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Joint RTRP Lower Voltage and Other Design Alternatives Report

Riverside City Council
May 14, 2024

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Joint RTRP Lower Voltage and Other Design Alternatives Report
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May 14, 2024
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January 12, 2018CITY OF RIVERSIDESOUTHERN CALIFORNIA EDISONRiverside Transmission Reliability Project (A.15-04-013)Lower Voltage and Other Design Alternatives ReportRIVERSIDE PUBLIC UTILITIESPROJECT CONTACT:George HansonEMAIL:[email protected]:(951) 826-5404SOUTHERN CALIFORNIA EDISON CO.PROJECT CONTACT:Ken SpearEMAIL:[email protected]:(714) 987-5242

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TABLE OF CONTENTS1. EXECUTIVE SUMMARY.......................................................................................................... 11.1 ALJ RULING.............................................................................................................................. 11.2 DESCRIPTION AND PROJECT OBJECTIVES OF THE RTRP HYBRIDPROPOSAL AND PRINCIPLES AND METHODOLOGY FOR CONSIDERATION OF ALTERNATIVES............................................... 11.2.1 Description of the RTRP Hybrid Proposal ......................................................................... 11.2.2 Objectives of the RTRP Hybrid Proposal........................................................................... 21.2.3 Principles and Methodology for Consideration of Alternatives ......................................... 31.2.4 Alternatives Development in the 2013 FEIR...................................................................... 41.2.5 Additional Considerations Affecting Development and Evaluation of Alternatives.......... 41.2.5.1 Technical Considerations ........................................................................................... 41.2.5.2 Timing and Permitting Considerations and Reliability Impacts of Potential Delays. 41.2.5.3 Potential Tariff Implications Relating to Low Voltage Alternatives.......................... 51.3 OVERVIEW OF ALTERNATIVES AND POTENTIAL INTERIM SOLUTIONS CONSIDERED............... 61.4 SUMMARY OF THE EVALUATION OF 69 KV ALTERNATIVE DESIGNS........................................ 91.4.1 69 kV Alternatives .............................................................................................................. 91.4.1.1 Alternative A .............................................................................................................. 91.4.1.2 Alternative B ............................................................................................................ 101.4.1.3 Alternative C ............................................................................................................ 111.4.2 Summary of Conclusions Regarding 69 kV Alternatives................................................. 131.4.2.1 Lower Voltage Alternatives would likely Increase Environmental Impacts............ 131.4.2.2 The Lower Voltage Alternatives would be more Costly than the RTRP Hybrid Proposal 141.4.2.3 The Lower Voltage Alternatives Studied in this Report would Require Complex Substation Re-designs, Increased Reliability Risks, and Potential Expansions into Adjacent Properties.................................................................................................................................. 141.4.2.4 Potential Delays Resulting from Pursuit of Lower Voltage Alternatives would Unacceptably Extend Riverside’s Exposure to Reliability Risks and Increase Costs.............. 151.4.2.5 Based on Environmental, Social, and Policy Considerations, the Lower Voltage Alternatives are Infeasible........................................................................................................ 151.5 INTERIM SOLUTIONS................................................................................................................ 171.5.1 Minimum Interim Power Needs........................................................................................ 171.5.2 Reliance on Interim Solutions Cannot be Expected to Address Riverside’s Electrical Needs in lieu of the RTRP Hybrid Proposal..................................................................... 171.5.2.1 Energy Storage ......................................................................................................... 181.5.2.2 Local Generation ...................................................................................................... 191.5.2.3 Distributed Generation ............................................................................................. 201.5.2.4 Conservation/Demand Response Programs.............................................................. 201.6 CONCLUSION........................................................................................................................... 212. INTRODUCTION AND BACKGROUND .............................................................................. 232.1 BRIEFHISTORY OF THE RTRPAND THE RTRP HYBRIDPROPOSAL....................................... 232.2 ALJ RULING............................................................................................................................ 23 ii

3. RTRP PROJECT OBJECTIVES AND PRINCIPLES AND METHODOLOGY FOR CONSIDERATION OF ALTERNATIVES..................................................................................... 253.1 RTRP PROJECT OBJECTIVES, PURPOSE AND NEED................................................................. 253.2 PRINCIPLES FOR CONSIDERATION OF ALTERNATIVES............................................................ 263.2.1 CPUC’s GO 131-D Requires Consideration of CEQA .................................................... 263.2.2 Other Considerations for Alternatives .............................................................................. 283.3 ALTERNATIVES DEVELOPMENT IN THE 2013 FEIR................................................................. 283.4 METHODOLOGY FOR ANALYSIS AND EVALUATION OF ALTERNATIVES STUDIED IN THIS REPORT.................................................................................................................................... 303.4.1 Identification of Alternatives to be Studied ...................................................................... 303.4.2 Technical Considerations.................................................................................................. 303.4.2.1 Vista Substation and Riverside Generation.............................................................. 303.4.2.2 The RTRP and the RTRP Hybrid Proposal .............................................................. 313.4.2.3 Riverside System Growth and Load Forecasts......................................................... 313.4.2.4 Overhead and Underground Lines Design Considerations ...................................... 333.4.2.5 Overhead and Underground ROW and Structures Requirements ............................ 353.5 TIMING AND PERMITTING CONSIDERATIONS AND RELIABILITY IMPACTS OF POTENTIAL DELAYS IN MEETING PROJECT OBJECTIVES............................................................................ 373.6 POTENTIAL TARIFF IMPLICATIONS RELATING TO LOW VOLTAGE ALTERNATIVES................ 394. ALTERNATIVES EVALUATION .......................................................................................... 414.1 LOWER VOLTAGE ALTERNATIVES CONSIDERED IN THE 2013 FEIR....................................... 414.2 NEW LOWER VOLTAGE ALTERNATIVES CONSIDERED IN RESPONSE TO THE ALJ’SRULING. 424.2.1 Conceptual Evaluation of 115 kV Alternative.................................................................. 424.2.2 Conceptual Evaluation of New 230/69 kV Substation Alternative .................................. 424.2.3 Three 69 kV Alternatives Studied in Detail (Alternatives A, B and C)............................ 434.2.3.1 Alternative A ............................................................................................................ 474.2.3.2 Alternative B ............................................................................................................ 694.2.3.3 Alternative C ............................................................................................................ 944.3 OTHER INTERIM SOLUTIONS CONSIDERED............................................................................ 1044.3.1 Minimum Interim Power Needs...................................................................................... 1054.3.2 Analysis of Interim Solutions ......................................................................................... 1054.3.2.1 Energy Storage Systems ......................................................................................... 1064.3.2.2 Gas-Fired Generation ............................................................................................. 1084.3.2.3 Large Scale Solar.................................................................................................... 1104.3.2.4 Distributed Generation ........................................................................................... 1114.3.2.5 Conservation/Demand Response Programs............................................................ 1125. SUMMARY AND CONCLUSION......................................................................................... 1135.1 CONCLUSION......................................................................................................................... 115 iii
TABLES:TABLE 1 LOWER VOLTAGE ALTERNATIVES COST SUMMARY (NOMINAL 2023 DOLLARS) .................................................................................................................... 14TABLE 2 RIVERSIDE PROJECTED LOAD FORECAST (TABULAR).................................... 32TABLE 3 ROUTE LENGTHS, PARCELS AND STRUCTURE COUNTS ................................. 36TABLE 4 ALTERNATIVE A ENVIRONMENTAL JUSTICE COMPARISON TO THE RTRP HYBRID PROPOSAL ................................................................................................... 64TABLE 5 ALTERNATIVE A AND RTRP HYBRID PROPOSAL IMPACTS COMPARISON. 65TABLE 6 ALTERNATIVE A PRELIMINARY COST ESTIMATE, FULLY LOADED COSTS (NOMINAL 2023 DOLLARS)...................................................................................... 66TABLE 7 ALTERNATIVE B ENVIRONMENTAL JUSTICE COMPARISON TO RTRP HYBRID PROPOSAL ................................................................................................... 89TABLE 8 ALTERNATIVE B AND RTRP HYBRID PROPOSAL IMPACTS COMPARISON. 90TABLE 9 ALTERNATIVE B PRELIMINARY COST ESTIMATE, FULLY LOADED (NOMINAL 2023 DOLLARS)...................................................................................... 91TABLE 10 ALTERNATIVE C ENVIRONMENTAL JUSTICE COMPARISON TO RTRP HYBRID PROPOSAL ................................................................................................... 99TABLE 11 ALTERNATIVE C AND RTRP HYBRID PROPOSAL IMPACTS COMPARISON100TABLE 12 ALTERNATIVE C PRELIMINARY COST ESTIMATE, FULLY LOADED (NOMINAL 2023 DOLLARS).................................................................................... 101TABLE 13 LOWER VOLTAGE ALTERNATIVES AND 230 KV PROJECT IMPACTS COMPARISON............................................................................................................ 114TABLE 14 LOWER VOLTAGE ALTERNATIVES COST SUMMARY (NOMINAL 2023 DOLLARS) .................................................................................................................. 115FIGURES:FIGURE 1 69 KV ALTERNATIVE ROUTES.................................................................................. 7FIGURE 2 RIVERSIDE PROJECTED LOAD FORECAST (GRAPHIC) ..................................... 32FIGURE 3 TYPICAL 69 KV TANGENT STEEL STRUCTURES VS 230 KV STRUCTURES.. 34FIGURE 4 TYPICAL 69 KV DUCT BANK ................................................................................... 35FIGURE 5 REGIONAL LOCATION OF SUBSTATIONS EVALUATED FOR 69 KV ALTERNATIVES.......................................................................................................... 45FIGURE 6 69 KV ALTERNATIVE A MAP................................................................................... 49FIGURE 7RIVERSIDE’S TRANSMISSION SYSTEM FOLLOWING COMPLETION OF THE RTRP ALTERNATIVE A ............................................................................................. 53FIGURE 8 MIRA LOMA SUBSTATION PLOT PLAN ................................................................ 55FIGURE 9 MIRA LOMA SUBSTATION AERIAL VIEW............................................................ 57FIGURE 10 RIVERSIDE LOW-VOLTAGE ALTERNATIVE SCENARIOS FOR LOAD FLOW ANALYSIS .................................................................................................................... 59FIGURE 11 69 KV ALTERNATIVE B MAP ................................................................................... 71FIGURE 12 RIVERSIDE’S TRANSMISSION SYSTEM – FOLLOWING COMPLETION OF ALTERNATIVE B ........................................................................................................ 74FIGURE 13 ETIWANDA SUBSTATION PLOT PLAN .................................................................. 75FIGURE 14 ETIWANDA SUBSTATION-WESTERN AREA MODIFICATIONS ........................ 77FIGURE 15 ETIWANDA SUBSTATION AERIAL VIEW ............................................................. 79FIGURE 16 CIRCLE CITY SUBSTATION AERIAL VIEW AND PLOT PLAN .......................... 83FIGURE 17 69 KV ALTERNATIVE C MAP ................................................................................... 95 iv
FIGURE 18 RIVERSIDE’S TRANSMISSION SYSTEM – FOLLOWING COMPLETION OF RTRP ALTERNATIVE C ............................................................................................. 98APPENDICES:APPENDIX A PHOTOGRAPHS FOR ALTERNATIVE CORRIDORS........................................A-1APPENDIX B SCE ENVIRONMENTAL SCREENING REPORT ............................................... B-1APPENDIX C POWER ENGINEERS QUALIFICATIONS........................................................... C-1 v
ACRONYMS AND ABBREVIATIONS°F degrees FahrenheitALJ Administrative Law JudgeATRA Annual Transmission Reliability Assessment BES Battery Energy Storage CAISO California Independent System OperatorCalEnviroScreen 3.0 California Communities Environmental Health Screening Tool CalEPA California Environmental Protection Agency CDFW California Department of Fish and WildlifeCEQA California Environmental Quality ActCPCN Certificate of Public Convenience and NecessityCPUC California Public Utilities CommissionCWA Clean Water ActDBESP Determination of Biologically Equivalent or Superior PreservationDEIR Draft Environmental Impact ReportDG distributed generationEIR Environmental Impact ReportEPC Engineering, Procurement and ConstructionESS energy storage systemFEIR Final Environmental Impact ReportFERC Federal Energy Regulatory CommissionGIS Geographical Information SystemGO General Order HCP Habitat Conservation PlanHVAC High Voltage Access ChargeI-15 Interstate 15kV kilovoltLWCF Land and Water Conservation FundLVAC Low Voltage Access ChargeMSHCP Multiple Species Habitat Conservation Plan MW megawattMWh megawatt hourNEPA National Environmental Policy ActNOP Notice of PreparationOEHHA Office of Environmental Health Hazard AssessmentPEA Proponent’s Environmental AssessmentPSLF Positive Sequence Load Flow PTO Participating Transmission OwnerPUC California Public Utilities CodePV photovoltaicReport Lower Voltage and Other Design Alternatives ReportRERC Riverside Energy Resource CenterRiverside City of Riverside, California and Riverside Public UtilitiesROW(s) Right(s)-of-wayRTRP Riverside Transmission Reliability ProjectRuling ALJ’s Ruling Directing Report to Energy Division on Potentially Feasible Low-Voltage Project Alternatives vi
ACRONYMS AND ABBREVIATIONS – CONTINUEDSAIDI System Average Interruption Duration IndexSAIFI System Average Interruption Frequency IndexSCADA Supervisory Control and Data AcquisitionSCAQMD South Coast Air Quality Management DistrictSCE Southern California EdisonSEIR Subsequent Environmental Impact ReportSONET Synchronous optical networkTAC Transmission Access ChargeTO Transmission OwnerUSFWS U.S. Fish and Wildlife ServiceWDAT Wholesale Distribution Access Tariff 1 1. Executive Summary1.1 ALJ RulingOn August 15, 2017, Administrative Law Judge (ALJ) of the State of California Public Utilities Commission (CPUC) Hallie Yacknin issued the Administrative Law Judge’s Ruling Directing Report to Energy Division on Potentially Feasible Low-Voltage Project Alternatives(Ruling). In relevant part, the Ruling directed Southern California Edison Company (SCE), Riverside Public Utilities (RPU) and the California Independent System Operator Corporation (CAISO) to meet, confer andprepare a joint report to the CPUC Energy Division identifying:1. “lower voltage design alternative(s) to meet the [Riverside Transmission Reliability Project (RTRP or Project)] Project Objectives, either in full or in part;” and2. “any other interim solutions available to RPU that would mitigate the electrical system impacts until technological advancements in battery storage and distributed solar are feasible at the project scale.”SeeSection 2.2 for a more detailed discussion of the Ruling.In response to the ALJ’s Ruling, Riverside1and SCE, with the help of Riverside’s consultant POWER Engineers Inc. (POWER), developed this joint RTRP Lower Voltage and Other Design Alternatives Report(Report) with advice and guidance from CAISO. POWER is an engineering and environmental consulting firm with more than 40 years of experience in the electrical transmission and distribution industry. Qualifications for POWER, including a sample list of projects, have been included in Appendix C. POWER assisted the City of Riverside in the development of the Draft Environmental Impact Report (DEIR) and the 2013 Final Environmental Impact Report (2013 FEIR) for the RTRP and continues to provide support in the CPUC licensing process.1.2 Description and Project Objectives of the RTRP Hybrid Proposal and Principles and Methodology for Consideration of Alternatives1.2.1 Description of the RTRP Hybrid Proposal2The RTRP Hybrid Proposal includes many components that would be required for the completion of the entire project in order to meet the Project Objectives as listed in the 2013 FEIR and Section 2.2(Volume 2). At a macro level, these include the SCE 230 kilovolt (kV) components and the Riverside69 kV components. The SCE 230 kV components of the RTRP Hybrid Proposal include the following CAISO-controlled facilities:New double-circuit 230 kV transmission line 9.7 miles in length, which includes both overhead and underground design elements.New Wildlife Substation.1RPU is a department of the City of Riverside. This Report generally uses the term “Riverside” except where specific reference to RPU is more appropriate. 2This Report refers to the design proposal currently supported by SCE and Riverside as the “RTRP Hybrid Proposal.” The use of the term “Hybrid” refers to the combination of both overhead and underground transmission facilities included in the design. The RTRP design as originally proposed and evaluated in the 2013 FEIR consisted entirely of overhead facilities. 2 Mira Loma and Vista Substation upgrades.Telecommunications.In response to the Ruling, this Report develops for comparison purposes potential lower voltage Alternatives to the components of the RTRP Hybrid Proposal listed above. The cost comparisons included within this Report are specific to the 230 kV components of the RTRP Hybrid Proposal, comparing only those CAISO-controlled facilities to the lower voltage Alternatives that have been developed and are discussed in detail within this Report. SeeSections 2.1 and 3.4.2.2 for discussion of the history and a more detailed description of the RTRP Hybrid Proposal. 1.2.2 Objectives of the RTRP Hybrid ProposalThe 2013 FEIR, prepared by the City of Riverside acting as the California Environmental Quality Act (CEQA) Lead Agency, stated that a “new interconnection to SCE’s transmission system is urgently needed to provide capacity for existing as well as new electrical load and an additional point of interconnect for reliability purposes.” The February 2017 CPUC Initial Study for the Subsequent Environmental Impact Report (SEIR) reinforces these stated Objectives, asserting that the “SCE project objectives are to provide Riverside and its customers with adequate transmission capacity to serve existing and projected load, to provide for long-term system capacity for load growth and to provide needed system reliability.” The RTRP Hybrid Proposal will add a second point of delivery that would provide an additional 560 megawatts (MW) of transformation and delivery capacity (approximately doubling Riverside’s current capacity of 557 MW from SCE’s 230 kV bulk power transmission system.The Project Objectives originally developed in support of the RTRP’s purpose and need expressed in the 2013 FEIR also guided the development and evaluation of Alternatives considered in this Report. Specifically, the Project Objectives of the RTRP (and the RTRP Hybrid Proposal) are to:Provide sufficient capacity, in a timely manner, to meet existing electric system demand and anticipated future load growth.Provide an additional point of delivery for bulk power into the Riverside electrical system, thereby reducing dependence on Vista Substation and increasing overall reliability.Split and upgrade the subtransmission electrical system as a function of prudent utility practice.Meet Proposed Project need while minimizing environmental impacts.Meet Proposed Project need in a cost-effective manner.The term “reliability” refers broadly to the ability to provide electric service as required by customers in accordance with nationally recognized industry standards relating to continuity of service and ability to withstand system disturbances. The RTRP Hybrid Proposal has several related but distinct Project Objectives for maintaining reliability of service to Riverside customers, including(1) increasing capacity to meet Riverside’s existing and forecast demand, (2) providing a second source of delivered energy to Riverside from the SCE/CAISO grid, so that service could be maintained if Vista Substation were out of service, and (3) facilitating configuration of Riverside’s distribution system to maximize reliability of distribution service. SeeSection 3.1 for more detailed discussion of the Project Objectives, purpose and need for the RTRP Hybrid Proposal. 3 1.2.3 Principles and Methodology for Consideration of AlternativesConsideration of alternatives to the RTRP Hybrid Proposal is generally governed by the CPUC’s General Order (GO) 131-D, CEQA, and the California Public Utilities Code. GO 131-D was adopted to be responsive to the requirements of CEQA.3The CEQA Guidelines emphasize the selection of a “reasonable range” of alternatives in an environmental impact report (EIR) “which would feasibly attain most of the basic objectives of the project but would avoid or substantially lessen any of the significant effects of the project, and evaluate the comparative merits of the alternatives.”4Under CEQA, “feasible” means “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, social, and technological factors,” but may also take into account “other considerations,” permitting the rejection of mitigation measures and/or alternatives that are impractical or undesirable from a policy standpoint.5In addition, CPUC Section 1002 states, in relevant part, “the commission, as a basis for granting any certificate pursuant to Section 1001 shall give consideration to the following factors: (1) Community values, (2) Recreational and park areas, (3) Historical and aesthetic values, (4) Influence on environment, .”Consistent with the standards summarized above, SCE and Riverside sought to identify lower voltage alternatives that would avoid or substantially reduce environmental impacts that would result from the RTRP Hybrid Project while meeting most or all of the Project Objectives in a timely and cost-effective manner. The analysis identified potential lower voltage designs sourced from SCE substations (or in one Alternative a proposed substation) located closest to the Riverside grid, expecting that this approach would be most likely to minimize both environmental impacts and costs of alternatives considered. SCE and Riverside identified potential routes and developed preliminary facilities designs and cost estimates for three 69 kV Alternatives. Following the preliminary but detailed scoping of the three Alternatives, SCE and Riverside evaluated each potential Alternative using the following three inquiries:1. Does the Alternative avoid or substantially lessen any significant effects of the RTRP Hybrid Proposal, including consideration of whether the Alternative itself could create significant effects potentially greater than those of the RTRP Hybrid Proposal?2. Does the Alternative accomplish all or most of the basic Project Objectives?3. Is the Alternative feasible?SeeSections 3.2 and 3.4.1 for more detailed discussion of the principles applicable to the evaluation of alternatives and the methodology for identification of potential alternatives.3SeeGO 131-D § II (GO 131-D responsive to CEQA’s requirements).4Title 14, Cal. Code of Regulations (CEQA Guidelines) §§ 15126.6(a) (Alternatives to the Proposed Project), (f) (Rule of Reason);see alsoCEQA Guidelines § 15124(b) (clear statement of objectives aids in developing alternatives).5California Public Resources Code (Pub. Resources Code) §§ 21061.1 (defining “feasible”), 21081 (no public agency shall approve a project with significant and unavoidable environmental impacts unless the public agency finds “specific economic, legal, social, technological, or other considerations . . . make infeasible the mitigation measures or alternatives identified in the environmental impact report” and “that specific overriding economic, legal, social, technological, or other benefits of the project outweigh the significant effects on the environment”); see alsoCEQA Guidelines §§ 15021(b) (“In deciding whether changes in a project are feasible, an agency may consider specific economic, environmental, legal, social, and technological factors”), 15364 (same); California Native Plant Soc. v. City of Santa Cruz, 177 Cal.App.4th957, 1001 (2009) (“other considerations” referenced in section 21081 include matters of policy). 4 1.2.4 Alternatives Development in the 2013 FEIRFor background and comparison purposes, Section 3.3 describes alternatives to the RTRP as originally proposed that were evaluated in the 2013 FEIR.1.2.5 Additional Considerations Affecting Development and Evaluation of Alternatives1.2.5.1 Technical Considerations Section 3.4.2 discusses technical considerations used for the development and evaluation of the lower voltage Alternatives studied in this Report, includingDescription of Vista Substation and Riverside generation (Section 3.4.2.1).Description of the RTRP and RTRP Hybrid Proposal (Section 3.4.2.2).Discussion of Riverside’s system growth and load forecasts (Section 3.4.2.3).Overhead and underground lines design considerations, including a summary of routelengths, parcels, and structure counts for the three 69 kV Alternatives studied in detail (Section 3.4.2.4).1.2.5.2 Timing and Permitting Considerations and Reliability Impacts of Potential DelaysSection 3.5 explains in detail that the need to address the reliability concerns arising from Riverside’s reliance on the Vista Substation as promptly as possible is urgent. SCE currently has a maximum 557 MW transfer limit under normal operating conditions it can provide to Riverside through Vista Substation, the sole point of interconnection between the Riverside and SCE/CAISO grids. Whenever this loading limit is approached under normal operating conditions, Riverside’s internal gas-fired generation must be operated to ensure that the Vista Substation loading does not exceed 557 MW. This load limit has been routinely exceeded during peak demand periods in the past nine years and with increasing frequency. As Riverside’s load is forecasted to continue to grow, it is expected that Riverside’s internal generation will be increasingly called upon to mitigate the Vista transfer limit issue, but the use of Riverside’s internal generation for this purpose faces an uncertain future.The reliability problem associated with the inadequate Vista transfer limit is further exacerbated if there is a contingency at Vista Substation,e.g.,an outage of one or both transformers at VistaSubstation. With one of the Vista Substation transformers out, the Vista transfer limit is reduced to 280 MW; when added to Riverside’s internal generation of 228 MW (assuming all generation is indeed available), the maximum load-serving capability for Riverside is reduced to 508 MW. Thus, absent any other mitigating measure, involuntary load shedding is highly likely when Riverside’s load exceeds 508 MW and there is a single transformer outage at Vista Substation. The numbers of hours that Riverside’s load exceeded 508 MW in 2015, 2016 and 2017 are 55, 92 and 143 hours,respectively. If a transformer outage at Vista Substation had occurred at the time of Riverside’s peak load, the resulting load shedding in 2015, 2016 and 2017 as a percentage of Riverside’s peak load could have been 13.16%, 15.19% and 20.50%, respectively. As Riverside’s load is forecasted to continue to grow, the threat of involuntary load shedding of Riverside’s customers due to the inadequate Vista Substation transfer limit will continue to grow. If a total collapse of Vista Substation were to occur (for example, due to a severe earthquake or destruction by a fire), it would cause severe and potentially catastrophic disruptions of electrical service to Riverside’s customers and SCE’s customers served from Vista Substation.Adoption of any of the 69 kV Alternatives or any of the interim solutions evaluated in this Report inevitably would delay effective mitigation of the reliability issues arising from Riverside’s dependence on Vista Substation and prolong exposure of an increasing number of Riverside’s customers to risks of extended outages. Implementation or selection of any of the 69 kV Alternatives 5 for the RTRP Hybrid Proposal could alter the required permitting and licensing process currently underway. SCE and Riverside estimate that delays associated with implementation of any of the 69 kV Alternatives would range from a minimum of 12 to 18 months to five years or more, depending on various factors, an unacceptably long period of time given the increasingly escalating exposures to reliability risks that Riverside will continue to face.Many of the corridors identified for routes under the 69 kV Alternatives have not been reviewed in detail as part of the 2013 FEIR process, and substantial baseline data collection and impact evaluation may be required along two or three additional line routes. In addition, the current infrastructure of Riverside’s distribution system is not expandable to accommodate multiple additional 69 kV connections at its existing substations. Detailed studies would need to be performed to adequately evaluate revised system performance and whether any system upgrades would be triggered by implementation of such an Alternative. Delays associated with the potential incremental regulatory and infrastructure requirements summarized above would place Riverside’s customers at prolonged risk of experiencing outages due to the single source arrangement existing at Vista Substation, Riverside’s load currently exceeding SCE’s available capacity at the Vista Substation, and the projected load growth as stated in the purpose and need statement (2013 FEIR). In addition, the potential incremental regulatory requirements and associated delays would add significant costs. This would be in addition to the higher cost estimates for the 69 kV delivery facilities (seeTables 6, 9, and 12) and the costs already incurred as part of the RTRP CEQA environmental review and Certificate of Public Convenience and Necessity (CPCN) licensing process. Every attempt should be made to conclude SCE’s current CPCN application and the development of the SEIR in an expedited fashion to concretely address the reliability issues caused by the inadequate Vista transfer limit.1.2.5.3 Potential Tariff Implications Relating to Low Voltage AlternativesSection 3.6 discusses in detail potential issues relating to tariff applicability, classification of facilities, and cost allocation that would arise from implementation of any of the 69 kV Alternatives. In June 2006, CAISO approved the 230 kV RTRP as “a necessary and cost effective addition to the ISO Controlled Grid” and directed SCE “to complete the construction of the [RTRP] as soon as possible and preferably no later than Q2, 2009.”6In 2009, the Federal Energy Regulatory Commission (FERC) approved the Transmission Owner (TO) Tariff Interconnection Agreement between SCE and Riverside governing the terms of development and construction of the 230 kV RTRP design.7Per the CAISO Tariff and relevant in the case of the RTRP Hybrid Proposal, the costs of High Voltage Transmission Facilities (200 kV or greater) under CAISO’s “Operational Control” are recovered via the High Voltage Access Charge (HVAC) regardless of ownership. Under the currently-effective HVAC design, all users of the high voltage CAISO-controlled grid (including Riverside and SCE) would share the costs for the RTRP Hybrid Proposal in proportion to their use of the grid.Under the currently-effective CAISO Tariff, the 69 kV Alternatives would not be included in the HVAC. Riverside believes that the 69 kV Alternatives may be considered lower voltage transmission 6SeeGeneral Session Minutes – Operations Committee Meeting, Cal. Indep. Sys. Operator Corp. (June 16, 2006) at 4.7S. Cal. Edison Co., 127 FERC ¶ 61,211 (2009) (letter order approving Settlement Agreement reflecting Amended Interconnection Facilities Agreement). 6 facilities that, under the currently-effective CAISO Tariff, would be recovered through the Low Voltage Access Charge (LVAC) paid by customers within the SCE Transmission Access Charge(TAC) Area that take service from such lower voltage facilities. SCE believes that the 69 kV Alternatives would be considered non-CAISO-controlled, distribution assets that, under SCE’s currently-effective Wholesale Distribution Access Tariff, would be recovered from Riverside and other users or beneficiaries of the 69 kV facilities, if any. Classification of any 69 kV Alternative facilities and allocation of associated costs would be subject to the jurisdiction of the FERC. 1.3 Overview of Alternatives and Potential Interim Solutions ConsideredAs noted above, in response to ALJ Yacknin’s Ruling, SCE and Riverside studied lower voltage Alternatives for increasing delivery capability to Riverside that would source from SCE’s existing (or, in one Alternative, planned) substations closest to Riverside.8This Report identifies and evaluates in detail the following potential 69 kV Alternatives to the RTRP Hybrid Proposal (69 kV Alternatives, seeFigure 1) that would, if found feasible, potentially meet, in whole or in part, most of the Project Objectives:Alternative A –Single Source; Total firm9 capacity = Initial 560 MW, Ultimate 840 MW; single substation interconnection (Mira Loma), initially with two 280 MW transformers and ultimately with three 280 MW transformers, with three double-circuit 69 kV lines and one single-circuit line for a total of seven 69 kV circuits.Alternative B –Three Source; Total firm capacity = 750 MW; single 280 MW transformers at three source substations (transformer capacity = 3 X 280 MW = 840 MW), three substations interconnections (Mira Loma, Etiwanda, and Circle City) with three double-circuit 69 kV lines for a total of six 69 kV circuits; two circuits from each substation. Delivery capacity of this Alternative is limited to 750 MW by 69 kV line circuit deliverability.8As in the 2013 FEIR, a 115 kV alternative was considered conceptually but not carried forward for detailed evaluation for the reasons discussed in Section 4.2.1. In addition, SCE and Riverside considered in concept a design alternative that would include a new 230/69 kV substation on a new site adjacent to or near the two Mira Loma – Vista 230 kV transmission lines but did not study that approach in detail for the reasons explained in Section 4.2.2.9Firm Transmission Service is defined as the highest quality service offered by a Transmission or Distribution Provider to customers under a filed rate schedule that anticipates no planned interruption.

