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Gary A. Stern, Ph.D.
Managing Director, State Regulatory Operations

March 12, 2019
ADVICE 3965-E-A
(U 338-E)
PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
ENERGY DIVISION
SUBJECT:

Supplement to Advice 3965-E, Southern California Edison
Company’s Updates to its 2019 Distribution Investment Deferral
Framework Request for Offer Projects and Request to Remove
Nogales and Newhall Projects from the 2019 Solicitation

PURPOSE
Southern California Edison Company (SCE) hereby submits for approval updates to the
four Distribution Investment Deferral Framework projects initially identified in SCE Advice
3904-E and Supplemental Advice 3904-E-A for deferral by means of competitive
solicitation of distributed energy resources. A disposition letter was issued on February
5, 2019 approving SCE Advice 3904-E and Supplemental Advice 3904-E-A. SCE is
seeking Commission approval to withdraw the Nogales and Newhall projects from the
2019 Distribution Investment Deferral Framework (DIDF) Request for Offer (RFO)
because the 2019 planning cycle analysis demonstrates that there is no longer a need
for either project. SCE intends to convene a Distribution Planning Advisory Group
(DPAG) meeting to review this analysis with stakeholders.
This supplemental advice letter is made in accordance with General Order (GO) 96-B,
General Rule 7.5.1, which authorizes utilities to make additional changes to an advice
letter through the submittal of a supplemental advice letter. This advice letter
supplements and replaces Advice 3965-E in its entirety.

P.O. Box 800

8631 Rush Street Rosemead, California 91770

(626) 302-9645

Fax (626) 302-6396





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ADVICE 3965-E-A (U 338-E) -2- March 12, 2019 BACKGROUND SCE’s 2018 Grid Needs Assessment (GNA)1 and Distribution Deferral Opportunity Report (DDOR)2 summarized the grid needs and associated projects resulting from the 2018 planning cycle (2018-2027). The 2018 DDOR also presented a candidate deferral project shortlist that was developed by applying initial deferral screens. SCE then applied prioritization metrics in conjunction with qualitative analysis of the candidate deferral projects to identify projects for the DIDF RFO. Three DPAG meetings were convened (on September 17, October 11, and October 30, 2018) to allow stakeholders an opportunity to understand each project and discuss its likelihood of being successfully deferred with DER. Following those three meetings, SCE proposed—via Advice 3904-E—to proceed to the DIDF RFO with four projects: (1) the Nogales Project, (2) the Sun City Project, (3) the Mira Loma Project, and (4) the Newhall Project. On February 5, 2019, the California Public Utilities Commission (Commission or CPUC) approved SCE’s proposal. GRID NEEDS CHANGED DUE TO UPDATED 2019 PLANNING CYCLE ANALYSIS SCE’s annual planning cycle typically commences during late Q3 to early Q4, and completes in Q2 of the following year. To support the new DIDF process, SCE accelerated its planning cycle to proactively validate the grid needs driving the Nogales, Sun City, Mira Loma, and Newhall projects based on the 2019 planning cycle. This was intended to provide the projects with updated grid needs information earlier in the DIDF process. SCE has completed the analysis required to provide the four projects’ needs with updated information based upon the 2019 planning cycle, and the analysis no longer indicates a need for the Nogales and Newhall projects. It also resulted in multiple changes to the locations and needs of the Mira Loma and Sun City projects. These changes are summarized in the following sections. Thus, SCE is seeking Commission approval to withdraw the Nogales and Newhall projects from the 2019 DIDF RFO because the 2019 planning cycle analysis demonstrates that there is no longer a need for either project. SCE intends to proceed with deferral of the Mira Loma and Sun City projects. SCE will convene a DPAG meeting to review the updated analysis. It is important to acknowledge the dynamic nature of the distribution system and associated planning process. As circumstances such as weather, economics, and individual developer decisions change, SCE must have the flexibility to incorporate such changes into its planning assumptions to reflect the most up-to-date information on 1 2 SCE 2018 GNA was originally filed on June 1, 2018 and amended on July 25, 2018. SCE’s 2018 DDOR was filed on September 4, 2018.
