilateral Transactions ........................................................................................................64
B. Energy Storage Procurement .............................................................................................64
C. Informational Only TOD Factors .......................................................................................65
1. Introduction ............................................................................................................65
2. The Joint IOU Information Only TOD Proposal ...................................................65
3. SCE’s Informational TOD Heat Maps ...................................................................66
2019 Final Written Plan Table Of Contents (Continued)
Section Page
vi
CONFIDENTIAL/PUBLIC APPENDIX A REDLINE OF DRAFT 2019 WRITTEN PLAN
PUBLIC APPENDIX B PROJECT DEVELOPMENT STATUS UPDATE
CONFIDENTIAL/PUBLIC APPENDIX C.1 RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS
CONFIDENTIAL/PUBLIC APPENDIX C.2 RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS
CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE
CONFIDENTIAL APPENDIX E RENEWABLE ENERGY SALES
CONFIDENTIAL APPENDIX E.1 REDLINE OF RENEWABLE ENERGY SALES
PUBLIC APPENDIX F 2019 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT
PUBLIC APPENDIX G.1 SCE’S 2019 LEAST-COST BEST-FIT METHODOLOGY
PUBLIC APPENDIX G.2 REDLINE OF SCE’S 2018 LEAST-COST BEST-FIT METHODOLOGY
PUBLIC APPENDIX H.1 2019 PROCUREMENT PROTOCOL
PUBLIC APPENDIX H.2 REDLINE OF 2018 PROCUREMENT PROTOCOL
PUBLIC APPENDIX I
2019 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT
PUBLIC APPENDIX I.1
REDLINE OF 2019 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT
vii
PUBLIC APPENDIX J NEW REC SALES PROCUREMENT PROTOCOL
PUBLIC APPENDIX K INFORMATION ONLY TOD FACTORS
1
I.
SUMMARY OF KEY UPDATES
In accordance with the Assigned Commissioner and Assigned Administrative Law Judge’s
Ruling Identifying Issues and Schedule of Review for 2019 Renewables Portfolio Standard (“RPS”)
Procurement Plans, dated April 19, 2019 (“ACR”), the Administrative Law Judge’s Ruling Modifying
Schedule, dated May 7, 2019 (“ALJ’s Ruling”), and Decision No. (“D.”) 19-12-042, Southern California
Edison Company’s (“SCE’s”) Final 2019 RPS Procurement Plan (“2019 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.
SCE, at present, has no need for more eligible renewable resources. As a result, SCE does not
propose to hold a 2019 RPS solicitation. Instead, in this RPS proceeding, SCE seeks permission to sell
SCE’s Renewable Energy Credits (“RECs”), as discussed in Section XVI below. SCE’s 2019 RPS Plan
includes a new 2019 Bundled RPS Energy Sales Solicitation Instructions (“REC Sales Protocol”) and
changes to: (1) SCE’s 2018 Pro Forma Renewable Power Purchase Agreement (“PPA”); (2) SCE’s
Least Cost Best Fit (“LCBF”) Methodology; and (3) SCE’s 2018 Pro Forma REC Sales Agreement.
Those changes are summarized below. SCE has included a redline of its LCBF Methodology against
the 2018 version of the document included in SCE’s 2018 RPS Plan as Appendix G.2. The most
significant changes to the other 2018 documents are summarized below.
A. Important Changes in the Written Plan1
1. Inclusion of Informational-Only Time-of-Use Factors
Pursuant to D.19-02-007, Ordering Paragraph (“OP”) No. 17,2 adopting the 2018 RPS
Plan, the Investor Owned Utilities (“IOUs”)3 developed a joint proposal for informational Time of
1 The Written Plan consists of this document without its attached appendices. 2 D.19-02-007, OP 17, p.118. 3 The IOUs are the Investor-Owned Utilities, which include Pacific Gas and Electric Company (“PG&E”),
SCE, and San Diego Gas & Electric Company (“SDG&E”).
2
Delivery (“TOD”) heat maps and mailed it to the service list of this proceeding on May 30, 2019.4
D.19-12-042 ordered SCE to include in its final 2019 RPS Plan “new informational-only TODs that are
based on the most recent inputs that are available.”5 SCE includes its informational only TOD factors
from the IOUs’ joint proposal in Appendix K. SCE was unable to change the TODs as no more recent
inputs are available at this time. SCE provides more detail on development of the informational TOD
heat maps, and the availability of new inputs in Section XIX.C.
2. Revisions to REC Sales Strategy
In this 2019 RPS Plan, SCE generally proposes sale of all three Portfolio Content Categories
(“PCCs”)6 of RECs as it did in its 2018 RPS Plan (rather than just PCC 1 RECs, as it proposed in the
2017 RPS Plan). Although SCE has not sold PCC 3 RECs due to the seemingly low value of those
RECs as reflected by benchmarking companies and broker quotes available to it, SCE wants the
flexibility to sell PCC 3 RECs in case market conditions change or it otherwise makes sense for SCE’s
customers. As explained in more detail in Section XVI, SCE proposes to sell RECs through the end of
the next full Compliance Period (“CP”), which presently is CP 4 ending 2024 (if there is a market for
such sales). . Finally, in compliance with D.18-12-003 on the Tree Mortality Non-Bypassable Charge
(“TM NBC”),7 SCE intends to sell RECs and related energy associated with its BioRAM Bioenergy
Renewable Auction Mechanism (“BioRAM”) contracts.
4 Final Decision on 2019 Renewables Portfolio Standard Procurement Plans (D.19-12-042) approved the Joint
IOU’s Proposal in OP 26. 5 D.19-12-042, OP 26, p. 95. 6 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.
7 D.18-12-003, OP 4. pp. 26-27 on Application (“A.”) 16-11-005.
3
B. Important Changes in 2019 Pro Forma
Unlike the 2018 Pro Forma Renewable Power Purchase Agreement (“PPA”), SCE’s 2019 Pro
Forma Renewable PPA is based on the technology-neutral pro forma contract approved by the
California Public Utilities Commission (“Commission” or “CPUC”) in Resolution E-5004 for
contracting with distributed energy resources. Basing the 2019 Pro Forma Renewable PPA on the
technology neutral pro forma contract will improve contract administration and allow for better
comparisons across SCE’s different solicitations. The technology-neutral pro forma contract originally
included only solar resources. However, SCE modified it to include wind, geothermal and other
renewable resources.
The 2019 Pro Forma Renewable PPA is organized and formatted differently than the 2018 Pro
Forma Renewable PPA and, therefore, a redline comparison of the two documents would be of no help
in determining any changes made. Therefore, SCE has not included a redline in this 2019 RPS Plan.
The substantive terms and conditions of the 2019 Pro Forma Renewable PPA remain consistent with the
2018 Pro Forma Renewable PPA except for one significant change. SCE removed the TOD factors
from the 2018 Pro Forma Renewable PPA, as allowed in D.19-02-007 and the 2019 Pro Forma
Renewable PPA likewise does not contain TOD factors. As explained in SCE’s 2018 RPS Plan filing,8
SCE believes that TOD factors are unlikely to serve as an incentive for production of power when it is
most needed. Additionally, the hours of need continue to evolve. Currently, in some of SCE’s older
contracts, SCE is paying higher prices for energy delivered in what are now “off hours” as peak use
times have changed. Therefore, SCE has removed TOD factors from the 2019 Pro Forma Renewable
PPA.
C. Important Changes in 2019 Pro Forma REC Sales Agreement
SCE revised its 2019 Pro Forma REC Sales Confirmation in Appendix I to include the below-
stated non-modifiable terms and conditions. In particular, D.11-01-025, in OP 35, requires inclusion of
the “following non-modifiable standard terms and conditions in all contracts for procurement for
8 See SCE’s 2018 RPS Plan, Appendix G.1.
4
compliance with the California renewables portfolio standard, whether bundled contracts or purchases of
renewable credits only:
a. STC REC-1. Transfer of Renewable Energy Credits Seller and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement the renewable energy credits transferred to Buyer conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation. To the extent a change in law occurs after execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law.
b. STC REC-2. Tracking of RECs in WREGIS Seller warrants that all necessary steps to allow the Renewable Energy Credits transferred to Buyer to be tracked in the Western Renewable Energy Generation Information System will be taken prior to the first delivery under the contract.”9
These non-modifiable terms and conditions apply to bundled contracts, which includes sales of
bundled products, like PCC 1 RECs, including both energy and a REC. D.11-01-025, at OP 37, requires
utilities to amend all pending contracts to include the applicable standard terms and conditions.10 For
this reason, SCE amended the 2019 Pro Forma REC Sales Confirmation to include the standard terms
and conditions in OP 35.
D. Important Changes to Discussion of Disadvantaged Communities Green Tariff and
Community Solar Green Tariff
SCE modified its Written Plan in red-line, as part of its Motion to Update its 2019 Draft RPS
Plan, dated August 23, 2019, to better reflect proposed treatment of Disadvantaged Communities Green
9 D.11-01-025, OP 35, pp. 21-22. 10 Id. at p. 23. Additionally, D.11-01-025, at OP 36, requires additional of “non-modifiable standard terms and
conditions” to “all contracts for purchase of renewable energy credits only of regulated utilities…” concerning Commission approval and applicable law. SCE did not add the non-modifiable terms and conditions in OP 36 to the 2019 Pro Forma REC Sales Confirmation because all of the REC sales that it has entered into to date have been for a PCC 1 Bundled Product. To the extent that SCE enters into any REC sales for PCC 3 REC sales which are REC-only sales, SCE will modify the 2019 Pro Forma REC Sales Confirmation to add in the necessary non-modifiable terms and conditions and will highlight the changes in red-line in any Tier 1 Advice Letters submitted to the Commission.
5
Tariff (“DAC-GT”) and Community Solar Green Tariff (“CSGT”) loads and resources in development
of SCE’s Renewable Net Short. SCE plans to adjust its RPS load forecasts to remove customer load
served under the DAC-GT and CSGT programs. Although this treatment is not statutorily required, the
rationale for this treatment is to apply analogous treatment of DAC-GT and CSGT load with the
statutory requirement under Senate Bill (“SB”) 43 for the Green Tariff Shared Renewable (“GTSR”) and
Community Renewable (“CR”) programs that the GTSR and CR customer load forecast be removed
from SCE’s RPS load forecast.11
II.
EXECUTIVE SUMMARY OF 2019 DRAFT RPS PLAN
This 2019 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 solicitation in 2019 (“2019 RPS Solicitation”) to procure new RPS eligible
resources, and its plan to sell RECs.
SCE’s 2019 RPS Plan includes its 2019 Procurement Protocol, 2019 Pro Forma Renewable
Power Purchase Agreement, 2019 REC Sales Procurement Protocol, 2019 Pro Forma RECs Sales
Agreement, and a description of SCE’s LCBF evaluation methodology, including consideration of
workforce development and disadvantaged communities, and a summary of the important changes from
SCE’s 2018 RPS solicitation documents.
If in future years SCE holds a solicitation, SCE would use a solicitation process that is intended
to capitalize on the maturing renewables market and target the most viable proposals that fit SCE’s
compliance and reliability needs and provide the most value to customers. In order to submit a proposal,
SCE will require that projects have: (1) a Phase II Interconnection Study (or an equivalent or more
11 Cal. Pub. Util. Code §2833(u). See, SCE’s Motion to Update, filed August 23, 2019, part of the filings adopted in D.19-12-042, OP1.
6
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.
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 2019 RPS Plan, SCE
proposes to not hold a 2019 RPS solicitation for the procurement of eligible renewable resources. In this
RPS docket, SCE proposes to sell RECs, as described in Section XVI below and in Appendix E.
In this 2019 RPS Plan, SCE will request offers from parties interested in purchasing REC
products from SCE. SCE requests the flexibility to request offers from parties interested in purchasing
all categories of REC products. SCE does not forecast a net short position potential through 2030 and
beyond with the use of its bank. Uncertainty exists regarding factors such as the future departing load
levels, especially as it relates to the formation of additional Community Choice Aggregators (“CCAs”)
(see Section IV.E.1 below for a discussion on CCAs). Therefore, in order to maximize value for
customers, SCE may sell REC products, consistent with its proposal in this 2019 RPS Plan.
7
III.
SUMMARY OF RECENT LEGISLATIVE AND/OR REGULATORY CHANGES
SCE takes the RPS program’s regulatory framework into account – both historical and recent
Legislative and regulatory changes. SB 2 (1x), which took effect on December 10, 2011, increased the
overall target percentage of procurement from renewable resources from 20% to 33% by 2020, and
departed from the prior structure of annual RPS goals and moved to multi-year compliance periods, with
interim procurement targets established for each multi-year compliance period. The Commission has
issued several decisions implementing SB 2 (1x), including D.11 12 020 setting RPS procurement
quantity requirements,12 D.11 12-052 implementing the three portfolio content categories of renewable
energy products that may be used to satisfy RPS targets, 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 adopted SB 350 requirements that
California Load Serving Entities (“LSEs”) must enter into ownership or contractual arrangements of 10
12 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.
8
years or more for eligible renewable resources for 65% of their PQR for all compliance periods
beginning January 1, 2021.13 D.17-06-026 also requires retail sellers to give notice of their election for
early compliance with long-term contracting requirements in Pub. Util. Code §399.13(b) by a letter sent
to the Director of Energy Division within 60 days from the effective date of the decision (which was
August 28, 2017).14
On August 28, 2017, SCE sent a letter to the Director of Energy Division giving notice of its
election for early compliance with long-term contracting requirements in Pub. Util. Code §399.13.15
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”.16 As required by D.17-06-026, SCE filed a motion to
update its 2017 RPS Plan to reflect its election for early compliance. D.17-12-007, dated December 14,
2017, granted SCE’s motion to update in OP 13.17
While SCE has elected early compliance with long-term contracting requirements in SB 350, not
all LSEs have done so. Beginning in 2021, all LSEs will need to comply with the 65% of PQR long-
term contracting requirements in SB 350.
On June 6, 2018, the Commission issued D.18-05-026 implementing SB 350 provisions on
penalties and waivers in the RPS program. D.18-05-026 maintained the existing RPS penalty scheme
and integrated changes made by SB 350 into the current RPS waiver scheme. OP 3 of D.18-05-026
requires that:
13 D.17-06-026, pp. 8-10. 14 D.17-06-026, OP 23, p. 56. 15 On the same day, Energy Division, through an email from Brent Tarnow, acknowledged receipt of SCE’s
notice. 16 D.17-06-026, OP 24, p. 56. 17 D.17-12-007, OP 13, p. 73.
9
Beginning with the 2018 Renewables Portfolio Standard Procurement Plan cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually demonstrate that transportation electrification is accounted for in their procurement plans by explicitly referencing forecasted transportation electrification in their Renewables Portfolio Standard procurement plans; providing a detailed description of the data and method used to support their forecast; and explaining how they considered the California Energy Commission’s Integrated Energy Policy Report transportation electricity demand forecast in creating their own forecast.18
Accordingly, SCE includes a discussion of its forecast of transportation electrification in Section IV.A,
which discusses how SCE forecasts RPS need.
On September 10, 2018, Governor Brown signed SB 100 which, among other significant
changes, increases the State’s RPS goals to 44% of retail sales by 2024, 52% by 2027, and 60% by
2030. SB 100 also establishes a state policy that eligible renewable energy resources and zero-carbon
resources supply 100% of retail sales by 2045. SCE’s renewable procurement planning may change as a
result of the Commission’s further implementation of SB 100’s changes to the RPS program, adoption
of new RPS legislation, a procurement expenditure limitation mechanism, or other changes to the RPS
program.
This 2019 RPS Plan addresses other issues set forth in the ACR, statute, and other Commission
decisions. Specifically, SCE’s 2019 RPS Plan includes discussion of the following additional topics:
Assessment of RPS portfolio supplies and demand;
Project development status update;
Potential compliance delays and risks;
Risk assessment;
Quantitative information discussing SCE’s renewable compliance;
Minimum margin of procurement;
Bid solicitation protocol;
Consideration of price adjustment mechanisms;
Curtailment, frequency, cost and forecasting;
18 D.18-05-026, OP 3, p. 32.
10
REC sales methodology, including pre-approval and Tier 3 Advice Letter approval processes
as well as sales of RECs from the BioRAM contracts, as required by D.18-12-003 on the TM
NBC;19
Cost quantification tables;
Safety considerations;
Comments on Coordination with Integrated Resource Planning (“IRP”) Proceeding;20
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 the DAC-GT
and CSGT programs; and
Other RPS planning considerations and issues.
IV.
ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND
A. Portfolio Supply and Demand
Table IV-1 below shows SCE’s percentage of retail sales for its RPS-eligible resources:
Table IV-1 Percentage of SCE’s Retail Sales from RPS-Eligible Resources
Compliance Period Year(s) % of Retail Sales from RPS Eligible Resources
First 2011-2013 20.7
Second 2014-2016 25.2
2017 2017 31.6
2018 2018 36.5
19 D.18-12-003, OP 4. pp. 26-27. 20 Rulemaking (“R.”) 16-02-007. The Draft 2019 Written Plan does not address this issue, but the Final 2019
Written Plan will address it after SCE receives further direction from the Commission on this matter which will be discussed in parties opening and reply comments submitted on July 19, 2019 and August 2, 2019 respectively.
11
To date, SCE’s RPS-eligible deliveries and executed renewable procurement contracts have
resulted from SCE’s RPS solicitations, SCE’s Renewables Standard Contract program, the Assembly
Bill 1969 feed-in tariffs, RAM and BioRAM auctions, the Renewable Market Adjusting Tariff
(“ReMAT”),21 the Bioenergy Market Adjusting Tariff (“BioMAT”), the utility-owned generation and
independent power producer (“IPP”) portions of SCE’s Solar Photovoltaic Program (“SPVP”), the
GTSR program,22 qualifying facility (“QF”) contracts, utility-owned small hydro projects, and bilateral
opportunities.
SCE did not hold an RPS Solicitation in 2016, 2017, and 2018. However, in 2018 and through
April in 2019, SCE has signed the following renewable contracts:
One bilateral contract for 107 MW, and
Four Bio-MAT contracts for 6.0 MW.
SCE determines its expected renewable procurement need by comparing its forecasted RPS
targets to its forecasted energy deliveries from contracted projects. The forecasted energy deliveries
include SCE’s probabilistic risk-adjusted forecast of generation from contracted projects that are not yet
online. SCE also considers generation from pre-approved procurement programs (i.e., ReMAT,
BioMAT), among other factors.
Appendices C.1 and C.2 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 new RPS goals prescribed in SB 100 for the years
2021 through 2030 and adopted in D.17-06-026. In anticipation of CPUC implementation of
21 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs
ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).
22 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; OP 12.
12
compliance during intervening years, SCE has used the same “straight line” method set out in D.
11-12-020 and D.16-12-040 to determine interim year targets and procurement requirements.
These Appendices use the updated standardized reporting template provided on the
Commission’s RPS website as directed in the ACR.23 The Commission initially adopted the
methodology utilized in the updated standardized template in its Administrative Law Judge’s Ruling on
Renewable Net Short, dated May 21, 2014, in R.11-05-005.
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., BioMAT) at a 100% success rate
before contracts are signed.24 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 delays, minimum margin of procurement, and other potential risks through the use of
SCE’s probabilistic risk-adjusted success rates for energy deliveries from contracted projects that are not
yet online. These probabilistic risk-adjusted success rates are intended to reflect a number of dynamic
factors and are periodically adjusted based on new information. The forecasts include individual
project-specific, risk-adjusted success rates for large, near-term projects and a flat 70% success rate for
the remaining projects, which is based on these projects’ overall weighted-average success rate. The
overall probabilistic risk-adjusted success rate for energy deliveries from SCE’s portfolio of contracts
with projects that are not yet online varies from approximately 78% in the CP 3 and approximately 77%
thereafter.
23 ACR, pp.14-15, including footnote 19. 24 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.
13
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).25 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.26 SCE 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.27 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.28 Prior to dedicated
resources procured to serve Green Rate customers beginning service, SCE transferred RECs from other
RPS-eligible resources in its Interim Green Rate Pool to serve Green Rate subscriptions. In March
2018, one dedicated Green Rate resource became operational. SCE expects to begin transferring RECs
from this dedicated Green Rate resource in 2019 for 2018 customer subscriptions.
SCE will also adjust its load forecast to remove customer load served under the DAC-GT and
CSGT programs. These programs are separate from the GTSR program and separate from the RPS
program. SCE will reduce its bundled retail sales forecast used to calculate its RPS goals by the amount
of energy used to serve customers in the new DAC-GT and CSGT programs, pending approval from the
CPUC of SCE’s forecasting methodology. For this reason, SCE will deduct DAC-GT and CSGT
subscriptions from SCE’s generation forecasts to remove energy deliveries that would be associated
with the load served under the DAC-GT and CSGT programs. Any RECs from unsubscribed energy
from the programs will be credited and used towards the RPS program.
25 No customers are presently being served under the Community Renewables Rate. As a result, SCE only
counted Green Rate customers here. 26 See CAL. PUB. UTIL. CODE § 2833(s). 27 CAL. PUB. UTIL. CODE § 2833(u). 28 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.
14
SCE's load forecast also accounts for future Transportation Electrification (“TE”) load growth.29
SCE models light duty electric vehicles (“EV”) derived from SCE’s Clean Power and Electrification
Pathways (“CPEP” or “PATHWAYS”) results to meet state’s Greenhouse Gas (“GHG”) goals.30 SCE
projects that in the transportation sector, approximately 7.5 million light-duty EVs statewide (2.7
Million in SCE territory) are needed by 2030 to meet California’s GHG emission targets.
Once vehicle population number is determined for each year, SCE calculates the total annual
energy by multiplying the number of forecasted EVs by the average KWh usage per vehicle.31 Then,
SCE establishes its EV charging load shape based on multiple factors such as exiting customer EV
charging behavior, future flexible charging programs, and duration of charge. Next, SCE applies EV
charging load shape to total annual EV energy to derive the hourly EV load forecast. SCE then
incorporates the hourly EV load forecast into its demand forecast used in this 2019 RPS Plan.
The difference between the RNS forecast using SCE’s assumptions, as reflected in Appendix C.2
and the Commission’s assumptions, as reflected in Appendix C.1 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 2019 through 2023 and the annual load forecasts through 2030 reflected
in the 2017 Integrated Energy Policy Report with adjustments for updates to certain CCA load forecasts.
This is consistent with the adopted standardized planning assumptions laid-out in the June 18, 2018
29 TE refers to only light-duty electric vehicles (“EV”) here. 30 SCE used Energy and Environmental Economic, Inc.’s (E3) PATHWAYS model
(https://www.ethree.com/tools/pathways-model/). PATHWAYS is an energy model that evaluates long-term decarbonization plans and performs cost analysis to support GHG mitigation planning. The model tracks GHG emissions from California’s demand and supply-side choices and is used by the California Air Resources Board to develop the state’s Scoping Plan. The model accounts for stock rollover attributes, such as technology useful lives and sale penetration rates, to determine yearly vehicle adoption targets needed to reach the final goal of 7.5 million EVs in 2030.
31 KWh usage assumption is derived from CEC IEPR 2017 EV Forecast (Bahrenian, Aniss, Jesse Gage, Sudhakar Konala, Bob McBride, Mark Palmere, Charles Smith, and Ysbrand van der Werf, 2018, Revised Transportation Energy Demand Forecast, 2018‐2030. California Energy Commission, Publication Number: CEC‐200‐ 2018‐003, available at https://efiling.energy.ca.gov/GetDocument.aspx?tn=223241).
15
Assigned Administrative Law Judge’s Ruling in the IRP docket, R.16-02-007.32 SCE uses its own
bundled retail sales forecast for renewable procurement planning because it is SCE’s best forecast of
bundled retail sales.
Table IV-2 below summarizes information on SCE’s RNS position:
Table IV-2 SCE’s RNS Position
Compliance Period
Assumptions Used PQR Billion
Kilowatt-hours (KWh)
RPS-eligible Procurement
Billion Kilowatt-
hours (KWh)
End Bank Balance /
<Shortfall> Billion
Kilowatt-hours (KWh)
1 (2011-2013) SCE’s assumptions 44.8 46.2 1.4 2 (2014-2016) SCE’s assumptions 52.4 56.7 5.7 3 (2017-2020) SCE’s assumptions 102.6 4 (2021-2024) SCE’s assumptions 110.5 5 (2025-2027) SCE’s assumptions 63.3 78.7 85.7 6 (2028-2030) SCE’s assumptions 73.2 68.3 80.9 1 (2011-2013) Commission’s assumptions 44.8 46.2 1.4 2 (2014-2016) Commission’s assumptions 52.4 56.7 5.7 3 (2017-2020) Commission’s assumptions 102.6 4 (2021-2024) Commission’s assumptions 110.5 5 (2025-2027) Commission’s assumptions 82.1 78.7 61.2 6 (2028-2030) Commission’s assumptions 93.0 68.38 36.5
Using SCE’s assumptions, SCE forecasts a net short position starting in 2028 without the use of
bank (as shown in Appendix C.2). But with the use of bank, SCE forecasts a net long position through
the end of CP 6 (2028-2030) and beyond. Using the Commission’s assumptions, SCE forecasts a net
short position starting in 2026 without the use of bank (as shown in Appendix C.1) and a net long
32 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail sales for the first five years and should use the LTPP standardized planning assumptions thereafter. See RNS Ruling, Attachment A at p. 25. The Commission adopted the standardized planning assumptions in R.16-02-007 in the June 18, 2018 Assigned Administrative Law Judge’s Ruling for the purpose of filing 2018 IRPs.
16
position through the end of CP 6 (2028-2030) and beyond with the use of bank. Accordingly, SCE
currently does not have a need for additional RPS-eligible energy.33
B. Alignment with Load Curves
RPS contracts are procured pursuant to the LCBF standard. That is, given a set of potential RPS
offers, SCE will select the portfolio of assets that maximizes total value to our customers. The most
salient factor for valuing RPS contracts, aside from contract price, is SCE’s expectation of future energy
revenues. Market revenue for RPS contracts is a function of expected generation and power prices.
Although SCE does not apply load curves directly in its evaluation of RPS contracts, customer load is
used to calculate our internal energy price forecasts. All else being equal, as net demand decreases, the
expected price to serve the demand also decreases. This can be seen in current market behavior already
(i.e. “duck curve,” leading to negative power prices.) As the price to serve demand decreases, the
expected market revenue from the RPS asset will also decrease, thereby reducing the economic value of
the contract. Contracts with lower economic value are less likely to be signed compared to contracts
with higher values; therefore, the change in expected load curves will tend to produce a balanced
portfolio over time
C. Responsiveness to Policies, Regulations, and Statutes
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 2018, SCE served 36.5% of its retail sales from
RPS-eligible resources. SCE does not forecast a net short in its RPS compliance position until 2026
without the use of bank and after 2030 with the use of bank using the Commission’s assumptions.
Therefore, SCE does not intend to hold a 2019 RPS Solicitation in this 2019 RPS Plan. In addition,
33 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”)
development based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 2020 are currently accounted for in SCE assumptions for departing load. See section II.F, subsection 1, pp. 22-24 for a detailed explanation of SCE’s CCA outlook. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division.
17
because of SCE’s long position, SCE may look to sell RECs consistent with its proposal in this 2019
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.
SCE may seek to sell RECs to allow SCE to optimize its renewables portfolio and provide value
for all bundled and departing load customers. SCE may conduct a solicitation of offers, negotiate
bilaterally or utilize brokers and exchanges to sell such products to maximize value to customers and
optimize the RPS portfolio. Section XVI contains a more thorough discussion of the REC sales strategy.
The procurement in SCE’s current renewables portfolio is primarily from contracts executed
prior to June 1, 2010 or contracts for Category 1 products with a small amount of Category 3 RECs.34
SCE forecasts that it will meet its RPS targets primarily through long-term procurement from contracts
executed prior to June 1, 2010 and 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 100.
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.
34 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering their product to CAISO. SCE has not contracted for Category 3 products.
18
SCE determines the value of resources with specific deliverability characteristics (such as
peaking, dispatchable, baseload, firm, and as-available) through its LCBF analysis. SCE uses its LCBF
methodology to compare project profiles, including duration of term, location, technology, online date,
viability, deliverability, and price, to estimate the value of each project to SCE’s customers and its
relative value in comparison to other proposals using both quantitative and qualitative factors. SCE also
considers resource diversity with respect to proposals featuring differing technologies, generation
profiles, and fuel sources, and performs a qualitative appraisal of the various benefits and drawbacks of
projects when considering over-generation and the duck curve.35 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 X.C. and Appendix G.1.
In addition to RPS solicitations, SCE continues to utilize a variety of other procurement methods
to help meet the State’s RPS targets, including mandated programs such as ReMAT,36 BioMAT, QF
standard contracts and other opportunities such as local capacity requirements solicitations, all source
solicitations, and bilateral negotiations for procuring renewable energy products.
D. Portfolio Diversity
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
35 The California Independent System Operator (“CAISO”) describes the Duck Curve in Fast Facts at - http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf. 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.
36 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).
19
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 X.C and Appendix G.1. The primary quantitative metric used for evaluating
bundled renewable energy is Net Market Value (“NMV”). SCE also relies on a number of qualitative
factors such as resource diversity and transmission area, among other factors such as impacts on
Disadvantaged Communities (“DACs”), when evaluating proposals.