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9 Alternative C –Single Source; Total firm capacity = 500 MW; single substation interconnection (Mira Loma), two 280 MW transformers (transformer capacity = 2 X 280 MW = 560 MW) with two double-circuit 69 kV lines for a total of four 69 kV circuits (500 MW). Delivery capacity of this Alternative is limited to 500 MW by 69 kV line circuit deliverability. Included with Alternative C is a 60 MW photovoltaic (PV) solar facility and a Battery Energy System (BES) (240 megawatt hours [MWh]). This generation provides substantially less capacity than its rated capability for serving load and for peak shaving purposes.10Analyses of the three 69 kV Alternatives are summarized in Section 1.4.1 and described in detail in Sections 4.2.3.1 (Alternative A), 4.2.3.2 (Alternative B), and 4.2.3.3 (Alternative C).This Report also evaluates for feasibility and suitability the following potential interim solutions to mitigate the Riverside electrical system impacts:Energy Storage System facilities (Battery, Pumped Hydro and Compressed Air).Local Generation (Gas-Fired Combustion Turbines and Utility Scale Solar Facility).Distributed Energy Resources.Energy Conservation programs.Analyses of potential interim solutions are summarized in Section 1.5 and described in detail in Section 4.3.1.4 Summary of the Evaluation of 69 KV Alternative Designs1.4.1 69 kV AlternativesNone of the 69 kV Alternatives studied would have less environmental impact than the RTRP HybridProposal or satisfy most of the Project Objectives.1.4.1.1 Alternative ASection 4.2.3.1.1 describes in detail the preliminary routes and facilities designs included in Alternative A, which would include interconnection at a single substation (Mira Loma) with three double-circuit 69 kV lines and one single-circuit line for a total of seven 69 kV circuits. Although the Alternative A design could provide the delivery capacity required by Riverside and a second interconnection to the SCE/CAISO grid, Alternative A would result in increased environmental impacts and be more costly in terms of total dollars as compared with the RTRP Hybrid Proposal. Provide sufficient capacity, in a timely manner, to meet existing electric system demand and anticipated future load growth. Alternative A initially would provide 560 MW, and as loads increased it could provide up to 840 MW of capacity to meet Riverside’s future load growth provided that: (1) three new 280 MW transformers could be physically installed at SCE’s Mira Loma Substation, and (2) four new 69 kV line routes could be permitted and necessary rights acquired. Alternative A initially would provide up to 560 MW of capacity with installation of two transformers (matching the initial designed capacity for the RTRP Hybrid Proposal), provided that four new 69 kV 10The CPUC recognizes that solar PV generation provides less capacity than rated capability in its load serving capability due to its technological characteristics. For example, CAISO uses monthly Effective Load Carrying Capacity (ELCC) multipliers as sanctioned by the CPUC to reflect the deeply discounted value of solar PV load serving capability;e.g., the ELCC multipliers for calendar year 2018 range from a low of zero for some winter months (January and December 2018), signifying no capacity value assigned to solar PV generation, to a high of 0.448 for the month of June 2018, or less than 50% of the rated capability. 10 line routes could be permitted and the necessary rights acquired. Seethe discussion in Section 4.2.3.1.1.However, as discussed in detail in Section 3.5, compared with the RTRP Hybrid Proposal, Alternative A is likely to result in delays in timely addressing Riverside’s current and future anticipated electricsystem demands. The magnitude of the delay associated with Alternative A depends on various factors, including time needed for engineering and design, modification of the environmental analyses in the SEIR under development by the CPUC, and CPUC’s licensing of Alternative A. If adoption of the Alternative A design required initiation of a new CEQA process, the resulting delay likely would be five years or more.11Provide an additional point of delivery for bulk power into the Riverside electrical system, thereby reducing dependence on Vista Substation and increasing overall reliability. Alternative A would potentially meet the Project Objectives of providing additional points of delivery for power into a bifurcated Riverside electrical system from SCE’s Mira Loma Substation.Meet Proposed Project need while minimizing environmental impacts.As summarized in Section 1.4.2.1 and discussed in detail in Section 4.2.3.1.2.3, Alternative A would result in increased environmental impacts when compared with the RTRP Hybrid Proposal’s environmental impacts.Meet Proposed Project need in a cost-effective manner. As summarized in Section 1.4.2.2 and discussed in detail in Section 4.2.3.1.2.4, Alternative A’s estimated total costs exceed the estimated costs for the RTRP Hybrid Proposal. As described in Section 4.2.3.1.2.4, Alternative A is estimated to cost $499.1 million (nominal 2023 dollars), approximately 23% more than the estimated cost of the RTRP Hybrid Proposal of $405.3 million in nominal 2023 dollars.121.4.1.2 Alternative BSection 4.2.3.2.1 describes in detail the preliminary routes and facilities designs included in Alternative B, which would include interconnection at two existing SCE substations (Mira Loma and Etiwanda) and one proposed substation (Circle City), a new 230 kV line to the proposed Circle City Substation from the Mira Loma Substation, and a double-circuit 69 kV line from each of the three substations to Riverside. Alternative B potentially would meet the Project goals of increasing delivery capacity and providing a second source of power and energy to Riverside. However, compared with the RTRP Hybrid Proposal, Alternative B would result in a system that would be more difficult to operate and manage and susceptible to dropping load in a contingency condition,13undercutting its 11Alternatively, and as discussed in more detail in Section 3.5, the SEIR under development by the Commission could discuss the environmental impacts associated with Alternative A in compliance with CEQA. In that event, the estimated delay resulting from adoption of Alternative A could range from 12-18 months.12The ALJ’s ruling at 3 references a project cost of $234.5 million, which was submitted to the CPUC in April 2015 but did not include the underground facilities included in the RTRP Hybrid Proposal. In quarterly meetings with the Energy Division, SCE has shared forecast costs for the RTRP Hybrid Proposal of $353 million (constant 2015 dollars), which equates to $405.3 million in nominal 2023 dollars. For comparison purposes, this Report uses nominal 2023 dollars for the RTRP Hybrid Proposal and all three of the 69 kV Alternatives studied.13The term “contingency condition” is used throughout this Report, and it refers to the system in normal condition with an unexpected failure or outage of a single system component or two components, such as a generator, transmission line, circuit breaker, switch or other electrical equipment. 11 reliability. Alternative B would result in increased environmental impacts compared with the RTRP Hybrid Proposal and would cost more in terms of total dollars. SeeSection 4.2.3.2.2.3 for detailed discussion of the anticipated environmental impacts of Alternative B and Section 4.2.3.2.2.4 for discussion of Alternative B estimated costs.Provide sufficient capacity, in a timely manner, to meet existing electric system demand and anticipated future load growth. Alternative B would also potentially provide sufficient capacity to meet existing Riverside electric system demand and anticipated future load growth. While the transformer capacity of Alternative B would be designed to support 840 MW, Alternative B’s capacity to deliver that power would be limited to 750 MW (i.e., six 125 MW 69 kV circuits (three double-circuit 69 kV lines – three routes). Thus, while it would meet the currently projected needs of Riverside, Alternative B would provide less potential future delivery capacity than the RTRP Hybrid Proposal. Seethe discussion in Section 4.2.3.2.2.1.Like Alternative A and for the reasons discussed in Section 3.5, as compared with the RTRP Hybrid Proposal, Alternative B is likely to result in delays in timely addressing Riverside’s current and future anticipated electric system demands. The magnitude of the delay associated with Alternative B depends on various factors, including time needed for engineering and design, modification of the environmental analyses in the SEIR under development by the CPUC, and CPUC’s licensing of Alternative B. If adoption of the Alternative B design required initiation of a new CEQA process, the resulting delay likely would be five years or more.Provide an additional point of delivery for bulk power into the Riverside electrical system, thereby reducing dependence on Vista Substation and increasing overall reliability. The Alternative B design would add a second source of electricity to Riverside’s grid. However, as discussed in detail in Section 4.2.3.2.2.2, Alternative B would result in a system that would be significantly more difficult to operate and manage, as it would provide power to the western half of Riverside’s bifurcated distribution system through three different transmission sources: the Mira Loma, Etiwanda, and (proposed) Circle City Substations, resulting in three new distinct and separately sourced “load pockets” within Riverside’s service territory. This would make Riverside’s system operationally complex, inflexible, difficult to operate and manage, and susceptible to load shedding under contingency conditions.Meet Proposed Project need while minimizing environmental impacts.As summarized in Section 1.4.2.1 and discussed in detail in Section 4.2.3.2.2.3, Alternative B would result in increased environmental impacts when compared with the RTRP Hybrid Proposal’s likely environmental impacts, especially in view of the fact that Alternative B would require installation of a new 230 kV transmission line longer than the 230 kV line included in the RTRP Hybrid Proposal.Meet Proposed Project need in a cost-effective manner. As summarized in Section 1.4.2.2 and discussed in detail in Section 4.2.3.2.2.4, Alternative B’s total costs would far exceed the anticipated costs associated with the RTRP Hybrid Proposal. With the required 230 kV line to Circle City Substation, Alternative B is estimated to cost $1,064.2 million (nominal 2023 dollars) or more than two-and-one-half times the estimated cost of the RTRP Hybrid Proposal of $405.3 million in nominal 2023 dollars.1.4.1.3 Alternative CSection 4.2.3.3.1 describes in detail the preliminary routes and facilities designs included in Alternative C, which would include interconnection at a single substation (Mira Loma) with two double-circuit 69 kV lines for a total of four 69 kV circuits. Alternative C would provide 500 MW of additional firm delivery capacity and an additional point of delivery for power into the Riversideelectrical system, but it would not effectively reduce Riverside’s dependence on Vista Substation and 12 increase overall reliability. While the CPUC-jurisdictional portion of the Project would cost less than Alternatives A or B or the RTRP Hybrid Proposal, such costs do not include the cost of the additional contemplated generation that would be necessary to provide reliable service to Riverside load.14Alternative C also is likely to result in increased environmental impacts compared with the RTRP Hybrid Proposal.SeeSections 1.4.2.1 and 4.2.3.3.2.2.Provide sufficient capacity, in a timely manner, to meet existing electric system demand and anticipated future load growth. Alternative C would only provide up to 500 MW of additional firm delivery capacity to meet Riverside’s needs. While the transformer capacity of Alternative C would be designed to support 560 MW, Alternative C’s capacity to deliver that power would be limited to 500 MW (i.e., four 125 MW 69 kV lines). Therefore, Alternative C would not meet the 560 MW capacity goal of the Project and would not meet the power delivery capacity of the RTRP Hybrid Proposal or longer term capacity requirements without the addition of supplemental internal generation. Seethe discussion in Section 4.2.3.3.2.1.Like Alternatives A and B and for the reasons discussed in Section 3.5, as compared with the RTRP Hybrid Proposal, Alternative C is likely to result in delays in timely addressing Riverside’s current and future anticipated electric system demands. The magnitude of the delay associated with Alternative C depends on various factors, including time needed for engineering and design, modification of the environmental analyses in the SEIR under development by the CPUC, and CPUC’s licensing of Alternative C. If adoption of the Alternative C design required initiation of a new CEQA process, the resulting delay likely would be five years or more.Provide an additional point of delivery for bulk power into the Riverside electrical system, thereby reducing dependence on Vista Substation and increasing overall reliability. Alternative C would add a second source of electricity to Riverside’s grid but would not effectively reduce dependence on Vista Substation and increase overall reliability. In the event service from Vista Substation was interrupted, Alternative C could only provide a maximum of 680 MW (500 MW of firm delivery capacity plus 180 MW of local generation).15Riverside’s maximum load is forecasted to be 734 MW in 2038. Thus, Alternative C would fall 54 MW short by 2038, using the assumption that 180 MW of local gas-fired generation would be available in 2038. Alternative C would not effectively replace the 14Two potentially viable generation options were considered for Alternative C supplemental generation, i.e., gas-fired peakers and PV Solar with battery energy storage (BES). PV Solar with BES was selected for further study in this Report over gas-fired peakers mainly because of the concerns with the long term viability of gas-fired peakers as sources of firm power in light of increasingly stringent environmental regulations. As noted in Sections 1.5.2.2.1 and 4.3.2.2, the use of additional peakers would likely result in greater air quality impacts, and strict operation permit requirements for gas-fired generation sources regulated by the South Coast Air Quality Management District (SCAQMD) renders continued dependence on peakers questionable. Even if environmentally and legally feasible, the increased use of peakers to meet Riverside’s demands would: (1) be less cost effective than the RTRP Hybrid Proposal; (2) suffer from reliability risks due to uncertainties in the availability of natural gas fuel sources; (3) require finding available land to site additional gas-fired generation, and (4) not represent prudent utility practice in that it would defer transformer capacity additions by continued installation of peaking units. Reference Section 4.3.2 Analysis of Interim Solutions for further discussion on large scale utility solar and gas-fired peakers.15Riverside’s RERC generation includes 4 – 48 MW units (192 MW), and Springs Generation includes 4 - 9MW units (36 MW) of generation for a total Riverside internal generation of 228 MW. Under contingency conditions, as described in this Report, one RERC unit would be out of service for a loss of 48 MW, leaving total remaining generation of 180 MW (228 MW – 48 MW). 13 firm power supplied by Vista Substation in the event that source became unavailable and it would not satisfy the Project’s reliability Objective even with the addition of supplemental internal generation. Seethe discussion in Sections 4.2.3.3.2.1 and 4.2.3.3.2.4.Meet Proposed Project need while minimizing environmental impacts.As summarized in Section 1.4.2.1 and discussed in detail in Section 4.2.3.3.2.2, Alternative C would likely result in increased environmental impacts when compared with the RTRP Hybrid Proposal’s likely environmental impacts.Meet Proposed Project need in a cost-effective manner. As summarized in Section 1.4.2.2 and discussed in detail in Section 4.2.3.3.2.3, Alternative C’s estimated costs for delivery facilities alone are less than the estimated costs for the RTRP Hybrid Proposal. Alternative C is estimated to cost $239.4 million (nominal 2023 dollars) for firm delivery facilities. Alternative C would require additional internal generation to provide equivalent capacity (560 MW), and the costs for such internal generation would increase the cost for Alternative C above the cost for the RTRP Hybrid Proposal. Refer to Section 4.2.3.3.2.3 for a breakdown of the Solar and battery energy system costs. The Alternative C total cost, with additional generation, is estimated at $503.4 million as compared to the estimated cost of the RTRP Hybrid Proposal of $405.3 million, approximately 24% more than the estimated cost of the RTRP Hybrid Proposal.1.4.2 Summary of Conclusions Regarding 69 kV Alternatives1.4.2.1 Lower Voltage Alternatives would likely Increase Environmental Impacts.As discussed in detail in Section 3.2, the CEQA Guidelines require that consideration of project alternatives be based primarily on ability to reduce significant environmental impacts relative to the proposed project. All three of the potential Alternatives studied herein would require multiple 69 kV routes as compared with the single double-circuit 230 kV transmission line proposed as part of the RTRP Hybrid Proposal. Further, the 69 kV Alternatives would have higher environmental impacts because of the additional equipment and necessary expansions of Mira Loma Substation and (for Alternative B) Etiwanda Substation and the proposed Circle City Substation. As a result, the areas affected by the potential Alternatives would be more extensive than the area that would be affected by the RTRP Hybrid Proposal, and all of the Alternatives evaluated would increase, rather than “avoiding or substantially lessening any significant [environmental] effects of the project . . . .”16SeeSections 4.2.3.1.2.3 (Alternative A), 4.2.3.2.2.3 (Alternative B), and 4.2.3.3.2.2 (Alternative C).Further, Alternative B also would require the siting, licensing, and construction of a separate 230 kV transmission line source to be routed to the proposed Circle City Substation that is not part of the currently proposed design for that substation and would likely be approximately 20 percent longer than the 230 kV line proposed as part of the RTRP Hybrid Proposal. The necessary 230 kV line to Circle City Substation was not designed in detail in this Report. However, this source line by itself would increase rather than reduce environmental impacts in comparison to the RTRP Hybrid Proposal due to the similar environmental baseline conditions occurring in the area between the Mira Loma Substation and the Circle City Substation.SeeSection 4.2.3.2.2.3. Effectively, in addition to adding 69 kV lines, Alternative B simply relocates the proposed 230 kV line included in the RTRP Hybrid Proposal into different residential communities to the west without reducing environmental impacts.Fundamentally, none of the 69 kV Alternatives studied herein would effectively mitigate public opposition to the RTRP Hybrid Proposal. In fact, the 69 kV Alternatives would likely result in 16SeeCEQA Guidelines §§ 15126.6 (a) and (f).