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ADVICE 3965-E-A (U 338-E) -3- March 12, 2019 anticipated distribution grid needs. This will have an impact on the DIDF. SCE is committed to the success of the DIDF and will be recommending improvements to the DIDF to better align it with SCE’s planning processes and to propose process refinements to address similar situations (e.g., updating needs) in the future.3 SUMMARY OF PROJECT CHANGES The following four tables provide a side-by-side comparison of the Nogales, Sun City, Mira Loma, and Newhall projects based on initial analysis from the 2018 planning cycle and updated analysis from the 2019 planning cycle. Table 1: Nogales Project Comparison of 2018 and 2019 Planning Cycles 2019 Planning Cycle Nogales Project 2018 Planning Cycle Grid Needs Capacity: • Wahoo 12 kV circuit out of Nogales 66/12 kV Substation Underground Cable Temperature: • Caboose, Diner, and Trestle 12 kV circuits out of Railroad 66/12 kV Substation Nature of Grid Needs • • Scope Construct (1) new 12 kV circuit out of Nogales 66/12 kV Substation Need Year Forecasted demand expected to exceed capacity limitations. Forecasted demand expected to exceed underground cable temperature limitations. None N/A N/A 2021 N/A $3.85 M N/A Capacity Requirements (MW) 1.83 0.00 Energy Requirements (MWh) 5.61 0.00 Unit Cost of Traditional Mitigation 3 SCE intends to submit these recommendations on March 19, 2019 in response to the February 25, 2019 Administrative Law Judge’s Ruling Requesting Answers To Questions To Improve The Distribution Investment Deferral Framework Process.
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ADVICE 3965-E-A (U 338-E) -4- March 12, 2019 Table 2: Newhall Project Comparison of 2018 and 2019 Planning Cycles 2019 Planning Cycle Newhall Project 2018 Planning Cycle Grid Needs Voltage Support: • North Oaks 66/16 kV Substation None Nature of Grid Needs Forecasted voltage deviation greater than 5% at North Oaks 66/16 kV Substation under first contingency (loss of a single 66 kV line within Saugus ‘C’ System). N/A Scope Install (2) 14.4 MVAR substation capacitor banks at Newhall 66/16 kV Substation N/A Need Year 2021 N/A $1.51 M N/A Capacity Requirements (MW) 4.00 0.00 Energy Requirements (MWh) 7.35 0.00 Unit Cost of Traditional Mitigation Table 3: Mira Loma Project Comparison of 2018 and 2019 Planning Cycles Mira Loma Project Grid Needs 2018 Planning Cycle 2019 Planning Cycle Capacity: • Brewer 12 kV circuit out of Mira Loma 66/12 kV Substation Underground Cable Temperature: • Brewer 12 kV circuit out of Mira Loma 66/12 kV Substation Capacity: • Brewer 12 kV circuit out of Mira Loma 66/12 kV Substation Underground Cable Temperature: • Brewer 12 kV circuit out of Mira Loma 66/12 kV Substation • Matterhorn 12 kV circuit out of Mira Loma 66/12 kV Substation • Forecasted demand expected to exceed capacity limitations. Forecasted demand expected to exceed underground cable temperature limitations. Nature of Grid Needs • Scope Construct (1) new 12 kV circuit out of Mira Loma 66/12 kV Substation Need Year 2021 No Change No Change No Change
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ADVICE 3965-E-A (U 338-E) Unit Cost of Traditional Mitigation -5- March 12, 2019 $3.78 M $2.00 M Capacity Requirements (MW) 5.20 4.26 Energy Requirements (MWh) 61.38 36.24 Table 4: Sun City Project Comparison of 2018 and 2019 Planning Cycles Sun City Project 2018 Planning Cycle 2019 Planning Cycle Capacity: • Sun City 115/12 kV Substation • Equinox, Photon, and Sundance 12 kV circuits out of Sun City 115/12 kV Substation Capacity: • Sun City 115/12 kV Substation • Newcomb 115/12 kV Substation • Equinox 12 kV circuit out of Sun City 115/12 kV Substation • Bradley 12 kV circuit out of Newcomb 115/12 kV Substation Underground Cable Temperature: • Equinox 12 kV circuit out of Sun City 115/12 kV Substation • Bradley and Lusk 12 kV circuits out of Newcomb 115/12 kV Substation Forecasted demand expected to exceed underground cable temperature limitations. • Grid Needs Nature of Grid Needs Scope Need Year Increase Sun City 115/12 kV substation transformer capacity, construct (1) new 12 kV circuit out of Sun City 115/12 kV Substation • Forecasted demand expected to exceed capacity limitations. Forecasted demand expected to exceed underground cable temperature limitations. No Change 2022 No Change $5.41 M $7.41 M Capacity Requirements (MW) 12.87 23.71 Energy Requirements (MWh) 25.10 136.11 Unit Cost of Traditional Mitigation