Because SCE’s need assessment results in a long position, SCE may use sales of renewable
energy products,37 project deferrals, and solicitation deferrals (as it did by not holding a 2012, 2016,
2017, or 2018 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.38
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.39 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.
37 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.
38 Contract amendments have the potential to decrease contract prices or provide other benefits to customers. 39 SCE also considers statutory and regulatory restrictions on banking of excess procurement.
20
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 LSE. 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.
After SCE executes an RPS PPA, SCE’s Energy Contracts Management group manages the
PPA. Each PPA is assigned a contract manager who serves as the primary point of contact to address all
obligations and milestones under the PPA. To the extent allowable, many PPAs will require some form
of modification prior to attaining commercial operation. Modifications may include financing consents,
updates to facility descriptions, amendments that reduce costs to the seller and/or SCE without
increasing revenues, true-up of PPA milestones and timelines as interconnection and permitting
information is updated, and other miscellaneous changes to accommodate adjustments during the project
development process. Generally, PPAs require few modifications after attaining commercial operation.
At this juncture in the contract lifecycle, contract administration efforts become more focused on
monitoring the contractual performance and payment obligations. However, disputes, settlements,
outages, changes to delivery obligations or other issues may arise and are also managed by the same
contract managers.
21
In evaluating modifications or amendments to a PPA, SCE applies guidance from D.88-10-032.
Although D.88-10-032 was enacted as a set of guidelines for the administration of QF contracts, SCE
has been using it when administering all forms of PPAs. At a high level, D.88-10-032 gave the IOUs
the option to determine whether to enter into- an amendment with any counterparty.40 In the event an
amendment is elected, the IOU should negotiate in good faith.41 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.42 The details of D.88-10-032 provide further guidance to the IOUs to
restrict modifications to PPAs with viable projects,43 and reject modifications that would result in
creating an essentially new project.44
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.45
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.46 SCE will comply with D.19-02-007, OP 18,
which requires it to “seek the Commission’s approval through an advice letter for any significant
modification to any procurement contract for renewable portfolio standard-eligible resources that was
approved by the Commission.”47
40 See D.88-10-032 at p. 16. 41 Id. at Conclusions of Law (“CoL”) 8. 42 Id. at p. 16, CoL 13-14. 43 Id. at p. 17, CoL 4, Appendix A at pp. 4-5. 44 Id. at p. 26, CoL 17. 45 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. 46 For example, the Commission has indicated specific IOU actions regarding amendments to certain terms in
tariff-based agreements. 47 D.19-02-007, OP 18, p.118.
22
E. Lessons Learned
SCE’s experience in renewable contracting has enabled SCE to negotiate successfully and bring
projects online with a variety of counterparties on a diverse array of technologies. SCE is committed to
recognizing the unique characteristics of each situation and working toward balanced and mutually
acceptable agreements. To this end, SCE continues to refine both its RPS solicitation process and its
pro forma PPA as a result of lessons learned from SCE’s extensive experience in contracting for
renewable resources and working with developers. Over the course of the last several years, SCE has
also incorporated or accounted for several trends in its renewable procurement planning and solicitation
process. SCE discusses important lessons learned and significant past and future trends below.
Additionally, as SCE has noted in past RPS Procurement Plans, more stringent eligibility requirements,
such as the requirement that projects have a Phase II Interconnection Study (or an equivalent or more
advanced interconnection status or exemption) and an “application deemed complete” (or equivalent)
status within the applicable land use entitlement process in order to submit a proposal, have resulted in
higher viability project proposals. SCE intends to continue these requirements in any future solicitations
for all projects.
1. Possible Future Trend Toward Departing Load
On June 3, 2019, the Commission issued D.19-05-043 in R.19-03-009 Implementing
Senate Bill 237 Related to DA (“DA OIR”). Consistent with that decision in the DA OIR, SCE reflects
the Commission-adopted additional DA customer migrating load impact in SCE’s bundled load
forecast.48 In addition to the additional DA migrating customer load impact, SCE expects additional
cities and eligible public entities within the SCE service territory to begin CCA service. SCE
incorporates existing departing CCA load including Lancaster Choice Energy (“LCE”), Apple Valley
Choice Energy (“AVCE”), Pico Rivera Innovative Municipal Energy (“PRIME”), Clean Power Alliance
(“CPA”) Phase 1 (municipal accounts in unincorporated Los Angeles County), San Jacinto Power
48 D.19-05-043 raises SCE’s authorized DA Cap by 1,747 GWhs from 11,710 to 13,457 GWhs through multi-
year phase-in approach. As a result, SCE assumes a two-year phase-in starting from January 1, 2020 for the total of 1,747 GWh new DA load which reduces SCE’s bundled load forecast.
23
(“SJP”), Rancho Mirage Energy Authority (“RMEA”), CPA Phase 2 (non-residential accounts in
unincorporated Los Angeles County and the Cities of Rolling Hills Estates and South Pasadena), and
CPA Phases 3 and 4 (residential and non-residential accounts in Agoura Hills, Alhambra, Arcadia,
Beverly Hills, Calabasas, Camarillo, Carson, Claremont, Culver City, Downey, Hawaiian Gardens,
Hawthorne, Malibu, Manhattan Beach, Moorpark, Ojai, Oxnard, Paramount, Redondo Beach, Rolling
Hills Estates (residential only), Santa Monica, Sierra Madre, Simi Valley, South Pasadena (residential
only), Temple City, Thousand Oaks, Unincorporated Los Angeles County (residential only), Ventura
(City), Ventura County, West Hollywood and Whittier). Consistent with LSEs’ most recent 2020 initial
Year-ahead RA forecast filings,49 SCE incorporates additional new 2020 CCAs including CPA Phase 5
(serving non-residential and residential accounts in Westlake Village), Western Community Energy
(“WCE”, serving Eastvale, Hemet, Jurupa Valley, Norco, Perris, and Wildomar), Desert Communities
Energy (“DCE”, serving Palm Springs), Commerce, Pomona (serving residential and municipal
accounts), Baldwin Park (serving residential and municipal accounts), Palmdale (serving residential and
municipal accounts), and Hanford (serving residential and municipal accounts).
Additional cities, counties, and governmental aggregations within the SCE service
territory have either initiated contact, requested load data from SCE, or passed a municipal ordinance
related to their interest and intention to developing CCAs. These entities have the potential to represent
a significant additional departure of load from SCE’s bundled procurement service. As additional large
departures come to fruition, they will have proportionally significant impacts on SCE’s progress towards
meeting its RPS compliance goals by reducing SCE’s potential RPS need.
Departing load should not impact SCE’s planned procurement activities unless and until
new LSEs formalize their departure through a Binding Notice of Intent (“BNI”), an initial RA filing, the
start of CCA service, or formal submission of an April RA forecast for the following year pursuant to
49 SCE incorporates its updated 2020 Year-ahead RA forecast which was filed with the Commission on May 24,
2019.
24
California Public Utilities Code Section 380.50 In expectation of growing CCA departing load in the
near future, SCE prepared a Monte Carlo simulation of CCA departing load starting in 2021 and has
accordingly adjusted its procurement plan at this time.51 In addition, future policy changes with regard
to DA reopening could also bring impact to SCE’s planned procurement activities. As these actual load
departures materialize, SCE will consider how these departures impact its RPS compliance, including
the size of the RPS bank and the need to sell RECs to newly forming CCAs. If a sufficiently large
amount of SCE’s current bundled service customers depart bundled service, SCE may be even more
significantly over-procured to meet its RPS compliance goals.
2. Need for REC Sales
SCE is well positioned to meet its RPS compliance obligation both in the near term and
in the foreseeable future. As described in confidential Appendix E, SCE has more renewable energy to
meet its compliance responsibilities than it needs for the forseeable future. Additionally, SCE can create
customer value and introduce some rate stability by engaging in sales transactions. The Commission
adopted SCE’s REC sales strategy in its Draft 2018 RPS Plan, with some modifications, in D.19-02-
007.52 In this 2019 RPS Plan, SCE, once again, seeks permission to engage in REC sales with some
modifications from the 2018 RPS Plan, as more fully described in Chapter XVI and Appendix E.
In addition to providing benefits to SCE’s customers, an open market for REC sales may
provide for a low-cost option for RPS compliance for other LSEs in California. Long-term contracting
may not be an option for smaller LSEs given the higher costs and long-term commitments. In absence
of that option, an open market can provide for a lower-cost option for short-term REC purchases.53
50 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. 51 SCE performs scenario analysis for departing load when making procurement decisions based on the best
information available at that time. SCE shares this information with its PRG, including Energy Division. SCE’s current scenario analysis for departing load includes Lancaster, Apple Valley, Pico Rivera, CPA Phase One, San Jacinto, Rancho Mirage, CPA Phase Two, DCE, CPA Phases Three to Five, and the Monte Carlo simulation for departing load beginning in 2020.
52 D.19-02-007, OP 10, pp. 116-117. 53 As explained in more detail in section XI and confidential Appendix E.
25
RECs offered for sale through SCE’s solicitations will include RECs produced as a result of energy
delivered through BioRAM contracts, as required by D.18-12-003 on the TM NBC.
Finally, given the SB 350 changes in compliance rules confirmed in D.17-06-026, IOUs
will have some flexibility to fulfill their compliance requirements through a combination of long-term
contracts and short-term products, reducing the overall costs for their customers. Given this change,
SCE will seek portfolio optimization opportunities to make those tradeoffs between long-term contracts
and short-term purchases. An active REC sales strategy will be a key part of SCE’s portfolio
optimization strategy.
V.
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. Appendix B utilizes the most recent Project Development
Status update template from the Commission’s RPS website, as required by the ACR.54 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.
VI.
POTENTIAL COMPLIANCE DELAYS
Although SCE is well positioned to meet its compliance goals, there are factors that may delay
SCE’s achievement of the RPS goals: (1) curtailment; (2) permitting, siting, approval, and construction
of both renewable generation projects and transmission; (3) a heavily subscribed interconnection queue;
(4) developer performance issues; and (5) load uncertainty associated with possible departing load and
54 ACR, p. 12, footnote 16.
26
increasing electrification of transportation. SCE discusses each of these potential issues that could cause
compliance delays below and describes the steps it has taken to mitigate the effects of these challenges.
As discussed in Section IV.A, 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. 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 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.
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B. 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 and impede new
renewable resources from being declared fully deliverable.
The long and complicated permitting process for renewable generation and transmission
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 and transmission
projects online. One such project is the Eldorado-Lugo and Lugo-Mohave Series Capacitor (“ELM”)
Project which is a Policy Driven Transmission Project approved through the CAISO Transmission
Planning Process (“TPP”). With the purpose of increasing transmission capacity in support of achieving
the States RPS goals, the project is also required for 13 generation projects, totaling about 2,500 MW, to
achieve Full Capacity Deliverability Status (“FCDS”). As part of the process that identified the ELM
Project through the CAISO TPP for the purpose of identifying policy driven transmission additions, the
renewable resource portfolios provided by the Commission to the CAISO required projects to be fully
deliverable. Subsequently, 13 generation projects entered into Interconnection Agreements with SCE
which listed as a requirement for FCDS the completion of the ELM Project. The delay in the completion
of the ELM Project which currently has a completion date of June of 2021 will be responsible for
several projects not being able to timely achieve FCDS.
C. A Heavily Subscribed Interconnection Queue
A heavily subscribed CAISO interconnection queue is also a major barrier to achieving the
State’s RPS goals. The May 2019 CAISO Interconnection Queue reports 145 solar and wind projects
seeking interconnection to the CAISO controlled grid representing more than 27,000 MW of capacity.55
55 See http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx.
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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 (“IAs”), contribute to the
uncertainty around available system capacity. When capacity is reserved for generators that have not
signed IAs, 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.
D. Developer Performance Issues
Achieving California’s renewable energy goals also depends on the successful performance of
renewable developers in meeting contractual obligations, timely completing construction milestones,
and achieving commercial operation. Hurdles encountered during these activities require developers to
alter their milestone schedules. This can result in delays, lengthy contract amendment negotiations, and
contract terminations. Recently, developer performance has become less of an issue as the renewables
market has matured and RFP requirements such as a Phase II Interconnection Study have been
implemented. However, there have been developer performance issues in some cases especially among
the mandated carve-out feed-in-tariff programs such as ReMAT. Several of SCE’s contracts have
terminated due to developer performance issues (e.g., poor site selection, failure to timely secure the
necessary permits, and inability to complete the CAISO new resource implementation processes in a
timely manner). As stated above, this is especially true in SCE’s smaller and mandated procurement
programs. In these programs, requirements showing the viability of a project, such as the requirement of
a Phase II Transmission Study or equivalent, are not an eligibility criteria. Projects that have achieved
this level of development typically have significant dollars invested and secured project-backing. As a
result, in most cases potential fatal flaws in project location, technology, or environmental factors have
been identified and resolved.
To the extent that delays, termination events, and under-performance occur, the amount of
delivered energy on which SCE can rely to reach the State’s goals is reduced.
29
E. Load Uncertainty Including Faster Implementation of Transportation Electrification And
Departing Load
There are two key factors that create load uncertainty which could impact SCE’s ability to
achieve its RPS goals. First, as discussed in Section IV.A above, SCE’s load forecast reflects its
anticipated future transportation electrification load growth required to meet state’s future GHG goals.
However, if future TE load growth is more accelerated or in excess of SCE’s current forecasts, SCE’s
ability to reach its RPS target may be negatively impacted because it may not have sufficient RPS-
eligible resources to serve a significantly larger load than it presently forecasts. Given predicted levels
and uncertainties of future departing load to CCAs and DA, however, even TE adoption materially in
excess of SCE’s current forecasts is unlikely to change the overall fact that SCE will be significantly
long on RPS for the foreseeable future. That said, it is also possible that SCE may experience
significant returns of CCA (or other alternate ESP-served) load, which could negatively impact its
ability to achieve its RPS targets.
VII.
RISK ASSESSMENT
SCE describes risks that may result in compliance delays in Section VI. As explained in Section
IV.A, 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 considers 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 and C.2 reflects these considerations.
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VIII.
QUANTITATIVE INFORMATION
A. RNS Calculations
As discussed in Section IV.A, Appendices C.1 and C.2 include SCE’s RNS calculations using
the standardized reporting template. Appendix C.2 quantifies SCE’s physical and optimized RNS based
on the following SCE assumptions:
SCE’s most recent bundled retail sales forecast for 2019 through 2030 which excludes
Green Rate customer subscriptions;
Transfers of energy deliveries from SCE’s interim pool of RPS eligible resources to the
Green Rate program to serve Green Rate customers until dedicated Green Rate resources
come online; and conversely, transfers of energy deliveries from dedicated Green Rate
resource that are not used by Green Rate customers;
Contracted projects that are currently online will deliver 100% of their expected amount
of renewable energy;
Probabilistic risk-adjusted success rates for energy deliveries from contracted projects
that are not yet online. SCE’s forecasts include individual project-specific, risk-adjusted
success rates for large, near-term projects and a flat 70% success rate for the remaining
projects, which is based on these projects’ overall weighted average success rate; and
100% success rate for projects originating from pre-approved programs such as BioMAT
before contracts from such programs are signed.56
Appendix C.1 provides SCE’s physical and optimized RNS through 2030 using the
Commission’s RNS Methodology. Appendix C.1 uses the same assumptions as in Appendix C.2 except
that:
56 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.
31
Instead of using SCE’s most recent bundled retail sales forecast for all years, it uses
SCE’s most recent bundled retail sales forecast for 2019 through 2023 and the annual
load forecasts through 2030 reflected in the 2017 Integrated Energy Policy Report with
adjustments for updates to certain CCA load forecasts.57
Currently, SCE does not propose including a voluntary margin of over-procurement (“VMOP”)
in its renewable procurement planning. SCE will account for risks by applying probabilistic risk
adjustment of expected generation from executed contracts with projects that are not yet online.
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
57 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.
32
Initiative Program, future customer adoption of distributed generation, future electric vehicle use, and
other electrification load growth. In addition, in recent years, rapid acceleration of actual and predicted
CCA formation have led to materially longer forecast RPS positions for SCE. Last, the potential
increases in DA customer migrating load driven by state’s policies around DA reopening could make
SCE’s RPS positions even longer. 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 expects a small but increasing level of curtailment in solar between 2019
and 2020. Wind remains less predictable but is expected to have little to no curtailment during this time
period. Looking at the historical CAISO system-wide data,58 the CAISO curtailed about 1.5% of solar
production, and less than 0.2% of wind production in 2018. Solar curtailments were focused in shoulder
months, peaking in March and October, while the wind curtailments were more spread out across the
year. The current year, 2019, is showing a similar pattern, with solar curtailments trending higher than
last year,59 while wind curtailments are hovering in the 0.2% range.
Considering the increasing solar and wind penetration, and retirements of the gas fired
resources, SCE expects that the RPS curtailments will increase. However, forecasting such curtailments
is challenging as many factors impact curtailment levels. These factors include the inherent variability
58 Wind and solar curtailment data, available at http://caiso.com/informed/Pages/ManagingOversupply.aspx. 59 Solar curtailments are reaching 5.3% in March 2019, compared to 4.4% in March 2018.
33
in wind and solar production, uncertainty in load (and net load) forecasts, and a variety of system and
weather variables (e.g. California hydro conditions, available imports). Furthermore, the CAISO and
other stakeholders are working on a variety of projects and initiatives to improve the system capabilities
to manage oversupply – from the Western Energy Imbalance Market (“EIM”) expansion, improved
regional coordination, as well as implementing Time of Use (“TOU”) rates, Demand Response
programs and deploying Energy Storage.
4. Are there any significant changes to the success rate of individual RPS projects that
impact the RNS?
SCE reviews the status of contracted projects that are not yet online every quarter to
assess the likelihood that each project will be successfully constructed and deliver energy. For the larger
contracted projects that terminated in the last year, SCE had gradually dropped their likelihood of
success over time such that when the projects eventually terminated, there was not a significant impact
to SCE’s forecast RNS. Overall, SCE has seen a number of large, near-term projects continue to make
strides towards completion, resulting in a collectively higher anticipated success rate for these large,
near-term projects than was allocated to similar projects prior to 2016. As mentioned in Section VI.E
above, the requirement of a Phase II Interconnection Study or better has 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.
34
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 California Energy Commission (“CEC”) during RPS verification,
fuel source mix in the renewables portfolio, performance of existing resources, project success rates,
delay or acceleration of online dates, performance of new facilities once they are operational, the level
of the existing portfolio that is re-contracted, and curtailment, among other factors. Annual variability
of these factors can either increase or decrease the bank from year-to-year.
7. What are your strategies for short-term management (10 years forward) and long-
term management (10-20 years forward) of RECs above the PQR? Please discuss
any plans to use RECs above the PQR for future RPS compliance and/or to sell
RECs above the PQR.
When sufficiently long during short-term periods, SCE has used sales of renewable
energy products, project deferrals, portfolio optimization, and solicitation deferrals in order to adjust its
renewable procurement back in line with its forecasted RNS. If SCE forecasted short-term shortfalls,
SCE would satisfy the need through additional procurement. For example, SCE could re-contract with
existing projects, initiate an RPS solicitation, procure through pre-approved procurement programs, or
make short-term purchases with Commission approval. Additionally, SCE diligently manages contracts
to ensure all contractual obligations are met. SCE uses these activities for renewables portfolio
optimization.
Specifically, regarding the sale of RECs, when SCE has a long position in the near term,
SCE evaluates whether a sale of renewable energy products is appropriate. This evaluation includes a
35
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.
Currently, 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 XVI.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.
36
If SCE implements a VMOP methodology in the future, SCE would use the same
methods to procure its projected VMOP procurement need as it uses to procure towards its RPS targets,
including procurement of Category 1 products.
10. Are there cost-effective opportunities to use banked RECs above the PQR for future
RPS compliance in lieu of additional RPS procurement to meet the RNS?
There are a few alternatives for the potential use of banked RECs above the PQR,
including applying them in the future compliance periods, engaging in sales for the amount of bank, and
a combination of sales of products and procurement of other products. As noted above in response to
question 7, SCE does not hold an excessive amount of bank for the sole purpose of selling it later. SCE
generally allocates any near-term forecasted RECs above the PQR to years of forecasted shortfall. SCE
conducts various portfolio optimization strategies also described in its response to question 7 to manage
its renewables portfolio.
11. How does your current RNS fit within the regulatory limitations for portfolio
content categories? Are there opportunities to optimize your portfolio by procuring
RECs across different portfolio content categories?
The procurement in SCE’s current renewables portfolio is primarily from either contracts
executed prior to June 1, 2010 or contracts for PCC 1 products with a small amount of PCC 3 RECs.60
Accordingly, SCE’s procurement fits within the minimum target for PCC 1 products and the maximum
target for PCC 3 products established by SB 2 (1x) and D.11-12-052, as well as the targets established in
SB 350 and D.17-06-026. SCE does see opportunities to optimize its portfolio and achieve customer
value through sales across the three portfolio content categories. Given SCE’s current position of no
RPS need in the near term, SCE may conduct solicitations for sales of REC products in 2019. Through
soliciting REC sales, SCE may find opportunities to create value for its customers.
60 The PCC 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering their
product to CAISO. SCE has not contracted for PCC 3 products.
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IX.
MINIMUM MARGIN OF PROCUREMENT
SCE’s renewable procurement efforts will be guided by its forecast of its renewable procurement
needs, as described in Section IV.A and provided in Appendices C.1 and C.2. In its forecast of its
renewable procurement position and need, SCE currently accounts for the risks of project failure and
delay associated with contracted projects that are not yet online. To this end, SCE uses individual
project-specific, risk-adjusted success rates for large, near-term projects and a flat 70% success rate for
the remaining projects, which is based on these projects’ overall weighted average success rate. This
probabilistic risk adjustment methodology for discounting expected energy deliveries from projects
under development is modeled to represent project development success rates as well as any
contingency that would make meeting the State’s RPS goals less likely (e.g., delays due to transmission,
curtailment, material shortages, load growth beyond that which is forecasted, or less than expected
output from resources). Additionally, this methodology provides an appropriate minimum margin of
procurement “necessary to comply with the renewables portfolio standard to mitigate the risk that
renewable projects planned or under contract are delayed or cancelled.”61 SCE will reassess its position
on a periodic basis and, as such, expects that success rates may need to be modified in the future to
reflect changes to SCE’s portfolio.
The Commission should rely on retail sellers to calculate their minimum margins of procurement
and should not attempt to impose a one-size-fits-all approach. As many of the projects in SCE’s
portfolio become operational, SCE will face different risks, including integration of these resources.
The risks associated with project failure will be replaced by less significant risks of projects generating
below full capacity. Similarly, SCE expects that the portfolio risk picture is not the same for each retail
seller. For example, risks may vary depending on whether a portfolio contains a high proportion of
contracts that are online (as discussed above) or depending on the various technologies being used (e.g.,
geothermal technology, which is a baseload resource, versus wind or solar technologies, which are more
61 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).
38
intermittent). 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.
X.
BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES
A. Solicitation Protocol for REC Sales
SCE includes the 2019 REC Sales Protocol as part of this 2019 RPS Plan. SCE will use the 2019
REC Sales Protocol, included here as Appendix J, as a basis for its REC sales solicitations. RECs
offered for sale through SCE’s solicitations will include RECs produced as a result of energy delivered
through BioRAM contracts, as required by D.18-12-003 on the TM NBC. The 2019 REC Sales
Protocol includes, among other things, the following items:
SCE’s requirements for initial delivery dates and preferred contract term lengths;
Deliverability characteristics and locational preferences;
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 selling;
A schedule of key dates related to the solicitation; and
2019 REC Sales Confirmation (“2019 REC Sales Agreement”), attached as Appendix I.
A discussion of the important changes in the proposed solicitation documents from SCE’s 2018
solicitation documents is included in Section I.B.
As stated previously in this Written Plan, IOUs will have some flexibility to fulfill their
compliance requirements through a combination of long-term contracts and short-term products,
reducing the overall costs for their customers. Given this change, SCE will seek portfolio optimization
39
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. More details on SCE’s
strategy are included in Appendix E.
B. Procurement Protocol
Although SCE does not intend to hold a solicitation to purchase renewable power under this
2019 RPS Plan, Appendix H.1 contains SCE’s 2019 Procurement Protocol, which includes an overview
of a solicitation, schedule, product being solicited, and other details. Appendix H.2 includes a redline
from the version filed in 2018.
C. LCBF Criteria
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 assess the top
proposals’ qualitative attributes. These qualitative attributes, including factors such as local reliability,
resource diversity, and nominal contract payments, are considered to either eliminate or add projects to
the final shortlist or to determine tie-breakers, if any. Once a project is added to the shortlist, SCE may
enter into a PPA with the project. By taking many quantitative and qualitative factors into
consideration, SCE ensures that it will select projects best suited for its portfolio in order to meet
customer needs and attain the State’s RPS goals. Appendix G.1, on LCBF Methodology, describes the
full list of both quantitative and qualitative factors taken into account as part of offer evaluation,
including an expanded discussion on preference to renewable energy resources located in certain
communities, as required by Pub. Util. Code § 399.13(a)(7). These quantitative and qualitative factors
specifically include impacts on Workforce Development and Disadvantaged Communities, as required
by D.19-02-007.62
62 D.19-02-007, pp. 96-100 and OP 16, p. 118.
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1. Workforce Development
SCE takes into consideration numerous qualitative factors when assessing cost-
effectiveness during the selection process. Appendix G.1, on LCBF Methodology, describes the full list
of qualitative factors, including an expanded discussion of qualitative consideration of Workforce
Development. As described in Appendix G.1, SCE will require the Seller to provide information during
the bid process assessing the benefits on employment or Workforce Development. This information
includes identifying the number of new jobs created during construction and operation phases and
employment and training opportunities for disadvantaged groups (e.g. women, minorities and disabled
veterans).63
2. Disadvantaged Communities
Appendix G.1, on LCBF Methodology, describes the full list of qualitative factors taken
into account as part of offer evaluation, including an expanded discussion of qualitative consideration of
Disadvantaged Communities (“DAC”). DAC are identified through California’s Environmental
Protection Agency’s CalEnviroScreen 3.0. As described in Appendix G.1, SCE will require the Seller to
provide information during the bid process assessing the benefits for DAC. This information includes
the CalEnviroScreen Score and community impacts, such as new job opportunities, increases or
decreases in air pollution and other environmental benefits and burdens, and other community benefits
and burdens.
XI.
CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS
As in the past three RPS solicitations that SCE has held, SCE would not plan to solicit price
structures based on indices in future RPS solicitations. Sellers can, however, bid escalation factors in
their prices. Proposals with adjustable pricing based on indices were more common when the renewable
industry was starting out. Uncertainties over relatively new technologies made it reasonable to tie
pricing to certain commodity indices, inflation rates, or other indices that made sense given the
63 See Appendix G.1, pp. 10.
41
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.
XII.
CURTAILMENT, FREQUENCY, COSTS AND FORECASTING
Although SCE has observed very few instances of negative pricing in the day-ahead market,64
negative prices have been observed on a more regular basis in the real-time market. SCE identifies
several factors contributing to increases in instances of negative prices. Over-generation typically
occurs in off-peak hours when baseload and must-take renewable generation is high and demand is low,
which can cause negative market price hours. On-peak negative prices tend to be localized, transient,
and related to congestion caused by a particular transmission bottleneck.
It is generally difficult to forecast negative prices. SCE continues to manage potential instances
of negative pricing and the associated impact to SCE customers through several different strategies. As
a general practice, SCE schedules variable energy resources, such as solar and wind facilities, into the
day-ahead market whenever possible. Because resources that are awarded day-ahead schedules are only
exposed to negative prices in real-time for actual deliveries in excess of their bid-in, day-ahead awards,
this practice helps to limit customer exposure to negative prices. This practice is consistent with least-
cost dispatch principles, which govern SCE’s approach to marketing its entire portfolio of contracted
and utility-owned resources.
64 ~2.11% of hours in sampled nodes in the day-ahead market.
42
Additionally, resources with economic curtailment rights are bid accordingly (economically) into
the day-ahead and real-time markets as practicable. Resources with such curtailment rights are then
curtailed as needed based on the CAISO’s economic dispatch.65 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
therefore serve to further limit customer exposure to negative prices both in day-ahead and in real-time,
even if SCE ultimately pays the full contract price for curtailed energy.
In future RPS solicitations, SCE plans to not require sellers to bid the pre-paid economic
curtailment option with the curtailment cap. SCE will retain the right to curtail at its discretion but will
pay for curtailments directly resulting from SCE marketing decisions. As in prior years, SCE will not
pay for curtailments in response to an emergency, or due to the CAISO or transmission provider
instructions.
65 The CAISO may (and does) curtail resources based on grid reliability factors as well, which can happen to all
renewable resources, whether they are bid economically in the market or not.
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XIII.
COST QUANTIFICATION
The Excel spreadsheet attached as Appendix D includes actual expenditures per year for RPS-
eligible generation for every year from 2003 through 2018, as well as actual RPS-eligible generation for
every year from 2003 through 2018. As required by the ACR, this spreadsheet utilizes the most recent
template posted on the Commission’s RPS website.66 Appendix D also includes a forecast of future
expenditures SCE may incur every year from 2019 through 2030, as well as a forecast of expected
generation for every year from 2019 through 2030.
XIV.