15 customers. SeeSections 4.2.3.1.2.2, 4.2.3.2.2.5, and 4.2.3.3.2.4. The Alternative A design includes the addition of three transformers at Mira Loma Substation, which would exceed the transformer limit as dictated by SCE’s “Subtransmission Planning Criteria and Guidelines” (September 24, 2015) and substation design standards. SCE’s standards provide a baseline to evaluate and compare the merits of proposed changes to determine impact on safety, reliability, operations, maintenance, construction and cost. The four A-bank transformer limitation seeks to limit the amount of exposure if the substation were to become unavailable and also allows for a reasonable amount of circuit congestion in the local area. SeeSection 4.2.3.1.2.2.Alternative B has reliability concerns not only with the addition of transformers to multiple source substations (Mira Loma, Etiwanda, and Circle City), but it also requires significant changes to the configuration of Riverside’s distribution system, which would result in reduced reliability as compared to the RTRP Hybrid Proposal. SeeSection 4.2.3.2.2.2.1.4.2.4 Potential Delays Resulting from Pursuit of Lower Voltage Alternatives would Unacceptably Extend Riverside’s Exposure to Reliability Risks and Increase CostsAs discussed in more detail in Section 3.5, pursuing a lower voltage Alternative would likely increase the time required to approve and install the facilities needed to address Riverside’s current and future anticipated electric system demands. As referenced previously, the low voltage Alternatives may result in delays of five years or more to the anticipated in-service date of the new interconnection depending on various factors, including time needed for engineering and design, modification of the environmental analyses in the SEIR under development by the CPUC, and CPUC licensing.Due to the limitations on capacity at Vista Substation (Riverside’s sole interconnection with the SCE/CAISO grid), Riverside’s customers already are exposed to risk of blackouts, load shedding and outages under contingency conditions, and that risk would be extended and increased if the workalready performed to support the RTRP Hybrid Proposal has to start over to pursue a lower voltage Alternative. Such delay would be inconsistent with the Project Objectives and, in addition to potentially extending the in-service date of the project, may substantially increase the project costs as additional efforts are made in support of CPUC licensing. Such costs would be in addition to the significant expense already incurred as part of the CEQA environmental review and CPCN licensing process.1.4.2.5 Based on Environmental, Social, and Policy Considerations, the Lower Voltage Alternatives are InfeasibleUnder California law, feasibility is defined as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors.”17 No public agency shall approve a project with significant and unavoidable environmental impacts unless the public agency finds “specific economic, legal, social, technological, or other considerations make infeasible the mitigation measures or alternatives identified in the environmental impact report” and “that specific overriding economic, legal, social, technological, or other benefits of the project outweigh the significant effects on the environment.”18 Under CEQA, the “other considerations” referenced in section 21081 have been found to include “policy considerations,” permitting the rejection of mitigation or alternatives that are “impractical or17SeeCEQA Guidelines § 15364; see alsoPub. Resources Code § 21061.1.18SeePub. Resources Code § 21081. 16 undesirable from a policy standpoint.”19The CEQA Guidelines also stress that the selection of project alternatives should be based primarily on the ability of one or more proposed alternatives to reduce significant impacts relative to the proposed project.20Sections 4.2.3.1.2.5, 4.2.3.2.2.5, and 4.2.3.3.2.4 discuss in detail the feasibility considerations relating to Alternatives A, B, and C, respectively. None of the 69 kV Alternatives is capable of being accomplished within the same time period as the RTRP Hybrid Proposal. Depending on the extent of subsequently-required engineering and design modifications as well as permitting and related regulatory proceedings, the additional time necessary for the completion of any of the Alternatives could be five years or more.21As described in Section 3.5, these delays would place the reliability of Riverside’s system at continued risk of load shedding and potential distribution system blackout conditions, as SCE and Riverside expect that loading limits on Riverside’s sole existing interconnection to the SCE system at the Vista Substation will continue to be exceeded under normal operating conditions during peak demand periods. Under emergency conditions, including an outage of one of the Vista Substation transformers used to serve Riverside, involuntary load shedding is highly likely. Under both normal and emergency conditions, Riverside will be required to continue to rely on internal, gas-fired peaking units that are vulnerable to fuel supply deficiencies associated with the gas system and usage limitations related to air permitting. Increased delay also has the potential to add significant costs to any project. These costs would be in addition to the costs already incurred as part of the RTRP CEQA environmental review and CPCN licensing process. It is critical that any Alternative to the RTRP Hybrid Proposal be capable of completion within the same timeframe. None of the 69 kV Alternatives satisfies that criterion.Each of the Alternatives is environmentally infeasible due to the requirements for significantly more miles of transmission line to accomplish even some of the basic Project Objectives of the RTRP. The increase in transmission lines would have higher environmental impacts because of a greater footprint with multiple right(s)-of-way (ROWs), greater effects to the community from the greater footprint, and additional equipment being required at Mira Loma, Etiwanda, and the proposed Circle City Substations. Each of the lower voltage Alternatives would extend the environmental and community impacts beyond the footprint of the RTRP Hybrid Proposal. Social factors also support a finding of infeasibility as to each of the 69 kV Alternatives. The large number of structures and line miles described above in connection with environmental factors will create a greater impact on the communities located adjacent to the facilities for the 69 kV Alternatives relative to the impact that the shorter route and reduced number of structures associated with the RTRP Hybrid Proposal will have on communities adjacent to the project. Because each of the 69 kV Alternatives includes at least one line route that does not follow the same route as the RTRP Hybrid Proposal, SCE and Riverside anticipate that new community opposition could arise and that new environmental analyses of the routes may be required, with a corresponding delay on the project’s timing. In addition, each of the 69 kV Alternatives is likely to have larger environmental justice impacts on disadvantaged communities. Finally, each of the 69 kV Alternatives would cost more, in terms of total dollars and without respect to any tariff implications, than the RTRP Hybrid Proposal. SeeSections 4.2.3.1.2.4 (Alternative A), 4.2.3.2.2.4 (Alternative B), and 4.2.3.3.2.3 (Alternative C). The cost increases identified in those 19See California Native Plant Soc. v. City of Santa Cruz, 177 Cal.App.4th 1001 (describing acceptable policy-based infeasibility determinations under CEQA).20SeeCEQA Guidelines § 15126.6(b).21Seefurther discussion of potential delay in Section 3.5. 17 sections do not reflect the potential cost increases associated with delays and new environmental and permitting processes. The increased total costs contribute to an overall finding of infeasibility based on the environmental and social considerations noted above.221.5 Interim SolutionsIn response to the ALJ’s directive, SCE and Riverside also evaluated whether various interim solutions might be available to Riverside to mitigate Riverside’s electrical system needs. With respect to the Report’s consideration of “other interim solutions,” it is uncertain and speculative when, if ever, “technological advancements in battery storage and distributed solar [would be] feasible at the project scale” allowing those options to serve as viable alternatives to the RTRP Hybrid Proposal. Seethe discussion in Section 4.3. Nonetheless, this Report explores the potential for various interim solutions to mitigate Riverside’s electrical system needs in a manner consistent with the Project Objectives. Section 4.3 contains detailed discussion of potential interim solutions.1.5.1 Minimum Interim Power NeedsThe Vista Substation source to Riverside has a loading limit of 557 MW. For planning purposes, Riverside’s total current internal generation capacity is 180 MW under a contingency condition.23Thus, Riverside’s total current capacity to serve load (internal generation plus Vista Substation transformers) is 737 MW (557 MW + 180 MW).Any interim solution providing less than 489 MW by 2023 would notconstitute an equivalent, redundant source of reliable energy in the event power from SCE’s Vista Substation was interrupted. Assuming Riverside’s internal generation capacity remained constant, this capacity is assumed equivalent to Riverside’s forecast need in 2023 (669 MW), less Riverside’s assumed internal generation capacity (180 MW), or 489 MW. If the interim solution was to remain in place until 2038, the minimum needed capacity for any interim solution is equivalent to the forecast need in 2038 (734 MW), less Riverside’s generation capacity (180 MW) under contingency conditions, or 554 MW.Based on the facts above and in order to satisfy RTRP’s Project Objective of reducing dependence on Vista Substation and increasing overall reliability, this Report assumes any given interim solution would need to supply a minimum of 489 MW of capacity by 2023, ramping up to 554 MW by 2038. Seethe discussion in Section 4.3.1.1.5.2 Reliance on Interim Solutions Cannot be Expected to Address Riverside’s Electrical Needs in lieu of the RTRP Hybrid ProposalThis Report considers the potential for various types of internal generation resources and expanded conservation to meet Riverside’s electrical needs on an interim basis. The degree to which such interim solutions might offset Riverside’s needed capacity varies with each technology. However, as summarized in this section and discussed in detail in Section 4.3, no interim solution considered could reasonably be expected to satisfy the Project Objectives to provide the capacity needed for future peak loads or increase reliability. These interim solutions would not effectively eliminate the need for a second source to reduce the dependence on Vista Substation to provide 557 MW of power 22As described in detail in Sections 4.2.3.1.2.5 and 4.2.3.2.2.5, technological considerations also support conclusions that Alternatives A and B are infeasible. 23In this context, the contingency condition refers to the outage of a single internal generating unit (48 MW) at Riverside Energy Resource Center (RERC) whether it is a scheduled or unscheduled outage under normal system conditions. The 737 MW figure also assumes availability of the RERC units (4 - 48 MW) and the Springs Generation units (4 - 9 MW) for needed operational hours. 18 to Riverside. In view of limitations on suitable sites, as well as the environmental and economic challenges presented by many of these interim solutions, Riverside considers it to be speculative to assume that such interim solutions could satisfy the Project Objectives of the RTRP Hybrid Proposal.1.5.2.1 Energy StorageInterim energy storage systems (ESS) considered for this Report include electrochemical (BES), pumped-hydro storage, and compressed-air storage.While BES could provide benefits to Riverside’s electrical system and offset some of Riverside’s demand, the deployment of batteries cannot reasonably be expected to offset 489 MW of load by 2023 for the reasons discussed in detail in Section 4.3.2.1. Primarily due to constraints related to the scale and cost of battery technology at this time, the deployment of batteries cannot reasonably be expected to offset the 489 MW of load that is needed in order to provide comparable levels of reliability to the RTRP Hybrid Proposal. Assuming that Riverside could obtain, test, install, and operationally deploy 489 MW of BES by 2023 is unrealistic when viewed in light of the significantly lower (in relative terms) procurement targets established for the California-jurisdictional electric utilities under State law. None of these utilities has been directed to obtain sufficient BES to serve an anticipated 73.1% share of its projected peak load (2023), which is what a 489 MW BES procurement target would be equivalent to with respect to Riverside. Indeed, a 489 MW procurement target of BES for Riverside would exceed the installed grid-scale BES capacity throughout the entire United States as of the first quarter of 2016.24In addition to scale, BES continues to represent an expensive technology, particularly at the quantities needed to provide a viable interim alternative solution to the RTRP Hybrid Proposal. Recently-published studies by Lazard Frères & Co. LLC reflect that the capital cost of lithium-ion energy storage ranges from $1.2 million/MW to $1.7 million/MW for the purpose of gas peaker replacement and $2.3 million/MW to $3.3 million/MW for the purpose of distribution system augmentation.25This compares to an average capital cost of $1.0 million/MW for gas peakers and a capital cost of $0.7 million/MW for the RTRP Hybrid Proposal. Although the costs for lithium-ion technology may decrease in the near term,26it is unlikely that projected cost decreases in the next five years would be adequate to render this technology economically viable as an alternative to the RTRP Hybrid Proposal.Finally, BES is incapable of providing the same reliability benefits of the Project and would not obviate the need for a second interconnection to ensure reliability. Even if the scale and cost did not render BES highly impractical, BES simply cannot perform the same functions of the RTRP Hybrid Proposal, and Riverside’s electric system would continue to be vulnerable to the loss of the Vista Substation interconnection. In addition, to accommodate charging and discharging for a large BES project, Riverside would need to plan and potentially perform upgrades to its distribution system in order to ensure that the reliability impacts would be manageable and any effects of the BES on the transmission system outside of Riverside are studied, well-understood by SCE and the CAISO, and mitigated if necessary. 24David Hart and Alfred Sarkissian, Deployment of Grid-Scale Batteries in the United States at 8 & n.8 (2016), available athttps://energy.gov/sites/prod/files/2017/01/f34/Deployment%20of%20Grid-Scale%20Batteries%20in%20the%20United%20States.pdf.25Lazard, Levelized Cost of Storage Analysis – Version 3.0 (2017) at 15, available at https://www.lazard.com/perspective/levelized-cost-of-storage-2017/.26The Lazard analysis (id.at 16) predicts a 36% decrease in lithium-ion costs over the next five years. 19 For all of the reasons summarized above and discussed in greater detail in Section 4.3.2.1, the scale, cost, and technological limitations of BES make BES infeasible as an interim alternative to the Project.271.5.2.2 Local GenerationIn order to provide 489 MW of capacity by 2023, local generation facilities in the form of additional gas-fired combustion turbines (“peakers”) or a large, utility-scale solar facility were reconsidered.28Consistent with the findings of the 2013 FEIR and for the reasons articulated in Sections 4.3.2.2 and 4.3.2.3, reliance on local generation would not be a viable interim solution to Riverside’s electrical needs in lieu of the RTRP Hybrid Proposal.1.5.2.2.1 Gas-fired Combustion TurbinesThe use of additional peakers to provide the needed electrical capacity would likely result in greater air quality impacts. For that reason, the legal feasibility of relying on additional peakers is questionable and speculative at best, in light of the strict operation permit requirements for gas-fired generation sources regulated by the South Coast Air Quality Management District (SCAQMD). Riverside Energy Resource Center (RERC) turbine starts are typically limited to no more than two per day for a total of 1,200 operating hours per year. Based on current SCAQMD regulations, it is unlikely that Riverside would be able to use additional peakers to serve 489 MW of electrical demand by 2023.Even if legally feasible, in light of the significant number of MWs required, the use of peakers as an interim solution would: (1) likely be prohibitively expensive (or at a minimum, less cost effective than the RTRP Hybrid Proposal); (2) suffer from reliability risks due to uncertainties in the availability of natural gas fuel sources; (3) require finding available land to site additional gas-firedgeneration; and (4) not represent prudent utility practice in that it would defer transformer capacity additions by continued installation of peaking units. Section 4.3.2.2 discusses these considerations in detail.1.5.2.2.2 Large, Utility-scale Solar FacilityThe use of a large scale solar facility to meet 489 MW of demand by 2023 is likely technically infeasible due to siting constraints for such facilities within or near the City of Riverside. There are currently no large-scale (defined as over 25 MW by SCE and Riverside for the purposes of this Report) solar projects within the City of Riverside. Riverside preliminarily estimates it would need at least 360 acres (approximately 6.0 acres/MW) to support even a 60 MW solar farm, including a battery electric storage system and Riverside interconnection facilities (substation and lines). A screening of contiguous, undeveloped areas, not dedicated to parks/open space within the City of Riverside, revealed that procuring an approximate 360-acre site large enough to accommodate a 60 MW solar facility is infeasible, much less 489 MW of solar capacity. While smaller scale solar facilities of less than 25 MW may be more feasible to site individually, it is unrealistic to expect that 27The other types of storage systems (pumped-hydro and compressed-air) are not technically feasible within the City of Riverside. As described in Section 4.3.2.1, geological features necessary to support these technologies do not exist within or near the City of Riverside, and large-scale pumped hydro or compressed air storage located outside of the City of Riverside likely would require a high voltage transmission line similar to what is currently proposed as part of the RTRP Hybrid Proposal in order to deliver the power.28SeeFEIR Volume 2, Section 6.4.2 at 6-27 to 6-30 (considering and dismissing new generation as a viable alternative to the RTRP as proposed). 20 Riverside can site 489 MW of such facilities in order to reliably satisfy Riverside’s electrical capacity needs. Further, as an intermittent generating resource, solar capacity would not meet the Project’s Objective to effectively reduce dependence on Vista Substation and increase reliability.Even if enough sites were available to make solar technically feasible, this interim solution would likely have more environmental impacts than the RTRP Hybrid Proposal, as it would require a larger footprint and also the acquisition and disturbance of new ROWs in support of the interconnection with the Riverside grid. It would also likely be substantially more costly than the RTRP Hybrid Proposal as discussed in Section 4.3.2.3.1.5.2.3 Distributed GenerationDistributed generation (DG) resources (e.g., fuel cells, micro turbines, photovoltaic solar, wind, landfill gas, digester gas, etc.) were also reconsidered.29Consistent with the findings of the 2013 FEIR and for the reasons articulated in Section 4.3.2.4, reliance on DG is not anticipated to be a viable interim solution to Riverside’s electrical needs in lieu of the RTRP Hybrid Proposal.A DG resource is typically less than 5.0 MW in net generating capacity, and such resources are located on distribution feeders near customer load. Riverside’s estimated current total for DG is less than 30 MW. DG capacity is typically implemented incrementally over time. There is not sufficient data to determine how many kW or MW of DG are actually provided to Riverside from DG users due to the complexity of metering between demand and energy for DG. Since 2008, Riverside has offered incentives for business and residential photovoltaic installations. To date, this program has resulted in approximately 11 MW of local solar generation; expecting that DG capacity could expand by 489 MW by 2023 would be unrealistic. DG resources also typically have a relatively small capacity compared to the cost.Given the small scale of DG resources and the limited penetration of such resources in the Riversidesystem to date, reliance on DG could not timely offset the need for 489 MW of additional capacity by 2023 to the Riverside system in order to satisfy the reliability goals of the RTRP Hybrid Proposal. Further, an interim DG solution would not satisfy the Project goals of providing an additional point of delivery for bulk power into the Riverside electrical system and would not split and upgrade the sub-transmission electrical system.1.5.2.4 Conservation/Demand Response ProgramsEnergy Conservation and Load Management measures were also reconsidered.30Consistent with the findings of the 2013 FEIR and for the reasons articulated in Section 4.3.2.5, reliance on energy conservation and load management would not be a viable interim solution to Riverside’s electrical needs in lieu of the RTRP Hybrid Proposal.Riverside offers a variety of “demand-side management” programs and incentives, including programs encouraging energy efficiency, demand response, and DG. In Riverside’s service territory, annual increases in load growth have exceeded the reductions in energy consumption from energy efficiency programs resulting in annual net increases in electrical demand. As noted in Section 3.4.2.3, Riverside’s load forecasts already incorporate the observed impacts of Riverside’s load 29SeeFEIR Volume 2, Section 6.4.2 at 6-30 to 6-31 (considering and dismissing DG as a viable alternative to RTRP as proposed).30SeeFEIR Volume 2, Section 6.4.2 at 6-31 (considering and dismissing energy conservation and load management as a viable alternative to RTRP as proposed). 21 reduction programs, and expecting such programs to achieve an incremental reduction of 489 MW more (or 77% of Riverside’s most recent peak demand (639 MW)) would be unrealistic.1.6 ConclusionFor the reasons summarized above and as set forth in detail below, there are no feasible lower voltage design alternatives to meet the Project Objectives, and there are no interim solutions available to Riverside to mitigate its needs for the RTRP Hybrid Proposal. The RTRP Hybrid Proposal is environmentally superior and more cost-effective than the lower voltage Alternatives and interim solutions, and it has been designed to address and resolve identified reliability needs of the Riverside electric system. Those needs were identified more than ten years ago, and they continue to exist today. The lower voltage Alternatives and interim measures do not reliably address Riverside’s system needs and are inferior to the RTRP Hybrid Proposal. 22 THIS PAGE INTENTIONALLY LEFT BLANK
23 2. Introduction and Background2.1 Brief History of the RTRP and the RTRP Hybrid ProposalIn June 2006, CAISO determined the need for the RTRP as a necessary addition to the CAISO Controlled Grid to meet the needs for reliable service to the City of Riverside and directed its construction. Shortly thereafter, Riverside began the development of the EIR for the RTRP. Riversideissued a public Notice of Preparation (NOP) of the project EIR in January 2007 and later circulated a revised NOP in November 2009. The City of Riverside’s Draft EIR was circulated in August 2011. During 2013, the City of Jurupa Valley approved new development projects in the RTRP alignment. The RTRP Final Environmental Impact Report (FEIR), including SCE’s proposed 230 kV transmission line and Wildlife Substation,was certified on February 5, 2013. CEQA litigation ensued beginning with a March 2013 lawsuit by the City of Jurupa Valley. Jurupa Valley’s Petition seeking to overturn Riverside’s approval of RTRP and certification of the FEIR was denied by the Los Angeles County Superior Court in 2014.31Thereafter, the California Court of Appeals affirmed that denial,32and the California Supreme Court likewise denied a petition filed by Jurupa Valley.In April 2015, SCE filed Application No. 15-04-013 for a CPCN to construct the RTRP designated as the environmentally superior alternative in the FEIR and previously approved by Riverside. In May 2015, the CPUC found under CEQA that the Riverbend and Vernola Apartment Community projects approved by Jurupa Valley constituted “changed circumstances” warranting a subsequent CEQA review of the project. During the third quarter of 2016, SCE reached settlement agreements with two developers resulting in proposed modifications to the RTRP to resolve concerns relating to the new residential developments. SCE subsequently submitted CPCN application revisions to the CPUC (in September 2016) to include the new alignment and underground segments proposed to address the Riverbend and Vernola Apartment Community concerns. A key change was the inclusion of approximately two miles of underground transmission as SCE’s preferred alternative in lieu of the originally proposed 230 kV project. The modified 230 kV transmission line, which includes both overhead and underground design, is referred to as the RTRP Hybrid Proposal.SCE’s CPCN application was deemed complete by the CPUC in January 2017. The CPUC also issued a NOP to inform the public that it would be completing a Subsequent EIR (SEIR) to analyze the environmental impacts of the RTRP based on the RTRP Hybrid Proposal.2.2 ALJ RulingOn August 15, 2017, ALJ Yacknin issued the Ruling. In relevant part, the Ruling directed:Southern California Edison Company (“SCE”), RPU and CAISO to meet and confer and prepare a joint report