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ADVICE 3965-E-A (U 338-E) -6- March 12, 2019 SUMMARY OF CHANGES TO OVERALL PROCUREMENT TARGETS As a result of the individual project changes noted above, the tables below summarize the updated capacity and energy procurement targets. Table 5: Overall Comparison of Capacity Requirements (MW) 2018 Planning Cycle (Advice 3904-E) Mira Loma 5.20 4.26 -0.94 Sun City 12.87 23.71 +10.84 Nogales 1.83 0.0 -1.83 Newhall 4.00 0.0 -4.00 Total Capacity Requirements (MW) 2019 Planning Cycle 23.90 27.97 +4.07 MW Delta Table 6: Overall Comparison of Energy Requirements (MWh) 2018 Planning Cycle (Advice 3904-E) Mira Loma 61.38 36.24 -25.14 Sun City Energy Requirements (MWh) 2019 Planning Cycle 25.10 136.11 +111.01 Nogales 5.61 0.0 -5.61 Newhall 6.89 0.0 -6.89 Total 98.98 172.35 +73.37 MWh Delta
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ADVICE 3965-E-A (U 338-E) -7- March 12, 2019 NOTABLE CHANGES BETWEEN 2018 AND 2019 PLANNING CYCLES THAT RELATE TO THE NEED CHANGES The following factors in the 2019 planning cycle resulted in reduced forecasted load in the Nogales and Newhall project areas when compared to the 2018 planning cycle. 1. Higher DER Growth Forecast from 2017 IEPR Consistent with the August 9, 2017 Assigned Commissioner’s Ruling on the Adoption of Distributed Energy Resources Growth Scenarios, SCE used the 2016 IEPR Update, adopted February 2017, as the basis of its 2018 planning cycle. Consistent with Ordering Paragraph No. 1.a. of Decision (D.)18-02-004, SCE used the 2017 IEPR, adopted in February 2018, as the basis of its 2019 planning cycle. A comparison of these two forecasts demonstrates overall higher DER growth projections in the 2017 IEPR, particularly with regard to the solar photovoltaic projections, when compared to the 2016 IEPR update. A comparison of the load and DER projections for the Nogales and Newhall projects can be found in Appendix A. 2. Lower Starting Points The initial stage of SCE’s annual planning process includes selection of a “starting point” for each circuit and substation in SCE’s system. The starting point reflects the weathernormalized peak demand, based on the observed peak demand, which for the majority of SCE’s system occurs during summer months. The starting point also includes adjustments to account for DER. Next, the IEPR load and DER projections are disaggregated down to the circuit level, and added on top of the starting point to produce the “normal projected load.” The normal projected load is then adjusted to represent projected load under a 1-in-10 year heat storm. SCE’s distribution circuits and substations are planned based on the 1-in-10 projected load. SCE’s sub-transmission system is analyzed under base case and first contingency scenarios. For the base case scenario, all sub-transmission lines are assumed to be in service, and the 1-in-5 year projected load is used. For the first contingency scenario, multiple iterations of analysis are performed, each with a different sub-transmission line removed from service. When performing first contingency analysis of its sub-transmission system (also referred to as likely contingency or N-1), SCE uses the normal projected load. SCE leverages the normal projected load instead of the 1-in-5 projected load for first contingency analysis as it may be overly conservative to assume the system loses a line from service concurrent with 1-in-5 peak load conditions. SCE employs both forecast methodologies (1-in-5 and 1-in-10) across its electrical systems, however, the use of each methodology is specific to the level of the electrical