SAFETY CONSIDERATION
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 2019 Pro Forma provides that the seller must operate
the generating facility in accordance with “Prudent Electrical Practices.”67 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. .
. .”68
66 ACR, p. 21, footnote 26. 67 See 2019 Pro Forma (attached as Appendix F) at Section 6.01(a). 68 Id. at Exhibit A.
44
Consistent with SCE’s focus on safety, SCE’s 2019 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.69
SCE also has a safety section in its 2019 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
2019 Pro Forma.70
XV.
COMMENTS ON COORDINATION WITH INTEGRATED RESOURCE PLANNING
PROCEEDING
The ALJ’s Ruling, in OP 2, orders that parties may file Opening Comments on Coordination of
the RPS Procurement Plan with the IRP no later than July 19, 2019 and reply comments on the same
issue no later than August 2, 2019.71 SCE will incorporate the Commission’s findings on this matter in
its Final 2019 RPS Plan and will offer comments on July 19, 2019.
XVI.
AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS
A. Justification of SCE’s Request for Pre-Approval Or Tier 3 Approval Process for Certain
RPS-Eligible Transactions
SCE requests authorization to enter into a limited quantity of renewable energy transactions for
REC products through a Tier 1 or Tier 3 Advice Letter approval process.
SCE seeks to use the Tier 1 process for all transactions that meet the following strict upfront
standards and criteria:
Transactions through an RFO or Bi-lateral contracts subject to the following:
69 Id. at Section 4.01(d). 70 See 2019 Procurement Protocol (attached as Appendix H.1) at Section 9.03. 71 ALJ’ Ruling, OP 2, p.3.
45
Term would be limited to transactions through the next full CP (CP 4 ending
2024)
Transactions through RFOs, awards would only be made to projects with offers at
or above the price floor as set forth in Appendix E.
Bi-lateral contracts would only be entered into after an RFO was held under this
2019 RPS Plan
Transactions with term lengths that extend beyond the end of the next CP (CP 4 ending 2024) or
do not otherwise meet the above criteria would be subject to a Tier 3 Advice Letter approval process.
SCE notes that the price floor set forth in Appendix E is an interim step pending the outcome of
the PCIA decision. To the extent that the PCIA decision, on Track 3, addresses a new price floor, SCE
will adopt that new price floor.
1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The
Foreseeable Future
SCE is well positioned to meet the CP 3 2020 33% RPS target with existing projects and
projects under development (risk-adjusted). Therefore, SCE did not hold an RPS procurement
solicitation for the 2016, 2017 and 2018 cycles. SCE forecasts that it will have excess RECs at least
through 2028 without the use of its REC bank and through CP 6 (2028-2030) and beyond with the use of
the REC bank for compliance purposes using SCE’s assumptions.
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
adjust the portfolio quickly using short term products. Until recently,72 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 and there was not significant depth in
72 D.17-06-026.
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the short-term markets. Large LSEs instead used the banking rules to build portfolios to account for
uncertainties in project development, load forecasts and production. This led to the development of
banked positions that also resulted in an inability to use short-term products to meet any future needs
due to RPS retirement rules. New legislation (SB 350) adopted in 2016 removed these barriers.
A combination of long-term and short-term procurement will allow LSEs to build more
cost-effective portfolios for customers. Long-term procurement can focus on bringing new projects
online. Short-term procurement can focus on balancing the portfolio to meet compliance requirements
at the lowest possible cost. This combination of long-term and short-term procurement will also allow
for a free exchange of RECs between different entities who may have over/under procured for their
compliance needs.
The Commission’s RPS compliance reports demonstrate the state’s progress in meeting
its aggressive RPS procurement targets, driven by the investments made by the three large IOUs in
California. Currently all IOUs are long for RPS energy, and some ESPs and/or CCAs may need RECs
to meet compliance requirements soon, as well as meeting their additional sustainability goals that many
have set forth - above and beyond their compliance requirements. Allowing for the free trade of these
long positions between LSEs will allow for a lower cost outcome for all customers. An open market
will provide for a lower cost and flexible option for meeting RPS requirements.
In addition, all retail sellers must procure a minimum level of PCC 1 RECs; the minimum
level increases over multi-year compliance periods.73 For CP 3, the minimum requirement for PCC 1
procurement is 75%, which is higher than previous compliance periods. Also, there is a maximum limit
on the amount of PCC 3 procurement that may be used in each compliance period, which decreases over
the same time frame. As a result, entities cannot solely depend on PCC 3 RECs acquired towards the
end of a CP. Any newly formed entity during the CP 3 timeframe (2018-2020) will have to meet the
same requirements for RPS compliance as described. Most of these requirements will have to be met
using existing facilities, since development of new projects (i.e., siting, licensing, construction,
73 CAL. PUB. UTIL. CODE § 399.16(c).
47
contracting) is a time-consuming process that will likely not be able to be completed in time to meet the
33% RPS compliance requirement by 2020. Accordingly, it is important for all market participants to
have access to purchase RECs sourced from existing facilities to avoid potential market distortions and
compliance shortfalls.
In addition, as discussed in Section III above, beginning in 2021, SB 350, as implemented
in D.17-06-026, requires that all entities must meet 65% of their RPS target with eligible renewable
resources having long-term contracts or ownership arrangements of 10 years or more. Accordingly, it is
important for all market participants to have access to purchase long-term RECs sourced from existing
facilities either for the duration of a contract for a specific facility or for 10 years for non-project specific
contracts to avoid potential market distortions.
3. REC Sales Will Create Customer Value
a) Selling is better than banking up to the established limits
When SCE considers whether to engage in sales of renewable energy products,
SCE compares the value obtained from selling RECs to the costs of having to procure additional
renewable energy in the future. SCE analyzes the impact to its renewable needs and the costs to
customers using 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
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assumptions include, but are not limited to, lower performance of existing resources than expected,
lower risk-adjusted project success rates for contracted generation that is not yet online, and higher
levels of curtailment than expected. SCE assesses its renewable procurement position with such adverse
assumptions to ensure that, even in a sub-optimal scenario, SCE would still expect to meet its RPS
targets after making the sale. SCE’s overall approach appropriately balances the risks and costs of
selling renewable energy products with the risks and costs of maintaining an RPS bank.
b) REC Sales Stabilize Rates By Realizing Near Term Value
SCE has a REC bank beyond CP 6 (2028-2030)74 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
and SB 100. As a result, REC sales can help create near term value and in turn create near term rate
relief for SCE customers. SCE holds a significantly long position to meet compliance needs in the near
term. If SCE can generate some revenues through REC sales, it will help smooth out SCE’s RPS
compliance positions over these coming years. In turn, these REC sales would smooth out the rate
impacts over the years to SCE’s customers because RECs from more expensive contracts would be sold
and replaced with cheaper renewable energy for compliance for future years, taking advantage of
declining renewable prices.
c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could Help
Lower Costs for Customers, While Requiring Other LSEs to Use More Long-term
Products
SB 35075 requires that 65% of the total renewable portfolio that a retail seller
counts toward the RPS target for each compliance period must be from long-term contracts, starting no
later than 2021. The previous long-term contracting requirement for retail sellers was smaller - 0.25%
of prior period’s total retail sales.
74 See Section IV.A, above. 75 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416.
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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.76 Any retail seller making
such an election must, however, meet the 65% long-term contracting requirement.77 Short-term
contracts would facilitate the following types of projects/products to count toward RPS targets:
Seven-year renewable QF 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, 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.
d) SCE Was Directed to Sell BioRAM RECs
D.18-12-003 directed SCE to sell the RECs associated with its BioRAM contracts
as PCC 1 RECs as soon as possible after issuance of the Decision.78 BioRAM associated REC sales are
to be filed with the Commission as a Tier 1 Advice Letter so long as the contract:
1. utilizes a Commission-approved RPS Sales pro forma agreement;
2. shows any necessary modifications to the pro forma agreement via a
comparison document provided with the Tier 1 filing; and
3. is for a duration of five years or less.79
In its REC Sale Solicitation (“REC RFO”), SCE will allow buyers to bid on
RECs: i) that are generated solely from BioRAM projects; or ii) that are generated solely from
76 Id. at OPs 15-24, at pp. 54-56. 77 Id. at CoL 6, at p. 42. 78 D.18-12-003, at p. 12. 79 Id.
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renewable resources other than BioRAM projects. REC sales generated from renewable resources other
than BioRAM projects will be subject to the price floor as set forth in Table XVI-4. RECs generated
solely from BioRAM projects are not subject to the price floor set forth in Table XVI-4.
B. REC Sales Framework
1. REC Sales Framework
The REC Sales Framework approved in D.19-12-042, OP 19,80 includes terms, volume
limits, and a pricing floor as summarized in Table XVI-3 below:
80 D.19-12-042, OP 19, pp. 90-91.
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Table XVI-3 Commission-Adopted REC Sales Framework
Parameter Approved 2019 RPS Plan
Transaction mediums RFO Process, Bilateral (strong showing)
Terms 5 years or less
Sales Volume Limit Methodology based on a per-vintage year basis. SCE will maintain a compliance margin amount. Attempt to sell all RECs from BioRAM projects.
PRG Consultation Quarterly, at PRG meetings
Parameter Approved 2018 RPS Plan
Pricing Confidential Pricing floor as set forth in Appendix E
Approval Process Tier 1 if sold through solicitation. All others, Tier 3.
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2. Tier 3 Approval Process
SCE may also engage in bilateral REC sales transactions that do not utilize the pro forma
REC Sales Agreement attached as Appendix I to this Written Plan, have term lengths that extend beyond
2024, do not conform to the price floor constraints as set forth in Appendix E, or that are not executed
after SCE received bids for a sales solicitation resulting from this 2019 RPS Plan.81 These bilateral REC
sales transactions would be subject to the Commission’s review and approval of completed transactions
through a Tier 3 Advice Letter process (consistent with D.09-06-050).82
C. SCE’s Proposed Limits on REC Sales
Appendix E, Section II describes and provides an example calculation of the REC sales volume
limit on a per-vintage year basis, as ordered by D.19-12-042, OP 28. SCE will attempt to sell all of its
BioRAM RECs.
D. Acceptable REC pricing
Appendix E, Section III sets out the confidential pricing standard for SCE’s REC sales, as
adopted in D.19-012-042, OP 28.
E. Proposed Transactional Methods
SCE proposes two 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 and Electronic Solicitations
SCE proposes to maximize value to its customers through competitive solicitations and
electronic 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
81 See, D.19-02-007, pp. 116-117, OP 10. 82 Id.
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mandated procurement, non-competitive programs. Typically, these programs may focus on specific
technologies or project size. Conversely, SCE’s RPS Solicitations have consistently brought the lowest
renewable prices through the competitive bidding process. Similarly, higher prices may be realized
through a competitive solicitation when SCE sells RECs. Additionally, a competitive solicitation will
allow SCE to discover where the market is, in terms of the prices buyers are willing to pay for RECs.
2. Bilateral Transactions
In certain instances, SCE may accept bilateral offers to purchase RECs. For example, if
there are a small number of interested parties in the REC market or deadlines are approaching where an
interested party needs to purchase RECs, to meet a unique need, prior to a solicitation being launched.
These and other situations may lead to SCE selling RECs bilaterally rather than through a competitive
process.
F. Proposed Timeline for REC Sales
SCE’s Procurement Protocol (the form of which is included in Appendix J) sets out a proposed
timeline for any REC Sales done through an RFO. Bilateral REC sales transactions would occur
following Commission approval of SCE’s 2019 RPS Plan.
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.83 The Commission also authorized the IOUs to use an optional
streamlined RAM procurement tool in future RPS solicitations.84 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.85
83 See D.14-11-042 at pp. 91-92, pp. 102-104. 84 Id. at pp. 91-92. 85 Id. at p. 92.
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Since the Standard Contract Option is part of the RPS Solicitation, it only gets utilized when
SCE holds a solicitation. Consistent with the Commission’s intent to provide the IOUs with flexibility
to optimize their portfolios based on their procurement needs while providing a streamlined procurement
tool,86 the Standard Contract Option allows 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.87
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.”88 If SCE holds a procurement for Community Renewables, SCE
will use the Standard Contract Option for GTSR procurement needs as discussed in Section XVIII. SCE
may also use the Standard Contract Option to fulfill other authorized procurement needs in the future.
86 Id. 87 SCE’s 2018 Pro Forma is structured with the assumption that the generating facility will have a first point of
interconnection with the CAISO. Accordingly, changes to the 2018 Pro Forma will be required for dynamically scheduled projects.
88 D.14-11-042 at p. 92.
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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.89
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 2019 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 2019 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 2019, SCE made changes to the 2018 Pro Forma that are applicable to the Standard Contract
Option. Please see Section I.B.
89 Id. at p. 93.
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XVIII.
GREEN ENERGY TARIFF PROGRAMS
A. Green Tariff Shared Renewable and Community Renewable Programs
On September 28, 2013, Governor Brown signed SB 43 into law.90 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.91 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”92 (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.93
The GTSR program structure approved by the Commission consists of two elements: (1) a green
tariff option (called the “Green Rate” or “GR” 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
90 SB 43 was codified in California Public Utilities Code Section 2831 et seq. 91 See D.15-01-051 at OP 7. 92 CAL. PUB. UTIL. CODE § 2833(d)(1). 93 See D.15-01-051 at OP 7 and D.15-01-051 at pp. 4-5.
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community-based projects.94 With regard to the Green Rate, SCE procured its 50 MW advance
procurement requirement in its 2015 RPS solicitation. SCE does not anticipate doing additional Green
Rate procurement. This is because the Green Rate program currently has a limited number of
subscribed customers and SCE’s advance procurement is expected to satisfy initial customer enrollment.
1. 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.95 The Commission limited initial procurement to new solar facilities between 0.5 MW and
3 MW,96 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.97 Additionally, now that the CAISO has resolved Distributed Energy Resource Provider
issues, D.16-05-006 allows for aggregation of sub-500 kW resources to participate in the CR program as
long as they aggregate to at least 500 kW and meet all CAISO requirements.98 CR projects must be
located within SCE’s service territory99 and must satisfy the eligibility requirements associated with the
RAM procurement tool.100
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;101
(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
94 Id. at pp. 3-4. 95 Id. at OP 1. 96 Id. at pp. 36-37, p. 39, CoL 17. 97 See D.16-05-006, CoLs 2 and 4. 98 Id. at OP 5. 99 See D.15-01-051 at pp. 21-23, CoL 14. 100 See D.16-05-006 at p. 35, CoL 4. 101 Advice 3180-E was approved by Energy Division, effective as of February 23, 2015.
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SCE’s Marketing Implementation Advice Letter;102 (v) Advice 3432-E, which is the 20 Year Forecast of
GTSR bill credits and charges;103 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.104
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;105 (ii) Advice 3496-E, 2017 annual marketing,
education and outreach plan and budget for the GTSR program;106 (iii) Advice 3525-E, which is SCE’s
GTSR program rate component updates for 2017;107 (iv) Advice 3525-E-A, supplemental filing to make
modifications to Advice 3525-E;108 (v) Advice 3536-E, which implements the California alternate rates
for energy for the GTSR Program;109 (vi) Advice 3557-E, which updated the CR-RAM Rider and RFO
Instructions for CR-RAM Two;110 (vii) Advice 3614-E, which is the update to the 20 Year Forecast of
GTSR bill credits and charges;111 (viii) Petition for Modification (“PFM”) for D.15-01-051 to change
102 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution E-4734. 103 Advice 3432-E was approved by Energy Division, effective as of July 11, 2016. 104 Advice 3422-E was approved by Energy Division, effective as of June 15, 2016. 105 Advice 3461-E was approved by Energy Division, effective as of September 25, 2016. 106 Advice 3496-E was approved by Energy Division, effective as of November 27, 2016. 107 Advice 3525-E was approved by Energy Division, effective as of January 1, 2017. 108 Advice 3525-E-A was approved by Energy Division, effective as of January 1, 2017. 109 Advice 3536-E was approved by Energy Division, effective as of October 26, 2017. 110 Advice 3557-E was approved by Energy Division, effective as of March 12, 2017. 111 Advice 3614-E was approved by Energy Division, effective as of June 5, 2017.
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the AmLaw 100112 securities opinion requirement;113 (ix) Advice 3638-E, modifying the securities
opinion requirement in the CR-RAM Rider pursuant to D.17-07-007;114 (x) Advice 3694-E, which
updated the CR-RAM Rider and RFO Instructions for CR-RAM Three;115 (xi) Advice 3678-E, 2018
annual marketing, education and outreach plan and budget for the GTSR program;116 (xii) Advice 3678-
E-A, supplement to Advice 3678-E;117 (xiii) Advice 3710-E, updating the GTSR program rate
components for 2018;118 (xiv) Advice 3710-E-A, supplement to Advice 3170-E;119 (xv) Advice 3737-E,
which updated the 20-year forecast of GTSR bill credits and charges;120 (xvi) Advice 3790-E, which
updated the CR-RAM Rider and RFO Instructions for CR-RAM Four,121 (xvii) Advice 3891-E, which
updated the CR-RAM Rider and RFO Instructions for CR-RAM Five,122 (xviii) Advice 3877-E, SCE’s
2019 annual marketing, education and outreach plan and budget for the GTSR program,123 (xix) Advice
3878-E seeking approval of a PPA from the CR-RAM 3 solicitation,124 (xx) Advice 3905-E, SCE’s
GTSR program rate component updates for 2019,125 (xxi) Advice 3905-E-A, supplements Advice 3905-
112 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United States
based on gross revenue. 113 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. 114 Advice 3638-E was approved by Energy Division, effective as of July 28, 2017. 115 Advice 3694-E was approved by Energy Division, effective as of November 15, 2017. 116 Advice 3678-E was approved by Energy Division, effective as of November 15, 2017. 117 Advice 3678-E-A was approved by Energy Division, effective as of November 15, 2017. 118 Advice 3710-E was approved by Energy Division, effective as of January 1, 2018. 119 Advice 3710-E-A was approved by Energy Division, effective as of January 1, 2018. 120 Advice 3737-E was approved by Energy Division, effective as of January 31, 2018. 121 Advice 3790-E was approved by Energy Division, effective as of May 20, 2018. 122 Advice 3891-E was approved by Energy Division, effective as of December 31, 2018. 123 Advice 3877-E was approved by Energy Division, effective as of November 14, 2018. 124 SCE submitted Advice 3878-E on October 16, 2018. The Advice letter has not been approved as of the date
of this filing. 125 Advice 3905-E was approved by Energy Division, effective as of January 7, 2019.
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E,126 (xxii) Advice 3962-E, which updated the 20-year forecast of GTSR bill credits and charges,127
(xxiii) Advice 3898-E, which requests to update the GTSR Tariff to remove language regarding the
programs’ closure as of January 1, 2019,128 and (xxiii) Advice 3976-E approving a PPA from the CR-
RAM 4 solicitation.129
2. Community Renewables - Modifications to the 2019 Procurement Protocol, 2019
Pro Forma Standard Contract Option, and LCBF Methodology
SCE incorporated CR-related modifications into its 2016 Procurement Protocol, created a
CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option, and incorporated
modifications to its LCBF Methodology for CR and CR-EJ eligible projects. SCE planned to include a
Community Renewables solicitation in any 2016 RPS solicitation that it would hold after seeking and
receiving Commission permission. SCE intended that if it did not go forward with a 2016 RPS
solicitation, it would move forward separately with a second Community Renewables Solicitation,
which SCE launched on April 7, 2017.
SCE incorporated additional CR-related modifications into its 2017 Procurement
Protocol and updated its CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option,
which is the latest approved contract option. SCE subsequently launched its third, fourth, and fifth
Community Renewables Solicitations on December 22, 2017, May 23, 2018, and January 14, 2019
respectively. As of CR-RAM 3, SCE has provided two CR-RAM Rider options to offerors—one
specifically for Distributed Energy Resources (“DERs”) and the other for projects that do not aggregate
resources.
126 Advice 3905-E-A was approved by Energy Division, effective as of January 7, 2019. 127 Advice 3962-E was approved by Energy Division, effective as of February 28, 2019. 128 Advice 3898-E was approved by Energy Division, effective as of November 20, 2018. 129 Advice 3976-E was approved by Energy Division, effective as of April 27, 2019.
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a) 2019 Procurement Protocol – CR Modifications
The 2019 Procurement Protocol does not include any requirements applicable
only to CR and CR-EJ projects. If SCE holds a CR-RAM Solicitation, SCE will file an Advice Letter
and include a CR-RAM specific protocol.
3. SCE’s Request to Terminate the GTSR Program and Required Modifications to
GTSR
On December 22, 2017, SCE filed a Tier 3 Advice 3722-E requesting the Commission’s
approval to terminate the GTSR program on January 1, 2019,130 and to seek approval to recover
outstanding GTSR costs through the 2018 ERRA Review of Operations Filing.131 In that letter, SCE
explained that it would seek Commission approval in 2018 for new programs to replace its GTSR
Program, which it did (described in Section XVIII.E below). On December 22, 2017 and December 26,
2017, respectively, PG&E and SDG&E filed Tier 3 advice letters seeking to extend GTSR beyond
January 1, 2019 and to make modest modifications to the program.132 On August 20, 2019, Energy
Division issued Draft Resolution E-5028 which, if approved, will deny SCE’s request to terminate
GTSR and will require the three IOUs to make certain modifications to GTSR.
4. Adjustment to RPS Load Forecast for GTSR and CR Program
As discussed in Chapter IV, Section A, SCE adjusted its RPS load forecast to remove
customer load served under the Green Tariff portion of the GTSR program.133 This is consistent with SB
43 and intentions of the GTSR and CR programs, which require the utilities to retire the RECs from
subscribed energy on behalf of the subscribing customers.134 SB 43 thus allows the utility to “exclude
from total retail sales the kilowatt hours generated by an eligible renewable energy resource that is
130 See D.15-01-051 at OP 13. 131 Advice 3722-E. As of the date of this filing, Advice 3722-E is pending Commission approval. 132 See PG&E Advice 3920-G/5206-E and SDG&E Advice 3168-E. 133 No customers are presently being served under the Community Renewables Rate. As a result, SCE only
counted Green Rate customers here. 134 See CAL. PUB. UTIL. CODE § 2833(s).
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credited to a participating customer pursuant to the utility’s green tariff shared renewables program,
commencing with the point in time at which the generating facility achieves commercial operation.”135
Consistent with SB 43, SCE reduced its bundled retail sales forecast used to calculate its RPS goals by
the amount of energy used to serve Green Rate customer load.136 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.137 Prior to dedicated resources procured to serve Green Rate
customers beginning service, SCE transferred RECs from other RPS-eligible resources in its Interim
Green Rate Pool to serve Green Rate subscriptions. In March 2018, one dedicated Green Rate resource
became operational. SCE expects to begin transferring RECs from this dedicated Green Rate resource in
2019 for 2018 customer subscriptions.
B. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar Programs
On June 21, 2018, the Commission approved D.18-06-027, Alternate Decision Adopting
Alternatives to Promote Solar Distributed Generation in Disadvantaged Communities, which
implements three new programs to promote solar energy in disadvantaged communities. On June 3,
2019, the Commission issued Resolution E-4999 approving with modifications the tariffs filed by the
IOUs to implement two of the three programs – the DAC-GT and CSGT programs. These programs
provide bill credits to eligible customers who elect to take service under SCE’s DAC-GT or CSGT
tariffs.
Under the DAC-GT program, eligible customers138 may have 100% of their load served by
eligible renewable resources. They will receive a 20% bill credit off their otherwise applicable rate.
SCE’s program size is 56.5 MW.
135 CAL. PUB. UTIL. CODE § 2833(u). 136 Id. 137 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.
138 The DAC-GT program is open to customers who are eligible for CARE or FERA, and who reside in an eligible DAC.
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Like the DAC-GT program, the CSGT program provides a 20% bill credit to eligible
customers139 who “subscribe” to the output of a community renewable facility located within an eligible
DAC. Additionally, the CSGT program requires the sponsorship of the solar facility by a community
sponsor, who can attest to community interest in the project. The community sponsor(s), if eligible, may
share in the bill credits for up to 25% of a CSGT project’s output Any RECs from unsubscribed energy
procured through the DAC-GT and CSGT programs that is not subscribed by SCE customers (“DAC
Programs Excess Energy”) will be allocated to SCE’s RPS position.
On July 3, 2019, SCE filed supplemental AL 3851-E-B to implement the modifications required
by Resolution E-4999. Also pursuant to Resolution E-4999, on August 2, 2019, SCE filed AL 4049-E
seeking approval of SCE’s DAC-GT and CSGT solicitation materials and AL 4050-E seeking approval
of SCE’s DAC-GT and CSGT budget for 2019-2020 and SCE’s Marketing, Education, and Outreach
Plan for the programs for 2019-2021.
Additionally, SCE filed Advice Letters 3841-E, 3841-E-A, and 3841-E-B establishing the DAC-
and CSGT Balancing Accounts. On July 11, 2019, Energy Division sent a letter approving ALs 3841-E,
3841-E-A, and 3841-E-B with an effective date of September 5, 2018.
1. Adjustment to RPS Load Forecast for DAC-GT and CSGT Programs
Like how SCE adjusts its load forecast to account for the load served under the GTSR
and CR programs, SCE proposes to adjust its RPS load forecast to remove customer load served under
the DAC-GT and CSGT programs. Although the provisions of SB 43 do not govern the DAC-GT and
CSGT programs, the rationale for adjusting the load forecast for the DAC programs equally applies.
Specifically, as with the GTSR and CR programs,140 SCE will be retiring the RECs from subscribed
energy on behalf of subscribing customers. Thus, it is reasonable for SCE to reduce its bundled retail
139 Customers must reside in an eligible DAC as defined in D.18-06-027 and Resolution E-4999, and live within
a census tract that is within a prescribed distance of the solar facility. Customers who reside in an eligible DAC, but who are not eligible for CARE or FERA may receive a bill credit once low income subscription levels are met.
140 No customers are presently being served under the Community Renewables Rate. As a result, SCE only counted Green Rate customers here.
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sales forecast used to calculate its RPS goals by the amount of energy used to serve DAC-GT and CSGT
customer load. Like the GTSR program, SCE will also deduct DAC-GT and CSGT subscriptions from
SCE’s generation forecasts to remove energy deliveries associated with the load served under the DAC-
GT and CSGT programs.
C. New Green Energy Programs
In Advice 3722-E, in which it requested the Commission’s approval to terminate the GTSR
program, SCE stated it would propose a replacement program for GTSR. On September 26, 2018, SCE
filed Application (“A.”) 18-09-015 seeking Commission approval of five new Green Energy Programs
to replace the existing GTSR program in 2021. On October 29, 2018 protests and responses were filed,
and a prehearing conference was held on December 3, 2018. On February 8, 2019 and February 15,
2019, respectively, SCE and other parties filed opening and reply briefs, as directed by ALJ Liang-
Uejio’s January 18, 2019 Ruling Directing the Filing of Legal Briefs, on whether SCE’s proposed new
programs need to comply with Public Utilities Code §§ 2281-2833, which resulted from SB 43
establishing the GTSR program. A scoping memo was issued on April 19, 2019. On June 3, 2019, The
Commission issued D.19-05-031 dismissing SCE’s application without prejudging the merits of SCE’s
proposals. SCE is considering whether to submit a new application proposing new green energy
programs that would not be intended to replace GTSR. SCE would not file any such application until
2020.
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
65
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 2024.141
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.142
C. Informational Only TOD Factors
1. Introduction
Pursuant to D.19-02-007, Ordering Paragraph No. 17, 143 adopting the 2018 RPS Plan,
the IOUs developed a joint proposal for informational only TOD Factors and mailed it to the service list
of this proceeding on May 30, 2019. D.19-012-042, OP 16 approved the Joint IOU Proposal.
2. The Joint IOU Information Only TOD Proposal
The Joint IOUs are proposing multiple sets of informational TOD heat maps in a month-
hour matrix for different years. The values in the heat maps provide information on the relative value of
electricity delivered during different hours and months while also capturing changes over a long-term
contract horizon. Hours in the heat maps with values closer to zero have a higher expectation of
curtailment. The proposed Joint IOU informational TOD heat map methodology is described below.
In general, creating the informational TOD heat maps will involve four steps:
a) Each IOU will use the Marginal Energy Cost (“MEC”)144 data from its most recent
General Rate Case (“GRC”) Phase II filing as the source data.
141 See D.13-10-040 at pp. 15, 26. 142 See Southern California Edison Company’s (U 338-E) Application for Approval of its 2018 Energy Storage
Procurement Plan (filed biennially). The Application can be located here: 2018 Energy Storage Procurement and Investment Plan.
143 D.19-02-007, OP 17, p.118. 144 The MEC data used in the GRC proceeding represents the energy price for an incremental unit of energy
needed to serve customer loads and includes the costs related to congestion and line losses.
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b) Each IOU will calculate the hourly average MEC over the entire year (8760 hours for
non-leap years) using their GRC dataset from Step 1. Each year will have two sets of
informational TOD heat maps: 1) Weekdays and 2) Weekends and Holidays. The month-
hour average for each of the weekdays and weekends & holidays will be divided by the
annual average. Any individual hours with a value less than zero will be set to zero
before computing the annual and month-hour averages.145
c) Each IOU will provide the informational TOD heat maps for three different years based
on each IOU’s GRC filing year (e.g., Year 1, Year 5, and Year 10). Therefore, a total of
six informational TOD heat maps will be provided from each IOU including two heat
maps for each year, one for weekdays and another for weekends and holidays.
d) Finally, each IOU will apply Microsoft Excel’s built-in heat map with default (i.e.
automatically suggested) formatting to all heat maps individually, with red indicating the
highest and green the lowest MEC, represented as a proportion of the annual average.