identifying lower voltage designs or other interim design remedies to the proposed project. The report shall address the following:31City of Jurupa Valley v. City of Riverside(Super. Ct. Los Angeles County, 2014, No. BS140385).32City of Jurupa Valley v. City of Riverside(Nov. 12, 2015, B257623)[nonpub. opn.]. 24 Identification of a lower voltage design alternative(s) to meet the projectobjectives, either in full or in part, including the following details:a. locations of substation connection points between SCE and RPU;b. locations and routing of existing overhead and underground distribution corridors that would be utilized;c. locations and dimensions of any required new overhead or underground ROW;d. description of how MW targets would be achieved and from which sources;e. cost comparison to the proposed project;f. Any other pertinent design assumptions or considerations.g. If lower voltage design alternatives are found to be infeasible, explain in detail the basis for the infeasibility [.]Identification of any other interim solutions available to RPU that would mitigate the electrical system impacts until technological advancements in battery storage and distributed solar are feasible at the project scale.In response to the ALJ’s Ruling, Riverside and SCE developed this joint Report with advice and guidance from CAISO. 25 3. RTRP Project Objectives and Principles and Methodology for Consideration of Alternatives Section 3 describes factors and considerations affecting the selection, development, and evaluation of the lower voltage Alternatives explored in this Report. 3.1 RTRP Project Objectives, Purpose and NeedThe full description of the purpose and need for the RTRP is included in the 2013 FEIR. For purposes of reference and identification of lower voltage alternatives as directed by the ALJ, this Report includes a summary of the RTRP purpose and need. The purpose of the RTRP Hybrid Proposal is to provide Riverside with adequate capacity to serve existing load, to provide for long-term system capacity for load growth, and to provide needed system reliability. The rapid population growth and commercial development in Riverside have led to an increase in local electric customers and in their use of electric energy. Currently, the sole source of bulk electrical energy for Riverside electric customers is through SCE’s Vista Substation, located within the City of Grand Terrace. As discussed in detail in Section 3.4.2.3, Riverside’s electrical demand routinely exceeds the available 557 megawatts (MW) of capacity from Vista Substation, and Riverside forecasts a peak demand growth rate of approximately 0.5% per year for the next 20 years. It is normal utility practice to have alternate sources of supply at various points in the electric system. A new interconnection to SCE’s transmission system is urgently needed to provide capacity for Riverside’s existing as well as new electrical load and an additional point of interconnection for reliability purposes. Without this addition, load shedding and area electrical blackouts would eventually be required.33In addition, reinforcement is urgently needed to the existing 69 kilovolt (kV) subtransmission system to meet standard reliability criteria. Without reinforcements, load shedding may occur following unplanned 69 kV line outages during peak load conditions. The Board of Governors of the CAISO, which operates California’s power transmission system, recognized the need for another interconnection point in Riverside’s system in 2006 and directed SCE and Riversideto pursue the RTRP.The following Project Objectives from the 2013 FEIR were developed in support of the RTRP Purpose and Need which guided the development and evaluation of alternatives considered in the 2013 FEIR:Provide sufficient capacity, in a timely manner, to meet existing electric system demand and anticipated future load growth.Provide an additional point of delivery for bulk power into the Riverside electrical system, thereby reducing dependence on Vista Substation and increasing overall reliability.Split and upgrade the subtransmission electrical system as a function of prudent utility practice.34Meet Proposed Project need while minimizing environmental impacts.Meet Proposed Project need in a cost-effective manner.33Load shedding is the intentional, controlled interruption of electrical load. It is performed by system operators, such as CAISO, or by automatic equipment, in order to protect the electric system from excessive loss-of-life of electrical equipment or from permanent damage, such as from an overload.34The RTRP Hybrid Proposal and the three 69 kV Alternatives studied in this Report all would split the Riverside electrical system. This Project Objective, therefore, does not provide any basis on which to compare the Alternatives and is not discussed at length herein. 26 These Project Objectives guide the CPUC’s development of a range of reasonable alternatives to the RTRP Hybrid Proposal. As described in Section 3.2.2, alternatives are eliminated from further consideration when they fail to meet most of the basic Project Objectives, are infeasible, and/or would not avoid significant environmental impacts. Alternatives considered and eliminated for the RTRP in the 2013 FEIR and as part of the evaluation in this Report of potential alternatives to the RTRP Hybrid Proposal or interim solutions to address Riverside’s system needs are identified and documented in Sections 4.1 and 4.3. The potentially feasible lower voltage Alternatives to the RTRP Hybrid Proposal are described in Section 4.2. As explained in Section 5, this Report concludes that the environmentally superior alternative to meet Project Objectives is the 230 kV RTRP Hybrid Proposal.3.2 Principles for Consideration of Alternatives The CPUC’s consideration of potential alternatives in reviewing SCE’s RTRP licensing applications is generally governed by the CPUC’s General Order (GO) 131-D, CEQA, and the California Public Utilities Code.3.2.1 CPUC’s GO 131-D Requires Consideration of CEQAGO 131-D was adopted to be responsive to the requirements of CEQA.35Specifically, GO 131-Drequires the preparation of a Proponent’s Environmental Assessment (PEA) or equivalent information regarding the environmental impacts associated with a proposed project under the CPUC’s jurisdiction, including an exploration of feasible project alternatives that may decrease significant environmental impacts.36The 2013 FEIR was submitted in support of RTRP’s CPCN application as information equivalent to a PEA.CEQA Requires Consideration of a “Reasonable Range” of “Feasible” AlternativesThe CEQA Guidelines emphasize the selection of a “reasonable range” of alternatives in an EIR “which would feasibly attain most of the basic objectives of the project but would avoid or substantially lessen any of the significant effects of the project, and evaluate the comparative merits of the alternatives.”37“Because an EIR must identify ways to mitigate or avoid the significant effects that a project may have on the environment (Public Resources Code Section 21002.1), the discussion of alternatives shall focus on alternatives to the project or its location which are capable of avoiding or substantially lessening any significant effects of the project, even if these alternatives would impede to some degree the attainment of the project objectives, or would be more costly.”38Importantly however, an “EIR need not consider every conceivable alternative to a project. Rather it must consider a reasonable range of potentially feasible alternatives that will foster informed decision making and public participation.”39Thus the “range of alternatives required in an EIR is governed by 35SeeGO 131-D § II (GO 131-D responsive to CEQA’s requirements).36SeeGO 131-D §§ IX.A.1 h. (environmental impact document(s) required in support of CPCN), IX.B.1.e. (environmental impact document(s) required in support of a Permit to Construct); CEQA Guidelines § 15126.6(Consideration and Discussion of Alternatives to the Proposed Project).37CEQA Guidelines §§ 15126.6(a) (Alternatives to the Proposed Project), (f) (Rule of Reason);see alsoCEQA Guidelines § 15124(b) (clear statement of objectives aids in developing alternatives).38CEQA Guidelines § 15126.6(b) (Purpose). 39CEQA Guidelines §§ 15126.6(a) (Alternatives to the Proposed Project), (f) (Rule of Reason). 27 a ‘rule of reason’ that requires the EIR to set forth only those alternatives necessary to permit a reasoned choice.”40“An EIR need not consider an alternative whose effects cannot be reasonably ascertained and whose implementation is remote and speculative.”41Of those alternatives that would avoid or substantially lessen any of the significant effects of the project, “the EIR need examine in detail only the ones that the lead agency determines could feasibly attain most of the basic objectives of the project.”42Under CEQA, “feasible” means “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, social, and technological factors, or “other considerations” including “policy considerations,” which may permit the rejection of mitigation or alternatives that are “impractical or undesirable from a policy standpoint.”43“Among the factors that may be taken into account when addressing the feasibility of alternatives are site suitability, economic viability, availability of infrastructure, general plan consistency, other plans or regulatory limitations, jurisdictional boundaries (projects with a regionally significant impact should consider the regional context), and whether the proponent can reasonably acquire, control or otherwise have access to the alternative site (or the site is already owned by the proponent).”44Therefore, consistent with CEQA’s guidance regarding the selection and evaluation of alternatives, each of the new, lower voltage Alternatives described in Section 4.2.3 below has been evaluated using three inquiries:(1) Does the Alternative avoid or substantially lessen any significant effects of the Proposed Project, including consideration of whether the Alternative itself could create significant effects potentially greater than those of the Proposed Project?A key CEQA requirement for an alternative is that it must have the potential to “avoid or substantially lessen any of the significant effects of the project.”45If an alternative is identified that does not have the potential to provide an overall environmental advantage as compared to the proposed project, it is typically eliminated from further consideration.For the purposes of this Report, it is not possible to evaluate all of the impacts of the Alternatives in comparison to the RTRP Hybrid Proposal with absolute certainty or specifically quantify impacts. However, it is possible to identify elements of an Alternative that are likely to be the sources of impact and to relate them, to the extent possible, to general conditions in the subject area.40CEQA Guidelines § 15126.6(f) (Rule of Reason). 41CEQA Guidelines § 15126.6(f)(3). 42CEQA Guidelines § 15126.6(f) (Rule of Reason). 43Pub. Resources Code §§ 21061.1 (defining “feasible”), 21081 (no public agency shall approve a project with significant and unavoidable environmental impacts unless the public agency finds “specific economic, legal, social, technological, or other considerations make infeasible the mitigation measures or alternatives identified in the environmental impact report” and “that specific overriding economic, legal, social, technological, or other benefits of the project outweigh the significant effects on the environment”); California Native Plant Soc. v. City of Santa Cruz, 177 Cal.App.4th 1001 (policy-based infeasibility determinations under CEQA permissible);see alsoCEQA Guidelines §§ 15021(b) (“In deciding whether changes in a project are feasible, an agency may consider specific economic, environmental, legal, social, and technological factors”), 15364 (same).44CEQA Guidelines § 15126.6(f)(1). 45CEQA Guidelines §§ 15126.6(a) (Alternatives to the Proposed Project), (f) (Rule of Reason). 28 (2) Does the Alternative accomplish all or most of the basic Project Objectives?The EIR need examine in detail only the alternatives the lead agency determines could attain most of the basic Project Objectives.46The Project Objectives of the RTRP Hybrid Proposal are described in Section 3.1 above.(3) Is the Alternative feasible?Under CEQA, “feasibility” means “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors,” or “other considerations” including “policy considerations.”47The approach to each of these questions in evaluating the potential lower voltage Alternatives studied in this Report is described in more detail in Section 4.3.2.2 Other Considerations for AlternativesThe CPUC’s final decision on the project will also be guided by the California Public Utilities Code (PUC) in addition to the requirements of CEQA. Specifically, PUC Section 1002 states, in relevant part The commission, as a basis for granting any certificate pursuant to Section 1001 shall give consideration to the following factors: (1) Community values. (2) Recreational and park areas. (3) Historical and aesthetic values. (4) Influence on environment, The discussion of the potential lower voltage Alternatives studied for this Report seeks to aid the CPUC’s consideration of “community values” in the RTRP proceeding, foster informed decision-making and a reasoned choice by the CPUC, and also aid in the development of responses to comments on the SEIR. Supported by this Report and others, the final CPCN decision on the RTRP Hybrid Proposal will represent a balancing of the communities’ interests, the need to protect environmental resources in the area, and the need for the RTRP.3.3 Alternatives Development in the 2013 FEIRThe RTRP Project Objectives listed in Section 3.1 guided the development of a range of reasonable alternatives to the RTRP or to the location of the RTRP that were evaluated in the 2013 FEIR. A number of alternatives were considered and either eliminated or kept for detailed analysis within the 2013 FEIR. Alternatives were eliminated from further consideration when they failed to meet most of the basic Project Objectives, were infeasible, or would not avoid significant environmental impacts. The reasonable routing and siting alternatives included in the 2013 FEIR for the RTRP 230 kV transmission line, 69 kV subtransmission lines, and substation sites were identified through an environmental analysis process that sought to avoid or substantially reduce any potentially significant effects of the RTRP, while satisfying the Project Objectives. Alternatives considered and eliminated from consideration for the RTRP were also identified and documented in Chapter 6 (Section 6.4, Volume 2) of the 2013 FEIR. 46CEQA Guidelines § 15126.6(f)(Rule of Reason). 47Pub. Resources Code §§ 21061.1 (defining “feasible”), 21081; California Native Plant Soc. v. City of Santa Cruz, 177 Cal.App.4th 1001;see alsoCEQA Guidelines §§ 15021(b), 15364. 29 A broad range of alternatives were evaluated for the RTRP in accordance with CEQA Guidelines §15126.6(c). The 2013 FEIR, which was upheld by both superior and appellate courts,48included an evaluation of the alternatives that were considered but rejected as infeasible for constructability, operational, or environmental impact, or other reasons. Below is a list of the alternatives considered and eliminated within the 2013 FEIR.Other VoltagesSubtransmission/Transmissiono69 kVo115 kVo500 kVNon-Wire AlternativesNew GenerationDistributed GenerationEnergy Conservation and Load ManagementAlternative TechnologiesUnderground entire 230 kV High-Voltage Transmission LineUnderground all 69 kV Subtransmission LinesDirect Current TransmissionAlternative ConductorsSiting and Routing Alternatives230 kV Transmission Line RoutesoLimonite RouteoBain Street RouteoEastern Route(s)230 kV Substation SitesoExpand SCE’s Vista SubstationoExpand SCE’s Mira Loma SubstationoExpand Riverside’s RERC SubstationoExpand Riverside’s Mountain View Substation69 kV Subtransmission Line Routes69 kV Substation Sites48Trial court:City of Jurupa Valley v. City of Riverside(Super. Ct. Los Angeles County, 2014, No. BS140385).Court of Appeals:City of Jurupa Valley v. City of Riverside(Nov. 12, 2015, B257623) [nonpub. opn.] 30 The 2013 FEIR applied CEQA Guidelines §15126.6(c) to guide the identification and selection of alternatives for the RTRP including those alternatives that may be eliminated from detailed consideration. The three general elimination criteria that were considered when evaluating the alternatives included (i) alternatives that would fail to meet most of the basic Project Objectives, (ii) alternatives that were determined to be infeasible, and (iii) alternatives that would not avoid significant environmental impacts.3.4 Methodology for Analysis and Evaluation of Alternatives Studied in This Report3.4.1 Identification of Alternatives to be StudiedConsistent with the regulatory standards described in Section 3.2, SCE and Riverside sought to identify lower voltage alternatives that would avoid or substantially reduce environmental impacts that would result from the RTRP Hybrid Project while meeting most or all of the Project Objectivesin a timely and cost-effective manner. The analysis identified potential lower voltage designs sourced from SCE substations (or in one Alternative a proposed substation) located closest to the Riversidegrid, expecting that this approach would be most likely to minimize both environmental impacts and costs of Alternatives considered. SCE and Riverside identified potential routes and developed preliminary facilities designs and cost estimates for three 69 kV Alternatives. Following the preliminary but detailed scoping of the three Alternatives, SCE and Riverside evaluated each potential Alternative using the following three inquiries:1. Does the Alternative avoid or substantially lessen any significant effects of the RTRP Hybrid Proposal, including consideration of whether the Alternative itself could create significant effects potentially greater than those of the RTRP Hybrid Proposal?2. Does the Alternative accomplish all or most of the basic Project Objectives?3. Is the Alternative feasible?SCE and Riverside also reconsidered some of the alternatives that had been evaluated and rejected in the 2013 FEIR, including a potential 115 kV alternative. 3.4.2 Technical ConsiderationsThe technical considerations discussed within this section were used for the development and evaluation of the lower voltage Alternatives studied in this Report. 3.4.2.1 Vista Substation and Riverside GenerationSCE’s existing Vista Substation is Riverside’s only source of power from the CAISO-controlled bulk electric system. The only other major source that Riverside uses to supplement the power delivered by SCE through the Vista Substation is the RERC gas-fired generation units, which are operated as peaking units. Vista Substation serves Riverside by way of two 280 MW transformers and seven dedicated 69 kV lines and cannot be expanded due to design limitations, space and construction constraints at the Substation. The service coming from Vista Substation is rated at a maximum capacity of 557 MW. When Riverside’s load approaches 480 MW, Riverside’s RERC generation units are brought on-line as needed. There are four gas-fired turbines at RERC, and each unit is rated at 48 MW (for a total of 192 MW). In addition there are four 9 MW units (36 MW) at Riverside’s Springs Generating plant (Springs) that are rarely dispatched due to start-up limitations.49Riverside’s 49Springs Generation capacity contributions were not included in the FEIR as discussed in FEIR Volume 2, Section 1.5.2. However, these units are included in this Report, because Springs generation is available now and should be included as part of the interim solutions. Springs generation is also included in the long term solutions to maintain consistency throughout this Report. Finally, including the Springs generation provides more 31 internal generating units are brought on-line as needed to support Riverside’s load requirements during extreme weather conditions to provide additional capacity and to prevent overload conditions on the lines and transformers, as well as for other contingencies such as unplanned equipment,transformer, and/or line outages contingencies.While these generation resources reduce the amount of power that must flow through the transformers at Vista Substation to Riverside by generating and supplying it locally, they are “peaker” units. The number of hours the RERC units can operate is limited by the permit requirements issued by the SCAQMD – 1,200 hours per year and no more than two starts per day. These units are typically run less than four hours per day. The Springs generating units also are subject to start-up and use restrictions. SeeSection 4.3 for additional information on gas-fired generation.3.4.2.2 The RTRP and the RTRP Hybrid ProposalThe RTRP was determined by SCE, Riverside, and the CAISO to be the preferred approach for providing Riverside with the additional required capacity and a second and independent point of service that would deliver the capacity and reliability needed to meet the electrical demands and load growth projected for Riverside.The RTRP Hybrid Proposal is currently designed to serve load by looping through the proposed Wildlife Substation (providing two line service) with a double-circuit 230 kV transmission line. The RTRP Hybrid Proposal double-circuit 230 kV transmission line, as designed, has a normal-condition rating of 916 MW and an emergency-condition rating of 1,239 MW. The RTRP Hybrid Proposal is designed to have the capacity to provide for the future expansion of both the Wildlife and Wilderness Substations. Two 280 MW 230/69 kV transformers, such as those installed at Vista Substation, would be part of the RTRP Hybrid Proposal and would approximately double the power that could besupplied to Riverside. The RTRP Hybrid Proposal would provide full redundancy during an unplanned outage of Vista Substation and would meet the Purpose and Need as defined in the 2013 FEIR. 3.4.2.3 Riverside System Growth and Load ForecastsSCE currently has a loading limit of 557 MW it can provide to Riverside through Vista Substation, the sole point of interconnection between the Riverside and CAISO/SCE grids. This load limit is now routinely exceeded during peak demand periods. For example, in late August 2017, a six day heat wave produced consecutive day maximum temperatures in excess of 105F in the Riverside service area resulting in a new Riverside peak load of 639 MW.50Riverside’s peak loads are expected to continue to increase at approximately 0.5 percent per year for the next 20 years, driven primarily by continued load growth in the Commercial and Industrial customer classes. Additionally, the City’s population continues to increase at approximately 1.0 percent per year, in turn driving new housing developments and supporting commercial services. On October 10, 2017, Riverside submitted its 10-year forward system load and 1-in-2 peak forecasts to the CAISO in satisfaction of CAISO Tariff Sections 4.9.5.3 and 4.9.10.1.51The Power Resources conservatism to the Report. Importantly, the inclusion or exclusion of the 36 MW of Springs generation does not alter the conclusions of either the FEIR or this Report.50A historical assessment of this heatwave suggests that this consecutive day maximum temperature trend approximately corresponded to a 1-in-20 temperature event.51The forecasted loads in the October 2017 forecasts are less than projected loads included in the 2013 FEIR due to economic changes since 2006 when the 2013 FEIR loads were projected.