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ADVICE 3965-E-A (U 338-E) -8- March 12, 2019 system that is being planned. For instance, the planning activities associated with distribution substations, which are located in discrete local areas of SCE’s service territory, employ a 1-in-10 year forecast. The 1-in-10 year forecast is a more conservative method of forecasting. It is used to ensure adequate capacity for electrical facilities that are situated in discrete areas of limited geographical coverage, which means that there is a limited ability to transfer load to adjacent electrical facilities because adjacent facilities may be experiencing weather conditions that similarly impact all nearby electrical facilities. As planning activities elevate upwards in the electrical system, geographical service areas expand. In these instances, the likelihood that all facilities within the larger service area will be impacted by the same weather conditions is reduced, thus potentially providing for an increased ability for adjacent facilities to provide loading relief as needed. Because the size of the geographical service areas increases as one moves from the distribution substations to the sub-transmission substations and associated subtransmission lines, diversity of load profiles increases as well as the diversity of weather conditions. Additionally, it is unlikely that all substations would experience peak demand at the same time and date of the year. This allows SCE to reduce the level of conservatism applied, while still maintaining adequate capacity to meet customer demand. Thus, SCE employs a 1-in-5 heat storm forecast when performing “base case” analysis of its sub-transmission substations and the associated subtransmission lines within those systems. Base case refers to all lines in-service. This approach helps to ensure that adequate capacity is provided while also minimizing the possibility of constructing unnecessary electrical facilities. For the circuits involved in the Nogales project and substations involved in Newhall project, SCE observed decreases in starting points in the summer of 2018 when compared to starting points recorded during summer of 2017. A comparison of the starting points for the Nogales and Newhall projects can be found in Appendix A. REQUEST FOR COMMISSION APPROVAL Based on the information provided within this Advice Letter, SCE requests that the Commission approve the updates to the four DIDF RFO projects, including removal of the Nogales and Newhall projects. TIER DESIGNATION This advice filing is submitted with a Tier 1 designation.
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ADVICE 3965-E-A (U 338-E) -9- March 12, 2019 EFFECTIVE DATE SCE request this advice letter be made effective the same day as submitted, March 12, 2019. PROTESTS Anyone wishing to protest this advice filing may do so by letter via U.S. Mail, facsimile, or electronically, any of which must be received no later than 20 days after the date of this advice filing. Protests should be submitted to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, California 94102 E-mail: EDTariffUnit@cpuc.ca.gov Copies should also be mailed to the attention of the Director, Energy Division, Room 4004 (same address above). In addition, protests and all other correspondence regarding this Advice Letter should also be sent by letter and transmitted via facsimile or electronically to the attention of: Gary A. Stern, Ph.D. Managing Director, State Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California 91770 Facsimile: (626) 302-6396 E-mail: AdviceTariffManager@sce.com Laura Genao Managing Director, State Regulatory Affairs c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California 94102 Facsimile: (415) 929-5544 E-mail: Karyn.Gansecki@sce.com There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and must be received by the deadline shown above.