Due to existing GRC data availability, each IOU is initially providing the informational
TOD heat maps for two different years – 2020 and 2024 – instead of three different years as proposed
above to be done going forward. Following each future GRC filing in which one of the IOUs updates its
energy price forecast, each IOU will follow the general methodology described above and provide new
informational TOD heat maps for three different years in the next filing of its RPS Plan.
3. SCE’s Informational TOD Heat Maps
SCE used its 2018 GRC146 filing data to develop the informational TOD heat maps for
2020 and 2024 that are shown in Appendix K. SCE’s MEC forecasts were created using a fundamental
model of the CAISO system in Energy Exemplar’s PLEXOS software. Assumptions were populated for
145 This is done to take into account recent changes in the California Independent System Operator’s (“CAISO”) energy markets such as the expansion of the Energy Imbalance Market, which appear to be resulting in a soft floor of zero in Day-Ahead and Real-Time energy prices in the CAISO.
146 See SCE’s Phase 2 of 2018 General Rate Case Marginal Cost and Sales Forecast Proposals. Section C and Appendix C includes methodology, data source, and major input assumptions. MECs for test year 2021 were used in Phase 2 of SCE’s 2018 GRC.
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available generation, heat rates, system load, and fuel and GHG costs – minimized to achieve the lowest
system operating cost.
D. 19-12-042 ordered SCE to include in its final 2019 RPS Plan “new informational-only
TODs that are based on the most recent inputs that are available.”147 SCE includes its informational
only TOD factors from the IOUs’ Joint Proposal in Appendix K utilizing the most recent public price
forecasts that are available. Due to the unavailability of updated GRC Phase 2 pricing data, SCE is not
able to update the TODs in Appendix K at this time. SCE will have updated publicly available pricing
data when it submits its 2021 GRC Phase 2 later in 2020. SCE will refresh the informational TOD heat
maps with publicly available pricing information from its 2021 Phase 2 GRC filing148 and include the
update in its 2020 RPS Plan, as explained in the Joint IOUs’ Proposal.
The approved Joint IOUs’ Proposal includes using publicly available Phase 2 GRC
pricing data to develop the informational only TOD heat maps to avoid revealing utility’s proprietary
energy price forecasts which are protected for three years pursuant to the D.06-06-066 Matrix. The
Phase 2 GRC pricing data typically is consistent with SCE’s confidential energy price forecasts.
Informational TOD heat maps are intended to communicate to potential bidders when
energy delivery can be more valuable to the system. Heat maps depicting the relative magnitude of
factors between hours and months are more useful information than the actual factors themselves. The
Joint IOUs’ Proposal included heat map formatting with color schemes to visualize this information
more effectively.
147 D.19-12-042, OP 26, p. 95. 148 SCE’s GRC team is planning to file the 2021 GRC Phase 2 in June 2020. If updated pricing data from that
filing data is available in time, SCE will include the new informational only TOD factors in its 2020 Draft RPS plan.
PUBLIC APPENDIX A
Redline of Draft 2019 Written Plan
(U 338-E)
Draft 2019 Written Plan
June 21, 2019
Final 2019 Written Plan
January 29, 2020
PUBLIC VERSION
Appendix A - Page 1
2019 DraftFinal Written Plan Table Of Contents (Continued)
Section Page
i
I. SUMMARY OF KEY UPDATES...................................................................................................1
A. Important Changes in the Written Plan ..............................................................................21
1. Inclusion of Informational-Only Time-of-Use Factors ..........................................21
2. Revisions to REC Sales Strategy .............................................................................2
B. Important Changes in 2019 Pro Forma ...............................................................................3
C. Important Changes in 2019 Pro Forma REC Sales Agreement ..........................................3
D. Important Changes to Discussion of Disadvantaged Communities Green Tariff and Community Solar Green Tariff ...........................................................................4
II. EXECUTIVE SUMMARY OF 2019 DRAFT RPS PLAN ...........................................................45
III. SUMMARY OF RECENT LEGISLATIVE AND/OR REGULATORY CHANGES .....................................................................................................................................67
IV. ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND .......................................910
A. Portfolio Supply and Demand ..........................................................................................910
B. Alignment with Load Curves .........................................................................................1416
C. Responsiveness to Policies, Regulations, and Statutes ..................................................1516
D. Portfolio Diversity .........................................................................................................1718
E. Lessons Learned.............................................................................................................2022
1. Possible Future Trend Toward Departing Load .................................................2122
2. Need for REC Sales ...........................................................................................2324
V. PROJECT DEVELOPMENT STATUS UPDATE ...................................................................2425
VI. POTENTIAL COMPLIANCE DELAYS ..................................................................................2425
A. Curtailment ....................................................................................................................2526
B. Permitting, Siting, Approval, and Construction of Renewable Generation Projects and Transmission .............................................................................................2527
C. A Heavily Subscribed Interconnection Queue ...............................................................2627
Appendix A - Page 2
2019 DraftFinal Written Plan Table Of Contents (Continued)
Section Page
ii
D. Developer Performance Issues .......................................................................................2628
E. Load Uncertainty Including Faster Implementation of Transportation Electrification And Departing Load ...............................................................................2729
VII. RISK ASSESSMENT ................................................................................................................2829
VIII. QUANTITATIVE INFORMATION .........................................................................................2830
A. RNS Calculations ...........................................................................................................2830
B. Response to RNS Questions ..........................................................................................2931
1. How do current and historical performance of online resources in your RPS portfolio impact future projection of RPS deliveries and your subsequent RNS? .......................................................................................2931
2. Do you anticipate any future changes to the current bundled retail sales forecast? If so, describe how the anticipated changes impact the RNS. .............................................................................................................3031
3. Do you expect curtailment of RPS projects to impact your projected RPS deliveries and subsequent RNS? ................................................3032
4. Are there any significant changes to the success rate of individual RPS projects that impact the RNS? ...................................................................3133
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? ................................3233
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. ...........................................................................3234
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. ..................................................................................................3334
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. ...................................3435
Appendix A - Page 3
2019 DraftFinal 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. ...................................................3435
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? ..........................................................................3436
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? ..............................................................................3536
IX. MINIMUM MARGIN OF PROCUREMENT ..........................................................................3537
X. BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES ...................3638
A. Solicitation Protocol for REC Sales ...............................................................................3638
B. Procurement Protocol.....................................................................................................3739
C. LCBF Criteria ................................................................................................................3739
1. Workforce Development ....................................................................................3840
2. Disadvantaged Communities .............................................................................3840
XI. CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS ..........................................3940
XII. CURTAILMENT, FREQUENCY, COSTS AND FORECASTING ........................................3941
XIII. COST QUANTIFICATION ......................................................................................................4143
XIV. SAFETY CONSIDERATION ...................................................................................................4143
XV. COMMENTS ON COORDINATION WITH INTEGRATED RESOURCE PLANNING PROCEEDING .....................................................................................................4244
XVI. AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS .....................................4344
A. Justification of SCE’s Request for Pre-Approval Or Tier 3 Approval Process for Certain RPS-Eligible Transactions .............................................................4344
1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The Foreseeable Future ....................................................................4445
Appendix A - Page 4
2019 DraftFinal Written Plan Table Of Contents (Continued)
Section Page
iv
2. California Customers Need an Open Market for RECs .....................................4445
3. REC Sales Will Create Customer Value ............................................................4647
a) Selling is better than banking up to the established limits .....................4647
b) REC Sales Stabilize Rates By Realizing Near Term Value ..................4748
c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could Help Lower Costs for Customers, While Requiring Other LSEs to Use More Long-term Products......................................................................................................48
d) SCE Was Directed to Sell BioRAM RECs ................................................49
B. SCE’s Proposal ..................................................................................................................49
1. Pre-Approval ..........................................................................................................49
B. REC Sales Framework .......................................................................................................50
1. REC Sales Framework ...........................................................................................50
2. Tier 3 Approval Process.....................................................................................5152
C. SCE’s Proposed Limits on REC Sales ...........................................................................5152
D. Acceptable REC pricing ................................................................................................5152
E. Proposed Transactional Methods ...................................................................................5152
1. Competitive Solicitations and Electronic Solicitations ..........................................52
2. Bilateral Transactions ........................................................................................5253
3. Brokers and Exchanges ..........................................................................................52
F. Proposed Timeline for REC Sales .....................................................................................53
XVII. STANDARD CONTRACT OPTION............................................................................................53
A. Procurement Need ..............................................................................................................54
B. Standard Contract...............................................................................................................55
XVIII. GREEN ENERGY TARIFF SHARED RENEWABLE PROGRAMPROGRAMS .....................56
Appendix A - Page 5
2019 DraftFinal Written Plan Table Of Contents (Continued)
Section Page
v
A. Green Tariff Shared Renewable and Community Renewable Programs ...........................56
1. Community Renewables - Background .................................................................57
B2. Community Renewables - Modifications to the 2019 Procurement Protocol, 2019 Pro Forma Standard Contract Option, and LCBF Methodology ..........................................................................................................60
1.a) 2019 Procurement Protocol – CR Modifications ...................................6061
C3. SCE’s Request to Terminate the GTSR Program and Required Modifications to GTSR ..........................................................................................61
D
4. Adjustment to RPS Load Forecast for GTSR and CR Program ............................61
B. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar Programs ...................................................................................................................61
E. SCE’s GTSR Replacement Program .............................................................................6262
1. Adjustment to RPS Load Forecast for DAC-GT and CSGT Programs ................................................................................................................63
C. New Green Energy Programs ............................................................................................64
XIX. OTHER RPS PLANNING CONSIDERATIONS AND ISSUES .............................................6264
A. Bilateral Transactions ....................................................................................................6264
B. Energy Storage Procurement .........................................................................................6264
C. Informational Only TOD Factors ...................................................................................6365
1. Introduction ........................................................................................................6365
2. The Joint IOU Information Only TOD Proposal ...............................................6365
3. SCE’s Informational TOD Heat Maps ...............................................................6566
Appendix A - Page 6
2019 DraftFinal Written Plan Table Of Contents (Continued)
Section Page
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CONFIDENTIAL/PUBLIC APPENDIX A REDLINE OF DRAFT 20182019 WRITTEN PLAN
PUBLIC APPENDIX B PROJECT DEVELOPMENT STATUS UPDATE
CONFIDENTIAL/PUBLIC APPENDIX C.1 RENEWABLE NET SHORT CALCULATIONS BASED ON CPUC ASSUMPTIONS
CONFIDENTIAL/PUBLIC APPENDIX C.2 RENEWABLE NET SHORT CALCULATIONS BASED ON SCE ASSUMPTIONS
CONFIDENTIAL/PUBLIC APPENDIX D COST QUANTIFICATION TABLE
CONFIDENTIAL APPENDIX E RENEWABLE ENERGY SALES
CONFIDENTIAL APPENDIX E.1 REDLINE OF RENEWABLE ENERGY SALES
PUBLIC APPENDIX F 2019 PRO FORMA RENEWABLE POWER PURCHASE AGREEMENT
PUBLIC APPENDIX G.1 SCE’S 2019 LEAST-COST BEST-FIT METHODOLOGY
PUBLIC APPENDIX G.2 REDLINE OF SCE’S 2018 LEAST-COST BEST-FIT METHODOLOGY
PUBLIC APPENDIX H.1 2019 PROCUREMENT PROTOCOL
PUBLIC APPENDIX H.2 REDLINE OF 2018 PROCUREMENT PROTOCOL
PUBLIC APPENDIX I
2019 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT
PUBLIC APPENDIX I.1
REDLINE OF 2019 PRO FORMA RENEWABLE ENERGY CREDITS SALES AGREEMENT
PUBLIC APPENDIX J NEW REC SALES PROCUREMENT PROTOCOL
PUBLIC APPENDIX K INFORMATION ONLY TOD FACTORS
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I.
SUMMARY OF KEY UPDATES
In accordance with the Assigned Commissioner and Assigned Administrative Law Judge’s
Ruling Identifying Issues and Schedule of Review for 2019 Renewables Portfolio Standard (“RPS”)
Procurement Plans, dated April 19, 2019 (“ACR”) and, the Administrative Law Judge’s Ruling
Modifying Schedule, dated May 7, 2019 (“ALJ’s Ruling”), and Decision No. (“D.”) 19-12-042,
Southern California Edison Company’s (“SCE’s”) DraftFinal 2019 RPS Procurement Plan (“2019 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.
SCE, at present, has no need for more eligible renewable resources. As a result, SCE does not
propose to hold a 2019 RPS solicitation. Instead, in this RPS proceeding, SCE seeks permission to sell
SCE’s Renewable Energy Credits (“RECs”), as discussed in Section XVI below. SCE’s RECs Sales
proposal does include some revisions, including requesting the ability to transact through additional
mediums and pre-approval of REC sales. The additional transaction mediums include brokers,
exchanges, and electronic solicitations. SCE proposes to conduct such REC sales in accordance with
strict upfront standards and criteria. SCE requests these changes because the marketplace for REC sales
has changed significantly. Due to load migration to Community Choice Aggregators (“CCAs”) and
Direct Access (“DA”) expansion, SCE is very long on RECs. CCAs and other Energy Service Providers
(“ESP”) are actively seeking RECs. The ability to conduct sales through brokers and utilize pre-
approval review of sales will allow more flexibility to transact, allow SCE access to more markets,
provide approval efficiency, all while maximizing customer value.SCE’s 2019 RPS Plan includes a new
2019 Bundled RPS Energy Sales Solicitation Instructions (“REC Sales Protocol”) and changes to: (1)
SCE’s 2018 Pro Forma Renewable Power Purchase Agreement (“PPA”); and (2) SCE’s Least Cost Best
Fit (“LCBF”) Methodology; and (3) SCE’s 2018 Pro Forma REC Sales Agreement. Those changes are
summarized below. SCE’s 2019 Pro Forma REC Sales Agreement remains unchanged from SCE’s
2018 Pro Forma REC Sales Agreement. SCE has included a redline of its LCBF Methodology against
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the 2018 version of the document included in SCE’s 2018 RPS Plan as Appendix G.2. The most
significant changes to the other 2018 documents are summarized below.
A. Important Changes in the Written Plan1
1. Inclusion of Informational-Only Time-of-Use Factors
Pursuant to Decision (“D.”) 19-02-007, Ordering Paragraph (“OP”) No. 17,12 adopting
the 2018 RPS Plan, the Investor Owned Utilities (“IOUs”)23 developed a joint proposal for
informational Time of Delivery (“TOD”) heat maps and mailed it to the service list of this proceeding
on May 30, 2019.4 D.19-12-042 ordered SCE to include in its final 2019 RPS Plan “new informational-
only TODs that are based on the most recent inputs that are available.”5 SCE includes its informational
only TOD factors from the IOUs’ joint proposal in Appendix K. SCE may modify the informational
TOD heat maps in Appendix K depending upon the outcome of the California Public Utilities
Commission’s (“Commission’s”) review of themwas unable to change the TODs as no more recent
inputs are available at this time. SCE provides more detail on development of the informational TOD
heat maps, including its proposed methodology,and the availability of new inputs in Section XIX.C.
2. Revisions to REC Sales Strategy
In this 2019 RPS Plan, SCE generally proposes sale of all three Portfolio Content Categories
(“PCCs”)36 of RECs as it did in its 2018 RPS Plan (rather than just PCC 1 RECs, as it proposed in the
1 The Written Plan consists of this document without its attached appendices. 12 D.19-02-007, OP 17, p.118. 23 The IOUs are the Investor-Owned Utilities, which include Pacific Gas and Electric Company (“PG&E”),
SCE, and San Diego Gas & Electric Company (“SDG&E”). 4 Final Decision on 2019 Renewables Portfolio Standard Procurement Plans (D.19-12-042) approved the Joint
IOU’s Proposal in OP 26. 5 D.19-12-042, OP 26, p. 95. 36 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”)
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2017 RPS Plan). Although SCE has not sold PCC 3 RECs due to the seemingly low value of those
RECs as reflected in throughby benchmarking companies and broker quotes available to it, SCE wants
the flexibility to sell PCC 3 RECs in case market conditions change or it otherwise makes sense for
SCE’s customers. As explained in more detail in Section XVI, SCE proposes to: i) sell RECs through
the end of the next full Compliance Period (“CP”), which presently is CP 4 ending 2024 (if there is a
market for such sales); ii) make changes to its price floor methodology; and iii) enter into pre-approved
renewable energy transactions for RECs meeting strict upfront standards and criteria. SCE also requests
authorization to enter into a limited quantity of short-term (3 years or less) renewable energy
transactions for REC products transacted through brokers and exchanges. . Finally, in compliance with
D.18-12-003 on the Tree Mortality Non-Bypassable Charge (“TM NBC”),47 SCE intends to sell RECs
and related energy associated with its BioRAM Bioenergy Renewable Auction Mechanism (“BioRAM”)
contracts.
B. Important Changes in 2019 Pro Forma
SCE’s 2019Unlike the 2018 Pro Forma Renewable Power Purchase Agreement (“PPA”), SCE’s
2019 Pro Forma Renewable PPA is based on the technology-neutral pro forma contract approved by the
California Public Utilities Commission (“Commission” or “CPUC”) in Resolution E-5004 for
contracting with distributed energy resources. Basing the 2019 Pro Forma Renewable PPA on the
technology neutral pro forma contract will improve contract administration and allow for better
comparisons across SCE’s different solicitations. The technology-neutral pro forma contract originally
included only solar resources. However, SCE modified it to include wind, geothermal and other
renewable resources.
The 2019 Pro Forma Renewable PPA is organized and formatted differently than the 2018 Pro
Forma Renewable PPA and, therefore, a redline comparison of the two documents would be of no help
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.
47 D.18-12-003, OP 4. pp. 26-27 on Application (“A.”) 16-11-005.
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in determining any changes made. Therefore, SCE has not included a redline in this 2019 RPS Plan.
The substantive terms and conditions of the 2019 Pro Forma Renewable PPA remain consistent with the
2018 Pro Forma Renewable PPA except for one significant change. SCE removed the TOD factors
from the 2018 Pro Forma Renewable PPA, as allowed in D.19-02-007 and the 2019 Pro Forma
Renewable PPA likewise does not contain TOD factors. As explained in SCE’s 2018 RPS Plan filing,58
SCE believes that TOD factors are unlikely to serve as an incentive for production of power when it is
most needed. Additionally, the hours of need continue to evolve. Currently, in some of SCE’s older
contracts, SCE is paying higher prices for energy delivered in what are now “off hours” as peak use
times have changed. Therefore, SCE has removed TOD factors from the 2019 Pro Forma Renewable
PPA.
C. Important Changes in 2019 Pro Forma REC Sales Agreement
SCE revised its 2019 Pro Forma REC Sales Confirmation in Appendix I to include the below-
stated non-modifiable terms and conditions. In particular, D.11-01-025, in OP 35, requires inclusion of
the “following non-modifiable standard terms and conditions in all contracts for procurement for
compliance with the California renewables portfolio standard, whether bundled contracts or purchases of
renewable credits only:
a. STC REC-1. Transfer of Renewable Energy Credits Seller and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement the renewable energy credits transferred to Buyer conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation. To the extent a change in law occurs after execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law.
b. STC REC-2. Tracking of RECs in WREGIS Seller warrants that all necessary steps to allow the Renewable Energy Credits transferred to Buyer to be tracked in the Western Renewable Energy Generation Information System will be taken prior to the first delivery under the contract.”9
58 See SCE’s 2018 RPS Plan, Appendix G.1.
9 D.11-01-025, OP 35, pp. 21-22.
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These non-modifiable terms and conditions apply to bundled contracts, which includes sales of
bundled products, like PCC 1 RECs, including both energy and a REC. D.11-01-025, at OP 37, requires
utilities to amend all pending contracts to include the applicable standard terms and conditions.10 For
this reason, SCE amended the 2019 Pro Forma REC Sales Confirmation to include the standard terms
and conditions in OP 35.
D. Important Changes to Discussion of Disadvantaged Communities Green Tariff and
Community Solar Green Tariff
SCE modified its Written Plan in red-line, as part of its Motion to Update its 2019 Draft RPS
Plan, dated August 23, 2019, to better reflect proposed treatment of Disadvantaged Communities Green
Tariff (“DAC-GT”) and Community Solar Green Tariff (“CSGT”) loads and resources in development
of SCE’s Renewable Net Short. SCE plans to adjust its RPS load forecasts to remove customer load
served under the DAC-GT and CSGT programs. Although this treatment is not statutorily required, the
rationale for this treatment is to apply analogous treatment of DAC-GT and CSGT load with the
statutory requirement under Senate Bill (“SB”) 43 for the Green Tariff Shared Renewable (“GTSR”) and
Community Renewable (“CR”) programs that the GTSR and CR customer load forecast be removed
from SCE’s RPS load forecast.11
II.
EXECUTIVE SUMMARY OF 2019 DRAFT RPS PLAN
This 2019 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
10 Id. at p. 23. Additionally, D.11-01-025, at OP 36, requires additional of “non-modifiable standard terms and
conditions” to “all contracts for purchase of renewable energy credits only of regulated utilities…” concerning Commission approval and applicable law. SCE did not add the non-modifiable terms and conditions in OP 36 to the 2019 Pro Forma REC Sales Confirmation because all of the REC sales that it has entered into to date have been for a PCC 1 Bundled Product. To the extent that SCE enters into any REC sales for PCC 3 REC sales which are REC-only sales, SCE will modify the 2019 Pro Forma REC Sales Confirmation to add in the necessary non-modifiable terms and conditions and will highlight the changes in red-line in any Tier 1 Advice Letters submitted to the Commission.
11 Cal. Pub. Util. Code §2833(u). See, SCE’s Motion to Update, filed August 23, 2019, part of the filings adopted in D.19-12-042, OP1.
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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 solicitation in 2019 (“2019 RPS Solicitation”) to procure new RPS eligible
resources, and its plan to sell RECs.
SCE’s 2019 RPS Plan includes its 2019 Procurement Protocol, 2019 Pro Forma Renewable
Power Purchase Agreement, 2019 REC Sales Procurement Protocol, 2019 Pro Forma RECs Sales
Agreement, and a description of SCE’s LCBF evaluation methodology, including consideration of
workforce development and disadvantaged communities, and a summary of the important changes from
SCE’s 2018 RPS solicitation documents.
If in future years SCE holds a solicitation, SCE would use a solicitation process that is intended
to capitalize on the maturing renewables market and target the most viable proposals that fit SCE’s
compliance and reliability needs and provide the most value to customers. In order to submit a proposal,
SCE will require that projects have: (1) a Phase II Interconnection Study (or an equivalent or more
advanced interconnection status or exemption); and (2) an “application deemed complete” (or
equivalent) status within the applicable land use entitlement process. Because of uncertainty
surrounding SCE’s long-term load forecast due to potential changes in its load profile (i.e., the effects of
electric transportation, local solar photovoltaic (“PV”) generation, and departing load), SCE would
request that all bidders submit one offer for a term of 10 years or less for each project.
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 2019 RPS Plan, SCE
proposes to not hold a 2019 RPS solicitation for the procurement of eligible renewable resources. In this
RPS docket, SCE proposes to sell RECs, as described in Section XVI below and in Appendix E.
In this 2019 RPS Plan, SCE will request offers from parties interested in purchasing REC
products from SCE. SCE requests the flexibility to request offers from parties interested in purchasing
all categories of REC products. SCE does not forecast a net short position potential through 2030 and
beyond with the use of its bank. Uncertainty exists regarding factors such as the future departing load
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levels, especially as it relates to the formation of additional Community Choice Aggregators (“CCAs”)
(see Section IV.E.1 below for a discussion on CCAs). Therefore, in order to maximize value for
customers, SCE may sell REC products, consistent with its proposal in this 2019 RPS Plan.
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III.
SUMMARY OF RECENT LEGISLATIVE AND/OR REGULATORY CHANGES
SCE takes the RPS program’s regulatory framework into account – both historical and recent
Legislative and regulatory changes. Senate Bill (“SB”) 2 (1x), which took effect on December 10, 2011,
increased the overall target percentage of procurement from renewable resources from 20% to 33% by
2020, and departed from the prior structure of annual RPS goals and moved to multi-year compliance
periods, with interim procurement targets established for each multi-year compliance period. The
Commission has issued several decisions implementing SB 2 (1x), including D.11 12 020 setting RPS
procurement quantity requirements,612 D.11 12-052 implementing the three portfolio content categories
of renewable energy products that may be used to satisfy RPS targets, 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 adopted SB 350 requirements that
California Load Serving Entities (“LSEs”) must enter into ownership or contractual arrangements of 10
612 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.
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years or more for eligible renewable resources for 65% of their PQR for all compliance periods
beginning January 1, 2021.713 D.17-06-026 also requires retail sellers to give notice of their election for
early compliance with long-term contracting requirements in Pub. Util. Code §399.13(b) by a letter sent
to the Director of Energy Division within 60 days from the effective date of the decision (which was
August 28, 2017).814
On August 28, 2017, SCE sent a letter to the Director of Energy Division giving notice of its
election for early compliance with long-term contracting requirements in Pub. Util. Code §399.13.915
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”.1016 As required by D.17-06-026, SCE filed a motion
to update its 2017 RPS Plan to reflect its election for early compliance. D.17-12-007, dated December
14, 2017, granted SCE’s motion to update in OP 13.1117
While SCE has elected early compliance with long-term contracting requirements in SB 350, not
all LSEs have done so. Beginning in 2021, all LSEs will need to comply with the 65% of PQR long-
term contracting requirements in SB 350.
On June 6, 2018, the Commission issued D.18-05-026 implementing SB 350 provisions on
penalties and waivers in the RPS program. D.18-05-026 maintained the existing RPS penalty scheme
and integrated changes made by SB 350 into the current RPS waiver scheme. OP 3 of D.18-05-026
requires that:
713 D.17-06-026, pp. 8-10. 814 D.17-06-026, OP 23, p. 56. 915 On the same day, Energy Division, through an email from Brent Tarnow, acknowledged receipt of SCE’s
notice. 1016 D.17-06-026, OP 24, p. 56. 1117 D.17-12-007, OP 13, p. 73.
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Beginning with the 2018 Renewables Portfolio Standard Procurement Plan cycle, all retail sellers as defined in Public Utilities Code Section 399.12(j) must annually demonstrate that transportation electrification is accounted for in their procurement plans by explicitly referencing forecasted transportation electrification in their Renewables Portfolio Standard procurement plans; providing a detailed description of the data and method used to support their forecast; and explaining how they considered the California Energy Commission’s Integrated Energy Policy Report transportation electricity demand forecast in creating their own forecast.1218
Accordingly, SCE includes a discussion of its forecast of transportation electrification in Section IV.A,
which discusses how SCE forecasts RPS need.
On September 10, 2018, Governor Brown signed SB 100 which, among other significant
changes, increases the State’s RPS goals to 44% of retail sales by 2024, 52% by 2027, and 60% by
2030. SB 100 also establishes a state policy that eligible renewable energy resources and zero-carbon
resources supply 100% of retail sales by 2045. SCE’s renewable procurement planning may change as a
result of the Commission’s further implementation of SB 100’s changes to the RPS program, adoption
of new RPS legislation, a procurement expenditure limitation mechanism, or other changes to the RPS
program.
This 2019 RPS Plan addresses other issues set forth in the ACR, statute, and other Commission
decisions. Specifically, SCE’s 2019 RPS Plan includes discussion of the following additional topics:
Assessment of RPS Portfolio Suppliesportfolio supplies and Demanddemand;
Project development status update;
Potential compliance delays and risks;
Risk Assessmentassessment;
Quantitative information discussing SCE’s renewable compliance;
Minimum margin of procurement;
Bid solicitation protocol;
Consideration of price adjustment mechanisms;
Curtailment, Frequencyfrequency, Costcost and Forecastingforecasting;
1218 D.18-05-026, OP 3, p. 32.
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REC sales methodology, including pre-approval and Tier 3 Advice Letter approval processes
as well as sales of RECs from the BioRAM contracts, as required by D.18-12-003 on the TM
NBC;1319
Cost quantification tables;
Safety considerations;
Comments on Coordination with Integrated Resource Planning (“IRP”) Proceeding;1420
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 the DAC-GT
and CSGT programs; and
Other RPS planning considerations and issues.
IV.
ASSESSMENT OF RPS PORTFOLIO SUPPLIES AND DEMAND
A. Portfolio Supply and Demand
Table IV-1 below shows SCE’s percentage of retail sales for its RPS-eligible resources:
Table IV-1 Percentage of SCE’s Retail Sales from RPS-Eligible Resources
Compliance Period Year(s) % of Retail Sales from RPS
Eligible Resources
First 2011-2013 20.7
Second 2014-2016 25.2
2017 2017 31.6
2018 2018 36.5
1319 D.18-12-003, OP 4. pp. 26-27. 1420 Rulemaking (“R.”) 16-02-007. The Draft 2019 Written Plan does not address this issue, but the Final
2019 Written Plan will address it after SCE receives further direction from the Commission on this matter which will be discussed in parties opening and reply comments submitted on July 19, 2019 and August 2, 2019 respectively.