34 Other overhead considerations include the location of the poles along the streets. Decisions would have to be made as to whether the poles should be in public ROW or on private lands or a combination of both to minimize the impact the pole locations would have on public and private facilities.

FIGURE 3 TYPICAL 69 KV TANGENT STEEL STRUCTURES VS 230 KV STRUCTURESAnother design challenge is transferring existing services from the existing overhead lines to the new structures. If the new 69 kV overhead line is on the opposite side of street from the existing distribution, and the existing distribution is transferred to the new lines, the service drops to the facilities (businesses, houses, etc.) would have to be extended across the street. The other alternative is to leave the distribution, but this would require distribution poles and lines on one side of the street and the new double-circuit 69 kV line on the other side. Installing above-ground facilities on both sides of a right-of-way is contrary to CPUC General Order 95 (para. 31.3) and SCE’s design standards and normal practice. If the new double-circuit 69 kV lines could be built on or near thecenterline of existing overhead distribution facilities, then the work to transfer the distribution and communications would be complex, but would not result in conflicting/parallel lines on the streets. 3.4.2.4.2 UndergroundThe underground segments would consist of two underground 69 kV circuits encased in a concrete duct bank. There would be six 5.0-inch conduits with a 4/0 bare copper ground.SeeFigure 4. This concrete duct bank would be approximately two feet wide and two feet deep and buried at least three feet deep from ground line to the top of the duct bank. The trench depth for installation would vary depending on obstructions that would have to be avoided such as other buried electrical lines, storm water lines, sewer lines, water lines, gas lines, communication circuits and other facilities. There may be a requirement to split the circuits to avoid a conflict, and this would have to be addressed in the final design phase of any Alternative.

35 FIGURE 4 TYPICAL 69 KV DUCT BANKRiser poles would be necessary to transition the conductors/cables from overhead to underground. These riser poles will be double-circuit steel structures placed on anchor bolt foundations. There would be six steel arms supporting the cables, terminations, and lightning arresters. Cables could be placed outside or inside the steel structures.It is assumed that the existing distribution facilities would not materially change in the selected underground segments and would not be included in the new underground 69 kV system.3.4.2.5 Overhead and Underground ROW and Structures RequirementsSCE would acquire ROWs for the 69 kV routes evaluated with easement widths of 30 feet for underground and overhead easements. SCE’s estimated costs reflect the assumption of ROW acquisition for all parcels crossed, minus the number located in franchise, as shown in Table 3 below. Final engineering design would determine the exact number of private parcels versus franchise, and the cost of acquisition would change in accordance with the parcel count. The numbers of structures required for the overhead lines are estimated below. The assumption used for an average span length between structures is 200 feet based on SCE’s and Riverside’s experience installing 69 kV lines in their respective service areas. This span length was divided into the mileage for each of the routes studied to estimate the total structures for each overhead route. Spans will vary considerably following completion of design depending on any number of factors such as pole loading, clearance issues, obstructions in the ROW (above ground and below ground), and provisions for distribution and communications service. The structure totals for the RTRP Hybrid Proposal (based on actual preliminary design) and the 69 kV Alternatives studied are as follows:RTRP Hybrid Proposal (9.7 Miles) 63 (47 Steel Poles, 12 Lattice Towers, 4 Riser Poles)

37 3.5 Timing and Permitting Considerations and Reliability Impacts of Potential Delays in Meeting Project ObjectivesThe need to address the reliability concerns arising from Riverside’s reliance on the Vista Substation as promptly as possible is urgent. SCE currently has two transformers, each nominally rated at 280 MW for a maximum 557 MW transfer limit under normal operating conditions it can provide to Riverside through Vista Substation, the sole point of interconnection between the Riverside and SCE/CAISO grids. Whenever this loading limit is approached under normal operating conditions,Riverside’s internal gas-fired generation must be operated to ensure that the Vista Substation loading does not exceed 557 MW.53This load limit has been routinely exceeded during peak demand periods in the past nine years and with increasing frequency. For example, the numbers of hours that Riverside’s load exceeded 557 MW in 2015, 2016 and 2017 are 9, 18 and 48 hours, respectively. This year, a six-day heat wave in late August settled in over the Riverside service territory producing consecutive day maximum temperatures in excess of 105 degrees Fahrenheit (°F) and culminating in a new Riverside peak load of 639 MW. On October 10, 2017, Riverside submitted its 10-year forward system load and 1-in-2 peak forecasts to the CAISO in satisfaction of CAISO Tariff Sections 4.9.5.3 and 4.9.10.1. Riverside is forecasting a 591.5 MW 1-in-2 peak for 2018, assuming typical summer temperature conditions. Riverside also calculates peak forecasts for more extreme temperature conditions, such as 1-in-10, 1-in-20, and 1-in-40 peak loads, which are 642.4, 656.8 and 669.3 MW, respectively, for 2018.54As Riverside’s load is forecasted to continue to grow, it is expected that Riverside’s internal generation will be increasingly called upon to mitigate the Vista transfer limit issue. As explained in the footnote below, the use of Riverside’s internal generation for this purpose faces an uncertain future.The reliability problem associated with the inadequate Vista Substation transfer limit is further exacerbated if there is a contingency at Vista Substation,e.g.an outage of one or both transformers at Vista. The Vista Substation transfer limit is reduced to 280 MW if one transformer is out at Vista Substation; when added to Riverside’s internal generation of 228 MW (assuming all generation is indeed available), the maximum load-serving capability for Riverside under this contingency condition is reduced to 508 MW. Thus, absent any other mitigating measure,55involuntary load shedding is highly likely when Riverside’s load exceeds 508 MW under this contingency condition at Vista Substation. The numbers of hours that Riverside’s load exceeded 508 MW in 2015, 2016 and 2017 are 55, 92 and 143 hours, respectively. If this contingency condition at Vista Substation had occurred at the time of Riverside’s peak load, the resulting load shedding in 2015, 2016 and 2017 as 53In the past 15 years, Riverside has built 228 MW of gas-fired generation (Peakers) within Riverside, primarily in recognition of the Vista Substation transfer limitation and in order to ensure reliability of electric service to Riverside’s customers is maintained until the permanent solution in RTRP is put in place. The use of Riverside’s gas-fired generation for this purpose faces an increasingly uncertain future due to: (a) some of this generation is older and requires frequent maintenance overhauls, and spare parts are increasingly difficult to replace; (b) given the Aliso Canyon natural gas storage issues, the supply of natural gas is not assured, especially during the summer peak season, and (c) increasingly stringent air regulations and legislative mandates are likely to limit electric generation using fossil fuel. 54Riverside’s planning forecasts take into account Riverside’s load reduction programs, such as conservation programs and local renewable resources (as well as anticipated load increases associated with expansion of electric vehicle charging), but even considering the load reduction programs, Riverside is still forecasting a peak demand growth rate of approximately 0.5% per year for the next 20 years.55Currently, SCE has operating procedures that deal with the condition of one transformer outage at Vista Substation. Under certain conditions, involuntary load shedding (shared between Riverside and SCE) is required if one Vista transformer is out to maintain the integrity of Vista Substation electric equipment. 38 percentages of Riverside’s peak load could have been 13.16%, 15.19% and 20.50%, respectively.56As Riverside’s load is forecasted to continue to grow, the threat of involuntary load shedding of Riverside’s customers due to the inadequate Vista Substation transfer limit will continue to grow.Although there is currently no analysis as to the likelihood of a total collapse of Vista Substation ,i.e.both transformers serving Riverside are simultaneously out of service at Vista Substation, it sufficesto say that if a total collapse of Vista Substation were to occur (for example, due to a severe earthquake, cyber or terrorist attack, vandalism, fire or some other means), it would cause an unprecedented calamity to Riverside’s customers and SCE’s customers served from Vista Substation.Adoption of any of the 69 kV Alternatives or any of the interim solutions evaluated inevitably would delay effective mitigation of the reliability issues arising from Riverside’s dependence on Vista Substation and prolong exposure of an increasing number of Riverside’s customers to risks of extended outages. Implementation or selection of any of the 69 kV Alternatives for the RTRP Hybrid Proposal could alter the required permitting and licensing process currently underway. SCE and Riverside estimate that delays associated with implementation of any of the 69 kV Alternatives could range from a minimum of 12 to 18 months to five years or more, depending on various factors, an unacceptably long period of time given the increasingly escalating exposures to reliability risks that Riverside will continue to face. Every attempt should be made to conclude SCE’s current CPCN application and the development of the SEIR in an expedited fashion to concretely address the reliability issues caused by the inadequate Vista transfer limit.Many of the corridors identified for routes under the 69 kV Alternatives have not been reviewed in detail as part of the 2013 FEIR process, and baseline data collection and impact evaluation may be required along two or three additional line routes. For example, all three Alternatives would be constructed on lands that have the potential to support sensitive biological resources that are regulated through the Western Riverside County Multiple Species Habitat Conservation Plan (MSHCP), and consultations with the Regional Conservation Authority and a MSHCP Consistency Analysis Report are likely required. Due to the number of crossings of the Santa Ana River, a MSHCP Determination of Biologically Equivalent or Superior Preservation (DBESP) may be required. Potential impacts to federally listed species within San Bernardino County would require surveys and consultations with U.S. Fish and Wildlife Service (USFWS) under Section 10 of the Endangered Species Act. A Habitat Conservation Plan (HCP) under section 10(a)(1)(B) of the Endangered Species Act may be implemented, since there is no federal nexus. Impacts to State listed species may require consultations with the California Department of Fish and Wildlife (CDFW), and an Incidental Take Permit (Section 2081 subdivision (b) of the Fish and Game Code) may be required. All of the Alternatives would potentially require mitigation fees associated with impacts to vernal pool wetlands, small mammals, and habitat loss for burrowing owls around the Mira Loma Substation. Several of the corridors identified in the Alternatives may result in impacts to water resources that could require authorization under the Clean Water Act (CWA) Section 404, a CWA 401 Water Quality Certification, a Waste Discharge Requirement and/or a Streambed Alteration Agreement. Cultural resources within the routes for the Alternatives that are protected by federal and State laws if they have some level of significance under the criteria of the National Register of Historic Places may also require surveys and consultations with the State Historic Preservation Officer. Environmental surveys (i.e.,biological, water, cultural), if required by the regulatory agencies, could result in 56Riverside’s system peaks in 2015, 2016 and 2017 were 585 MW, 599 MW and 639 MW, respectively. The resulting load shedding as percentages of peak load could have been: (585-508)/585=13.16% for 2015, (599-508)/599=15.19% for 2016 and (639-508)/639=20.50% for 2017. 39 upwards of three years of surveys based on protocols required. The surveys would then be used to complete the consultations with the regulatory agencies discussed above.In addition, the current infrastructure of Riverside’s distribution system is not expandable to accommodate multiple additional 69 kV connections at its existing substations. Detailed studies such as power flow analyses, relay protection and coordination, short-circuit duty, grounding, charging current, and extension of the synchronous optical network (SONET) to SCE substations remain to be analyzed contingent upon further consideration of any of the lower voltage Alternatives. Studies would also need to be performed to adequately evaluate revised system performance and whether any system upgrades (including line additions, substation upgrades and reconfigurations, addition of a new 69 kV switching station, reactive compensation support devices, etc.) would be triggered. This may cause additional project approvals and implementation delays, increasing the risk of failing to meet the reliability Project Objectives of the RTRP Hybrid Proposal and additional costs related to any new sites for improvements.Delays associated with the potential incremental regulatory requirements summarized above would place Riverside’s customers at prolonged risk of experiencing outages due to the single source arrangement existing at Vista Substation, Riverside’s load currently exceeding SCE’s available capacity at the Vista Substation, and the projected load growth as stated in the purpose and need statement (2013 FEIR). In addition, the potential incremental regulatory requirements and associated delays would add significant costs. This would be in addition to the higher cost estimates for the 69 kV Alternatives (seeTables 6, 9, and 12) and the costs already incurred as part of the RTRP CEQA environmental review and CPCN licensing process3.6 Potential Tariff Implications Relating to Low Voltage AlternativesIn 2002, SCE informed Riverside that its system peak loads were rapidly approaching the limits of delivery capacity at SCE’s Vista Substation. Riverside requested SCE to either increase the capacity of the Vista Substation or establish a second point of interconnection to the CAISO grid in order to accommodate and reliably serve Riverside’s anticipated load growth. In late 2004, and based on its analyses of reliability considerations, Riverside submitted to SCE an application for the RTRP to establish a second point of interconnection at 230 kV as the design best suited to provide reliable service to Riverside. In June 2006, CAISO approved the RTRP as “a necessary and cost effective addition to the ISO Controlled Grid” and directed SCE “to complete the construction of the [RTRP] as soon as possible and preferably no later than Q2, 2009.”57In 2009, FERC approved the TO Tariff Interconnection Agreement between SCE and Riverside governing the terms of development and construction of RTRP.58FERC regulates, among other things, the interstate transmission of electricity and the CAISO. In turn, the CAISO operates the transmission systems within its jurisdiction, and the owners of those transmission systems are subject to the CAISO’s tariff.Per the CAISO Tariff and relevant in the case of the RTRP Hybrid Proposal, the costs of High Voltage Transmission Facilities (200 kV or greater) under CAISO’s “Operational Control” are recovered via the HVAC regardless of ownership. In general, each Participating Transmission Owner57SeeGeneral Session Minutes – Operations Committee Meeting, Cal. Indep. Sys. Operator Corp. (June 16, 2006) at 4.58S. Cal. Edison Co., 127 FERC ¶ 61,211 (2009) (letter order approving Settlement Agreement reflecting Amended Interconnection Facilities Agreement). 40 (PTO) is allowed to recover and pays a share of the HVAC proportional to its MWh of retail load. Both SCE and Riverside pay for the costs of the HVAC in proportion to their loads, as do all other Load Serving Entities that use the high voltage CAISO-controlled grid. Thus, under the currently-effective HVAC design, all users of the high voltage CAISO-controlled grid would share the costs for the RTRP Hybrid Proposal in proportion to their use of the grid.The CAISO-controlled grid also includes lower voltage transmission facilities that are operated at, for example, 138 kV or 69 kV. The costs for such lower voltage transmission facilities are recovered under the LVAC. The customers that pay the LVAC are customers within a Transmission Owner’s TAC Area that take service from such lower voltage facilities.In contrast to CAISO-controlled transmission, the vast majority of SCE’s distribution service is governed by the CPUC under its retail rate authority. However, use of distribution facilities to serve eligible wholesale loads (such as Riverside’s) is subject to the rate jurisdiction of the FERC. SCE’stariffs for wholesale customers under the jurisdiction of FERC include: (1) the TO Tariff; and (2) the Wholesale Distribution Access Tariff (WDAT).The WDAT governs transportation of power using the Distribution Provider’s (such as SCE’s) Distribution System. By definition, Distribution System facilities are not integrated with the CAISO Grid and typically serve local load. Facilities or portions of facilities that are constructed by the Distribution Provider for the sole use/benefit of a particular Distribution Customer requesting service under the Tariff are known as “Direct Assignment Facilities,” the costs of which are recovered from the users of such facilities.Under the currently-effective CAISO Tariff, the 69 kV Alternatives would not be included in the HVAC. Riverside believes that the 69 kV Alternatives may be considered lower voltage transmission facilities that, under the currently-effective CAISO Tariff, would be recovered through the LVAC. In such case, responsibility for a majority of the costs of the 69 kV Alternatives would be recovered from SCE customers, including a small percentage from Riverside, and other users or beneficiaries of low voltage facilities (as opposed to being recovered from all Load-Serving Entities that use the high-voltage CAISO-controlled grid through the HVAC). SCE disagrees, and believes that the 69 kV Alternatives would likely be considered non-CAISO-controlled, distribution assets directly assigned to Riverside. In that case, the currently-effective WDAT would recover the costs from the users of the 69 kV facilities, and responsibility for a majority of the costs for the 69 kV Alternatives would fall on Riverside ratepayers and other users or beneficiaries of the 69 kV facilities, if any. While tariffs may be changed through application to FERC, no such application is contemplated or thought to be appropriate by SCE. However, Riverside has rights under the Federal Power Act to seek tariff changes. SCE and Riverside agree that FERC has jurisdiction to determine the classification of any 69 kV Alternative facilities for purposes of cost allocation. 41 4. Alternatives Evaluation4.1 Lower Voltage Alternatives Considered in the 2013 FEIRA broad range of alternatives were evaluated within the 2013 FEIR for the RTRP in accordance with CEQA. (Draft EIR Section 6.4, as included in the 2013 Final EIR [FEIR Section 6.4].) Below is a summary of the 115 kV and 69 kV alternatives evaluated in the 2013 FEIR and the reasons for concluding those alternatives were infeasible.Lower voltage 115 kV transmission lines have much less capacity than a 230 kV line and would require multiple lines (4 to 5 circuits) to accomplish the same bulk power transfer from SCE to Riverside as the 230 kV RTRP.59Several options were evaluated in the 2013 FEIR:1. Building a new 230/115 kV substation and delivering power to Riverside at Vista Substation via multiple new 115 kV lines.602. Building several 115 kV lines from the nearest independent 115 kV interconnection point,which is SCE’s Valley Substation in Romoland, 25 miles southeast of Riverside. This would require multiple (4 to 5 circuits) of 25-mile long transmission lines, requiring more ROW than a single 230 kV line and, because it would occupy a much wider footprint through the communities, resulting in greater environmental impact and higher cost (e.g., cost of the land for expanded ROW, longer line lengths).61These 115 kV alternatives were found to be infeasible.Because of needing many more times the transmission lines to accomplish the same purpose, higher environmental impacts because of a greater project footprint with multiple ROWs, greater effects to the community from the greater footprint, and higher costs, utilizing 115 kV for transmission of additional capacity into Riverside’s system was dismissed from further consideration. While some of these additional impacts from this alternative would be significant the cost would be significantly more for the larger ROW and the multiple lines within one corridor, which would make this alternative infeasible.62A 69 kV alternative source also was considered in the 2013 FEIR. This alternative would require six or more 69 kV subtransmission lines from SCE’s Mira Loma Substation to provide similar power transfer capability as the RTRP. Similar to the 115 kV alternatives, multiple 69 kV circuits would require more ROW and would result in a larger footprint, higher environmental impact, significantly more land for the larger ROW, and many more transmission lines within a single corridor. Also, separate and additional 230/69 kV transformers would be required at Mira Loma Substation to support the capacity requirements.63This 69 kV alternative was found to be infeasible. Because of greater impacts to the community, land uses, and natural resources from a wider footprint, higher costs from many more lines to build and maintain, and additional equipment 59FEIR Volume 2, Section 6.4.1, p. 6-26.60FEIR Volume 2, Section 6.4.1, p. 6-26.61FEIR Volume 2, Section 6.4.1, pp. 6-26 – 6-27.62FEIR Volume 2, Section 6.4.1, p. 6-27.63FEIR Volume 2, Section 6.4.1, p. 6-27. 42 being required at Mira Loma Substation, this alternative was eliminated from further consideration.64For the foregoing reasons, the 2013 FEIR concluded that utilizing 115 kV or 69 kV for transmission of additional electrical capacity into Riverside’s system was infeasible.4.2 New Lower Voltage Alternatives Considered in Response to the ALJ’s RulingIn response to the ALJ’s Ruling, SCE and Riverside conducted a new evaluation of potential 115 kV and 69 kV alternatives.4.2.1 Conceptual Evaluation of 115 kV AlternativeSCE and Riverside considered two possible choices for potential lower voltage alternatives to meet the purpose and need for the RTRP Hybrid Proposal: 69 kV and 115 kV lines. SCE and Riversideconsidered in concept the potential for 115 kV voltage interconnection options to meet the megawatt target necessary for the Project Objectives of the RTRP Hybrid Proposal but determined not to study any 115 kV alternative in detail, primarily based on the required expansion of the existing transmission substations within the area to provide power via 115 kV facilities to Riverside. As discussed in the 2013 FEIR (FEIR Volume 2, Section 6.4.1, p. 6-26), lower voltage transmission lines such as 115 kV have much less capacity than a 230 kV line and would require multiple circuits to accomplish the same bulk power transfer from SCE to Riverside as the RTRP Hybrid Proposal. SCE’s Vista Substation currently is a 230/115 kV substation as well as a 230/69 kV substation. An expansion of Vista Substation to include new 230/115 kV facilities would be required to accommodate additional power delivery to Riverside at 115 kV. Additionally, it would require several new 115 kV circuits to carry the same bulk capacity of the single proposed 230 kV loop-in included in the RTRP Hybrid Proposal. Vista Substation is already constructed to its designed maximum operating capacity and cannot be expanded. In addition, the 115 kV facilities at Vista Substation are not independent from the existing 69 kV source at Vista Substation, because they share the same 230 kV source. Therefore, this would not meet the RTRP objective for a second independent point of interconnection for Riverside. For these reasons, a 115 kV alternative at Vista Substation was not evaluated in detail for this Report.The next nearest potential 115 kV interconnection point would be at SCE’s Valley 500/115 kV Substation in Romoland, located 25 miles southeast of the Riverside service delivery point. Four or more 25-mile long 115 kV transmission circuits would be required for a Riverside systeminterconnection to Valley Substation. Like Vista Substation, Valley Substation is also constructed to its designed maximum operating capacity, and there is also no opportunity for expansion. There is not enough existing spare capacity to provide Riverside with 560 MW of 115 kV service. Therefore, a new 560 MW, 115 kV service from Valley Substation is not feasible and was not studied in detail for this Report.4.2.2 Conceptual Evaluation of New 230/69 kV Substation AlternativeSCE and Riverside considered in concept a design alternative that would include a new 230/69 kV substation located on a new site along and adjacent to or near the two Mira Loma – Vista 230 kV Transmission Lines. This alternative would be similar to the RTRP Hybrid Proposal but would have the new SCE 230/69 kV substation located north of Riverside (adjacent to the 230 kV line) and then have seven to eight 69 kV lines (four routes) extend to a new 66 kV substation in Riverside, rather 64FEIR Volume 2, Section 6.4.1, p. 6-27. 43 than the single double-circuit 230 kV line (one route) included in the RTRP Hybrid Proposal. The service with this design would be similar to the Vista Substation source that currently provides service to Riverside via seven 69 kV lines.Siting and permitting a new 230/69 kV substation along the Mira Loma – Vista corridor would bechallenging, and the multiple 69 kV lines to Riverside in combination would increase the environmental and land-owner impacts and costs associated with this alternative beyond what was evaluated in the 2013 FEIR and for the lower voltage Alternatives studied in this Report. Therefore, this alternative was eliminated from further detailed evaluation.4.2.3 Three 69 kV Alternatives Studied in Detail (Alternatives A, B and C)The Lower Voltage Alternatives A, B, and C studied in this Report would consist of seven, six, and four 69 kV circuits, respectively, to serve as Riverside’s second source from the SCE/CAISO bulk electric system. Depending on the Alternative, these circuits would emanate from various substations within SCE’s system and terminate at different points within Riverside’s electrical system. Alternative A is very similar to the 69 kV alternative source considered in the 2013 FEIR that was found to be infeasible. This Report includes a more detailed evaluation of a potential Alternative to utilize seven 69 kV lines emanating from SCE’s Mira Loma Substation in response to the ALJ’s direction.SCE and Riverside also evaluated the 69 kV Alternatives for expandability from 560 MW as studied in the FEIR to the ultimate potential capacity of the RTRP Hybrid Proposal. The FEIR discussed two transformers for a total rating of 560 MW (two 280 MW transformers) for the RTRP. The ultimate potential capacity of the RTRP Hybrid Proposal would be 840 MW, with the addition of a third transformer at Wilderness Substation (three 280 MW transformers). Both the Wildlife Substation and Wilderness Substation would be designed to accommodate the addition of a third transformer position. The 230 kV line included in the RTRP Hybrid Proposal is rated at 916 MW (normal-condition rating) which would accommodate the increased capacity of three transformers to 840 MW.SCE evaluated interconnection at two existing substations and one proposed substation within SCE’s system, including: Mira Loma Substation, Etiwanda Substation, and the proposed Circle City Substation.SeeFigure 5. Alternative A would be capable of providing 560 MW initially (two 280 MW transformers) with an ultimate buildout of 840 MW (three 280 MW transformers) and seven 125 MW 69 kV circuits. The Alternative B design (three 280 MW transformers and six 125 MW 69 kV circuits) would be capable of providing 750 MW of delivery capacity (limited by the delivery capacity of the 69 kV lines). The Alternative C design (two 280 MW transformers and four 125 MW69 kV circuits) would provide a second source but only provide 500 MW of firm power delivery capacity from SCE. Large scale solar generation, including a BES is considered in this Report to provide up to 60 MW of non-firm capacity for Alternative C. This would bring the total capacity of Alternative C to 560 MW, but the additional 60 MW is non-firm intermittent power.6565Seethe discussion in Section 4.2.3.3.1.3 regarding the selection of large scale solar to provide supplemental generation under Alternative C. 44 THIS PAGE INTENTIONALLY LEFT BLANK