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ADVICE 3965-E-A (U 338-E) - 10 - March 12, 2019 NOTICE In accordance with General Rule 4 of GO 96-B, SCE is serving copies of this advice filing to the interested parties shown on the attached GO 96-B, R.14-10-003 and R.14-08-013 et al. service lists. Address change requests to the GO 96-B service list should be directed by electronic mail to AdviceTariffManager@sce.com or at (626) 3024039. For changes to all other service lists, please contact the Commission’s Process Office at (415) 703-2021 or by electronic mail at Process_Office@cpuc.ca.gov. Further, in accordance with Public Utilities Code Section 491, notice to the public is hereby given by filing and keeping the advice filing at SCE’s corporate headquarters. To view other SCE advice letters filed with the Commission, log on to SCE’s web site at https://www.sce.com/wps/portal/home/regulatory/advice-letters. For questions, please contact Ally Guilliatt at (626) 302-4885 or by electronic mail at allison.guilliatt@sce.com. Southern California Edison Company /s/ Gary A. Stern, Ph.D. Gary A. Stern, Ph.D. GAS:ag:jm
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APPENDIX A The following section provides a comparison of the starting point, load growth, DER growth, and final forecast from the 2018 and 2019 2019 planning cycles. NOGALES PROJECT Nogales Project Starting Point Comparison Table 1: Nogales Project Starting Point Comparison (Amps) Circuit Wahoo 12 kV Caboose 12 kV Diner 12 kV Trestle 12 kV 2018 Planning Cycle (data from 2017 summer) 501 426 458 438 2019 Planning Cycle (data from 2018 summer) % Change 435 -13% 379 -11% 431 -6% 421 -4% Nogales Project Forecasted Load and DER Growth Comparison 2019 2018 Table 2: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – Wahoo 12 kV (Amps) Wahoo 12 kV Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 10.2 -1.1 -0.9 -1.6 -0.4 -0.7 -0.6 -1.1 -1.1 -0.9 11.6 0.2 0.4 0.4 0.9 0.7 0.6 0.8 0.7 0.8 -1.4 -1.3 -1.2 -2.0 -1.3 -1.4 -1.3 -1.9 -1.8 -1.6 ___ -1.2 -1.0 -2.8 -3.9 5.7 -3.9 -3.8 -2.6 -2.6 ___ 2.5 3.9 0.0 0.0 10.0 0.0 0.0 0.0 0.0 ___ -3.7 -4.8 -2.8 -3.9 -4.3 -3.9 -3.8 -2.6 -2.6 2028 ___ ___ ___ -3.8 0.0 -3.8 2019 2018 Table 3: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – Caboose 12 kV (Amps) Caboose 12 kV Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 0.1 0.0 0.6 0.1 2.5 1.9 1.9 2.3 1.9 2.2 1.0 0.7 1.3 1.5 3.3 2.7 2.4 3.1 2.7 2.9 -0.9 -0.8 -0.7 -1.5 -0.8 -0.8 -0.5 -0.7 -0.8 -0.7 ___ -2.3 -1.4 -2.7 -3.3 -3.7 -1.5 -2.4 -2.5 -2.5 ___ 0.0 0.4 0.0 0.0 0.0 1.0 0.0 0.0 0.0 ___ -2.3 -1.8 -2.7 -3.3 -3.7 -2.5 -2.4 -2.5 -2.5 2028 ___ ___ ___ -3.3 0.0 -3.3
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2019 2018 Table 4: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – Diner 12 kV (Amps) Diner 12 kV Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 -0.3 -0.7 -0.1 -0.7 1.3 0.6 0.9 1.2 0.7 1.0 1.0 0.7 1.3 1.3 2.7 2.2 2.4 3.1 2.7 2.9 -1.3 -1.5 -1.4 -2.0 -1.4 -1.7 -1.5 -1.8 -2.0 -1.9 ___ -5.2 -1.7 -2.0 -2.8 -3.9 -3.0 -4.2 -3.1 -2.9 ___ 0.0 0.0 0.5 0.7 0.7 0.0 0.0 0.0 0.0 ___ -5.2 -1.7 -2.5 -3.5 -4.6 -3.0 -4.2 -3.1 -2.9 2028 ___ ___ ___ -4.6 0.0 -4.6 2019 2018 Table 5: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – Trestle 12 kV (Amps) Trestle 12kV Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 -0.1 0.0 1.4 0.7 3.2 2.4 1.6 2.0 1.4 1.7 1.0 0.7 1.9 1.9 4.0 3.3 2.4 3.1 2.7 2.9 -1.1 -0.7 -0.6 -1.2 -0.8 -0.9 -0.8 -1.1 -1.3 -1.2 ___ -2.3 -1.0 -2.7 -2.1 -2.7 -1.3 -2.0 -2.1 -1.9 ___ 0.0 0.4 0.0 0.0 0.0 1.0 0.0 0.0 0.0 ___ -2.3 -1.4 -2.7 -2.1 -2.7 -2.3 -2.0 -2.1 -1.9 2028 ___ ___ ___ -1.9 0.0 -1.9 Nogales Project 1-in-10 Projected Load Comparison Table 6: Comparison of 1-in-10 Projected Load from 2018 and 2019 Planning Cycles – Wahoo 12 kV (Amps) Wahoo 12 kV 1-in-10 Projected Load (2018) 1-in-10 Projected Load (2019) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 560 559 558 556 556 555 555 553 552 551 ___ ___ 475 474 471 467 473 469 465 462 459 455 Table 7: Comparison of 1-in-10 Projected Load from 2018 and 2019 Planning Cycles – Caboose 12 kV (Amps) Caboose 12 kV 1-in-10 Projected Load (2018) 1-in-10 Projected Load (2019) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 464 464 465 465 468 470 472 475 477 479 ___ ___ 411 409 406 403 399 397 394 392 389 385 Table 8: Comparison of 1-in-10 Projected Load from 2018 and 2019 Planning Cycles – Diner 12 kV (Amps) Diner 12 kV 1-in-10 Projected Load (2018) 1-in-10 Projected Load (2019) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 499 498 498 497 499 499 500 502 502 503 ___ ___ 464 462 460 457 453 450 445 442 439 434