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To date, SCE’s RPS-eligible deliveries and executed renewable procurement contracts have
resulted from SCE’s RPS solicitations, SCE’s Renewables Standard Contract program, the Assembly
Bill 1969 feed-in tariffs, RAM and BioRAM auctions, the Renewable Market Adjusting Tariff
(“ReMAT”),1521 the Bioenergy Market Adjusting Tariff (“BioMAT”), the utility-owned generation and
independent power producer (“IPP”) portions of SCE’s Solar Photovoltaic Program (“SPVP”), the
GTSR program,1622 qualifying facility (“QF”) contracts, utility-owned small hydro projects, and bilateral
opportunities.
SCE did not hold an RPS Solicitation in 2016, 2017, and 2018. However, in 2018 and through
April in 2019, SCE has signed the following renewable contracts:
One bilateral contract for 107 MW, and
Four Bio-MAT contracts for 6.0 MW.
SCE determines its expected renewable procurement need by comparing its forecasted RPS
targets to its forecasted energy deliveries from contracted projects. The forecasted energy deliveries
include SCE’s probabilistic risk-adjusted forecast of generation from contracted projects that are not yet
online. SCE also considers generation from pre-approved procurement programs (i.e., ReMAT,
BioMAT), among other factors.
Appendices C.1 and C.2 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 new RPS goals prescribed in SB 100 for the years
2021 through 2030 and adopted in D.17-06-026. In anticipation of CPUC implementation of
1521 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs
ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).
1622 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; OP 12.
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compliance during intervening years, SCE has used the same “straight line” method set out in D.
11-12-020 and D.16-12-040 to determine interim year targets and procurement requirements.
These Appendices use the updated standardized reporting template provided on the
Commission’s RPS website as directed in the ACR.1723 The Commission initially adopted the
methodology utilized in the updated standardized template in its Administrative Law Judge’s Ruling on
Renewable Net Short, dated May 21, 2014, in R.11-05-005.
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., BioMAT) at a 100% success rate
before contracts are signed.1824 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 delays, minimum margin of procurement, and other potential risks through the use of
SCE’s probabilistic risk-adjusted success rates for energy deliveries from contracted projects that are not
yet online. These probabilistic risk-adjusted success rates are intended to reflect a number of dynamic
factors and are periodically adjusted based on new information. The forecasts include individual
project-specific, risk-adjusted success rates for large, near-term projects and a flat 70% success rate for
the remaining projects, which is based on these projects’ overall weighted-average success rate. The
overall probabilistic risk-adjusted success rate for energy deliveries from SCE’s portfolio of contracts
with projects that are not yet online varies from approximately 78% in the CP 3 and approximately 77%
thereafter.
1723 ACR, pp.14-15, including footnote 19. 1824 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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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).1925 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.2026 SCE 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.2127 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.2228 Prior to
dedicated resources procured to serve Green Rate customers beginning service, SCE transferred RECs
from other RPS-eligible resources in its Interim Green Rate Pool to serve Green Rate subscriptions. In
March 2018, one dedicated Green Rate resource became operational. SCE expects to begin transferring
RECs from this dedicated Green Rate resource in 2019 for 2018 customer subscriptions.
SCE will also adjust its load forecast to remove customer load served under the DAC-GT and
CSGT programs. These programs are separate from the GTSR program and separate from the RPS
program. SCE will reduce its bundled retail sales forecast used to calculate its RPS goals by the amount
of energy used to serve customers in the new DAC-GT and CSGT programs, pending approval from the
CPUC of SCE’s forecasting methodology. For this reason, SCE will deduct DAC-GT and CSGT
subscriptions from SCE’s generation forecasts to remove energy deliveries that would be associated
with the load served under the DAC-GT and CSGT programs. Any RECs from unsubscribed energy
from the programs will be credited and used towards the RPS program.
1925 No customers are presently being served under the Community Renewables Rate. As a result, SCE only counted Green Rate customers here.
2026 See CAL. PUB. UTIL. CODE § 2833(s). 2127 CAL. PUB. UTIL. CODE § 2833(u). 2228 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.
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SCE's load forecast also accounts for future Transportation Electrification (“TE”) load
growth.2329 SCE models light duty electric vehicles (“EV”) derived from SCE’s Clean Power and
Electrification Pathways (“CPEP” or “PATHWAYS”) results to meet state’s Greenhouse Gas (“GHG”)
goals.2430 SCE projects that in the transportation sector, approximately 7.5 million light-duty EVs
statewide (2.7 Million in SCE territory) are needed by 2030 to meet California’s GHG emission targets.
Once vehicle population number is determined for each year, SCE calculates the total annual
energy by multiplying the number of forecasted EVs by the average KWh usage per vehicle.2531 Then,
SCE establishes its EV charging load shape based on multiple factors such as exiting customer EV
charging behavior, future flexible charging programs, and duration of charge. Next, SCE applies EV
charging load shape to total annual EV energy to derive the hourly EV load forecast. SCE then
incorporates the hourly EV load forecast into its demand forecast used in this 2019 RPS Plan.
The difference between the RNS forecast using SCE’s assumptions, as reflected in Appendix C.2
and the Commission’s assumptions, as reflected in Appendix C.1 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 2019 through 2023 and the annual load forecasts through 2030 reflected
in the 2017 Integrated Energy Policy Report with adjustments for updates to certain CCA load forecasts.
This is consistent with the adopted standardized planning assumptions laid-out in the June 18, 2018
2329 TE refers to only light-duty electric vehicles (“EV”) here. 2430 SCE used Energy and Environmental Economic, Inc.’s (E3) PATHWAYS model
(https://www.ethree.com/tools/pathways-model/). PATHWAYS is an energy model that evaluates long-term decarbonization plans and performs cost analysis to support GHG mitigation planning. The model tracks GHG emissions from California’s demand and supply-side choices and is used by the California Air Resources Board to develop the state’s Scoping Plan. The model accounts for stock rollover attributes, such as technology useful lives and sale penetration rates, to determine yearly vehicle adoption targets needed to reach the final goal of 7.5 million EVs in 2030.
2531 KWh usage assumption is derived from CEC IEPR 2017 EV Forecast (Bahrenian, Aniss, Jesse Gage, Sudhakar Konala, Bob McBride, Mark Palmere, Charles Smith, and Ysbrand van der Werf, 2018, Revised Transportation Energy Demand Forecast, 2018‐2030. California Energy Commission, Publication Number: CEC‐200‐ 2018‐003, available at https://efiling.energy.ca.gov/GetDocument.aspx?tn=223241).
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Assigned Administrative Law Judge’s Ruling in the IRP docket, R.16-02-007.2632 SCE uses its own
bundled retail sales forecast for renewable procurement planning because it is SCE’s best forecast of
bundled retail sales.
Table IV-2 below summarizes information on SCE’s RNS position:
Table IV-2 SCE’s RNS Position
Compliance Period
Assumptions Used PQR Billion
Kilowatt-hours (KWh)
RPS-eligible Procurement
Billion Kilowatt-
hours (KWh)
End Bank Balance /
<Shortfall> Billion
Kilowatt-hours (KWh)
1 (2011-2013) SCE’s assumptions 44.8 46.2 1.4 2 (2014-2016) SCE’s assumptions 52.4 56.7 5.7 3 (2017-2020) SCE’s assumptions 102.6 4 (2021-2024) SCE’s assumptions 110.5 5 (2025-2027) SCE’s assumptions 63.3 78.7 85.7 6 (2028-2030) SCE’s assumptions 73.2 68.3 80.9 1 (2011-2013) Commission’s assumptions 44.8 46.2 1.4 2 (2014-2016) Commission’s assumptions 52.4 56.7 5.7 3 (2017-2020) Commission’s assumptions 102.6 4 (2021-2024) Commission’s assumptions 110.5 5 (2025-2027) Commission’s assumptions 82.1 78.7 61.2 6 (2028-2030) Commission’s assumptions 93.0 68.38 36.5
Using SCE’s assumptions, SCE forecasts a net short position starting in 2028 without the use of
bank (as shown in Appendix C.2). But with the use of bank, SCE forecasts a net long position through
the end of CP 6 (2028-2030) and beyond. Using the Commission’s assumptions, SCE forecasts a net
short position starting in 2026 without the use of bank (as shown in Appendix C.1) and a net long
2632 The Revised RNS Methodology states that retail sellers can use their own forecasts for bundled retail sales for the first five years and should use the LTPP standardized planning assumptions thereafter. See RNS Ruling, Attachment A at p. 25. The Commission adopted the standardized planning assumptions in R.16-02-007 in the June 18, 2018 Assigned Administrative Law Judge’s Ruling for the purpose of filing 2018 IRPs.
Appendix A - Page 23
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position through the end of CP 6 (2028-2030) and beyond with the use of bank. Accordingly, SCE
currently does not have a need for additional RPS-eligible energy.2733
B. Alignment with Load Curves
RPS contracts are procured pursuant to the LCBF standard. That is, given a set of potential RPS
offers, SCE will select the portfolio of assets that maximizes total value to our customers. The most
salient factor for valuing RPS contracts, aside from contract price, is SCE’s expectation of future energy
revenues. Market revenue for RPS contracts is a function of expected generation and power prices.
Although SCE does not apply load curves directly in its evaluation of RPS contracts, customer load is
used to calculate our internal energy price forecasts. All else being equal, as net demand decreases, the
expected price to serve the demand also decreases. This can be seen in current market behavior already
(i.e. “duck curve,” leading to negative power prices.) As the price to serve demand decreases, the
expected market revenue from the RPS asset will also decrease, thereby reducing the economic value of
the contract. Contracts with lower economic value are less likely to be signed compared to contracts
with higher values; therefore, the change in expected load curves will tend to produce a balanced
portfolio over time
C. Responsiveness to Policies, Regulations, and Statutes
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 2018, SCE served 36.5% of its retail sales from
RPS-eligible resources. SCE does not forecast a net short in its RPS compliance position until 2026
without the use of bank and after 2030 with the use of bank using the Commission’s assumptions.
Therefore, SCE does not intend to hold a 2019 RPS Solicitation in this 2019 RPS Plan. In addition,
2733 This conclusion assumes incremental departing load from Community Choice Aggregation (“CCA”)
development based on SCE’s 2018 Q2 assumptions. Operational and expected CCAs as well as a Monte Carlo simulation of additional CCA load beginning in 2020 are currently accounted for in SCE assumptions for departing load. See section II.F, subsection 1, pp. 22-24 for a detailed explanation of SCE’s CCA outlook. SCE performs scenario analysis for departing load when making procurement decisions based on the best information available at that time. SCE shares this information with its Procurement Review Group (“PRG”) including Energy Division.
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because of SCE’s long position, SCE may look to sell RECs consistent with its proposal in this 2019
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.
SCE may seek to sell RECs to allow SCE to optimize its renewables portfolio and provide value
for all bundled and departing load customers. SCE may conduct a solicitation of offers, negotiate
bilaterally or utilize brokers and exchanges to sell such products to maximize value to customers and
optimize the RPS portfolio. Section XVI contains a more thorough discussion of the REC sales strategy.
The procurement in SCE’s current renewables portfolio is primarily from contracts executed
prior to June 1, 2010 or contracts for Category 1 products with a small amount of Category 3 RECs.2834
SCE forecasts that it will meet its RPS targets primarily through long-term procurement from contracts
executed prior to June 1, 2010 and 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 100.
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.
2834 The Category 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering their product to CAISO. SCE has not contracted for Category 3 products.
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SCE determines the value of resources with specific deliverability characteristics (such as
peaking, dispatchable, baseload, firm, and as-available) through its LCBF analysis. SCE uses its LCBF
methodology to compare project profiles, including duration of term, location, technology, online date,
viability, deliverability, and price, to estimate the value of each project to SCE’s customers and its
relative value in comparison to other proposals using both quantitative and qualitative factors. SCE also
considers resource diversity with respect to proposals featuring differing technologies, generation
profiles, and fuel sources, and performs a qualitative appraisal of the various benefits and drawbacks of
projects when considering over-generation and the duck curve.2935 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 X.C. and Appendix G.1.
In addition to RPS solicitations, SCE continues to utilize a variety of other procurement methods
to help meet the State’s RPS targets, including mandated programs such as ReMAT,3036 BioMAT, QF
standard contracts and other opportunities such as local capacity requirements solicitations, all source
solicitations, and bilateral negotiations for procuring renewable energy products.
D. Portfolio Diversity
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
2935 The California Independent System Operator (“CAISO”) describes the Duck Curve in Fast Facts at - http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf. In essence, theThe 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.
3036 On December 15, 2017, the Commission’s Executive Director, Timothy Sullivan, sent a letter to the IOUs ordering them not to execute any new ReMAT contracts, hold any new ReMAT program periods, or accept any new ReMAT applications, effective immediately, pending further Commission action or court order following issues on December 6, 2017, of Judge Donato’s order in Winding Creek Solar LLC v. Florio, et al, Case 3:13-cv-04934-JD (N.D. Cal.).
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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 X.C and Appendix G.1. The primary quantitative metric used for evaluating
bundled renewable energy is Net Market Value (“NMV”). SCE also relies on a number of qualitative
factors such as resource diversity and transmission area, among other factors such as impacts on
Disadvantaged Communities (“DACs”), when evaluating proposals.
Because SCE’s need assessment results in a long position, SCE may use sales of renewable
energy products,3137 project deferrals, and solicitation deferrals (as it did by not holding a 2012, 2016,
2017, or 2018 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.3238
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.3339 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.
3137 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.
3238 Contract amendments have the potential to decrease contract prices or provide other benefits to customers.
3339 SCE also considers statutory and regulatory restrictions on banking of excess procurement.
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21
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 LSE. 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.
After SCE executes an RPS PPA, SCE’s Energy Contracts Management group manages the
PPA. Each PPA is assigned a contract manager who serves as the primary point of contact to address all
obligations and milestones under the PPA. To the extent allowable, many PPAs will require some form
of modification prior to attaining commercial operation. Modifications may include financing consents,
updates to facility descriptions, amendments that reduce costs to the seller and/or SCE without
increasing revenues, true-up of PPA milestones and timelines as interconnection and permitting
information is updated, and other miscellaneous changes to accommodate adjustments during the project
development process. Generally, PPAs require few modifications after attaining commercial operation.
At this juncture in the contract lifecycle, contract administration efforts become more focused on
monitoring the contractual performance and payment obligations. However, disputes, settlements,
outages, changes to delivery obligations or other issues may arise and are also managed by the same
contract managers.
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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.3440 In the event an
amendment is elected, the IOU should negotiate in good faith.3541 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.3642 The details of D.88-10-032 provide further guidance to the IOUs to
restrict modifications to PPAs with viable projects,3743 and reject modifications that would result in
creating an essentially new project.3844
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.3945
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.4046 SCE will comply with D.19-02-007, OP 18,
which requires it to “seek the Commission’s approval through an advice letter for any significant
modification to any procurement contract for renewable portfolio standard-eligible resources that was
approved by the Commission.”4147
3440 See D.88-10-032 at p. 16. 3541 Id. at Conclusions of Law (“CoL”) 8. 3642 Id. at p. 16, CoL 13-14. 3743 Id. at p. 17, CoL 4, Appendix A at pp. 4-5. 3844 Id. at p. 26, CoL 17. 3945 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. 4046 For example, the Commission has indicated specific IOU actions regarding amendments to certain terms
in tariff-based agreements. 4147 D.19-02-007, OP 18, p.118.
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E. Lessons Learned
SCE’s experience in renewable contracting has enabled SCE to negotiate successfully and bring
projects online with a variety of counterparties on a diverse array of technologies. SCE is committed to
recognizing the unique characteristics of each situation and working toward balanced and mutually
acceptable agreements. To this end, SCE continues to refine both its RPS solicitation process and its
pro forma PPA as a result of lessons learned from SCE’s extensive experience in contracting for
renewable resources and working with developers. Over the course of the last several years, SCE has
also incorporated or accounted for several trends in its renewable procurement planning and solicitation
process. SCE discusses important lessons learned and significant past and future trends below.
Additionally, as SCE has noted in past RPS Procurement Plans, more stringent eligibility requirements,
such as the requirement that projects have a Phase II Interconnection Study (or an equivalent or more
advanced interconnection status or exemption) and an “application deemed complete” (or equivalent)
status within the applicable land use entitlement process in order to submit a proposal, have resulted in
higher viability project proposals. SCE intends to continue these requirements in any future solicitations
for all projects.
1. Possible Future Trend Toward Departing Load
On June 3, 2019, the Commission issued D.19-05-043 in R.19-03-009 Implementing
Senate Bill 237 Related to DA (“DA OIR”). Consistent with that decision in the DA OIR, SCE reflects
the Commission-adopted additional DA customer migrating load impact in SCE’s bundled load
forecast.4248 In addition to the additional DA migrating customer load impact, SCE expects additional
cities and eligible public entities within the SCE service territory to begin CCA service. SCE
incorporates existing departing CCA load including Lancaster Choice Energy (“LCE”), Apple Valley
Choice Energy (“AVCE”), Pico Rivera Innovative Municipal Energy (“PRIME”), Clean Power Alliance
(“CPA”) Phase 1 (municipal accounts in unincorporated Los Angeles County), San Jacinto Power
4248 D.19-05-043 raises SCE’s authorized DA Cap by 1,747 GWhs from 11,710 to 13,457 GWhs through
multi-year phase-in approach. As a result, SCE assumes a two-year phase-in starting from January 1, 2020 for the total of 1,747 GWh new DA load which reduces SCE’s bundled load forecast.
Appendix A - Page 30
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(“SJP”), Rancho Mirage Energy Authority (“RMEA”), CPA Phase 2 (non-residential accounts in
unincorporated Los Angeles County and the Cities of Rolling Hills Estates and South Pasadena), and
CPA Phases 3 and 4 (residential and non-residential accounts in Agoura Hills, Alhambra, Arcadia,
Beverly Hills, Calabasas, Camarillo, Carson, Claremont, Culver City, Downey, Hawaiian Gardens,
Hawthorne, Malibu, Manhattan Beach, Moorpark, Ojai, Oxnard, Paramount, Redondo Beach, Rolling
Hills Estates (residential only), Santa Monica, Sierra Madre, Simi Valley, South Pasadena (residential
only), Temple City, Thousand Oaks, Unincorporated Los Angeles County (residential only), Ventura
(City), Ventura County, West Hollywood and Whittier). Consistent with LSEs’ most recent 2020 initial
Year-ahead RA forecast filings,4349 SCE incorporates additional new 2020 CCAs including CPA Phase
5 (serving non-residential and residential accounts in Westlake Village), Western Community Energy
(“WCE”, serving Eastvale, Hemet, Jurupa Valley, Norco, Perris, and Wildomar), Desert Communities
Energy (“DCE”, serving Palm Springs), Commerce, Pomona (serving residential and municipal
accounts), Baldwin Park (serving residential and municipal accounts), Palmdale (serving residential and
municipal accounts), and Hanford (serving residential and municipal accounts).
Additional cities, counties, and governmental aggregations within the SCE service
territory have either initiated contact, requested load data from SCE, or passed a municipal ordinance
related to their interest and intention to developing CCAs. These entities have the potential to represent
a significant additional departure of load from SCE’s bundled procurement service. As additional large
departures come to fruition, they will have proportionally significant impacts on SCE’s progress towards
meeting its RPS compliance goals by reducing SCE’s potential RPS need.
Departing load should not impact SCE’s planned procurement activities unless and until
new LSEs formalize their departure through a Binding Notice of Intent (“BNI”), an initial RA filing, the
start of CCA service, or formal submission of an April RA forecast for the following year pursuant to
4349 SCE incorporates its updated 2020 Year-ahead RA forecast which was filed with the Commission on May
24, 2019.
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California Public Utilities Code Section 380.4450 In expectation of growing CCA departing load in the
near future, SCE prepared a Monte Carlo simulation of CCA departing load starting in 2021 and has
accordingly adjusted its procurement plan at this time.4551 In addition, future policy changes with regard
to DA reopening could also bring impact to SCE’s planned procurement activities. As these actual load
departures materialize, SCE will consider how these departures impact its RPS compliance, including
the size of the RPS bank and the need to sell RECs to newly forming CCAs. If a sufficiently large
amount of SCE’s current bundled service customers depart bundled service, SCE may be even more
significantly over-procured to meet its RPS compliance goals.
2. Need for REC Sales
SCE is well positioned to meet its RPS compliance obligation both in the near term and
in the foreseeable future. As described in confidential Appendix E, SCE has more renewable energy to
meet its compliance responsibilities than it needs for the forseeable future. Additionally, SCE can create
customer value and introduce some rate stability by engaging in sales transactions. The Commission
adopted SCE’s REC sales strategy in its Draft 2018 RPS Plan, with some modifications, in D.19-02-
007.4652 In this 2019 RPS Plan, SCE, once again, seeks permission to engage in REC sales with some
modifications from the 2018 RPS Plan, as more fully described in Chapter XVI and Appendix E.
In addition to providing benefits to SCE’s customers, an open market for REC sales may
provide for a low-cost option for RPS compliance for other LSEs in California. Long-term contracting
may not be an option for smaller LSEs given the higher costs and long-term commitments. In absence
of that option, an open market can provide for a lower-cost option for short-term REC purchases.4753
4450 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. 4551 SCE performs scenario analysis for departing load when making procurement decisions based on the best
information available at that time. SCE shares this information with its PRG, including Energy Division. SCE’s current scenario analysis for departing load includes Lancaster, Apple Valley, Pico Rivera, CPA Phase One, San Jacinto, Rancho Mirage, CPA Phase Two, DCE, CPA Phases Three to Five, and the Monte Carlo simulation for departing load beginning in 2020.
4652 D.19-02-007, OP 10, pp. 116-117. 4753 As explained in more detail in section XI and confidential Appendix E.
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RECs offered for sale through SCE’s solicitations will include RECs produced as a result of energy
delivered through BioRAM contracts, as required by D.18-12-003 on the TM NBC.
Finally, given the SB 350 changes in compliance rules confirmed in D.17-06-026, IOUs
will have some flexibility to fulfill their compliance requirements through a combination of long-term
contracts and short-term products, reducing the overall costs for their customers. Given this change,
SCE will seek portfolio optimization opportunities to make those tradeoffs between long-term contracts
and short-term purchases. An active REC sales strategy will be a key part of SCE’s portfolio
optimization strategy.
V.
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. Appendix B utilizes the most recent Project Development
Status update template from the Commission’s RPS website, as required by the ACR.4854 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.
VI.
POTENTIAL COMPLIANCE DELAYS
Although SCE is well positioned to meet its compliance goals, there are factors that may delay
SCE’s achievement of the RPS goals: (1) curtailment; (2) permitting, siting, approval, and construction
of both renewable generation projects and transmission; (3) a heavily subscribed interconnection queue;
(4) developer performance issues; and (5) load uncertainty associated with possible departing load and
4854 ACR, p. 12, footnote 16.
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increasing electrification of transportation. SCE discusses each of these potential issues that could cause
compliance delays below and describes the steps it has taken to mitigate the effects of these challenges.
As discussed in Section IV.A, 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. 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 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.
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B. 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 and impede new
renewable resources from being declared fully deliverable.
The long and complicated permitting process for renewable generation and transmission
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 and transmission
projects online. One such project is the Eldorado-Lugo and Lugo-Mohave Series Capacitor (“ELM”)
Project which is a Policy Driven Transmission Project approved through the CAISO Transmission
Planning Process (“TPP”). With the purpose of increasing transmission capacity in support of achieving
the States RPS goals, the project is also required for 13 generation projects, totaling about 2,500 MW, to
achieve Full Capacity Deliverability Status (“FCDS”). As part of the process that identified the ELM
Project through the CAISO TPP for the purpose of identifying policy driven transmission additions, the
renewable resource portfolios provided by the Commission to the CAISO required projects to be fully
deliverable. Subsequently, 13 generation projects entered into Interconnection Agreements with SCE
which listed as a requirement for FCDS the completion of the ELM Project. The delay in the completion
of the ELM Project which currently has a completion date of June of 2021 will be responsible for
several projects not being able to timely achieve FCDS.
C. A Heavily Subscribed Interconnection Queue
A heavily subscribed CAISO interconnection queue is also a major barrier to achieving the
State’s RPS goals. The May 2019 CAISO Interconnection Queue reports 145 solar and wind projects
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seeking interconnection to the CAISO controlled grid representing more than 27,000 MW of
capacity.4955
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 (“IAs”), contribute to the
uncertainty around available system capacity. When capacity is reserved for generators that have not
signed IAs, 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.
D. Developer Performance Issues
Achieving California’s renewable energy goals also depends on the successful performance of
renewable developers in meeting contractual obligations, timely completing construction milestones,
and achieving commercial operation. Hurdles encountered during these activities require developers to
alter their milestone schedules. This can result in delays, lengthy contract amendment negotiations, and
contract terminations. Recently, developer performance has become less of an issue as the renewables
market has matured and RFP requirements such as a Phase II Interconnection Study have been
implemented. However, there have been developer performance issues in some cases especially among
the mandated carve-out feed-in-tariff programs such as ReMAT. Several of SCE’s contracts have
terminated due to developer performance issues (e.g., poor site selection, failure to timely secure the
necessary permits, and inability to complete the CAISO new resource implementation processes in a
timely manner). As stated above, this is especially true in SCE’s smaller and mandated procurement
programs. In these programs, requirements showing the viability of a project, such as the requirement of
a Phase II Transmission Study or equivalent, are not an eligibility criteria. Projects that have achieved
this level of development typically have significant dollars invested and secured project-backing. As a
4955 See http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx.
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30
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.
E. Load Uncertainty Including Faster Implementation of Transportation Electrification And
Departing Load
There are two key factors that create load uncertainty which could impact SCE’s ability to
achieve its RPS goals. First, as discussed in Section IV.A above, SCE’s load forecast reflects its
anticipated future transportation electrification load growth required to meet state’s future GHG goals.
However, if future TE load growth is more accelerated or in excess of SCE’s current forecasts, SCE’s
ability to reach its RPS target may be negatively impacted because it may not have sufficient RPS-
eligible resources to serve a significantly larger load than it presently forecasts. Given predicted levels
and uncertainties of future departing load to CCAs and DA, however, even TE adoption materially in
excess of SCE’s current forecasts is unlikely to change the overall fact that SCE will be significantly
long on RPS for the foreseeable future. That said, it is also possible that SCE may experience
significant returns of CCA (or other alternate ESP-served) load, which could negatively impact its
ability to achieve its RPS targets.
VII.
RISK ASSESSMENT
SCE describes risks that may result in compliance delays in Section VI. As explained in Section
IV.A, 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 considers historic generation from existing resources, including lower than expected
generation, variable generation, and resource availability, among other factors, when forecasting
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expected generation from its contracted renewable projects. The quantitative analysis provided in
Appendices C.1 and C.2 reflects these considerations.
VIII.
QUANTITATIVE INFORMATION
A. RNS Calculations
As discussed in Section IV.A, Appendices C.1 and C.2 include SCE’s RNS calculations using
the standardized reporting template. Appendix C.2 quantifies SCE’s physical and optimized RNS based
on the following SCE assumptions:
SCE’s most recent bundled retail sales forecast for 2019 through 2030 which excludes
Green Rate customer subscriptions;
Transfers of energy deliveries from SCE’s interim pool of RPS eligible resources to the
Green Rate program to serve Green Rate customers until dedicated Green Rate resources
come online; and conversely, transfers of energy deliveries from dedicated Green Rate
resource that are not used by Green Rate customers;
Contracted projects that are currently online will deliver 100% of their expected amount
of renewable energy;
Probabilistic risk-adjusted success rates for energy deliveries from contracted projects
that are not yet online. SCE’s forecasts include individual project-specific, risk-adjusted
success rates for large, near-term projects and a flat 70% success rate for the remaining
projects, which is based on these projects’ overall weighted average success rate; and
100% success rate for projects originating from pre-approved programs such as BioMAT
before contracts from such programs are signed.5056
Appendix C.1 provides SCE’s physical and optimized RNS through 2030 using the
Commission’s RNS Methodology. Appendix C.1 uses the same assumptions as in Appendix C.2 except
that:
5056 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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Instead of using SCE’s most recent bundled retail sales forecast for all years, it uses
SCE’s most recent bundled retail sales forecast for 2019 through 2023 and the annual
load forecasts through 2030 reflected in the 2017 Integrated Energy Policy Report with
adjustments for updates to certain CCA load forecasts.5157
Currently, SCE does not propose including a voluntary margin of over-procurement (“VMOP”)
in its renewable procurement planning. SCE will account for risks by applying probabilistic risk
adjustment of expected generation from executed contracts with projects that are not yet online.
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
5157 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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Initiative Program, future customer adoption of distributed generation, future electric vehicle use, and
other electrification load growth. In addition, in recent years, rapid acceleration of actual and predicted
CCA formation have led to materially longer forecast RPS positions for SCE. Last, the potential
increases in DA customer migrating load driven by state’s policies around DA reopening could make
SCE’s RPS positions even longer. 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 expects a small but increasing level of curtailment in solar between 2019
and 2020. Wind remains less predictable but is expected to have little to no curtailment during this time
period. Looking at the historical CAISO system-wide data,5258 the CAISO curtailed about 1.5% of solar
production, and less than 0.2% of wind production in 2018. Solar curtailments were focused in shoulder
months, peaking in March and October, while the wind curtailments were more spread out across the
year. The current year, 2019, is showing a similar pattern, with solar curtailments trending higher than
last year,5359 while wind curtailments are hovering in the 0.2% range.