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47 4.2.3.1 Alternative A4.2.3.1.1 Alternative A DescriptionSCE and Riverside studied a potential 69 kV lower voltage Alternative to serve Riverside’s existing demand and projected load growth by supplying electricity from SCE’s Mira Loma Substation as a single substation interconnection point. The initial design for this Alternative includes installation of two additional 230/69 kV 280 MW transformers at Mira Loma Substation with a total capacity of 560MW. A third 230/69 kV 280 MW transformer could be added in the future for 840 MW of capacity. Seven 69 kV circuits would be installed from Mira Loma Substation to Riverside.SeeFigure 6. The Alternative design includes three double-circuit 69 kV structures with two sets of conductors each having a normal condition rating of 125 MW and a four-hour emergency rating of 168 MW. Potential underground sections would be installed as double-circuits in common trench and underground structures with conductors that have a normal condition rating of 125 MW and a four-hour emergency rating of 181 MW. The overhead conductors would be the limiting component (168 MW) under an unplanned single-element contingency event. The design also includes one single-circuit 69 kV line for a total of seven 69 kV circuits. Seven 69 kV circuits are needed in order to have enough line capacity using emergency condition ratings under single-contingency events. In the event of a single-contingency event (unplanned outage of two 69 kV circuits due to a single double-circuit structure failure either overhead or underground) that would remove from service two 69 kV circuits, the remaining five in-service 69 kV circuits would operate at their emergency ratings for a total of 840 MW of capacity (five 69 kV circuits x 168 MW). The Alternative A design consists of four routes (A1, A2, A3, and A4) from Mira Loma Substation to the Riverside service territory that include both overhead and underground lines as shown on Figure 6- 69 kV Alternative A Map. All four routes are needed to provide the capacity required to meet Riverside’s load growth projections. Routes A1, A2, and A3 would terminate at a new Riverside69 kV Switching Station located adjacent to Riverside’s RERC facility. This location was selected for the RTRP Wildlife and Wilderness Substations and would be suitable for this Alternative as well. Route A4 would terminate at Riverside’s Harvey Lynn Substation. Refer to Appendix A for photographs along selected locations for each route associated with Alternative A. 48 THIS PAGE INTENTIONALLY LEFT BLANK
FIGURE 6 69 KV ALTERNATIVE A MAP

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51 4.2.3.1.1.1 Route A1 – Mira LomaRoute A1 would consist of approximately 7.8 miles of overhead transmission line and 2.7 miles of underground transmission line. The two assumed underground segments for this route include the underground segment from Limonite Avenue to Goose Creek Golf Club (also included in the RTRP Hybrid Proposal) and the line segment from Van Buren Boulevard to RERC Substation along Jurupa Avenue. The Van Buren/RERC segment is assumed to be underground due to the conflicts that would occur due to existing and proposed overhead lines and the unlikely probability of local government permitting multiple lines within the same street corridor.Route A1 follows approximately the same alignment as the 230 kV transmission line included in the RTRP Hybrid Proposal. However, the 69 kV route extends to the west on the north portion of the route to Mira Loma Substation, paralleling an existing transmission line on the south. Route A1 also deviates from the proposed 230 kV transmission line route between 68thStreet and Limonite Avenue, where the 69 kV line would extend to the intersection of Pats Ranch Road and Limonite Avenue and follow Pats Ranch Road south to its intersection with 68thStreet. Route A1 would parallel 68thStreet and an existing 69 kV subtransmission line east through the Goose Creek Golf Course where it would re-align with the proposed 230 kV route included in the RTRP Hybrid Proposal within the same proposed corridor. On the south end of Route A1, the 69 kV route deviates from the proposed 230 kV alignment just west of Van Buren Boulevard, where the Alternative would extend to Jurupa Avenue, paralleling this road corridor on the south side to a new 69 kV Switching Station located on the proposed Wildlife Substation site included in the RTRP Hybrid Proposal.4.2.3.1.1.2 Route A2 – Mira LomaRoute A2 would consist of approximately 7.7 miles of overhead transmission line and 2.1 miles of underground transmission line. The one underground segment in the design for Route A2 is on Cantu-Galleano Ranch Road. There is a SCE overhead 69 kV line on this line segment, and it is assumed that the Route A2 double-circuit 69 kV line would be undergrounded in this area to avoid conflicting with the existing overhead line or creating a tunnel effect on the street by having lines on both sides of the street.Route A2 extends east from Mira Loma Substation across an undeveloped parcel and is aligned with an existing subtransmission line corridor to the Cantu-Galleano Ranch Road corridor, following the road ROW to the intersection of Bellegrave Avenue. Route A2 then parallels Bain Street between the road ROW and the Bain Street canal south to the intersection of Limonite Avenue. The route then parallels the Limonite Avenue road ROW on the north side to the Hudson Street intersection, where it crosses to the south side of the road and then crosses Van Buren Boulevard. It then parallels Van Buren Boulevard on its east side between the Union Pacific Railroad and the road crossing the Santa Ana River corridor and Hidden Valley Wildlife Area, then turning to the northeast, running between the Santa Ana River Trail and the Riverside Water Quality Control Plant before intersecting with Wilderness Avenue, and terminating at a new 69 kV Switching Station located on the Wildlife Substation site included in the RTRP Hybrid Proposal.4.2.3.1.1.3 Route A3 – Mira LomaRoute A3 would consist of approximately 9.1 miles of overhead transmission line and 1.0 mile of underground transmission line. Route A3 would be undergrounded along a 1.0 mile section of Van Buren Boulevard. The one underground segment included in the Route A3 design is on Van Buren Boulevard between Harrel Street and Bellegrave Avenue. There is an SCE overhead 69 kV line on this line segment, and it is assumed that the Route A3 double-circuit 69 kV line would be placed 52 underground in this segment to avoid conflicting with the existing overhead line or creating a “tunnel effect” on the street by having lines on both sides of the street. Route A3 follows Micro Drive directly east out of Mira Loma Substation, crossing Interstate 15 (I-15) and Wineville Avenue before turning northeast, crossing an industrialized section of Jurupa Valley before intersecting with Van Buren Boulevard just east of Etiwanda Avenue. From here, Route A3 parallels Van Buren Boulevard between the Union Pacific Railroad and the roadway to Limonite Avenue. Route A3 then follows Limonite Avenue on its north side to Pedley Road, where it crosses to the south side of the road to Clay Street. The route parallels Clay Street on the west side to just north of the Union Pacific Railroad, where the route crosses the railroad and enters the Hidden Valley Wildlife Area and crosses the Santa Ana River. The route follows the south side of the Hidden Valley Wildlife Area before intersecting Industrial Street, crossing the Union Pacific Railroad again, and terminating at a new 69 kV Switching Station located on the Wildlife Substation site included in the RTRP Hybrid Proposal.4.2.3.1.1.4 Route A4 – Mira LomaRoute A4 would consist of approximately 0.2 mile of overhead transmission line and 13.3 miles of underground transmission line. Route A4 would exit the Mira Loma Substation as an overhead line and proceed east to Hamner Avenue, where it would be placed underground. The route would proceed south underground within the Hamner Avenue roadway for approximately seven miles to the intersection of Hidden Valley Parkway. From this point, the underground route would proceed east within the Hidden Valley Parkway and McKinley Street roadways to the intersection of S. Promenade Avenue. Route A4 would continue east underground within the roadways of S. Promenade Avenue and Collett Avenue to the termination point at La Sierra Avenue at the intersection with La Sierra Avenue, the 69 kV circuit would travel north and terminate at Riverside’s Harvey Lynn Substation. Except for a short segment located near Mira Loma Substation where the line would cross a greenfield section of private property, Route A4 would be constructed entirely underground within roadway ROW. Figure 7 shows a diagram of Riverside’s Transmission System following completion of the Alternative A design:

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FIGURE 9 MIRA LOMA SUBSTATION AERIAL VIEW
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59 Option 2:Extending the 230 kV switchrack to the east. It will also be difficult to relocate existing facilities, but it was determined to be feasible.SeeFigures 8 and 9. There are two 230 kV towers, two 69 kV tubular steel poles, and several 69 kV underground duct banks in the location considered for the new 69 kV switchrack.Thus, under the Option 2 approach, installing the necessary equipment at Mira Loma Substation to serve Riverside’s existing and projected load appears challenging, but technically feasible.SCE performed a steady state power flow analysis to assess the impact of Alternative A on SCE’s Bulk Electric System. As part of SCE’s Annual Transmission Reliability Assessment (ATRA), annual base cases for power flow analysis are developed for a 10-year planning period. The base case developed for the last year (2027) of SCE’s 2017 ATRA was used for the Alternative A power flow analysis. Riverside’s projected 2027 load (694.5 MW) was modeled in this base case.66Power flow analysis was performed for the following three scenarios.See Figure 10:

FIGURE 10 RIVERSIDE LOW-VOLTAGE ALTERNATIVE SCENARIOS FOR LOAD FLOW ANALYSIS66The power flow analysis for Alternative A utilized Riverside’s 1-in-40 peak load forecast for 2027 rather than the 1-in-20 forecasts utilized for this Report. The results of the power flow analysis would not change if the lower 1-in-20 forecast figure were used.