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Table 9: Comparison of 1-in-10 Projected Load from 2018 and 2019 Planning Cycles – Trestle 12 kV (Amps) Trestle 12kV 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 1-in-10 Projected Load (2018) 477 477 479 480 483 486 487 490 491 493 ___ 1-in-10 Projected Load (2019) ___ 456 455 452 450 447 475 473 471 469 467 NEWHALL PROJECT Newhall Project Starting Point Comparison Table 10: Newhall Project Starting Point Comparison (MVA) Substation North Oaks 66/16 kV Newhall 66/16 kV 2018 Planning Cycle (data from 2017 summer) 94.1 118 2019 Planning Cycle (data from 2018 summer) % Change 88.2 -6% 112.3 -5% Newhall Project Forecasted Load and DER Growth Comparison 2019 2018 Table 11: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – North Oaks Substation (MVA) North Oaks Sub Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 0.0 3.1 3.6 2.2 0.4 -0.2 -0.2 -0.2 -0.2 -0.1 0.28 3.39 3.81 2.58 0.57 0.03 0.03 0.04 0.04 0.03 -0.29 -0.25 -0.22 -0.35 -0.22 -0.22 -0.18 -0.20 -0.20 -0.16 ___ -0.2 0.7 2.5 2.3 2.6 1.8 1.3 0.9 0.7 ___ 0.42 1.56 3.07 2.88 3.31 2.33 1.82 1.33 1.23 ___ -0.62 -0.89 -0.60 -0.58 -0.66 -0.49 -0.51 -0.47 -0.52 2028 ___ ___ ___ 0.5 1.13 -0.61 2019 2018 Table 12: Comparison of Forecasted Growth from 2018 and 2019 Planning Cycles – Newhall Substation (MVA) Newhall Sub Total Growth Load Growth DER Growth Total Growth Load Growth DER Growth 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 0.1 3.8 4.5 4.5 3.0 1.6 0.3 -0.2 -0.3 -0.2 0.48 4.14 4.81 4.91 3.30 1.95 0.53 0.04 0.04 0.04 -0.38 -0.34 -0.33 -0.46 -0.31 -0.31 -0.26 -0.29 -0.29 -0.23 ___ -0.1 1.3 2.8 3.6 2.7 1.2 0.3 -0.1 -0.2 ___ 0.64 2.32 3.61 4.41 3.61 1.95 0.99 0.65 0.70 ___ -0.71 -1.04 -0.82 -0.76 -0.92 -0.79 -0.71 -0.74 -0.89 2028 ___ ___ ___ -0.2 0.70 -0.86
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Newhall Project Normal Projected Load Comparison The Newhall Project was identified during the 2018 planning cycle as a result of first contingency analysis of the Saugus C System (loss of a single 66 kV sub-transmission line from service). As such, a comparison of the Normal Projected Load from the 2018 and 2019 planning cycles is provided in the following tables. Table 13: Comparison of Normal Projected Load from 2018 and 2019 Planning Cycles – North Oaks Substation (MVA) North Oaks Substation 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Normal Projected Load (2018) 94.1 97.2 100.8 103.0 103.4 103.2 103.1 104.1 103.9 103.8 ___ Normal Projected Load (2019) ___ 88.0 88.7 91.1 93.4 96.1 97.9 100.5 101.4 102.1 102.6 Table 14: Comparison of Normal Projected Load from 2018 and 2019 Planning Cycles – Newhall Substation (MVA) Newhall Substation Normal Projected Load (2018) Normal Projected Load (2019) 2018 2019 2020 114.4 118.2 122.6 ___ 107.9 109.2 2021 2022 2023 2024 2025 2026 2027 2028 127.1 130.1 131.7 132.0 131.7 131.5 131.3 ___ 111.9 115.6 118.3 119.4 119.7 119.6 119.4 119.3 Newhall Project Maximum Voltage Deviation Comparison The following table includes the maximum voltage deviation at North Oaks 66/16 kV Substation under first contingency scenario, also referred to as N-1. First contingency refers to power flow analysis in which a single sub-transmission line is removed from service. SCE’s Subtransmission Reliability Criteria states that under a first contingency scenario, subtransmission systems shall be designed such that voltage deviation (drop) on the high side of the substation shall not exceed 5%. As such, SCE proposes mitigation when voltage deviation exceeds 5% under first contingency. Table 15: Comparison of Maximum Voltage Deviation at North Oaks Substation under First Contingency Scenario (N-1) from 2018 and 2019 Planning Cycles 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2018 Plan Year <4% <4% 4.9% 5.5% <4% <4% <4% 4.6% 4.5% <4% -- 2019 Plan Year -4.2% 4.2% 4.4% 4.6% <4% 4.5% 4.7% 4.8% 4.6% 4.6% Notable Changes in Saugus C System (2) projects to increase sub-transmission line conductor size Del Valle Substation to be operating in 2027