Considering the increasing solar and wind penetration, and retirements of the gas fired
resources, SCE expects that the RPS curtailments will increase. However, forecasting such curtailments
is challenging as many factors impact curtailment levels. These factors include the inherent variability
5258 Wind and solar curtailment data, available at http://caiso.com/informed/Pages/ManagingOversupply.aspx
. 5359 Solar curtailments are reaching 5.3% in March 2019, compared to 4.4% in March 2018.
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in wind and solar production, uncertainty in load (and net load) forecasts, and a variety of system and
weather variables (e.g. California hydro conditions, available imports). Furthermore, the CAISO and
other stakeholders are working on a variety of projects and initiatives to improve the system capabilities
to manage oversupply – from the Western Energy Imbalance Market (“EIM”) expansion, improved
regional coordination, as well as implementing Time of Use (“TOU”) rates, Demand Response
programs and deploying Energy Storage.
4. Are there any significant changes to the success rate of individual RPS projects that
impact the RNS?
SCE reviews the status of contracted projects that are not yet online every quarter to
assess the likelihood that each project will be successfully constructed and deliver energy. For the larger
contracted projects that terminated in the last year, SCE had gradually dropped their likelihood of
success over time such that when the projects eventually terminated, there was not a significant impact
to SCE’s forecast RNS. Overall, SCE has seen a number of large, near-term projects continue to make
strides towards completion, resulting in a collectively higher anticipated success rate for these large,
near-term projects than was allocated to similar projects prior to 2016. As mentioned in Section VI.E
above, the requirement of a Phase II Interconnection Study or better has 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.
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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 California Energy Commission (“CEC”) during RPS verification,
fuel source mix in the renewables portfolio, performance of existing resources, project success rates,
delay or acceleration of online dates, performance of new facilities once they are operational, the level
of the existing portfolio that is re-contracted, and curtailment, among other factors. Annual variability
of these factors can either increase or decrease the bank from year-to-year.
7. What are your strategies for short-term management (10 years forward) and long-
term management (10-20 years forward) of RECs above the PQR? Please discuss
any plans to use RECs above the PQR for future RPS compliance and/or to sell
RECs above the PQR.
When sufficiently long during short-term periods, SCE has used sales of renewable
energy products, project deferrals, portfolio optimization, and solicitation deferrals in order to adjust its
renewable procurement back in line with its forecasted RNS. If SCE forecasted short-term shortfalls,
SCE would satisfy the need through additional procurement. For example, SCE could re-contract with
existing projects, initiate an RPS solicitation, procure through pre-approved procurement programs, or
make short-term purchases with Commission approval. Additionally, SCE diligently manages contracts
to ensure all contractual obligations are met. SCE uses these activities for renewables portfolio
optimization.
Specifically, regarding the sale of RECs, when SCE has a long position in the near term,
SCE evaluates whether a sale of renewable energy products is appropriate. This evaluation includes a
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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.
Currently, 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 XVI.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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If SCE implements a VMOP methodology in the future, SCE would use the same
methods to procure its projected VMOP procurement need as it uses to procure towards its RPS targets,
including procurement of Category 1 products.
10. Are there cost-effective opportunities to use banked RECs above the PQR for future
RPS compliance in lieu of additional RPS procurement to meet the RNS?
There are a few alternatives for the potential use of banked RECs above the PQR,
including applying them in the future compliance periods, engaging in sales for the amount of bank, and
a combination of sales of products and procurement of other products. As noted above in response to
question 7, SCE does not hold an excessive amount of bank for the sole purpose of selling it later. SCE
generally allocates any near-term forecasted RECs above the PQR to years of forecasted shortfall. SCE
conducts various portfolio optimization strategies also described in its response to question 7 to manage
its renewables portfolio.
11. How does your current RNS fit within the regulatory limitations for portfolio
content categories? Are there opportunities to optimize your portfolio by procuring
RECs across different portfolio content categories?
The procurement in SCE’s current renewables portfolio is primarily from either contracts
executed prior to June 1, 2010 or contracts for PCC 1 products with a small amount of PCC 3 RECs.5460
Accordingly, SCE’s procurement fits within the minimum target for PCC 1 products and the maximum
target for PCC 3 products established by SB 2 (1x) and D.11-12-052, as well as the targets established in
SB 350 and D.17-06-026. SCE does see opportunities to optimize its portfolio and achieve customer
value through sales across the three portfolio content categories. Given SCE’s current position of no
RPS need in the near term, SCE may conduct solicitations for sales of REC products in 2019. Through
soliciting REC sales, SCE may find opportunities to create value for its customers.
5460 The PCC 3 RECs held by SCE were from the El Cabo facility when they were having issues delivering
their product to CAISO. SCE has not contracted for PCC 3 products.
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IX.
MINIMUM MARGIN OF PROCUREMENT
SCE’s renewable procurement efforts will be guided by its forecast of its renewable procurement
needs, as described in Section IV.A and provided in Appendices C.1 and C.2. In its forecast of its
renewable procurement position and need, SCE currently accounts for the risks of project failure and
delay associated with contracted projects that are not yet online. To this end, SCE uses individual
project-specific, risk-adjusted success rates for large, near-term projects and a flat 70% success rate for
the remaining projects, which is based on these projects’ overall weighted average success rate. This
probabilistic risk adjustment methodology for discounting expected energy deliveries from projects
under development is modeled to represent project development success rates as well as any
contingency that would make meeting the State’s RPS goals less likely (e.g., delays due to transmission,
curtailment, material shortages, load growth beyond that which is forecasted, or less than expected
output from resources). Additionally, this methodology provides an appropriate minimum margin of
procurement “necessary to comply with the renewables portfolio standard to mitigate the risk that
renewable projects planned or under contract are delayed or cancelled.”5561 SCE will reassess its
position on a periodic basis and, as such, expects that success rates may need to be modified in the
future to reflect changes to SCE’s portfolio.
The Commission should rely on retail sellers to calculate their minimum margins of procurement
and should not attempt to impose a one-size-fits-all approach. As many of the projects in SCE’s
portfolio become operational, SCE will face different risks, including integration of these resources.
The risks associated with project failure will be replaced by less significant risks of projects generating
below full capacity. Similarly, SCE expects that the portfolio risk picture is not the same for each retail
seller. For example, risks may vary depending on whether a portfolio contains a high proportion of
contracts that are online (as discussed above) or depending on the various technologies being used (e.g.,
geothermal technology, which is a baseload resource, versus wind or solar technologies, which are more
5561 CAL. PUB. UTIL. CODE § 399.13(a)(4)(D).
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intermittent). 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.
X.
BID SOLICITATION PROTOCOL, INCLUDING LCBF METHODOLOGIES
A. Solicitation Protocol for REC Sales
SCE includes the 2019 REC Sales Protocol as part of this 2019 RPS Plan. SCE will use the 2019
REC Sales Protocol, included here as Appendix J, as a basis for its REC sales solicitations. RECs
offered for sale through SCE’s solicitations will include RECs produced as a result of energy delivered
through BioRAM contracts, as required by D.18-12-003 on the TM NBC. The 2019 REC Sales
Protocol includes, among other things, the following items:
SCE’s requirements for initial delivery dates and preferred contract term lengths;
Deliverability characteristics and locational preferences;
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 selling;
A schedule of key dates related to the solicitation; and
2019 REC Sales Confirmation (“2019 REC Sales Agreement”), attached as Appendix I.
A discussion of the important changes in the proposed solicitation documents from SCE’s 2018
solicitation documents is included in Section I.B.
As stated previously in this Written Plan, IOUs will have some flexibility to fulfill their
compliance requirements through a combination of long-term contracts and short-term products,
reducing the overall costs for their customers. Given this change, SCE will seek portfolio optimization
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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. More details on SCE’s
strategy are included in Appendix E.
B. Procurement Protocol
Although SCE does not intend to hold a solicitation to purchase renewable power under this
2019 RPS Plan, Appendix H.1 contains SCE’s 2019 Procurement Protocol, which includes an overview
of a solicitation, schedule, product being solicited, and other details. Appendix H.2 includes a redline
from the version filed in 2018.
C. LCBF Criteria
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 assess the top
proposals’ qualitative attributes. These qualitative attributes, including factors such as local reliability,
resource diversity, and nominal contract payments, are considered to either eliminate or add projects to
the final shortlist or to determine tie-breakers, if any. Once a project is added to the shortlist, SCE may
enter into a PPA with the project. By taking many quantitative and qualitative factors into
consideration, SCE ensures that it will select projects best suited for its portfolio in order to meet
customer needs and attain the State’s RPS goals. Appendix G.1, on LCBF Methodology, describes the
full list of both quantitative and qualitative factors taken into account as part of offer evaluation,
including an expanded discussion on preference to renewable energy resources located in certain
communities, as required by Pub. Util. Code § 399.13(a)(7). These quantitative and qualitative factors
specifically include impacts on Workforce Development and Disadvantaged Communities, as required
by D.19-02-007.5662
5662 D.19-02-007, pp. 96-100 and OP 16, p. 118.
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1. Workforce Development
SCE takes into consideration numerous qualitative factors when assessing cost-
effectiveness during the selection process. Appendix G.1, on LCBF Methodology, describes the full list
of qualitative factors, including an expanded discussion of qualitative consideration of Workforce
Development. As described in Appendix G.1, SCE will require the Seller to provide information during
the bid process assessing the benefits on employment or Workforce Development. This information
includes identifying the number of new jobs created during construction and operation phases and
employment and training opportunities for disadvantaged groups (e.g. women, minorities and disabled
veterans).5763
2. Disadvantaged Communities
Appendix G.1, on LCBF Methodology, describes the full list of qualitative factors taken
into account as part of offer evaluation, including an expanded discussion of qualitative consideration of
Disadvantaged Communities (“DAC”). DAC are identified through California’s Environmental
Protection Agency’s CalEnviroScreen 3.0. As described in Appendix G.1, SCE will require the Seller to
provide information during the bid process assessing the benefits for DAC. This information includes
the CalEnviroScreen Score and community impacts, such as new job opportunities, increases or
decreases in air pollution and other environmental benefits and burdens, and other community benefits
and burdens.
XI.
CONSIDERATION OF PRICE ADJUSTMENT MECHANISMS
As in the past three RPS solicitations that SCE has held, SCE would not plan to solicit price
structures based on indices in future RPS solicitations. Sellers can, however, bid escalation factors in
their prices. Proposals with adjustable pricing based on indices were more common when the renewable
industry was starting out. Uncertainties over relatively new technologies made it reasonable to tie
pricing to certain commodity indices, inflation rates, or other indices that made sense given the
5763 See Appendix G.1, pp. 10.
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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.
XII.
CURTAILMENT, FREQUENCY, COSTS AND FORECASTING
Although SCE has observed very few instances of negative pricing in the day-ahead market,5864
negative prices have been observed on a more regular basis in the real-time market. SCE identifies
several factors contributing to increases in instances of negative prices. Over-generation typically
occurs in off-peak hours when baseload and must-take renewable generation is high and demand is low,
which can cause negative market price hours. On-peak negative prices tend to be localized, transient,
and related to congestion caused by a particular transmission bottleneck.
It is generally difficult to forecast negative prices. SCE continues to manage potential instances
of negative pricing and the associated impact to SCE customers through several different strategies. As
a general practice, SCE schedules variable energy resources, such as solar and wind facilities, into the
day-ahead market whenever possible. Because resources that are awarded day-ahead schedules are only
exposed to negative prices in real-time for actual deliveries in excess of their bid-in, day-ahead awards,
this practice helps to limit customer exposure to negative prices. This practice is consistent with least-
cost dispatch principles, which govern SCE’s approach to marketing its entire portfolio of contracted
and utility-owned resources.
5864 ~2.11% of hours in sampled nodes in the day-ahead market.
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Additionally, resources with economic curtailment rights are bid accordingly (economically) into
the day-ahead and real-time markets as practicable. Resources with such curtailment rights are then
curtailed as needed based on the CAISO’s economic dispatch.5965 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
therefore serve to further limit customer exposure to negative prices both in day-ahead and in real-time,
even if SCE ultimately pays the full contract price for curtailed energy.
In future RPS solicitations, SCE plans to not require sellers to bid the pre-paid economic
curtailment option with the curtailment cap. SCE will retain the right to curtail at its discretion but will
pay for curtailments directly resulting from SCE marketing decisions. As in prior years, SCE will not
pay for curtailments in response to an emergency, or due to the CAISO or transmission provider
instructions.
5965 The CAISO may (and does) curtail resources based on grid reliability factors as well, which can happen
to all renewable resources, whether they are bid economically in the market or not.
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XIII.
COST QUANTIFICATION
The Excel spreadsheet attached as Appendix D includes actual expenditures per year for RPS-
eligible generation for every year from 2003 through 2018, as well as actual RPS-eligible generation for
every year from 2003 through 2018. As required by the ACR, this spreadsheet utilizes the most recent
template posted on the Commission’s RPS website.6066 Appendix D also includes a forecast of future
expenditures SCE may incur every year from 2019 through 2030, as well as a forecast of expected
generation for every year from 2019 through 2030.
XIV.
SAFETY CONSIDERATION
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 2019 Pro Forma provides that the seller must operate
the generating facility in accordance with “Prudent Electrical Practices.”6167 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. .
. .”6268
6066 ACR, p. 21, footnote 26. 6167 See 2019 Pro Forma (attached as Appendix F) at Section 6.01(a). 6268 Id. at Exhibit A.
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Consistent with SCE’s focus on safety, SCE’s 2019 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.6369
SCE also has a safety section in its 2019 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
2019 Pro Forma.6470
XV.
COMMENTS ON COORDINATION WITH INTEGRATED RESOURCE PLANNING
PROCEEDING
The ALJ’s Ruling, in OP 2, orders that parties may file Opening Comments on Coordination of
the RPS Procurement Plan with the IRP no later than July 19, 2019 and reply comments on the same
issue no later than August 2, 2019.6571 SCE will incorporate the Commission’s findings on this matter
in its Final 2019 RPS Plan and will offer comments on July 19, 2019.
XVI.
AUTHORIZATION TO SELL RENEWABLE ENERGY CREDITS
A. Justification of SCE’s Request for Pre-Approval Or Tier 3 Approval Process for Certain
RPS-Eligible Transactions
SCE requests authorization to enter into a limited quantity of renewable energy transactions for
REC products through a pre-approvalTier 1 or Tier 3 Advice Letter approval process.
SCE seeks pre-approvalto use the Tier 1 process for all transactions that meet the following strict
upfront standards and criteria:
Transactions through an RFO or Bi-lateral contracts subject to the following:
6369 Id. at Section 4.01(d). 6470 See 2019 Procurement Protocol (attached as Appendix H.1) at Section 9.03. 6571 ALJ’ Ruling, OP 2, p.3.
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Term would be limited to transactions through the next full CP (CP 4 ending
2024)
Transactions through RFOs, awards would only be made to projects with offers at
or above the price floor as set forth in Appendix E.
Bi-lateral contracts would only be entered into after an RFO was held under this
2019 RPS Plan
Transactions through brokers and exchanges
Term would be limited to 3 years or less
SCE includes a list of approved brokers that have indicated they could potentially
engage in California REC Sales in Confidential Appendix E.
Transactions with term lengths that extend beyond the end of the next CP (CP 4 ending 2024) or
do not otherwise meet the above criteria would be subject to a Tier 3 Advice Letter approval process.
D.19-02-007 adopted a Tier 1 Advice Letter approval process for contracts resulting from
solicitations pursuant to the 2018 Plan. In this Draft 2019 RPS Plan, SCE proposes a pre-approval
process for the transactions listed above that meet strict upfront standards and criteria. SCE provides
more detail around the price floor, volume limits and approval process below and provides its REC sales
strategy in Confidential Appendix E.
SCE requests pre-approval at this time as market conditions have changed. There are more
CCAs, and there has been an increase in the amount of load that can be served as DA. Therefore, there
is a broader market for RECs. SCE wants to be responsive to that broader market and allow for the
quickest, most efficient approval process, while still protecting SCE’s customers interests. Specifically,
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SCE’s proposed upfront standards and criteria around pre-approval (term length, pricing and volume
limits) require SCE to act prudently and allow for greater ease and less burden on the part of SCE, the
Buyer and the Commission in completing the contracting process.
SCE notes that the price floor set forth in Appendix E is an interim step pending the outcome of
the PCIA decision. To the extent that the PCIA decision, on Track 3, addresses a new price floor, SCE
will adopt that new price floor.
1. SCE Has More Renewable Energy To Meet Its Goals Than It Needs For The
Foreseeable Future
SCE is well positioned to meet the CP 3 2020 33% RPS target with existing projects and
projects under development (risk-adjusted). Therefore, SCE did not hold an RPS procurement
solicitation for the 2016, 2017 and 2018 cycles. SCE forecasts that it will have excess RECs at least
through 2028 without the use of its REC bank and through CP 6 (2028-2030) and beyond with the use of
the REC bank for compliance purposes using SCE’s assumptions.
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
adjust the portfolio quickly using short term products. Until recently,6672 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 and there was not significant depth in
the short-term markets. Large LSEs instead used the banking rules to build portfolios to account for
uncertainties in project development, load forecasts and production. This led to the development of
banked positions that also resulted in an inability to use short-term products to meet any future needs
due to RPS retirement rules. New legislation (SB 350) adopted in 2016 removed these barriers.
6672 D.17-06-026.
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A combination of long-term and short-term procurement will allow LSEs to build more
cost-effective portfolios for customers. Long-term procurement can focus on bringing new projects
online. Short-term procurement can focus on balancing the portfolio to meet compliance requirements
at the lowest possible cost. This combination of long-term and short-term procurement will also allow
for a free exchange of RECs between different entities who may have over/under procured for their
compliance needs.
The Commission’s RPS compliance reports demonstrate the state’s progress in meeting
its aggressive RPS procurement targets, driven by the investments made by the three large IOUs in
California. Currently all IOUs are long for RPS energy, and some ESPs and/or CCAs may need RECs
to meet compliance requirements soon, as well as meeting their additional sustainability goals that many
have set forth - above and beyond their compliance requirements. Allowing for the free trade of these
long positions between LSEs will allow for a lower cost outcome for all customers. An open market
will provide for a lower cost and flexible option for meeting RPS requirements.
In addition, all retail sellers must procure a minimum level of PCC 1 RECs; the minimum
level increases over multi-year compliance periods.6773 For CP 3, the minimum requirement for PCC 1
procurement is 75%, which is higher than previous compliance periods. Also, there is a maximum limit
on the amount of PCC 3 procurement that may be used in each compliance period, which decreases over
the same time frame. As a result, entities cannot solely depend on PCC 3 RECs acquired towards the
end of a CP. Any newly formed entity during the CP 3 timeframe (2018-2020) will have to meet the
same requirements for RPS compliance as described. Most of these requirements will have to be met
using existing facilities, since development of new projects (i.e., siting, licensing, construction,
contracting) is a time-consuming process that will likely not be able to be completed in time to meet the
33% RPS compliance requirement by 2020. Accordingly, it is important for all market participants to
have access to purchase RECs sourced from existing facilities to avoid potential market distortions and
compliance shortfalls.
6773 CAL. PUB. UTIL. CODE § 399.16(c).
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In addition, as discussed in Section III above, beginning in 2021, SB 350, as implemented
in D.17-06-026, requires that all entities must meet 65% of their RPS target with eligible renewable
resources having long-term contracts or ownership arrangements of 10 years or more. Accordingly, it is
important for all market participants to have access to purchase long-term RECs sourced from existing
facilities either for the duration of a contract for a specific facility or for 10 years for non-project specific
contracts to avoid potential market distortions.
3. REC Sales Will Create Customer Value
a) Selling is better than banking up to the established limits
When SCE considers whether to engage in sales of renewable energy products,
SCE compares the value obtained from selling RECs to the costs of having to procure additional
renewable energy in the future. SCE analyzes the impact to its renewable needs and the costs to
customers using 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
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targets after making the sale. SCE’s overall approach appropriately balances the risks and costs of
selling renewable energy products with the risks and costs of maintaining an RPS bank.
b) REC Sales Stabilize Rates By Realizing Near Term Value
SCE has a REC bank beyond CP 6 (2028-2030)6874 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
and SB 100. As a result, REC sales can help create near term value and in turn create near term rate
relief for SCE customers. SCE holds a significantly long position to meet compliance needs in the near
term. If SCE can generate some revenues through REC sales, it will help smooth out SCE’s RPS
compliance positions over these coming years. In turn, these REC sales would smooth out the rate
impacts over the years to SCE’s customers because RECs from more expensive contracts would be sold
and replaced with cheaper renewable energy for compliance for future years, taking advantage of
declining renewable prices.
c) SB 350 Allows for IOUs’ Use Of More Short-term Products, Which Could Help
Lower Costs for Customers, While Requiring Other LSEs to Use More Long-term
Products
SB 3506975 requires that 65% of the total renewable portfolio that a retail seller
counts toward the RPS target for each compliance period must be from long-term contracts, starting no
later than 2021. The previous long-term contracting requirement for retail sellers was smaller - 0.25%
of prior period’s total retail sales.
Starting in 2017, any retail seller can elect to use the new SB 350 rules, allowing
35% of RECs towards the RPS targets to come from short-term contracts.7076 Any retail seller making
such an election must, however, meet the 65% long-term contracting requirement.7177 Short-term
contracts would facilitate the following types of projects/products to count toward RPS targets:
6874 See Section IV.A, above. 6975 D.17-06-026 http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID=191530416. 7076 Id. at OPs 15-24, at pp. 54-56. 7177 Id. at CoL 6, at p. 42.
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Seven-year renewable QF 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, 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.
d) SCE Was Directed to Sell BioRAM RECs
D.18-12-003 directed SCE to sell the RECs associated with its BioRAM contracts
as PCC 1 RECs as soon as possible after issuance of the Decision.7278 BioRAM associated REC sales
are to be filed with the Commission as a Tier 1 Advice Letter so long as the contract:
1. utilizes a Commission-approved RPS Sales pro forma agreement;
2. shows any necessary modifications to the pro forma agreement via a
comparison document provided with the Tier 1 filing; and
3. is for a duration of five years or less.7379
In its REC Sale Solicitation (“REC RFO”), SCE will allow buyers to bid on
RECs: i) that are generated solely from BioRAM projects; or ii) that are generated solely from
renewable resources other than BioRAM projects. REC sales generated from renewable resources other
than BioRAM projects will be subject to the price floor as set forth in Table XVI-4. RECs generated
solely from BioRAM projects are not subject to the price floor set forth in Table XVI-4.
7278 D.18-12-003, at p. 12. 7379 Id.
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B. SCE’s ProposalREC Sales Framework
1. Pre-ApprovalREC Sales Framework
SCE proposes pre-approval for most of its REC sales. This proposed approach
The REC Sales Framework approved in D.19-12-042, OP 19,80 includes terms, volume
limits, and a pricing floor as summarized in Table XVI-3 below:
80 D.19-12-042, OP 19, pp. 90-91.
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Table XVI-3 SCE’sCommission-Adopted REC Sales Framework
The proposed changes in Table XVI-3 below are designed to help maximize customer value by providing SCE with more flexibility to transact, access to more markets and more regulatory approval efficiency. Bold and underlined text = changes from the 2018 Plan
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Parameter Approved 2018 RPS Plan Proposed 2019 RPS Plan Rationale for Change
Pricing See Confidential Appendix E See Confidential Appendix E See Confidential Appendix E
Transaction Mediums
RFO Process, Bilateral RFO Process, Exchanges, electronic Solicitations, Brokers, Bilateral
Increase ability to transact by taking advantage of market mechanisms already in place. SCE has received offers to buy RECs through brokers that are at and above prices seen through RFOs.
Term Length 5 years or less No longer than the end of the next full Compliance Period (CP4; 2024) for pre‐approval. No longer than 3 years for any sales through brokers or exchanges. If the term is longer, then the contract is subject to the Tier 3 Advice Letter Process.
Provides reasonable term length for preapproved transactions. Restricts transactions through brokers and exchanges which provides more certainty around what the pre‐approved terms will be.
Sales Volume Limits
Methodology based on load/gen forecast and uncertainty around it, changing RPS legislation and anticipated pricing. SCE will maintain a “margin of safety”. Will attempt to sell all RECs from BioRAM.
Methodology based on load/gen forecast and uncertainty around it, changing RPS legislation and anticipated pricing. SCE will maintain a “margin of safety”. SCE will attempt to sell all RECs from BioRAM projects. Sales from brokers and exchanges will be further limited to no more than 50% of all RECs sold under the 2019 RPS Plan irrespective of the term or vintage.
Restricts amount of sales through brokers to ensure that the majority of sales will be completed through the RFO process so that further market data can be received prior to entering into broker transactions.
PRG Consultation Quarterly at PRG Meetings Same N/A
Approval Process Tier 1 if sold through RFO. All others, Tier 3.
Pre‐approval if: i) meets all CPUC pre‐approved price floor and volume limits; ii) is sold through an RFO or bilateral after results from an RFO have been received; and iii) the term length is no longer than the end of the next full Compliance Period (CP4; 2024). Transactions through brokers and exchanges preapproved if term is less than 3 years. Subject to CPUC approved price and volume constraints detailed in the RPS Plan. Also subject, in each case, to using the REC Sales Confirm with no changes. All others, Tier 3.
Pre‐approval allows SCE to transact quickly through brokers as well as RFOs and bilaterals. The terms under which SCE can transact are limited so there is some certainty around what is being pre‐approved. More efficient for SCE, buyers and the CPUC.
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Parameter Approved 2019 RPS Plan
Transaction mediums RFO Process, Bilateral (strong showing)
Terms 5 years or less
Sales Volume Limit Methodology based on a per-vintage year basis. SCE will maintain a compliance margin amount. Attempt to sell all RECs from BioRAM projects.
PRG Consultation Quarterly, at PRG meetings
Parameter Approved 2018 RPS Plan
Pricing Confidential Pricing floor as set forth in Appendix E
Approval Process Tier 1 if sold through solicitation. All others, Tier 3.
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Subject to the criteria set forth in this Section XV1 and Appendix E, SCE is seeking pre-
approval for: i) each of its contracts resulting from a solicitation and utilizing the pro forma REC Sales
Agreement that is attached to this Written Plan as Appendix I; and ii) bilateral contracts that utilize the
pro forma REC Sales Agreement and that are executed after SCE receives bids for a sales solicitation
resulting from this Written Plan; and iii) contracts entered into through brokers and exchanges utilizing
the pro forma REC Sales Agreement.
2. Tier 3 Approval Process
SCE may also engage in bilateral REC sales transactions that do not utilize the pro forma
REC Sales Agreement attached as Appendix I to this Written Plan, have term lengths that extend beyond
2024, do not conform to the price floor constraints as set forth in Appendix E, or that are not executed
after SCE received bids for a sales solicitation resulting from this 2019 RPS Plan.7481 These bilateral
REC sales transactions would be subject to the Commission’s review and approval of completed
transactions through a Tier 3 Advice Letter process (consistent with D.09-06-050).7582
C. SCE’s Proposed Limits on REC Sales
Appendix E, Section II describes and provides an example calculation of SCE’s proposedthe
REC sales volume limitslimit on a per-vintage year basis, as ordered by D.19-12-042, OP 28. SCE will
attempt to sell all of its BioRAM RECs.
D. Acceptable REC pricing
Appendix E, Section III sets out SCE’sthe confidential pricing standard for SCE’s REC sales, as
adopted in D.19-012-042, OP 28.
E. Proposed Transactional Methods
SCE proposes severaltwo 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
7481 See, D.19-02-007, pp. 116-117, OP 10. 7582 Id.
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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 and Electronic Solicitations
SCE proposes to maximize value to its customers through competitive solicitations and
electronic solicitations that encourage participants to offer the highest possible price when purchasing
RECs. When buying renewable energy, SCE has seen much higher costs being offered through
mandated procurement, non-competitive programs. Typically, these programs may focus on specific
technologies or project size. Conversely, SCE’s RPS Solicitations have consistently brought the lowest
renewable prices through the competitive bidding process. Similarly, higher prices may be realized
through a competitive solicitation when SCE sells RECs. Additionally, a competitive solicitation will
allow SCE to discover where the market is, in terms of the prices buyers are willing to pay for RECs.
2. Bilateral Transactions
In certain instances, SCE may accept bilateral offers to purchase RECs. For example, if
there are a small number of interested parties in the REC market or deadlines are approaching where an
interested party needs to purchase RECs, to meet a unique need, prior to a solicitation being launched.
These and other situations may lead to SCE selling RECs bilaterally rather than through a competitive
process. Such sales would be pre-approved, if entered into after and within 4 months of a solicitation
pursuant to this 2019 RPS Plan and meeting term limits, pricing, volume and other criteria set forth in
this 2019 RPS Plan including Appendix E.
3. Brokers and Exchanges
SCE requests authorization to enter into a limited quantity of short-term sales transactions
for REC products through brokers and exchanges. To SCE’s knowledge, no exchange currently carries
RECs. However, SCE would like authority from the Commission to act in case RECs are ultimately
listed on an exchange, and SCE can receive competitive pricing selling through the exchange. SCE has
encountered opportunities to sell RECs at competitive prices through brokers. This proposal would be
in-line with current practices of utilizing brokers for non-renewable resources.