60 The analysis was performed using the General Electric International, Inc. Positive Sequence Load Flow (PSLF) program. Contingency Analysis was performed in accordance with the NERC Transmission Planning Standard TPL-001-4 – Steady State & Stability Performance Planning Events categories P0 through P7. No new thermal overloads or voltage issues were identified on SCE’s Bulk Electric System in the transmission planning studies evaluated for Alternative A.4.2.3.1.2.2 Reliability ConsiderationsAlternative A would meet one Objective of the RTRP Hybrid Proposal by providing a second source to Vista Substation and would provide complete redundancy for the Vista Substation connection through planning year 2038. However, SCE’s current design standards generally limit a 230/69 kV transmission substation to four 280 MW transformers; this standard would be exceeded at Mira Loma Substation with the addition of three new 230/69 kV transformers to serve Riverside as incorporated in the Alternative A design, which could reduce the reliability of service to Riverside.SCE strives to construct substations in a consistent manner, meaning that the substation layouts, switch rack designs, equipment, and operating requirements at each substation are consistent and familiar to the field personnel that are required to operate and maintain the equipment at multiple substations. These standards are developed and revised as necessary based on experience to ensure SCE builds safe, reliable and operable substations on a consistent basis. In addition, the consistent design ensures that upgrades to existing substations and/or construction of new substations are constructed in a manner that provides the lowest total cost of ownership. During emergency conditions, the consistent design allows SCE to bring in “out of town” field crews to help restore power to SCE’s customers.SCE obtains this consistent design through the development and use of standards. In addition, SCE’s standards provide a baseline to evaluate and compare the merits of proposed changes to determine impact on safety, reliability, operations, maintenance, construction and cost. The four A-bank transformer limitation seeks to limit the amount of load and customer exposure if the substation were to become unavailable and also allows for a reasonable amount of circuit congestion in the local area.Further, SCE currently has three transformers in service at Mira Loma; if the fourth remaining transformer position is used for Alternative A, it could accelerate the need for a new SCE A-Station(four 230/69 kV transformers) in order to address both capacity and reliability concerns for the Mira Loma Substation service area.4.2.3.1.2.3 Environmental ConsiderationsAs described in Section 4.2.3.1.1 and shown in Figure 6, the Alternative A design includes four routes from Mira Loma Substation to the Riverside service territory that include both overhead and underground lines. Route A1 would be approximately 10.48 miles in length. Route A2 would be approximately 9.75 miles in length. Route A3 would be approximately 10.06 miles in length, and Route A4 would be approximately 13.49 miles in length. Thus, a total of approximately 43.8 miles of 69 kV lines would be required for Alternative A, an increase of approximately 34 miles of ROW ascompared to the RTRP Hybrid Proposal (9.7 miles).SCE and Riverside conducted a preliminary evaluation of potential environmental impacts along the routes for Alternative A for the following resource categories: AestheticsHydrology and Water QualityAgricultural and Forestry 61 Land Use and PlanningAir Quality and Greenhouse Gas EmissionsMineral ResourcesNoiseBiological ResourcesPopulation and HousingCultural ResourcesPublic Services and UtilitiesGeology and SoilsRecreationHazards and Hazardous MaterialsTransportation and TrafficThis analysis was intended to qualitatively evaluate impacts as a means to compare Alternative A to the RTRP Hybrid Proposal, providing a level of detail consistent with CEQA standards regarding the analysis of alternatives.Several methodologies were utilized to collect and review publicly available environmental and land use data within each 69 kV Alternative studied. Methods included: incorporating readily available Geographical Information System (GIS) coverages for Alternatives that cross or parallel the RTRP Hybrid Proposal’s alignment routes, review of maps and published literature, and review of files and records from SCE projects in the area, federal, State, and local regulatory agencies. For biological and water resources, a 500-foot buffer was evaluated for potential impacts. Refer to Appendix B for SCE’s Environmental Screening Report identifying the data sources on which biological and water resource evaluations were based for all of the 69 kV Alternatives studied in this Report.674.2.3.1.2.3.1 Environmental Impacts from Alternative AThe following outline provides a broad overview of the various environmental resource categories reviewed and potential routing constraints and areas of potential concern along Alternative A: Parcel segmentation potentially limiting future land uses resulting from the four transmission line alignments.Traversing existing industrial development parking areas potentially affecting access, available parking, and internal circulation.As compared to the RTRP Hybrid Proposal, an increased number of street crossings and construction activities for a greater distance within road ROW, impacting traffic along high traffic volume corridors and associated road networks, such as Bellegrave Avenue, Limonite Avenue, Van Buren Boulevard, Hamner Avenue, Hidden Valley Parkway, S. Promenade Avenue, and La Sierra Avenue. High volume intersections include:67In order to develop Appendix B, a desktop GIS environmental screening tool was utilized to identify and compare potential environmental impacts of the lower voltage Alternatives’ routes against the RTRP Hybrid Proposal. Each lower voltage Alternative and its associated routes, as well as the proposed RTRP Hybrid Proposal, were buffered 500 ft. The ESRI GIS Screening tool was then used to analyze publicly available environmental data (e.g.,CDFW’s California Natural Diversity Database [CNDDB] records and USFWS critical habitat) as well as data previously collected by SCE. Impacts from each route for each Alternative (A-B-C) were then quantified and compared to the RTRP Hybrid Proposal using the same desktop method. Other than the fieldwork already performed for the 2013 FEIR, RTRP Hybrid Proposal, and subsequent EIR (currently in development by the CPUC), no fieldwork was conducted specifically for the proposed lower voltage Alternatives evaluated in this Report. 62 oLimonite Avenue/Van Buren BoulevardoVan Buren Boulevard/Jurupa AvenueoCantu-Galleano Ranch Rd/Etiwanda AvenueoBellegrave Avenue/Bain StreetoHidden Valley Parkway/Hamner Avenue/I-15 InterchangeIncreased traffic impacts for the construction of approximately 44 miles of 69 kV transmission lines for four routes that include both overhead and a significant amount of underground lines within major arterials in the Cities of Jurupa Valley, Norco, Corona, and Riverside.Logistical, space, and design constraints related to structure placement in the Limonite Avenue/Van Burn Boulevard intersection due to existing overpass and railroad corridor.Potential need for private land ROW acquisition adjacent to road ROW for underground segments.New impacts on railroad operations and encroachment within railroad ROWs which would require approval and close coordination with Union Pacific Railroad.Potential increases in air/dust emissions. Also, dust and air impacts would shift to the north and east into other residential and commercial areas of Jurupa Valley. These impacts would be short-term, local, and consist predominantly of exhaust from mobile construction vehicles and equipment, fugitive dust along construction access roads, trenching activities, and concrete mixing operations. Areas subject to poorer air quality are those sites immediately adjacent to the ROW during surface-disturbing construction activities.Increased potential for cultural impacts and tribal concerns related to two additional routes (as compared to the RTRP Hybrid Proposal) over the Santa Ana River and along undeveloped utility corridors.Reduced recreation values on Goose Creek Golf Course similar to the proposed route in the 2013 FEIR.Additional routes, not previously considered in the 2013 FEIR, in the Hidden Valley Wildlife Area/Santa Ana River Trail. Additional routes will have impacts on vegetation, wildlife, visual, and recreation resources (including conflicts with the Santa Ana River Trail). Additional land conversions would undergo a National Park Service’s National Environmental Policy Act (NEPA) analysis and mitigation for Land and Water Conservation Fund (LWCF) conversion and replacement. Visual impacts created by Alternative A (Route A1) result in structure and vegetation contrasts similar to the RTRP Hybrid Proposal that block views or degrade the scenic quality of the Santa Ana River corridor, surrounding mountains, and other scenic areas from sensitive viewpoints; there also would be impacts on the City of Jurupa Valley I-15 entry corridor from three additional highway crossings. Visual impacts associated with additional riser pole structures located on Cantu-Galleano Ranch Road and Bain Street/Bellegrave Avenue adjacent to a residential area. Increased visual impacts along Bain St. Currently, there is no 69 kV transmission line along the San Servaine River Channel. Visual impacts on the City of Riverside designated Parkway and Gateway (Van Buren Boulevard). 63 The 69 kV riser poles would be more visually prominent than the typical 69 kV transmission line structures.Adjacent to three schools: Jurupa Valley High School, Mira Loma Middle School, and Van Der Molen Elementary.Noise level impacts would increase under Alternative A as compared with the RTRP Hybrid Proposal due to the increase in the footprint of the proposed Alternative. Noise impacts wouldbe temporary, but Alternative A would also shift noise impacts into other residential and commercial areas further east and north in Jurupa Valley.Conflicts with the Riverside Water Quality Control Plant are comparable to the RTRP Hybrid Proposal as evaluated in the 2013 FEIR.Jurisdictional water and wetland delineation will be required based on Alternative A location. The purpose of this delineation is to identify the extent of federal and State jurisdiction within Alternative A pursuant to Sections 401 and 404 of the federal Clean Water Act, as well as Section 13260 of the State Porter Cologne Water Quality Control Act and Section 1602 of the California Fish and Game Code.Wildlife impacts associated with Alternative A are expected to increase as compared with the RTRP Hybrid Proposal due to the three additional routes and would have to be evaluated; this includes the following known federal and State threatened and endangered species or habitats:oDelhi Sands flower-loving fly (Rhaphiomidas terminatus abdominalis) – two-year protocol surveys may need to be conducted in undeveloped open-spaces with Delhi Sands. The three additional routes included in the Alternative A design increase the footprint into these soil types as compared with the RTRP Hybrid Proposal.oRiparian Bird Species – additional routes will impact additional riparian areas important to these species:Least Bell’s vireo (Vireo bellii pusillus)Southwestern willow flycatcher (Empidonax traillii extimus)Western yellow-billed cuckoo (Coccyzus americanus occidentalis)oSmall Mammals – additional routes along riparian and open space corridors have the potential to increase impacts to these species:Los Angeles pocket mouse (Perognathus longimembris brevinasus)Northwestern San Diego pocket mouse (Chaetodipus fallax falla)San Bernardino kangaroo rat (Dipodomys merriami parvus)oBurrowing owl (Athene cunicularia) – State listed species, has the potential to occur along Alternative A and adjacent to Mira Loma Substation within San Bernardino County and would require surveys and consultations with the CDFW under theCalifornia Endangered Species Act. This species has been losing habitat in the area due to urban expansion limiting the species to remaining open spaces. Additional 69 kV routes have the potential to impact nesting pairs along open space corridors.Additionally, previous SCE projects have recorded the presence of burrowing owls adjacent to Mira Loma Substation, and potential expansion could have a higher probability of impacts.

67 4.2.3.1.2.5 Alternative A is Not Feasible Under California law, feasibility is defined as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors.”68No public agency shall approve a project with significant and unavoidable environmental impacts unless the public agency finds “specific economic, legal, social, technological, or other benefits of the project outweigh the significant effects on the environment.”69Under CEQA, the “other considerations” referenced in section 21081 have been found to include “policy considerations” permitting the rejection of mitigation or alternatives that are “impractical or undesirable from a policy standpoint.”70The CEQA Guidelines also stress that the selection of project alternatives should be based primarily on the ability of one or more proposed alternatives to reduce significant impacts relative to the proposed project.71Alternative A is not capable of being accomplished within the same time period as the RTRP Hybrid Proposal, and, based on the foregoing analysis of technological challenges and environmental impacts, is likely to increase, rather than avoid or reduce, the environmental effects of the project. Alternative A is also more costly than the RTRP Hybrid Proposal. Alternative A should therefore be rejected for reasons of infeasibility.With respect to timing, Alternative A is expected to increase the timeframe for completion of the project relative to the RTRP Hybrid Proposal. Depending on the extent of subsequently-required engineering and design modifications as well as permitting and related regulatory proceedings, the additional time necessary for the completion of any of the Alternatives could be five years or more.72As described in Section 3.5, these delays would place the reliability of Riverside’s system at continued risk of load shedding and potential distribution system blackout conditions, as SCE and Riverside expect that loading limits on Riverside’s sole existing interconnection to the SCE system at the Vista Substation will continue to be exceeded under normal operating conditions during peakdemand periods. Under emergency conditions, including an outage of one of the Vista Substation transformers used to serve Riverside, involuntary load shedding is highly likely. Under both normal and emergency conditions, Riverside will be required to continue to rely on internal, gas-fired peaking units that are vulnerable to fuel supply deficiencies associated with the gas system and usage limitations related to air permitting. It is critical that any Alternative to the RTRP Hybrid Proposal be capable of completion within the same timeframe. Alternative A does not satisfy that criterion.Consideration of technological factors supports a finding that Alternative A is infeasible. AlternativeA would require additional transformers to be installed at the Mira Loma Substation, which constitutes a technological constraint because, at this time, only one transformer position is available.Alternative A requires a minimum installation of two additional transformers in order to provide 560 MW of capacity. Even if additional land to install the second transformer could be acquired, the addition of more than one transformer at this location would be inconsistent with SCE and industry 68SeeCEQA Guidelines § 15364; see alsoPub. Resources Code § 21061.1.69SeePub. Resources Code § 21081.70See California Native Plant Soc. v. City of Santa Cruz, 177 Cal.App.4th1001 (2009) (describing acceptable policy-based infeasibility determinations under CEQA.71SeeCEQA Guidelines § 15126.6[b].72Seefurther discussion of potential delay in Section 3.5. 68 design standards, which could reduce the reliability of service to Riverside.73SCE’s design standards are adopted to reflect sound engineering practices in order to mitigate reliability and operability concerns. Under Alternative A, SCE would likely face an accelerated need for a new A-Station in order to address capacity and reliability concerns for the Mira Loma service area.In addition to technological factors, Alternative A is likely to increase environmental impacts as is described with greater particularity in Section 4.2.3.1.2.3.1. With respect to environmental factors, Alternative A requires seven 69 kV circuits along four separate routes to deliver an equivalent amount of energy as the RTRP Hybrid Proposal; this is equivalent to an estimated total of 43.8 miles of new line routes – consisting of three double-circuit 69 kV routes and one underground segment – which would create new environmental and landowner impacts. The RTRP Hybrid Proposal is 9.7 miles long, so the impacts for Alternative A are estimated at being three to four times greater from a routing perspective. The RTRP Hybrid Proposal consists of 63 steel structures, while Alternative A is estimated for 654 steel structures. The diversification of the 69 kV routes suggests that vulnerabilities to electric power flows stemming from structure damage from traffic and/or other environmental conditions may be decreased. At the same time however, the 69 kV routes would place a far greater number of structures into public ROWs, which may increase potential public safety concerns such as “car hit pole” incidents.The roughly ten-fold increase in the number of structure locations would also have a large impact on affected landowners in terms of securing easements and mitigating view shed concerns. While the RTRP Hybrid Proposal impacts 71 parcels with its overhead double-circuit 230 kV line, Alternative A is estimated to impact 284 parcels with double-circuit 69 kV overhead lines, a significant increase. The likely impacts to wildlife are also greater under Alternative A.Social factors also support a finding of infeasibility. The large number of structures and line miles described above in connection with environmental factors will create a greater impact on the communities located adjacent to the Alternative A facilities relative to the impact that the shorter route and reduced number of structures associated with the RTRP Hybrid Proposal will have on communities adjacent to the project. Given that three out of the four line routes do not follow the same route as the RTRP Hybrid Proposal, SCE and Riverside anticipate that new community opposition could arise and that new environmental analyses of the routes may be required, with a corresponding delay on the project’s timing. As shown in Table 4, Alternative A is likely to have larger environmental justice impacts on disadvantaged communities. Finally, Alternative A would cost more, in terms of total dollars and without respect to any tariff implications, than the RTRP Hybrid Proposal. As documented in Section 4.2.3.1.2.4, SCE and Riverside currently estimate the cost of Alternative A at $499.1 million, which is approximately $94 million (or approximately 23%) above the cost of the RTRP Hybrid Proposal. This added cost does not reflect the potential cost increases associated with delays and new environmental and permitting processes.The increased total costs contribute to an overall finding of infeasibility based on the technological, environmental, social, and policy considerations noted above.73SeeSCE Subtransmission Planning Criteria and Guidelines (September 24, 2015). SCE’s standards, subtransmission planning criteria and guidelines are considered proprietary and contain confidential material. Relevant portions of same can be made available upon request provided appropriate safeguards are in place to protect their confidentiality. 69 4.2.3.2 Alternative B4.2.3.2.1 Alternative B DescriptionAlternative B would utilize two existing SCE 230/69 kV substations (Mira Loma and Etiwanda) and would modify the design for a proposed SCE distribution substation (Circle City) to add a 230 kV interconnection and 230/69 kV transformation. One double-circuit 69 kV line would emanate from each substation for a total of three double-circuit lines (Route B1, Route B2, and Route B3), three ROWs, and six circuits as shown on Figure 11 - 69 kV Alternative B Map. Interconnection to Riverside’s system would be from Mira Loma Substation to Harvey Lynn Substation (one circuit) and to the existing 69 kV line between Kaiser Substation and Harvey Lynn Substation (one circuit). There would be two circuits to Freeman Substation from Circle City Substation and two circuits toMountain View Substation from Etiwanda Substation. In addition, Alternative B would require the construction of a new 230 kV transmission line feed to the proposed Circle City Substation similar to the 230 kV line included in the RTRP Hybrid Proposal. The 230 kV feed necessary for Alternative B is not included in the currently proposed plan for theCircle City Substation and would be a minimum of two miles longer than the 230 kV line included in the RTRP Hybrid Proposal. An alignment and detailed design for this required 230 kV interconnection to the Circle City Substation has not been developed for this Report; therefore the discussion of potential environmental impacts from Alternative B includes typical impacts to be expected and level of magnitude of those impacts in comparison to the RTRP Hybrid Proposal only and not a specific impact analysis for the necessary 230 kV transmission line. Refer to Appendix A for photographs along selected locations for each 69 kV route associated with Alternative B.4.2.3.2.1.1 Route B1 – Mira LomaRoute B1 would consist of approximately 4.5 miles of overhead transmission line and 5.8 miles of underground transmission line. Route B1 would be undergrounded from Limonite Avenue to the Goose Creek Golf Club. The underground section would parallel Limonite Avenue on the north, follow Pat’s Ranch Road along road ROW, follow 68thStreet to the Goose Creek Golf Course, and emerge as an overhead line just north of the Santa Ana River. Route B1 is identical to Route A1 (seeSection 4.2.3.1.1.1) north of the Santa Ana River. South of the Santa Ana River, the line route woulddeviate from the Route A1 corridor just east of the river crossing, extend south to Arlington Avenue, and follow the Arlington Avenue street ROW to the intersection with La Sierra Avenue. Route B1 would then follow the La Sierra Avenue road ROW south to the Harvey Lynn Substation and the tap point between Harvey Lynn and Kaiser Substations. Except for a short segment located just north of Arlington Avenue where the line would cross a greenfield section of private property, Route B1 south of the Santa Ana River would be constructed entirely underground within road ROW. 70 THIS PAGE INTENTIONALLY LEFT BLANK
FIGURE 11 69 KV ALTERNATIVE B MAP

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73 4.2.3.2.1.2 Route B2 – EtiwandaRoute B2 would consist of approximately 8.2 miles of overhead transmission line and 4.7 miles of underground transmission line. Route B2 is similar to Route A3 as described in the segment alongVan Buren Boulevard between Riverside Drive and the interconnection with Riverside’s system north of Mountain View Substation. However, instead of interconnecting at existing lines just north of the Mountain View Substation, Route B2 would interconnect directly into Mountain View Substation. In addition, Route B2 would deviate from Route A3 by extending along Van Buren Boulevard northwest to Etiwanda Avenue, following Etiwanda Avenue north to Etiwanda Substation. Route B2 would be undergrounded in the same sections as Route A2 along Van Buren Boulevard to the intersection with Etiwanda Avenue and along two sections of Etiwanda Avenue between Marlay Avenue and East Philadelphia Avenue, and between Jurupa Avenue and the Etiwanda Substation. 4.2.3.2.1.3 Route B3 – Circle CityRoute B3 would consist of approximately 7.1 miles of underground transmission line. Route B3 would be constructed entirely underground and is located along Lessen Lane, Magnolia Avenue, Tyler Street, and Indiana Avenue within street ROW from the proposed Circle City Substation to the Freeman Substation.4.2.3.2.2 Alternative B Evaluation4.2.3.2.2.1 Technical ConsiderationsSCE and Riverside evaluated using three substation sources to provide 750 MW of delivery capacity to Riverside. The three substations included SCE’s existing Mira Loma and Etiwanda Substations and SCE’s future proposed Circle City Substation. Alternative B includes a single 280 MW transformer at each of the three substations. One double-circuit line would emanate from each of the three substations to Riverside for a total delivery capacity of 750 MW.74All three substations would be configured for supplying 250 MW each to Riverside. Each of these substations would supply the power via overhead and/or underground double-circuit 69 kV circuits each with conductors having a normal condition capacity of 125 MW (total of 250 MW for each double-circuit line) and with a four-hour emergency capacity of 168 MW (total of 336 MW for each double-circuit line. The load at Riverside would be served by installing overhead double-circuit 69 kV circuits each with conductors having a normal condition capacity of 125 MW and with a four-hour emergency capacity of 168 MW (336 MW from each substation). Underground sections included in the Alternative B design would also be double-circuited in common trench and common underground structures with conductors having a normal condition rating of 125 MW and a four-hour emergency condition rating of 181 MW. The overhead conductors would be the limiting component (168 MW) during unplanned single-contingency events. In the event of a single-element contingency (outage of two 69 kV circuits due to the failure of a single double-circuit structure either overhead or underground), the four remaining 69 kV circuits described under Alternative B would operate at an emergency capacity totaling 672 MW (4 X 168 MW).74Alternative B is limited by the line rating of 125 MW normal condition rating (6 X 125 MW = 750 MW)rather than by the transformer rating.SeeFigure 11.

FIGURE 13 ETIWANDA SUBSTATION PLOT PLAN

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FIGURE 15 ETIWANDA SUBSTATION AERIAL VIEW

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81 Option 1: Extend the 230 kV and 69 kV switchracks to the east. This was determined to be infeasible due to physical space limitations. There is insufficient space within the existing substation property to extend the switchrack to the east. Switchrack extensions to the east would require the acquisition of the property adjacent to the east side of the substation. This property is owned by a third party generator and currently contains a well, waste water sump, and two customer-owned 69 kV lines. It is assumed that this land is being utilized by the customer and is essential to the operation of their business.Option 2: Extend the 230 kV and 69 kV switchracks to the west. There is sufficient space within the existing substation property to extend the switchracks to the west even though there are conflicts with the existing Mechanical Electric Equipment Room, driveway, and trailers. The required 69 kV circuits would need to exit the substation due south. Several transmission and subtransmission lines are located south of any proposed westward extension:Etiwanda-Rancho Vista Nos. 1 & 2 230 kV Transmission Lines.Mira Loma-Rancho Vista Nos. 1 & 2 230 kV Transmission Lines.Etiwanda-Grapeland-Pipe 69 kV Transmission Line.Etiwanda-Ameron 69 kV Transmission Line.Etiwanda-Arbors-Forge-Reduction 69 kV Transmission Line.Etiwanda-Archline-Cucamonga-Genamic 69 kV Transmission Line.Etiwanda-Inland-Wimbledon 69 kV Transmission Line.The Etiwanda Substation interconnection presents significant difficulties due to spatial limitations and the number of lines that would have to be crossed. To avoid crossing these lines, the new 69 kV circuits serving Riverside would most likely have to exit the substation via underground getaways.4.2.3.2.2.1.3 Circle City Substation SourceThe Alternative B design also includes modification of SCE’s currently proposed, but not approved, Circle City Substation, planned for location in the City of Corona, to add a 230 kV interconnection and a double-circuit 69 kV line to Riverside. The current proposal for the Circle City Substation is awaiting a DEIR from the CPUC and has a current need date of 2024. The need date and anticipated in-service date of the proposed Circle City Substation (if approved) would not meet the need date of Riverside to receive a second source of power and the needed additional capacity. Further, alternative sites and designs may still be considered by the CPUC with respect to the proposed Circle City Substation, which may also call into question that site’s use by any alternative to the RTRP Hybrid Proposal.SCE currently intends for the Circle City Substation to be a distribution substation, but Alternative B would require modification of the existing design plans to allow for a 230 kV line to connect Circle City to the 230 kV system. Without the 230 kV line, Alternative B would fail to meet the Objectivesestablished for the RTRP Hybrid Proposal. The Alternative B design would require two 230 kV source transmission lines that would likely originate from SCE’s existing Mira Loma Substation and traverse a minimum of 11 miles75until the lines terminated at the proposed Circle City Substation site. The Alternative B design configuration for the Circle City Substation would include two 230/69 kV 280 MW transformers to serve SCE customer load in the City of Corona and the surrounding area and one additional 230/69 kV 280 MW transformer to serve Riverside. Under the design contemplated as part of Alternative B, upgrading the substation to 230/69 kV to accommodate the 75Depending on routing this value could increase by several miles. 82 required A Banks for service to SCE customers and to Riverside would result in a non-standard substation.SeeSection 4.2.3.1.2.2 for explanation of SCE’s policy regarding standardization of substation design.Two new 69 kV circuits (single double-circuit ROW) from Circle City Substation would be routed to and terminated at Freeman Substation within Riverside’s electrical system. Circle City Substation would be located approximately seven miles from the termination point within Riverside’s electrical system.At a minimum, the following increases to the current proposed Circle City Substation scope (currently under CPUC review and awaiting an DEIR) also would be required:230 kV towers.230 kV switchrack.Three 280 MW 230/69 kV transformers.Additional 69 kV switchrack.Egress routes for two additional 69 kV circuits to serve Riverside.The size and dimensions of the property currently being considered for the substation as originally proposed could not accommodate all of the required facilities.SeeFigure 16.In addition, use of the proposed Circle City Substation would increase the number of miles for construction of 230 kV transmission line as compared to the RTRP Hybrid Proposal by at least two miles through more densely developed and populated areas than the areas that would be affected by the RTRP Hybrid Proposal, thereby increasing costs, environmental impacts, and the need for property acquisition. The area between Mira Loma Substation and the proposed Circle City Substation is densely populated and developed with both residential and commercial/industrial land uses. A high-level review of the area for this Report did not identify siting opportunities to construct 230 kV transmission lines without significant land and rights impacts and acquisitions.In light of the numerous reliability considerations discussed in Section 4.2.3.2.2.2 below, SCE did not perform a power flow analysis for Alternative B. Because Riverside’s load would be split among four of SCE’s source substations under Alternative B (including the existing Vista Substation source), SCE expects that the power flow analysis results would show less impact on the Bulk Electric System than Alternative A (Riverside served from two SCE source substations, Vista and Mira Loma). The potential impacts of the reliability considerations below, however, would require a more extensive analysis.