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ADVICE LETTER SUMMARY ENERGY UTILITY MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Company name/CPUC Utility No.: Southern California Edison Company (U 338-E) Utility type: ELC GAS PLC HEAT ELC = Electric PLC = Pipeline WATER Contact Person: Darrah Morgan Phone #: (626) 302-2086 E-mail: Darrah.Morgan@sce.com E-mail Disposition Notice to: AdviceTariffManager@sce.com EXPLANATION OF UTILITY TYPE GAS = Gas WATER = Water HEAT = Heat (Date Submitted / Received Stamp by CPUC) Tier Designation: 1 Advice Letter (AL) #: 3965-E-A Subject of AL: Supplement to Advice 3965-E, Southern California Edison Company’s Updates to its 2019 Distribution Investment Deferral Framework Request for Offer Projects and Request to Remove Nogales and Newhall Projects from the 2019 Solicitation Keywords (choose from CPUC listing): Compliance AL Type: Monthly Quarterly Annual One-Time Other: If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #: Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: Summarize differences between the AL and the prior withdrawn or rejected AL: Confidential treatment requested? Yes No If yes, specification of confidential information: Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information: Resolution required? Yes No Requested effective date: 3/12/19 No. of tariff sheets: -0- Estimated system annual revenue effect (%): Estimated system average rate effect (%): When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting). Tariff schedules affected: None Service affected and changes proposed1: Pending advice letters that revise the same tariff sheets: None 1 Discuss in AL if more space is needed. Clear Form
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Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, CA 94102 Email: EDTariffUnit@cpuc.ca.gov Name: Gary A. Stern, Ph.D. Title: Managing Director, State Regulatory Operations Utility Name: Southern California Edison Company Address: 8631 Rush Street City: Rosemead Zip: 91770 State: California Telephone (xxx) xxx-xxxx: (626) 302-9645 Facsimile (xxx) xxx-xxxx: (626) 302-6396 Email: advicetariffmanager@sce.com Name: Laura Genao c/o Karyn Gansecki Title: Managing Director, State Regulatory Affairs Utility Name: Southern California Edison Company Address: 601 Van Ness Avenue, Suite 2030 City: San Francisco State: California Zip: 94102 Telephone (xxx) xxx-xxxx: (415) 929-5515 Facsimile (xxx) xxx-xxxx: (415) 929-5544 Email: karyn.gansecki@sce.com Clear Form
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ENERGY Advice Letter Keywords Affiliate Direct Access Preliminary Statement Agreements Disconnect Service Procurement Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates Balancing Account Energy Charge Refunds Baseline Energy Efficiency Reliability Bilingual Establish Service Re-MAT/Bio-MAT Billings Expand Service Area Revenue Allocation Bioenergy Forms Rule 21 Brokerage Fees Franchise Fee / User Tax Rules CARE G.O. 131-D Section 851 CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map Cogeneration Increase Rates Service Outage Compliance Interruptible Service Solar Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges Contracts Line Extensions Tariffs Core Memorandum Account Taxes Credit Metered Energy Efficiency Text Changes Curtailable Service Metering Transformer Customer Charge Customer Owned Generation Mobile Home Parks Name Change Transition Cost Transmission Lines Decrease Rates Non-Core Transportation Electrification Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding Demand Side Management Oil Pipelines Voltage Discount Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service Depreciation Power Lines Clear Form
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