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Brokers provide a forum for market participants to trade anonymously with one another.
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. SCE would look to recent solicitations and,
where possible, obtain multiple broker quotes to ensure SCE receives a fair market price for the REC
transaction. 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. Low Carbon Fuel Standard (“LCFS”) credits, GHG Offsets)
products that may or may not be traded on exchanges. SCE is seeking pre-approval to enter into
transactions with brokers and exchanges for REC transactions as part of this filing so long as the
transaction meets the term limits, pricing, volume and other criteria set forth in this 2019 RPS Plan
including Appendix E.
F. Proposed Timeline for REC Sales
SCE’s Procurement Protocol (the form of which is included in Appendix J) sets out a proposed
timeline for any REC Sales done through an RFO. All other types ofBilateral REC sales transactions
would occur following Commission approval of SCE’s 2019 RPS Plan.
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.7683 The Commission also authorized the IOUs to use an optional
streamlined RAM procurement tool in future RPS solicitations.7784 The Commission directed the IOUs
7683 See D.14-11-042 at pp. 91-92, pp. 102-104. 7784 Id. at pp. 91-92.
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to include the streamlined procurement tool in their RPS Procurement Plans, at their discretion, starting
with the 2015 RPS Procurement Plans.7885
Since the Standard Contract Option is part of the RPS Solicitation, it only gets utilized when
SCE holds a solicitation. Consistent with the Commission’s intent to provide the IOUs with flexibility
to optimize their portfolios based on their procurement needs while providing a streamlined procurement
tool,7986 the Standard Contract Option allows 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.8087
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.”8188 If SCE holds a procurement for Community Renewables,
SCE will use the Standard Contract Option for GTSR procurement needs as discussed in Section XVIII.
7885 Id. at p. 92. 7986 Id. 8087 SCE’s 2018 Pro Forma is structured with the assumption that the generating facility will have a first
point of interconnection with the CAISO. Accordingly, changes to the 2018 Pro Forma will be required for dynamically scheduled projects.
8188 D.14-11-042 at p. 92.
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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.8289 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 2019 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 2019 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 2019, SCE made changes to the 2018 Pro Forma that are applicable to the Standard Contract
Option. Please see Section I.B.
8289 Id. at p. 93.
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XVIII.
GREEN ENERGY TARIFF SHARED RENEWABLE PROGRAMPROGRAMS
A. Green Tariff Shared Renewable and Community Renewable Programs
On September 28, 2013, Governor Brown signed SB 43 into law.8390 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.8491 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”8592 (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.8693
The GTSR program structure approved by the Commission consists of two elements: (1) a green
tariff option (called the “Green Rate” or “GR” 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
8390 SB 43 was codified in California Public Utilities Code Section 2831 et seq. 8491 See D.15-01-051 at OP 7. 8592 CAL. PUB. UTIL. CODE § 2833(d)(1). 8693 See D.15-01-051 at OP 7 and D.15-01-051 at pp. 4-5.
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community-based projects.8794 With regard to the Green Rate, SCE procured its 50 MW advance
procurement requirement in its 2015 RPS solicitation. SCE does not anticipate doing additional Green
Rate procurement. This is because the Green Rate program currently has a limited number of
subscribed customers and SCE’s advance procurement is expected to satisfy initial customer enrollment.
1. 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.8895 The Commission limited initial procurement to new solar facilities between 0.5 MW
and 3 MW,8996 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.9097 Additionally, now that the CAISO has resolved Distributed Energy Resource
Provider issues, D.16-05-006 allows for aggregation of sub-500 kW resources to participate in the CR
program as long as they aggregate to at least 500 kW and meet all CAISO requirements.9198 CR projects
must be located within SCE’s service territory9299 and must satisfy the eligibility requirements
associated with the RAM procurement tool.93100
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;94101 (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
8794 Id. at pp. 3-4. 8895 Id. at OP 1. 8996 Id. at pp. 36-37, p. 39, CoL 17. 9097 See D.16-05-006, CoLs 2 and 4. 9198 Id. at OP 5. 9299 See D.15-01-051 at pp. 21-23, CoL 14. 93100 See D.16-05-006 at p. 35, CoL 4. 94101 Advice 3180-E was approved by Energy Division, effective as of February 23, 2015.
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Implementation Advice Letter;95102 (v) Advice 3432-E, which is the 20 Year Forecast of GTSR bill
credits and charges;96103 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.97104
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;98105 (ii) Advice 3496-E, 2017 annual
marketing, education and outreach plan and budget for the GTSR program;99106 (iii) Advice 3525-E,
which is SCE’s GTSR program rate component updates for 2017;100107 (iv) Advice 3525-E-A,
supplemental filing to make modifications to Advice 3525-E;101108 (v) Advice 3536-E, which
implements the California alternate rates for energy for the GTSR Program;102109 (vi) Advice 3557-E,
which updated the CR-RAM Rider and RFO Instructions for CR-RAM Two;103110 (vii) Advice 3614-E,
which is the update to the 20 Year Forecast of GTSR bill credits and charges;104111 (viii) Petition for
Modification (“PFM”) for D.15-01-051 to change the AmLaw 100105112 securities opinion
95102 The Commission approved Advice 3218-E, 3219-E, and 3220-E, with modifications, in Resolution E-4734.
96103 Advice 3432-E was approved by Energy Division, effective as of July 11, 2016. 97104 Advice 3422-E was approved by Energy Division, effective as of June 15, 2016. 98105 Advice 3461-E was approved by Energy Division, effective as of September 25, 2016. 99106 Advice 3496-E was approved by Energy Division, effective as of November 27, 2016. 100107 Advice 3525-E was approved by Energy Division, effective as of January 1, 2017. 101108 Advice 3525-E-A was approved by Energy Division, effective as of January 1, 2017. 102109 Advice 3536-E was approved by Energy Division, effective as of October 26, 2017. 103110 Advice 3557-E was approved by Energy Division, effective as of March 12, 2017. 104111 Advice 3614-E was approved by Energy Division, effective as of June 5, 2017. 105112 “AmLaw 100” refers to The American Lawyer magazine’s annual ranking of law firms in the United
States based on gross revenue.
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requirement;106113 (ix) Advice 3638-E, modifying the securities opinion requirement in the CR-RAM
Rider pursuant to D.17-07-007;107114 (x) Advice 3694-E, which updated the CR-RAM Rider and RFO
Instructions for CR-RAM Three;108115 (xi) Advice 3678-E, 2018 annual marketing, education and
outreach plan and budget for the GTSR program;109116 (xii) Advice 3678-E-A, supplement to Advice
3678-E;110117 (xiii) Advice 3710-E, updating the GTSR program rate components for 2018;111118 (xiv)
Advice 3710-E-A, supplement to Advice 3170-E;112119 (xv) Advice 3737-E, which updated the 20-year
forecast of GTSR bill credits and charges;113120 (xvi) Advice 3790-E, which updated the CR-RAM Rider
and RFO Instructions for CR-RAM Four,114121 (xvii) Advice 3891-E, which updated the CR-RAM Rider
and RFO Instructions for CR-RAM Five,115122 (xviii) Advice 3877-E, SCE’s 2019 annual marketing,
education and outreach plan and budget for the GTSR program,116123 (xix) Advice 3878-E seeking
approval of a PPA from the CR-RAM 3 solicitation,117124 (xx) Advice 3905-E, SCE’s GTSR program
rate component updates for 2019,118125 (xxi) Advice 3905-E-A, supplements Advice 3905-E,119126 (xxii)
106113 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. 107114 Advice 3638-E was approved by Energy Division, effective as of July 28, 2017. 108115 Advice 3694-E was approved by Energy Division, effective as of November 15, 2017. 109116 Advice 3678-E was approved by Energy Division, effective as of November 15, 2017. 110117 Advice 3678-E-A was approved by Energy Division, effective as of November 15, 2017. 111118 Advice 3710-E was approved by Energy Division, effective as of January 1, 2018. 112119 Advice 3710-E-A was approved by Energy Division, effective as of January 1, 2018. 113120 Advice 3737-E was approved by Energy Division, effective as of January 31, 2018. 114121 Advice 3790-E was approved by Energy Division, effective as of May 20, 2018. 115122 Advice 3891-E was approved by Energy Division, effective as of December 31, 2018. 116123 Advice 3877-E was approved by Energy Division, effective as of November 14, 2018. 117 124 SCE submitted Advice 3878-E on October 16, 2018. The Advice letter has not been approved as of the
date of this filing. 118125 Advice 3905-E was approved by Energy Division, effective as of January 7, 2019. 119126 Advice 3905-E-A was approved by Energy Division, effective as of January 7, 2019.
Appendix A - Page 71
65
Advice 3962-E, which updated the 20-year forecast of GTSR bill credits and charges,120127 (xxiii)
Advice 3898-E, which requests to update the GTSR Tariff to remove language regarding the programs’
closure as of January 1, 2019,121128 and (xxiii) Advice 3976-E approving a PPA from the CR-RAM 4
solicitation.122129
2. B. Community Renewables - Modifications to the 2019 Procurement Protocol, 2019
Pro Forma Standard Contract Option, and LCBF Methodology
SCE incorporated CR-related modifications into its 2016 Procurement Protocol, created a
CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option, and incorporated
modifications to its LCBF Methodology for CR and CR-EJ eligible projects. SCE planned to include a
Community Renewables solicitation in any 2016 RPS solicitation that it would hold after seeking and
receiving Commission permission. SCE intended that if it did not go forward with a 2016 RPS
solicitation, it would move forward separately with a second Community Renewables Solicitation,
which SCE launched on April 7, 2017.
SCE incorporated additional CR-related modifications into its 2017 Procurement
Protocol and updated its CR Rider and Amendment to the 2016 Pro Forma Standard Contract Option,
which is the latest approved contract option. SCE subsequently launched its third, fourth, and fifth
Community Renewables Solicitations on December 22, 2017, May 23, 2018, and January 14, 2019
respectively. As of CR-RAM 3, SCE has provided two CR-RAM Rider options to offerors—one
specifically for Distributed Energy Resources (“DERs”) and the other for projects that do not aggregate
resources.
a) 1. 2019 Procurement Protocol – CR Modifications
The 2019 Procurement Protocol does not include any requirements applicable
only to CR and CR-EJ projects. If SCE holds a CR-RAM Solicitation, SCE will file an Advice Letter
and include a CR-RAM specific protocol.
120127 Advice 3962-E was approved by Energy Division, effective as of February 28, 2019. 121128 Advice 3898-E was approved by Energy Division, effective as of November 20, 2018. 122129 Advice 3976-E was approved by Energy Division, effective as of April 27, 2019.
Appendix A - Page 72
66
3. C. SCE’s Request to Terminate the GTSR Program and Required Modifications to
GTSR
On December 22, 2017, SCE filed a Tier 3 Advice 3722-E requesting the Commission’s
approval to terminate the GTSR program on January 1, 2019,123130 and to seek approval to recover
outstanding GTSR costs through the 2018 ERRA Review of Operations Filing.124131 In that letter, SCE
explained that it would seek Commission approval in 2018 for new programs to replace its GTSR
Program, which it did (described in Section XVIII.E below). On December 22, 2017 and December 26,
2017, respectively, PG&E and SDG&E filed Tier 3 advice letters seeking to extend GTSR beyond
January 1, 2019 and to make modest modifications to the program.132 On August 20, 2019, Energy
Division issued Draft Resolution E-5028 which, if approved, will deny SCE’s request to terminate
GTSR and will require the three IOUs to make certain modifications to GTSR.
4. Adjustment to RPS Load Forecast for GTSR and CR Program
As of the date of this filing, Advice 3722-E is pending Commission approval. discussed
in Chapter IV, Section A, SCE adjusted its RPS load forecast to remove customer load served under the
Green Tariff portion of the GTSR program.133 This is consistent with SB 43 and intentions of the GTSR
and CR programs, which require the utilities to retire the RECs from subscribed energy on behalf of the
subscribing customers.134 SB 43 thus allows the utility to “exclude from total retail sales the kilowatt
hours generated by an eligible renewable energy resource that is credited to a participating customer
pursuant to the utility’s green tariff shared renewables program, commencing with the point in time at
which the generating facility achieves commercial operation.”135 Consistent with SB 43, SCE reduced
123130 See D.15-01-051 at OP 13. 124131 Advice 3722-E. As of the date of this filing, Advice 3722-E is pending Commission approval. 132 See PG&E Advice 3920-G/5206-E and SDG&E Advice 3168-E. 133 No customers are presently being served under the Community Renewables Rate. As a result, SCE only
counted Green Rate customers here. 134 See CAL. PUB. UTIL. CODE § 2833(s). 135 CAL. PUB. UTIL. CODE § 2833(u).
Appendix A - Page 73
67
its bundled retail sales forecast used to calculate its RPS goals by the amount of energy used to serve
Green Rate customer load.136 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.137 Prior to dedicated resources procured to serve Green Rate customers beginning service, SCE
transferred RECs from other RPS-eligible resources in its Interim Green Rate Pool to serve Green Rate
subscriptions. In March 2018, one dedicated Green Rate resource became operational. SCE expects to
begin transferring RECs from this dedicated Green Rate resource in 2019 for 2018 customer
subscriptions.
B. D. SCE’s Disadvantaged Communities (DAC) Green Tariff and Community Solar
Programs
On June 21, 2018, the Commission approved D.18-06-027, Alternate Decision Adopting
Alternatives to Promote Solar Distributed Generation in Disadvantaged Communities, which
implements three new programs to promote solar energy in disadvantaged communities. Two of the
programs, the new DAC-Green Tariff program and the Community Solar Green Tariff program, are
similar to the GTSR Green Rate and Enhanced Community Renewables programs, respectively. The
DAC - Green Tariff Program will be available only to low-income residential customers in DACs,
defined as those meeting the qualifications for CARE and FERA. The Community Solar Green Tariff
Program will be similar to the DAC - Green Tariff program. The major difference between the DAC-
Green Tariff program and the Community Solar Green Tariff program is that the Community Solar
Green Tariff program requires community involvement with the solar project through a local sponsor
and will result in a solar facility serving a nearby community. The program is similar to Enhanced
Community Renewables in that the developer contracts with the customer to service the energy
component of the bill and contracts with SCE for the energy not subscribed by the SCE customer.
136 Id. 137 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.
Appendix A - Page 74
68
SCE filed Advice Letters 3851-E and 3851-E-A to implement the DAC-Green Tariff and
Community Solar Green Tariff Programs. The Advice Letter was filed on August 20, 2018, and the
supplement on February 27, 2019. On June 3, 2019, the Commission issued Resolution E-4999
approving SCE’s AL 3851-E and 3851-E-A with modifications. SCE the tariffs filed Advice Letter
3841by the IOUs to implement two of the three programs – the DAC-EGT and CSGT programs. These
programs provide bill credits to eligible customers who elect to take service under SCE’s DAC-GT or
CSGT tariffs.
Under the DAC-GT program, eligible customers138 may have 100% of their load served by
eligible renewable resources. They will receive a 20% bill credit off their otherwise applicable rate.
SCE’s program size is 56.5 MW.
Like the DAC-GT program, the CSGT program provides a 20% bill credit to eligible
customers139 who “subscribe” to the output of a community renewable facility located within an eligible
DAC. Additionally, the CSGT program requires the sponsorship of the solar facility by a community
sponsor, who can attest to community interest in the project. The community sponsor(s), if eligible, may
share in the bill credits for up to 25% of a CSGT project’s output Any RECs from unsubscribed energy
procured through the DAC-GT and CSGT programs that is not subscribed by SCE customers (“DAC
Programs Excess Energy”) will be allocated to SCE’s RPS position.
On July 3, 2019, SCE filed supplemental AL 3851-E-B to implement the modifications required
by Resolution E-4999. Also pursuant to Resolution E-4999, on August 2, 2019, SCE filed AL 4049-E
seeking approval of SCE’s DAC-GT and CSGT solicitation materials and AL 4050-E seeking approval
of SCE’s DAC-GT and CSGT budget for 2019-2020 and SCE’s Marketing, Education, and Outreach
Plan for the programs for 2019-2021.
138 The DAC-GT program is open to customers who are eligible for CARE or FERA, and who reside in an
eligible DAC. 139 Customers must reside in an eligible DAC as defined in D.18-06-027 and Resolution E-4999, and live within
a census tract that is within a prescribed distance of the solar facility. Customers who reside in an eligible DAC, but who are not eligible for CARE or FERA may receive a bill credit once low income subscription levels are met.
Appendix A - Page 75
69
Additionally, SCE filed Advice Letters 3841-E, 3841-E-A, and 3841-E-B establishing the DAC-
Green Tariff and Community Solar Green TariffCSGT Balancing Accounts. The Advice Letter was
filed on August 6, 2018 and the supplement on February 22, 2019. This Advice Letter remains
pendingOn July 11, 2019, Energy Division sent a letter approving ALs 3841-E, 3841-E-A, and 3841-E-
B with an effective date of September 5, 2018.
E. SCE’s GTSR Replacement Program
1. Adjustment to RPS Load Forecast for DAC-GT and CSGT Programs
Like how SCE adjusts its load forecast to account for the load served under the GTSR
and CR programs, SCE proposes to adjust its RPS load forecast to remove customer load served under
the DAC-GT and CSGT programs. Although the provisions of SB 43 do not govern the DAC-GT and
CSGT programs, the rationale for adjusting the load forecast for the DAC programs equally applies.
Specifically, as with the GTSR and CR programs,140 SCE will be retiring the RECs from subscribed
energy on behalf of subscribing customers. Thus, it is reasonable for SCE to reduce its bundled retail
sales forecast used to calculate its RPS goals by the amount of energy used to serve DAC-GT and CSGT
customer load. Like the GTSR program, SCE will also deduct DAC-GT and CSGT subscriptions from
SCE’s generation forecasts to remove energy deliveries associated with the load served under the DAC-
GT and CSGT programs.
C. New Green Energy Programs
In Advice 3722-E, in which it requested the Commission’s approval to terminate the GTSR
program, SCE stated it would propose a replacement program for GTSR. As of the date of this filing,
the Commission has not yet issued a Draft Resolution on Advice 3722-E. On September 26, 2018, SCE
filed Application (“A.”) 18-09-015 seeking Commission approval of five new Green Energy Programs
to replace the existing GTSR program in 2021. On October 29, 2018 protests and responses were filed,
and a prehearing conference was held on December 3, 2018. On February 8, 2019 and February 15,
2019, respectively, SCE and other parties filed opening and reply briefs, as directed by ALJ Liang-
140 No customers are presently being served under the Community Renewables Rate. As a result, SCE only counted Green Rate customers here.
Appendix A - Page 76
70
Uejio’s January 18, 2019 Ruling Directing the Filing of Legal Briefs, on whether SCE’s proposed new
programs need to comply with Public Utilities Code §§ 2281-2833, which resulted from SB 43
establishing the GTSR program. A scoping memo was issued on April 19, 2019. On June 3, 2019, The
Commission issued D.19-05-031 dismissing SCE’s application without prejudging the merits of SCE’s
proposals. SCE is considering whether to submit a new application proposing new green energy
programs that would not be intended to replace GTSR. SCE would not file any such application until
2020.
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 2024.125141
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.126142
125141 See D.13-10-040 at pp. 15, 26. 126142 See Southern California Edison Company’s (U 338-E) Application for Approval of its 2018 Energy
Storage Procurement Plan (filed biennially). The Application can be located here: 2018 Energy Storage Procurement and Investment Plan.
Appendix A - Page 77
71
C. Informational Only TOD Factors
1. Introduction
Pursuant to D.19-02-007, Ordering Paragraph No. 17, 127143 adopting the 2018 RPS Plan,
the IOUs developed a joint proposal for informational only TOD Factors and mailed it to the service list
of this proceeding on May 30, 2019.
SCE may modify the informational only TOD factors depending upon the outcome of the
Commission’s review of themD.19-012-042, OP 16 approved the Joint IOU Proposal.
2. The Joint IOU Information Only TOD Proposal
The Joint IOUs are proposing multiple sets of informational TOD heat maps in a month-
hour matrix for different years. The values in the heat maps provide information on the relative value of
electricity delivered during different hours and months while also capturing changes over a long-term
contract horizon. Hours in the heat maps with values closestcloser to zero have a higher expectation of
curtailment. The proposed Joint IOU informational TOD heat map methodology is described below.
In general, creating the informational TOD heat maps will involve four steps:
a) Each IOU will use the Marginal Energy Cost (“MEC”)128144 data from its most recent
General Rate Case (“GRC”) Phase II filing as the source data.
b) Each IOU will calculate the hourly average MEC over the entire year (8760 hours for
non-leap years) using their GRC dataset from Step 1. Each year will have two sets of
informational TOD heat maps: 1) Weekdays and 2) Weekends and Holidays. The month-
hour average for each of the weekdays and weekends & holidays will be divided by the
annual average. Any individual hours with a value less than zero will be set to zero
before computing the annual and month-hour averages.129145
127143 D.19-02-007, OP 17, p.118. 128144
The MEC data used in the GRC proceeding represents the energy price for an incremental unit of energy needed to serve customer loads and includes the costs related to congestion and line losses.
129145 This is done to take into account recent changes in the California Independent System Operator’s
(“CAISO”) energy markets such as the expansion of the Energy Imbalance Market, which appear to be resulting in a soft floor of zero in Day-Ahead and Real-Time energy prices in the CAISO.
Appendix A - Page 78
72
c) Each IOU will provide the informational TOD heat maps for three different years based
on each IOU’s GRC filing year (e.g., Year 1, Year 5, and Year 10). This means
thatTherefore, a total of six informational TOD heat maps will be provided from each
IOU including two heat maps for each year, one map showingfor weekdays and another
map showingfor weekends and holidays.
d) Finally, each IOU will apply Microsoft Excel’s built-in heat map with default (i.e.
automatically suggested) formatting to all heat maps individually, with red
beingindicating the highest and green being the lowest MEC, represented as a proportion
of the annual average.
Due to existing GRC data availability, each IOU is initially providing the informational
TOD heat maps for two different years – 2020 and 2024 – instead of three different years as proposed
above to be done going forward. Following each future GRC filing in which one of the IOUs updates its
energy price forecast, each IOU will follow the general methodology described above and provide new
informational TOD heat maps for three different years in the next filing of its RPS Plan.
3. SCE’s Informational TOD Heat Maps
SCE used its 2018 GRC130146 filing data to develop the informational TOD heat maps for
2020 and 2024 that are shown in Appendix K. SCE’s MEC forecasts were created using a fundamental
model of the CAISO system in Energy Exemplar’s PLEXOS software. Assumptions were populated for
available generation, heat rates, system load, and fuel and GHG costs – minimized to achieve the lowest
system operating cost.
D. 19-12-042 ordered SCE to include in its final 2019 RPS Plan “new informational-only
TODs that are based on the most recent inputs that are available.”147 SCE includes its informational
only TOD factors from the IOUs’ Joint Proposal in Appendix K utilizing the most recent public price
130146 See SCE’s Phase 2 of 2018 General Rate Case Marginal Cost and Sales Forecast Proposals. Section C and
Appendix C includes methodology, data source, and major input assumptions. MECs for test year 2021 were used in Phase 2 of SCE’s 2018 GRC.
147 D.19-12-042, OP 26, p. 95.
Appendix A - Page 79
73
forecasts that are available. Due to the unavailability of updated GRC Phase 2 pricing data, SCE is not
able to update the TODs in Appendix K at this time. SCE will have updated publicly available pricing
data when it submits its 2021 GRC Phase 2 later in 2020. SCE will refresh the informational TOD heat
maps with publicly available pricing information from its 2021 Phase 2 GRC filing148 and include the
update in its 2020 RPS Plan, as explained in the Joint IOUs’ Proposal.
The approved Joint IOUs’ Proposal includes using publicly available Phase 2 GRC
pricing data to develop the informational only TOD heat maps to avoid revealing utility’s proprietary
energy price forecasts which are protected for three years pursuant to the D.06-06-066 Matrix. The
Phase 2 GRC pricing data typically is consistent with SCE’s confidential energy price forecasts.
Informational TOD heat maps are intended to communicate to potential bidders when
energy delivery can be more valuable to the system. Heat maps depicting the relative magnitude of
factors between hours and months are more useful information than the actual factors themselves. The
Joint IOUs’ Proposal included heat map formatting with color schemes to visualize this information
more effectively.
148 SCE’s GRC team is planning to file the 2021 GRC Phase 2 in June 2020. If updated pricing data from that
filing data is available in time, SCE will include the new informational only TOD factors in its 2020 Draft RPS plan.
Appendix A - Page 80
PUBLIC APPENDIX B
Project Development Status Update
Reporting LSE Name
Project Name Technology Type Project Development Phase City County State Zip Code Latitude LongitudeContract Length (Years)
Contract Execution
Date
Contract Start Date
Contract End Date
Contract Capacity
Expected Annual
Generation
Total Contract Volume
Project Notes
SCE 41MB 8ME LLC Solar PV ‐ Ground mount Pre‐Construction Madera Madera CA 93636 36.9413 -119.960655 20 07/31/14 6/1/2020 5/31/2040 51.3 125 2,493
Expected Annual Generation (column Q) is averaged out for the term of the PPA, which
includes the annual degradation factor.
SCE 5149 Lancaster Energy LLC Solar PV ‐ Ground mount Pre‐Construction Lancaster Los Angeles CA 93535 34.73 -118.22 20 02/14/19 12/1/2019 11/30/2039 3 9.61 192.2
SCE 88FT 8ME LLC (Mount Signal II)
Solar PV ‐ Ground mount Construction Calexico Imperial CA 92231 32.6683 -115.639941 20 07/31/14 6/1/2020 5/31/2040 153.52 402 8,036
Expected Annual Generation (column Q) is averaged out for the term of the PPA, which
includes the annual degradation factor.
SCENorth Rosamond Solar,
LLCSolar PV ‐ Ground mount Construction Rosamond Kern CA 93560 34.86 -118.35 15 10/09/15 6/14/2019 6/30/2034 160 488 7320
Contract Capacity expected to be lower than 160
SCE Antelope DSR 3, LLC Solar PV ‐ Ground mount Construction Lancaster Los Angeles CA 93536 34.74 -118.302 20 07/28/16 9/5/2019 9/30/2039 20 56 1,120
SCE Blythe Solar III, LLC Solar PV ‐ Ground mount Pre‐Construction Blythe Riverside CA 92225 33.66 -114.735 20 10/15/15 6/1/2020 5/31/2040 136.8 385 7,310.61
SCE Maverick Solar, LLC Solar PV ‐ Ground mount Pre‐Construction Desert Center Riverside CA 92239 33.699 -115.218 15 11/21/16 12/1/2020 12/31/2035 125 416 6,240Project not yet on line.
Anticipated contract start and end date.
SCE Central CA Fuel Cell 2 Biogas Construction Tulare Tulare CA 93274 36.18300047 -119.3737186 20 04/20/18 12/31/2019 12/30/2039 2.8 21 420.717
SCE Copper Mountain Solar 4, LLC
Solar PV ‐ Ground mount Post‐Construction Boulder City Clark NV 89006 34.8393 -118.389699 20 07/31/14 1/1/2020 12/31/2039 93.6 239 4,781
Expected Annual Generation (column Q) is averaged out for the term of the PPA, which
includes the annual degradation factor.
SCE Jaton, LLC Solar PV ‐ Ground mount Pre‐Construction El Mirage San Bernardino CA 92301 34.34123 -117.34333 20 07/18/18 5/1/2020 4/30/2040 3 6.39 127.8
SCE CalCity Solar I, LLC Solar PV ‐ Ground mount Construction California City Kern CA 93505 35.141374 -117.965748 20 05/12/17 7/15/2019 7/15/2039 3 8.58 171.6
SCE Organic Energy Solutions Biogas Construction San Bernardino San Bernardino CA 92407 34.1732578 ‐117.3464156 20 04/20/18 9/15/2019 9/14/2039 1.6 11.85 237
SCESanta Barbara County
Public Works DepartmentBiogas Construction Goleta Santa Barbara CA 93117 34.482175 -120.123485 20 11/30/17 11/29/2019 11/29/2039 2.274 18.008 360
Contract terminated (effective 7/31/2019)
SCE Sun Streams, LLC Solar PV ‐ Ground mount Construction Tonopah Maricopa AZ 85354 33.358 -112.835 15 10/09/15 1/1/2020 12/31/2034 160 467 7005
SCE American Kings Solar, LLC Solar PV ‐ Ground mount Pre‐Construction Lemoore Kings CA 93425 36.2411 -119.8986 15 08/02/16 12/1/2020 11/30/2035 128 348 5212
SCE Sunshine Valley Solar, LLC Solar PV ‐ Ground mount Pre‐Construction Amargosa Valley Nye NV 89020 36.5261 -116.4944 15 10/09/15 1/1/2020 12/31/2034 104 302 4515
SCE Valentine Solar, LLC Solar PV ‐ Ground mount Construction Rosamond Kern CA 93560 34.906 -118.384 15 10/16/15 12/1/2019 11/30/2034 111.2 328 4920
SCE Voyager Wind I, LLC Wind Pre‐Construction Mojave Kern CA 93561 35.052839 -118.310547 15 11/19/15 1/1/2020 12/31/2034 132 439.4016 6591
SCEWindhub Solar A Solar
ProjectSolar PV ‐ Ground mount Pre‐Construction Mojave Kern CA 93501 35.023 -118.291 15 07/28/16 12/16/2019 11/30/2034 20 61 879
Appendix B - Page 1
PUBLIC APPENDIX C.1
Renewable Net Short Calculations Based on CPUC Assumptions
Renewable Net Short Calculations - 2019 RPS Procurement Plans
[LSE Name] Input required No input required Hard-coded
[Date Filed]
Variable Calculation Item
Deficit from RPS prior
to Reporting Year2011
Actual
2012
Actual
2013
Actual2011-2013
2014
Actual
2015
Actual
2016
Actual2014-2016
2017
Actual
2018
Actual
2019
Forecast
2020
Forecast2017-2020
2021
Forecast
2022
Forecast
2023
Forecast
2024
Forecast
2025
Forecast
2026
Forecast
2027
Forecast
2028
Forecast
2029
Forecast
2030
ForecastForecast Year CP1 CP2 1 2 CP3 3 4 5 6 7 8 9 10 11 12
Annual RPS Requirement
A CPUC Bundled Sales Assumptions 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 73,483 71,911 43,697 56,358 55,966 55,470 55,009 54,556 54,100 53,662 B RPS Procurement Quantity Requirement (%) 20.0% 20.0% 20.0% 21.7% 23.3% 25.0% 27.0% 29.0% 31.0% 33.0% 35.8% 38.5% 41.3% 44.0% 46.7% 49.3% 52.0% 54.7% 57.3% 60.0%C A*B Gross RPS Procurement Quantity Requirement (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 19,840 20,854 18,025 24,798 26,117 27,365 28,604 29,824 31,017 32,197 D Voluntary Margin of Over-procurement - - - - - - - - - - - - - - - - - - - - - - - E C+D Net RPS Procurement Need (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 19,840 20,854 18,025 24,798 26,117 27,365 28,604 29,824 31,017 32,197
RPS-Eligible Procurement
Fa Risk-Adjusted RECs from Online Generation 15,585 15,764 16,512 47,861 17,721 18,295 21,134 57,151 23,213 26,272 24,568 24,578 98,631 24,019 23,775 23,424 23,243 23,076 22,751 21,118 19,516 19,052 18,724
Faa Forecast Failure Rate for Online Generation (%) 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Fb Risk-Adjusted RECs from RPS Facilities in Development - - - - - - - - - - 1 ,052 3 ,150 4 ,202 3 ,973 3 ,949 3 ,925 3 ,887 3 ,847 3 ,817 3 ,750 3 ,659 3 ,566 3 ,475
Fbb Forecast Failure Rate for RPS Facilities in Development (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 19.5% 23.0% 22.2% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5%
Fc Pre-Approved Generic RECs - - - - - - - - - - - 30 30 59 83 105 107 106 106 106 107 106 106
Fe Executed REC Sales 362 778 473 1 ,614 - - 404 404 - - 300 - 300 - - - - - - - - - -
F Fa+Fb+Fc-Fe Total RPS Eligible Procurement (GWh) 15,223 14,986 16,039 46,247 17,721 18,295 20,730 56,747 23,213 26,272 25,320 27,758 102,563 28,051 27,806 27,453 27,236 27,030 26,674 24,975 23,281 22,725 22,306
F0 Category 0 RECs 15,170 14,876 15,804 45,850 16,484 15,148 14,912 46,544 13,262 12,546 9 ,944 9 ,465 45,216 8 ,994 9 ,007 9 ,051 8 ,956 8 ,913 8 ,706 8 ,512 8 ,427 8 ,232 8 ,136
F1 Category 1 RECs 52 110 235 398 1 ,237 3 ,147 5 ,818 10,203 9 ,885 13,726 15,375 18,264 57,251 18,998 18,717 18,298 18,173 18,010 17,862 16,356 14,747 14,387 14,063
F2 Category 2 RECs - - - - - - - - - - - - - - - - - - - - - - - F3 Category 3 RECs - - - - - - 0 0 67 - - - 67 - - - - - - - - - -
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1 ,143 1 ,477 1 ,267 745 2 ,325 4 ,337 3 ,373 5 ,418 9 ,428 2 ,439 912 (691) (3 ,630) (6 ,543) (8 ,292) (9 ,891) Gb F/A Annual Gross RPS Position (%) 21% 20% 22% 21% 23% 24% 28% 25% 32% 37% 63% 48% 48% 48% 45% 43% 42% 42%
Application of Bank
Ha Existing Banked RECs above the PQR 0 467 325 0 1,438 2 ,702 3 ,415 1437.70327 5,659 9 ,032 14,450 62,170 64,609 65,521 64,830 61,200 54,657 46,365 Hb RECs above the PQR added to Bank 467 (142) 1 ,113 1 ,438 1 ,265 713 2 ,244 4 ,222 3 ,373 5 ,418 9 ,428 2 ,439 912 - - - - - Hc Non-bankable RECs above the PQR - 9 30 39 2 32 81 115 - - - - - - - - - - - - - - - H Ha+Hb Gross Balance of RECs above the PQR 467 325 1 ,438 1 ,438 2 ,702 3 ,415 5 ,659 5 ,659 9 ,032 14,450 62,170 64,609 65,521 65,521 64,830 61,200 54,657 46,365 Ia Planned Application of RECs above the PQR towards RPS Compliance - - - - - - - - - - - - - - - - - - 691 3 ,630 6 ,543 8 ,292 9 ,891 Ib Planned Sales of RECs above the PQR - - - - - - - - - - - - - - - - - - - - - - - J H-Ia-Ib Net Balance of RECs above the PQR 467 325 1 ,438 1 ,438 2 ,702 3 ,415 5 ,659 5 ,659 9 ,032 14,450 62,170 64,609 65,521 64,830 61,200 54,657 46,365 36,474 J0 Category 0 RECs 1,040 - - 1 ,040 - - - - - - - - - - - - - - - - - - - J1 Category 1 RECs 52 110 235 398 1 ,237 2 ,984 - 4 ,222 9 ,885 13,726 9 ,428 2 ,439 912 - - - - - J2 Category 2 RECs - - - - - - - - - - - - - - - - - - - - - - -
Expiring ContractsK RECs from Expiring RPS Contracts - 369 1 ,347 1 ,715 1 ,790 2 ,202 2 ,593 2 ,695 2 ,698 2 ,927 4 ,374 5 ,700 5 ,826 5 ,823
Net RPS Position (Optimized Net Short)La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1 ,113 1 ,438 1 ,265 713 2 ,244 4 ,222 3 ,373 5 ,418 9 ,428 2 ,439 912 - - - - -
Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.5% 20.6% 23.4% 24.2% 28.0% 25.2% 31.6% 36.5% 62.8% 48.3% 48.3% 49.3% 52.0% 54.7% 57.3% 60.0%
Note: Values are to be input in GWhs
Appendix C.1 - Page 1
PUBLIC APPENDIX C.2
Renewable Net Short Calculations Based on SCE Assumptions
Renewable Net Short Calculations - 2019 RPS Procurement Plans
[LSE Name] Input required No input required Hard-coded
[Date Filed]
Variable Calculation Item
Deficit from RPS prior to
Reporting Year 2011 Actual 2012 Actual 2013 Actual 2011-2013 2014 Actual 2015 Actual 2016 Actual 2014-2016 2017 Actual 2018 Actual 2019 Forecast 2020 Forecast 2017-2020 2021 Forecast 2022 Forecast 2023 Forecast 2024 Forecast 2025 Forecast 2026 Forecast 2027 Forecast 2028 Forecast 2029 Forecast 2030 Forecast
Forecast Year CP1 CP2 1 2 CP3 3 4 5 6 7 8 9 10 11 12
Annual RPS Requirement
A SCE Bundled Sales Forecast 73,777 75,597 74,480 223,854 75,829 75,322 73,621 224,772 73,483 71,911 43,697 43,250 42,920 42,752 42,675 42,625 42,584 42,413
B RPS Procurement Quantity Requirement (%) 20.0% 20.0% 20.0% 21.7% 23.3% 25.0% 27.0% 29.0% 31.0% 33.0% 35.8% 38.5% 41.3% 44.0% 46.7% 49.3% 52.0% 54.7% 57.3% 60.0%
C A*B Gross RPS Procurement Quantity Requirement (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 19,840 20,854 18,025 19,030 20,030 21,091 22,191 23,301 24,415 25,448
D Voluntary Margin of Over-procurement - - - - - - - - - - - - - - - - - - - - - - -
E C+D Net RPS Procurement Need (GWh) 14,755 15,119 14,896 44,771 16,455 17,550 18,405 52,410 19,840 20,854 18,025 19,030 20,030 21,091 22,191 23,301 24,415 25,448
RPS-Eligible Procurement
Fa Risk-Adjusted RECs from Online Generation 15,585 15,764 16,512 47,861 17,721 18,295 21,134 57,151 23,213 26,272 24,568 24,578 98,631 24,019 23,775 23,424 23,243 23,076 22,751 21,118 19,516 19,052 18,724
Faa Forecast Failure Rate for Online Generation (%) 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Fb Risk-Adjusted RECs from RPS Facilities in Development - - - - - - - - - - 1,052 3,150 4,202 3,973 3,949 3,925 3,887 3,847 3,817 3,750 3,659 3,566 3,475
Fbb Forecast Failure Rate for RPS Facilities in Development (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 19.5% 23.0% 22.2% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5% 23.5%
Fc Pre-Approved Generic RECs - - - - - - - - - - - 30 30 59 83 105 107 106 106 106 107 106 106
Fe Executed REC Sales 362 778 473 1,614 - - 404 404 - - 300 - 300 - - - - - - - - - -
F Fa+Fb+Fc-Fe Total RPS Eligible Procurement (GWh) 15,223 14,986 16,039 46,247 17,721 18,295 20,730 56,747 23,213 26,272 25,320 27,758 102,563 28,051 27,806 27,453 27,236 27,030 26,674 24,975 23,281 22,725 22,306
F0 Category 0 RECs 15,170 14,876 15,804 45,850 16,484 15,148 14,912 46,544 13,262 12,546 9,944 9,465 45,216 8,994 9,007 9,051 8,956 8,913 8,706 8,512 8,427 8,232 8,136
F1 Category 1 RECs 52 110 235 398 1,237 3,147 5,818 10,203 9,885 13,726 15,375 18,264 57,251 18,998 18,717 18,298 18,173 18,010 17,862 16,356 14,747 14,387 14,063
F2 Category 2 RECs - - - - - - - - - - - - - - - - - - - - - - -
F3 Category 3 RECs - - - - - - 0 0 67 - - - 67 - - - - - - - - - -
Gross RPS Position (Physical Net Short)
Ga F-E Annual Gross RPS Position (GWh) 467 (133) 1,143 1,477 1,267 745 2,325 4,337 3,373 5,418 9,428 8,206 7,000 5,583 2,784 (20) (1,690) (3,142)
Gb F/A Annual Gross RPS Position (%) 21% 20% 22% 21% 23% 24% 28% 25% 32% 37% 63% 63% 63% 62% 59% 55% 53% 53%
Application of Bank
Ha Existing Banked RECs above the PQR 0 467 325 0 1,438 2,702 3,415 1437.703265 5,659 9,032 14,450 62,170 70,376 77,376 82,959 85,743 85,722 84,033
Hb RECs above the PQR added to Bank 467 (142) 1,113 1,438 1,265 713 2,244 4,222 3,373 5,418 9,428 8,206 7,000 5,583 2,784 - - -
Hc Non-bankable RECs above the PQR - 9 30 39 2 32 81 115 - - - - - - - - - - - - - - -
H Ha+Hb Gross Balance of RECs above the PQR 467 325 1,438 1,438 2,702 3,415 5,659 5,659 9,032 14,450 62,170 70,376 77,376 82,959 85,743 85,743 85,722 84,033
Ia Planned Application of RECs above the PQR towards RPS Compliance - - - - - - - - - - - - - - - - - - - - 20 1,690 3,142
Ib Planned Sales of RECs above the PQR - - - - - - - - - - - - - - - - - - - - - - -
J H-Ia-Ib Net Balance of RECs above the PQR 467 325 1,438 1,438 2,702 3,415 5,659 5,659 9,032 14,450 62,170 70,376 77,376 82,959 85,743 85,722 84,033 80,891
J0 Category 0 RECs 1,040 - - 1,040 - - - - - - - - - - - - - - - - - - -
J1 Category 1 RECs 52 110 235 398 1,237 2,984 - 4,222 9,885 13,726 9,428 8,206 7,000 5,583 2,784 - - -
J2 Category 2 RECs - - - - - - - - - - - - - - - - - - - - - - -
Expiring Contracts
K RECs from Expiring RPS Contracts - 369 1,347 1,715 1,790 2,202 2,593 2,695 2,698 2,927 4,374 5,700 5,826 5,823
Net RPS Position (Optimized Net Short)
La Ga+Ia-Ib-Hc Annual Net RPS Position after Bank Optimization (GWh) 467 (142) 1,113 1,438 1,265 713 2,244 4,222 3,373 5,418 9,428 8,206 7,000 5,583 2,784 - - -
Lb (F+Ia-Ib-Hc)/A Annual Net RPS Position after Bank Optimization (%) 20.6% 19.8% 21.5% 20.6% 23.4% 24.2% 28.0% 25.2% 31.6% 36.5% 62.8% 63.0% 63.0% 62.4% 58.5% 54.7% 57.3% 60.0%
Note: Values are to be input in GWhs
Appendix C.2 ‐ Page 1
PUBLIC APPENDIX D
Cost Quantification Table
1 Executed RPS-Eligible Contracts (Purchases and Sales) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 20182 Biogas $49,239,752 $55,218,581 $58,024,700 $55,842,748 $46,391,310 $45,669,901 $41,319,957 $46,567,994 $45,211,236 $35,156,543 $33,114,888 $33,398,837 $26,215,229 $19,996,620 $4,429,955 $4,269,2583 Biomass $30,229,214 $30,641,340 $29,266,687 $29,364,748 $31,995,803 $32,870,627 $37,676,121 $39,934,586 $32,641,659 $8,227,073 $0 $0 $0 $0 $27,282,062 $51,885,1454 Geothermal $533,787,287 $568,528,010 $569,145,247 $540,276,590 $564,191,771 $682,923,953 $591,094,390 $601,071,879 $559,744,574 $415,442,081 $433,420,493 $488,851,482 $406,326,046 $321,170,291 $347,988,678 $458,981,2115 Small Hydro $14,680,635 $13,351,784 $23,129,437 $22,350,522 $11,682,561 $17,217,269 $12,197,656 $19,239,880 $26,068,150 $18,236,862 $10,001,362 $2,468,152 $1,579,449 $5,225,793 $13,379,608 $6,179,3646 Solar PV $2,303 $1,077 $574 $111 $0 $0 $116,015 $6,014,872 $6,263,215 $10,236,565 $29,306,577 $201,163,017 $406,497,564 $628,952,523 $874,001,688 $900,982,8177 Solar Thermal $109,767,959 $109,176,941 $102,333,401 $100,464,297 $108,126,446 $118,442,549 $118,633,943 $122,739,976 $124,889,386 $101,611,519 $92,137,545 $111,917,597 $114,443,298 $107,560,298 $103,861,457 $112,331,9078 Wind $150,501,168 $168,906,414 $164,098,293 $158,644,762 $185,560,185 $211,157,917 $197,306,648 $298,846,815 $447,581,905 $553,158,034 $732,798,017 $733,090,366 $597,232,883 $759,447,708 $704,543,010 $872,844,0339 UOG Small Hydro $18,919,069 $20,783,330 $22,004,724 $25,476,773 $28,921,419 $29,624,912 $32,852,293 $35,084,449 $46,523,880 $54,403,396 $53,529,737 $54,486,018 $24,938,059 $22,100,742 $44,387,006 $32,287,80310 UOG Solar $0 $0 $0 $0 $0 $237,324 $1,518,688 $2,587,858 $15,703,577 $34,084,657 $24,802,431 $35,339,130 $42,453,790 $38,555,151 $35,591,827 $31,789,72411 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total RPS-Eligible Procurement and Generation Net Cost
[Sum of Rows 2 through 11]
13Bundled Retail Sales
(kWh)70,616,552,902 72,964,152,898 74,994,454,104 78,863,139,433 79,505,151,004 80,956,160,306 78,048,183,506 75,141,421,957 73,777,490,034 75,596,657,918 74,480,094,902 75,828,582,966 75,322,345,868 73,621,347,624 73,482,939,540 71,905,158,856
14 Incremental Rate Impact [Row 12 divided by Row 13] 1.284581802 1.32 ¢/kWh 1.29 ¢/kWh 1.18 ¢/kWh 1.23 ¢/kWh 1.41 ¢/kWh 1.32 ¢/kWh 1.56 ¢/kWh 1.77 ¢/kWh 1.63 ¢/kWh 1.89 ¢/kWh 2.19 ¢/kWh 2.15 ¢/kWh 2.58 ¢/kWh 2.933286697 3.44 ¢/kWh
1Executed But Not CPUC-Approved RPS-Eligible Contracts (Purchases and Sales)* 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
2 Biogas $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
3 Biomass $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
4 Geothermal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
5 Small Hydro $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
6 Solar PV $15,183 $413,120 $477,330 $474,352 $471,424 $466,778 $461,981 $458,404 $450,367 $439,244 $428,003 $416,907
7 Solar Thermal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
8 Wind $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
9 UOG Small Hydro $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
10 UOG Solar $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
11 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
12 Sales Revenue $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Executed But Not CPUC-Approved RPS-Eligible Procurement and Generation Cost
[Sum of Rows 2 through 11]
14Bundled Retail Sales
(kWh)41,722,583,955 41,062,569,622 40,530,688,077 39,986,848,985 39,485,433,851 39,100,539,760 38,792,103,836 38,380,229,439
15 Incremental Rate Impact [Row 13 divided by Row 14] 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh 0.00 ¢/kWh
16 Executed RPS-Eligible Contracts (Purchases and Sales)** 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
17 Biogas $7,910,636 $13,427,105 $13,603,015 $13,598,585 $13,588,926 $13,693,532 $13,880,244 $13,281,444 $9,849,774 $8,742,524 $8,675,957 $8,634,477
18 Biomass $48,990,534 $49,686,326 $50,080,154 $61,350,030 $41,582,984 $42,483,543 $43,387,968 $44,529,625 $45,390,342 $46,364,546 $47,138,770 $48,147,077
19 Geothermal $375,424,577 $321,068,439 $273,216,991 $246,782,013 $246,679,311 $247,831,542 $252,900,538 $246,173,632 $139,255,139 $49,684,059 $46,481,795 $46,482,741
20 Small Hydro $11,508,715 $7,097,645 $3,620,093 $3,538,667 $3,400,638 $3,413,190 $3,264,522 $3,275,986 $3,282,320 $3,246,445 $3,171,132 $3,181,835
21 Solar PV $965,155,089 $1,139,126,211 $1,183,024,300 $1,188,754,776 $1,192,916,246 $1,191,775,956 $1,196,365,116 $1,206,072,506 $1,197,351,581 $1,179,806,832 $1,163,683,129 $1,144,842,945
22 Solar Thermal $111,673,923 $92,629,627 $67,943,310 $66,309,844 $66,110,413 $65,646,419 $65,506,533 $65,633,296 $58,369,489 $51,940,319 $50,718,338 $49,693,082
23 Wind $898,934,431 $898,686,575 $884,773,290 $866,525,312 $866,178,573 $867,206,187 $864,824,181 $862,775,692 $862,070,287 $858,908,426 $844,165,833 $838,983,829
24 UOG Small Hydro $21,723,793 $22,281,471 $22,867,033 $23,481,873 $24,127,455 $24,805,317 $25,517,071 $26,264,413 $27,049,122 $27,873,066 $28,738,208 $29,646,607
25 UOG Solar $44,003,272 $11,268,720 $14,268,960 $15,768,000 $15,768,000 $15,811,200 $15,768,000 $15,768,000 $15,768,000 $15,811,200 $15,768,000 $15,768,000
26 Unbundled RECs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
27 Sales Revenue -$5,124,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total RPS-Eligible Procurement and Generation Cost
[Sum of Rows 17 through 27]
29Bundled Retail Sales
(kWh)41,722,583,955 41,062,569,622 40,530,688,077 39,986,848,985 39,485,433,851 39,100,539,760 38,792,103,836 38,380,229,439
30 Incremental Rate Impact [Row 28 divided by Row 29] 5.92 ¢/kWh 6.02 ¢/kWh 6.12 ¢/kWh 6.21 ¢/kWh 5.97 ¢/kWh 5.73 ¢/kWh 5.69 ¢/kWh 5.69 ¢/kWhTotal Incremental Rate Impact
[Row 15 + 30]5.69 ¢/kWh 5.70 ¢/kWh
Actual RPS-Eligible Procurement and Generation Net Costs ($)
$2,471,551,261
Forecast RPS-Eligible Procurement Costs and Revenues ($)
5.92 ¢/kWh 6.02 ¢/kWh 6.12 ¢/kWh 6.21 ¢/kWh 5.97 ¢/kWh 5.74 ¢/kWh
$2,481,414,172 $2,483,774,594 $2,358,386,054 $2,242,377,417 $2,208,541,163
31
$2,185,380,593
$428,003 $416,907
28 $2,480,200,970 $2,555,272,119 $2,513,397,145 $2,486,109,101 $2,470,352,547 $2,472,666,886
$471,424 $466,778 $461,981 $458,404 $450,367 $439,24413 $15,183 $413,120 $477,330 $474,352
$1,409,111,050 $1,660,714,599 $1,619,686,318 $1,903,009,126 $2,155,465,290
Table 2: Cost Quantification (Forecast Costs and Revenues, $)
$976,869,495 $1,138,144,451 $1,032,715,711 $1,172,088,308 $1,304,627,583 $1,230,556,730
Table 1: Cost Quantification (Actual Net Costs, $)
12 $907,127,388 $966,607,475 $968,003,063 $932,420,551
Appendix D - Page 1
1 Technology Type (Procurement / Generation and Sales) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 20182 Biogas 722,946,872 777,312,732 771,018,454 752,792,686 587,082,098 546,962,524 493,557,888 513,205,916 505,975,841 499,348,085 484,856,973 449,602,910 410,920,238 317,624,690 53,254,357 54,483,7103 Biomass 365,097,000 373,917,000 351,063,000 353,889,000 365,332,000 363,224,000 417,625,000 437,916,000 351,018,000 114,694,000 0 0 0 0 242,794,358 504,995,2864 Geothermal 7,079,544,959 7,882,153,152 7,823,442,082 7,481,228,810 7,611,424,731 7,739,370,197 7,675,040,864 7,633,511,171 7,178,640,942 6,421,878,833 6,536,991,410 6,745,455,452 6,687,895,884 5,406,191,071 5,621,420,322 5,983,460,6075 Small Hydro 236,744,651 246,952,691 325,458,412 348,497,816 196,112,961 182,554,690 138,319,853 220,027,751 301,898,312 193,824,909 111,406,134 28,189,908 17,624,603 65,933,508 195,578,526 73,794,4076 Solar PV 0 0 0 0 0 0 1,372,324 51,389,213 53,432,781 73,822,986 247,185,884 1,839,819,140 3,825,645,626 6,241,358,790 8,379,275,491 8,595,066,4327 Solar Thermal 756,941,166 739,291,464 622,099,854 613,049,994 666,864,846 730,264,176 839,801,580 879,081,877 889,065,595 868,991,935 680,234,418 751,904,813 833,904,840 773,651,852 761,837,240 796,132,1358 Wind 2,366,582,609 2,313,238,518 2,275,713,067 2,232,844,707 2,374,032,238 2,383,541,034 3,038,798,465 4,142,352,867 5,417,625,933 6,286,303,872 7,510,596,685 7,442,425,300 6,062,734,884 7,391,812,341 7,057,058,744 9,624,521,5049 UOG Small Hydro 535,123,742 466,007,745 545,840,580 599,902,056 362,302,038 344,846,249 426,458,028 461,590,000 618,139,310 434,380,326 269,814,338 274,950,708 234,845,891 394,208,307 546,129,426 381,725,01510 UOG Solar 0 0 0 0 0 438,489 2,798,912 4,846,187 54,532,151 98,598,314 68,910,176 98,184,960 117,952,073 107,120,236 98,887,043 88,304,78911 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 66,530,196 37,775,113
Total RPS-Eligible Procurement / Generation and Sales[Sum of Rows 2 through 11]
2 Biogas 0 0 0 0 0 0 0 0 0 0 0 03 Biomass 0 0 0 0 0 0 0 0 0 0 0 0
4 Geothermal 0 0 0 0 0 0 0 0 0 0 0 0
5 Small Hydro 0 0 0 0 0 0 0 0 0 0 0 0
6 Solar PV 607,287 14,636,551 16,682,877 16,579,536 16,478,038 16,316,400 16,144,881 16,013,274 15,730,120 15,339,729 14,942,055 14,552,135
7 Solar Thermal 0 0 0 0 0 0 0 0 0 0 0 0
8 Wind 0 0 0 0 0 0 0 0 0 0 0 0
9 UOG Small Hydro 0 0 0 0 0 0 0 0 0 0 0 0
10 UOG Solar 0 0 0 0 0 0 0 0 0 0 0 0
11 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0
12 RPS-Eligible Sales 0 0 0 0 0 0 0 0 0 0 0 0
Total Executed But Not CPUC-Approved RPS-EligibleDeliveries
[Sum of Rows 2 through 11]
15 Biogas 89,680,817 131,292,035 131,713,679 131,217,679 130,715,799 130,703,702 131,332,825 123,069,153 84,592,943 73,342,644 72,793,916 72,450,832
16 Biomass 491,917,800 493,362,907 491,917,800 535,158,471 354,045,667 355,090,286 354,045,667 354,045,667 354,045,667 355,090,286 354,045,667 354,045,667
17 Geothermal 3,938,147,602 3,387,190,494 3,357,911,181 3,357,911,181 3,297,691,794 3,222,253,240 3,213,636,181 3,034,321,280 1,738,799,972 523,929,830 485,399,972 485,399,972
18 Small Hydro 139,305,131 89,152,316 42,256,876 41,100,916 39,483,659 39,456,372 36,977,744 36,858,949 36,858,949 36,313,872 35,291,170 35,291,170
19 Solar PV 10,037,896,834 13,227,703,269 14,242,792,250 14,145,500,381 14,048,828,449 13,896,950,482 13,742,027,740 13,618,719,340 13,361,299,440 13,007,155,568 12,656,115,668 12,290,055,710
20 Solar Thermal 835,506,545 732,657,180 549,783,193 522,877,095 522,227,846 519,395,757 516,644,063 514,875,119 411,258,831 321,204,700 311,705,571 305,019,798
21 Wind 9,871,367,715 9,895,388,393 9,680,154,611 9,487,199,104 9,445,847,003 9,444,209,505 9,395,244,013 9,342,979,706 9,318,724,776 9,266,546,715 9,084,743,316 9,010,431,872
22 UOG Small Hydro 371,717,523 339,122,385 341,115,264 340,282,565 340,430,076 337,617,053 340,127,106 338,624,362 338,774,564 339,922,723 339,885,697 339,152,603
23 UOG Solar 122,231,311 31,302,000 39,636,000 43,800,000 43,800,000 43,920,000 43,800,000 43,800,000 43,800,000 43,920,000 43,800,000 43,800,000
24 Unbundled RECs 0 0 0 0 0 0 0 0 0 0 0 0
25 RPS-Eligible Sales -300,000,000 0 0 0 0 0 0 0 0 0 0 0
Total RPS-Eligible Deliveries[Sum of Rows 27 through 36]
SCE Note: Forecast assumes 100% successful development.
23,383,780,977 22,935,647,624
26,140,258,998
Actual RPS-Eligible Procurement / Generation and Sales (kWh)
Forecast RPS-Eligible Procurement / Generation and Sales (kWh)
28,223,070,292 27,989,596,397 27,773,835,340 27,407,293,576 25,688,155,142 23,967,426,337
2025 2026 2027 2028 2029
26 25,597,771,279 28,327,170,980 28,877,280,854 28,605,047,392
2030
14,552,135
14 Executed RPS-Eligible Contracts (Purchases and Sales) ** 2019 2020 2021 2022 2023 2024
16,316,400 16,144,881 16,013,274 15,730,120 15,339,729 14,942,055
2030
13 607,287 14,636,551 16,682,877 16,579,536 16,478,038
2022 2023 2024 2025 2026 20271Executed But Not CPUC-Approved RPS-Eligible Contracts (Purchases and Sales) * 2019 2020 2021
15,909,996,018
2028 2029
17,630,533,191 18,191,524,039 20,697,900,796 23,022,765,703
Table 4: Cost Quantification (Forecast Procurement / Generation and Sales, kWh)
12,163,150,912 12,291,201,359 13,033,772,914 14,343,920,982 15,370,328,865 14,991,843,26012,382,205,069
Table 3: Cost Quantification (Actual Procurement / Generation and Sales, kWh)
12 12,062,980,999 12,798,873,302 12,714,635,449
Appendix D - Page 2
CONFIDENTIAL APPENDIX
Renewable Energy Sales
CONFIDENTIAL APPENDIX .1
Redline of Renewable Energy Sales