FIGURE 16 CIRCLE CITY SUBSTATION AERIAL VIEW AND PLOT PLAN

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85 4.2.3.2.2.2 Reliability ConsiderationsAlternative B provides a second source of electricity to Riverside and, if found feasible, could provide the capacity required to meet future load growth up to 750 MW. A fourth route was considered for this Alternative which would have provided one or more additional circuits that would have matched the 840 MW ultimate design capacity for the RTRP Hybrid Proposal. The impacts to Riverside’s system reliability by adding one or two more circuits beyond the six described for this Alternative were significant. It was determined to see if the reliability concerns could be reduced by limiting this Alternative to six circuits. Even with this reduction in number of circuits interconnecting with Riverside it was determined that the reliability concerns with Alternative B are significant for the following reasons:Alternative B forces Riverside to divide the western portion of the system into discrete radial load pockets, as the SCE source systems (Mira Loma, Etiwanda, Circle City, and Vista) cannot be paralleled. SCE does not allow paralleling of these systems due to the effect of fault impedances from different sources on operation and protection elements of the electrical network (e.g., synchronization, protection co-ordination, switching). Creation of radial load pockets that cannot be paralleled reduces operational flexibility.A contingency loss of any SCE source (e.g., loss of a double-circuit tower, loss of two circuits) would force Riverside to immediately drop load. It cannot be instantaneously or automatically transferred to another source, as this would require appropriate coordination to avoid system paralleling.Alternative B will result in longer outages (hours versus minutes) and black-out times due to the above reasons. It is Riverside’s goal to maintain system reliability indices; SAIDI (System Average Interruption Duration Index) less than 50 minutes per year and SAIFI (System Average Interruption Frequency Index) fewer than 1.15 interruptions per customer per year. Under Alternative B, Riverside will not be able to meet its goal to serve its customers reliably.Normally, Riverside distribution substations are served by two sources. Alternative B reduces the number of source lines to some substations and reduces reliability. Riverside’s Harvey Lynn, Freeman and Mountain View Substations would experience less reliability due to reduced connectivity to other Riverside stations than exists today.Sensitive customer substations (hospitals, etc.) may be affected by the reduction in reliability.Riverside’s RERC generating facility would be underutilized due to islanded operation of the Harvey Lynn, Freeman and Mountain View Substations. To provide support to any of these stations, RERC would need to follow separately a specific timeline for synchronizing requests and 30-minute start-up sequences and comply with environmental permit restrictions on number of hours of operation.Alternative B offers reduced capacity during outage of Vista Substation due to load transfer limitations resulting from the islanded load pockets (e.g., Mountain View and Freeman Substations have ties to the Vista-fed system. The Harvey Lynn Substation source cannot be used to support Vista-fed systems in absence of the tie-line). For these reasons, full utilization of the three sources (coming from Mira Loma, Circle City and Etiwanda) and RERC cannot be achieved during an outage of Vista Substation, and Alternative B cannot provide complete redundancy for the Vista interconnection.4.2.3.2.2.3 Environmental ConsiderationsAs described above, Alternative B would utilize two existing SCE 230/69 kV substations (Mira Loma and Etiwanda) and would require a modified design for a proposed SCE 230/69 kV substation (Circle 86 City), with one double-circuit 69 kV line from each substation for a total of three double-circuit lines (Route B1, Route B2, and Route B3), three ROWs, and six circuits as shown on Figure 11 - 69 kVAlternative B Map. Route B1 would be approximately 10.4 miles; Route B2 is approximately 12.9miles, and Route B3 is approximately 7.1 miles. An approximate total of 30.4 miles of 69 kV lines would be required for Alternative B. In addition to the 69 kV lines that have been identified andmapped as part of this analysis, Alternative B would require a new 230 kV transmission source into the proposed Circle City Substation that would likely be at least 11 miles in length and would require an extensive routing and siting analysis to be performed similar to the RTRP 230 kV siting analysis as described in the 2013 FEIR, Section 6.2.1. Thus, Alternative B would increase ROW requirements by approximately 31.7 miles (41.4 miles – 9.7 miles) as compared to the 9.7 mile ROW required for the 230 kV line included in the RTRP Hybrid Proposal.SCE and Riverside conducted a preliminary evaluation of the environmental resource categories listed in Section 4.2.3.1.2.3 for potential impacts along Alternative B using the methodology described in Section 4.2.3.1.2.3. This analysis was intended to qualitatively evaluate impacts as a means to compare Alternative B to the RTRP Hybrid Proposal, providing a level of detail consistent with CEQA standards regarding the analysis of alternatives.4.2.3.2.2.3.1 Environmental Impacts from Alternative BThe following outline provides a broad overview of the various environmental resource categories reviewed and potential routing constraints and environmental concerns for Alternative B: Visual impacts created as a result of structure and vegetation contrasts and the blocking of views or degradation of the scenic quality of the Santa Ana River corridor, surrounding mountains, and other scenic areas from sensitive viewpoints as a result of an additional river crossing; impacts on views of the City of Jurupa Valley I-15 entry corridor; similar visual impacts to the visual character of urban neighborhoods and the Santa Ana River corridor due to the required 230 kV interconnection to the Circle City Substation. Visual impacts on the City of Riverside designated Gateway and Parkway (Van Buren Boulevard).Air/dust emissions are anticipated to increase due to the increased footprint and underground/trenching activities. A portion of these impacts would also shift further east and south into other residential and commercial areas within the City of Jurupa Valley and Riverside. Alternative B’s air and dust impacts would be short-term, local, and consist predominantly of exhaust from mobile construction vehicles and equipment, fugitive dust along construction access roads, trenching activities, and concrete mixing operations. Areas subject to poorer air quality are those sites immediately adjacent to the ROW during surface-disturbing construction activities.Cultural resources and tribal concerns are generally low except in undeveloped open space and park/recreation areas (e.g., Hidden Valley Wildlife Area). Additional surveys would be required to evaluate impacts of shifting/adding additional routes east and south along the Santa Ana River corridor.Reduced recreation values on Goose Creek Golf Course similar to the proposed route in the 2013 FEIR.Short term impacts on the visual character of the Arlington Avenue and La Sierra Avenue designated Parkway and Scenic Boulevard as a result of construction.Visual impacts of overhead to underground transition structures as seen from the Santa Ana River Trail, nearby residences and Arlington Avenue designated Parkway and Scenic Boulevard. 87 As compared to the RTRP Hybrid Proposal, an increased number and multiple crossings of streets and construction activities for a greater distance within road ROW, impacting traffic along high traffic volume corridors and associated road networks such as Etiwanda Avenue,Van Buren Boulevard, Arlington Avenue, and Magnolia Avenue. High volume intersections include:oLimonite Avenue/Van Buren BoulevardoArlington Avenue/La Sierra AvenueoLa Sierra Avenue/Magnolia AvenueoTyler Street/Magnolia AvenueoLimonite Avenue/Clay StreetoMagnolia Avenue/CA 91oVan Buren Boulevard/Etiwanda Avenue/CA 60Additional riser pole structures located on Etiwanda Avenue causing increased visual impacts.Impacts on the visual character of the Etiwanda Avenue commercial areas as a result of street tree removal.Private land ROW acquisition may be necessary adjacent to road ROW for underground segments.Impacts on railroad operations and encroachment within railroad ROWs, which would require approval and close coordination with Union Pacific Railroad.Noise level impacts would increase due to the increase in the footprint of Alternative B as compared with the RTRP Hybrid Proposal. Noise impacts would be temporary but would shift further east into residential areas of Jurupa Valley and south into residential and commercial areas in the City of Corona and Riverside.Jurisdictional water and wetland delineation will be required based on the location of Alternative B routes. The purpose of this delineation is to identify the extent of federal and state jurisdiction within Alternative B pursuant to Sections 401 and 404 of the federal Clean Water Act, as well as Section 13260 of the State Porter Cologne Water Quality Control Act and Section 1602 of the California Fish and Game Code.Alternative B may reduce impacts within the Hidden Valley Wildlife Area for vegetation, wildlife, visual, and recreation resources (including conflicts with the Santa Ana River Trail) as compared to the 230 kV route for the RTRP Hybrid Proposal as evaluated in the 2013 FEIR. However, the routes in the Alternative B design would need to be evaluated for LWCF conversion and replacement. Resource impacts associated with Alternative B, including impacts on known federal and State threatened and endangered species or habitats, are expected to increase as compared to the RTRP Hybrid Proposal due to the three additional 69 kV routes and the longer length and location of the 230 kV line required to interconnect Circle City Substation at 230 kV. Routes for the Alternative B design are within recorded areas known for threatened and endangered species and habitats. Protocol surveys may be required for the following species to determine potential impacts and permitting requirements:oDelhi Sands flower-loving fly-two-year protocol surveys may need to be conducted in undeveloped open-spaces with Delhi Sands. The three additional routes included in the Alternative B design increase the footprint into these soil types.oRiparian Bird Species – additional routes will impact additional riparian areas important to these species:Least Bell’s vireo. 88 Southwestern willow flycatcher.Western yellow-billed cuckoo.oSmall Mammals – additional routes along riparian and open space corridors have the potential to increase impacts to these species:Los Angeles pocket mouse – also referenced in site records surrounding the Etiwanda substation.Northwestern San Diego pocket mouse.San Bernardino kangaroo rat – potential habitat identified by previous SCE projects adjacent to Etiwanda substation.Burrowing owl – a State listed species, has the potential to occur along Alternative B within San Bernardino County and would require surveys and consultations with the CDFW under the California Endangered Species Act. This species has been losing habitat in the area due to urban expansion limiting the species to remaining open spaces. The additional 69 kV routesincluded in Alternative B have the potential to impact nesting pairs along open space corridors. Additionally, previous SCE projects have recorded the presence of burrowing owls adjacent to Mira Loma Substation, and potential expansion could have a higher probability of impacts.Vernal Pool Fairy Shrimp – vernal pools south and west of the Mira Loma substation have been identified by previous SCE projects. Alternative B would be constructed on lands that have the potential to support sensitive biological resources that are regulated through the Western Riverside County MSHCP. Several surveys may be required to determine species or habitat presence per the MSHCP requirements. Some of the surveys potentially required are listed below:oMSHCP narrow endemic plant survey.oMSHCP small mammal survey.oMSHCP riparian/riverine survey.oMSHCP burrowing owl survey.oMSHCP Vernal Pool and Vernal Pool Fairy Shrimp Habitat.USFWS critical habitats crossed by Alternative B include:oLeast Bell’s vireo – The Alternative B footprint would increase the impacted area from approximately 128 acres in the 2013 FEIR to 157 acres. Most Least Bell’s vireocritical habitat was avoided in the 2013 FEIR.oSanta Ana sucker – The Alternative B footprint would increase the impacted area from approximately 105 acres in the 2013 FEIR to 130 acres. Santa Ana sucker habitat was avoided entirely in the 2013 FEIR. oFederally listed San Diego Fairy Shrimp have the potential to occur adjacent to the Mira Loma substation. Least Bell’s Vireo and San Bernardino Kangaroo Rat have potential to occur adjacent to Etiwanda substation, within San Bernardino County. Any activities outside of these substations could require surveys and consultations with USFWS under Section 10 of the Endangered Species Act. 4.2.3.2.2.3.2 Environmental Justice Impacts From Alternative BWith respect to Environmental Justice and impacts on disadvantaged communities, Alternative B shifts the affected areas farther to the north, south, and east into disadvantaged communities in Fontana, Corona, Jurupa Valley, and Riverside already impacted by transportation corridors, power

92 4.2.3.2.2.5 Alternative B Is Not FeasibleAs explained previously with respect to Alternative A, under California law, feasibility is defined as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors,” but may also take into account “other considerations” permitting the rejection of alternatives that are impractical or undesirable from a policy standpoint.76Under CEQA, the selection of project alternatives should be based primarily on the ability of one or more proposed alternatives to reduce significant impacts relative to the proposed project.77As with Alternative A, Alternative B is not capable of being accomplished within the same time period as the RTRP Hybrid Proposal, and, based on the foregoing analysis of technological challenges and environmental impacts, is likely to increase, rather than avoid or reduce, the environmental effects of the project. Alternative B is also substantially more expensive than the RTRP Hybrid Proposal. Alternative B should be rejected for reasons of infeasibility.Alternative B is expected to increase the timeframe for completion of the project relative to the RTRP Hybrid Proposal. Depending on the extent of subsequently-required engineering and design modifications as well as permitting and related regulatory proceedings, the additional time necessary for the completion of any of the Alternatives could be five years or more, and, given that Alternative B includes construction of another 230 kV line that is longer than the line in the RTRP Hybrid Proposal, SCE and Riverside believe that any delays would be well in excess of five years.78Asdescribed in Section 3.5, these delays would place the reliability of Riverside’s system at continued risk of load shedding and potential distribution system blackout conditions, as SCE and Riversideexpect that loading limits on Riverside’s sole existing interconnection to the SCE system at the Vista Substation will continue to be exceeded under normal operating conditions during peak demand periods. Under emergency conditions, including an outage of one of the Vista Substation transformers used to serve Riverside, involuntary load shedding is highly likely. Under both normal and emergency conditions, Riverside will be required to continue to rely on internal, gas-fired peaking units that are vulnerable to fuel supply deficiencies associated with the gas system and usage limitations related to air permitting. It is critical that any alternative to the RTRP Hybrid Proposal be capable of completion within the same timeframe. Alternative B does not satisfy that criterion. Alternative B is also likely to significantly increase environmental impacts. With respect to environmental factors, Alternative B requires a new 230 kV circuit that is longer than the RTRP Hybrid Proposal, plus six 69 kV circuits along three separate routes to deliver an equivalent amount of energy as the RTRP Hybrid Proposal. This configuration would create new environmental and landowner impacts. The three 69 kV line routes would result in a total of 30.4 line miles, and the 230 kV line would be at least 11 miles, versus the 9.7-mile RTRP Hybrid Proposal. The increased line mileage correspondingly increases the environmental impacts. The RTRP Hybrid Proposal consists of 63 steel structures, while Alternative B is estimated to include 335 steel structures, which would also have a large impact on affected landowners in terms of securing easements and mitigating view shed concerns as well as increase vulnerabilities to damage from, for example, traffic and other environmental conditions. While the RTRP Hybrid Proposal impacts 71 parcels with its overhead 76SeeCEQA Guidelines § 15364; see alsoPub. Resources Code §§ 21061.1, 21081; California Native Plant Soc., 177 Cal.App.4th at 1001 (describing acceptable policy-based infeasibility determinations under CEQA).77SeeCEQA Guidelines § 15126.6(b).78Seefurther discussion of potential delay in Section 3.5. 93 double-circuit 230 kV line, Alternative B is estimated to impact 163 parcels with double-circuit 69 kV overhead lines, a significant increase.79Finally, the likely impacts to wildlife are greater under Alternative B.Social factors also support a finding of infeasibility. The large number of structures and line miles described above in connection with environmental factors will create greater impacts on the communities located adjacent to the Alternative B facilities relative to the impact that the shorter route and reduced number of structures associated with the RTRP Hybrid Proposal will have on communities adjacent to the project. Given that the line routes for Alternative B do not follow the same route as the RTRP Hybrid Proposal and would entail a longer 230 kV line, SCE and Riversideanticipate that new community opposition would arise and that new environmental analyses of the routes may be required, with a corresponding delay of the project’s timing. As shown in Table 7,Alternative B is likely to have larger environmental justice impacts on disadvantaged communities.As explained in Sections 4.2.3.2.2.1 and 4.2.3.2.2.2 above, while possible in theory, Alternative B would also pose significant technological, engineering, and design challenges, as well as impact SCE’s planning for its customers in the vicinity of Riverside. For example, if the only remaining transformer position available at Mira Loma were taken by Alternative B, SCE would likely face an accelerated need for a new A-Station in order to address capacity and reliability concerns for the Mira Loma service area. Alternative B would also require significant physical modifications to the Etiwanda Substation footprint that present major challenges, including the avoidance and/or relocation of existing infrastructure (e.g., a well, a waste water sump, multiple 69 kV circuits, etc.). Moreover, Alternative B would require modification of the proposed Circle City Substation (currently proposed as a distribution substation) to allow for a 230 kV line connection that would likely require SCE to enlarge the dimensions of the proposed substation footprint. Upgrading the substation to 230/69 kV to accommodate the required A Banks for service to SCE customers and to Riverside would result in a non-standard substation.SeeSection 4.2.3.1.2.2 for explanation of SCE’s policy regarding standardization of substation design. Further, as explained in Section 4.2.3.2.2.2, there are significant reliability and management concerns created by Alternative B. Specifically, Alternative B is expected to, among other things: reduce operational flexibility by creating radial load “pockets” in Riverside’s service territory that cannot be paralleled; result in longer outages and black-out times; necessarily result in inefficiencies in the operation of Riverside’s RERC generating facility; and impose load transfer limitations and reduced capacity in the event of an outage of Vista Substation. The potential for Alternative B to result in a system which is difficult to manage, unstable, and inherently less reliable (all at a significantly increased cost) contravene prudent utility practice and design. Alternative B is contrary to these sound policies and should be found infeasible on that basis.Finally, Alternative B would cost significantly more, in terms of total dollars and without respect to any tariff implications, than the RTRP Hybrid Proposal. As documented in Section 4.2.3.2.2.4, SCE and Riverside currently estimate the cost of Alternative B at over $1 billion, approximately $659million (or approximately 163%) above the cost of the RTRP Hybrid Proposal. This added cost does not reflect the potential cost increases associated with delays and new environmental and permitting processes. 79The figures above for parcel and structure counts reflect only the 69 kV lines included in Alternative B. The 11-mile 230 kV line from Mira Loma Substation to Circle City Substation would affect additional parcels and add more structures. 94 The increased total costs and noted technological challenges contribute to an overall finding of infeasibility based on environmental, social, and policy-based considerations regarding prudent electrical system planning and use of ratepayer funds noted above.4.2.3.3 Alternative C 4.2.3.3.1 Alternative C DescriptionThe Alternative C design provides electrical power from a single 230/69 kV substation (Mira Loma) source with two double-circuit 69 kV lines to Riverside.SeeFigure 17 - 69 kV Alternative C Map.80The total firm delivery capacity from SCE to Riverside under Alternative C would be 500 MW. Large scale utility solar generation, including a BES is considered in this Alternative to provide up to 60 MW of non-firm capacity. This would bring the total capacity of Alternative C to 560 MW, but the additional 60 MW would provide substantially less capacity than its rated capability for serving load and for peak shaving purposes.Refer to Appendix A for photographs along selected locations for each 69 kV route associated with Alternative C. A description of each 69 kV route is included below. A detailed description of the necessary supplemental internal generation (large scale utility solar and BES) associated with this Alternative is not included, as the siting for such a large scale project has not been identified and is not likely feasible in the Riverside area. Please refer to Section 4.3 for a description of the size and feasibility of other solutions considered, including solar and BES. 4.2.3.3.1.1 Route C1 – Mira Loma (same as Route A1)Route C1 would consist of approximately 7.8 miles of overhead transmission line and 2.7 miles of underground transmission line. Route C1 is identical to Route A1 as described above in Section 4.2.3.1.1.1.4.2.3.3.1.2 Route C2 - Mira Loma (same as Route A2)Route C2 would consist of approximately 7.7 miles of overhead transmission line and 2.1 miles of underground transmission line. Route C2 is identical to Route A2 as described in Section 4.2.3.1.1.2.80SCE and Riverside considered Etiwanda Substation and Circle City Substation as potential source points from SCE’s system for Alternative C. Interconnection to the proposed Circle City Substation and the Etiwanda Substation would be less viable options than interconnection to the Mira Loma Substation, primarily due to the need for a new 230 kV source (similar to the 230 kV line included in the RTRP Hybrid Proposal) to be routed and constructed into the proposed Circle City Substation, the spatial limitations of accommodating 230/69 kV and separate 69 kV transformers and other infrastructure, and the distance from Etiwanda Substation to the Riverside system.

FIGURE 17 69 KV ALTERNATIVE C MAP

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97 4.2.3.3.1.3 Supplemental Internal GenerationTwo potentially viable generation options were considered for Alternative C supplemental generation, i.e., gas-fired peakers and PV Solar with BES. PV Solar with BES was selected for further study in this Report over gas-fired peakers mainly because of concerns with the long term viability of gas-fired peakers as sources of firm power in light of increasingly stringent environmental regulations and State mandate to use increasing amounts of renewable resources.At the regional level the South Coast Air Quality Management District (SCAQMD) has increasingly tightened up its regulation associated with NOx emissions, one of the main sources of emissions of gas-fired generation, making it increasingly challenging to operate gas-fired generation. At the State level the California legislature has progressively enacted legislation that mandates the use of increasing amount of renewable resources to serve retail loads. The State legislature has already considered legislation in the last legislative year to mandate the use of non-carbon resources to supply 100% of retail load by a date certain. These factors call into question the long term viability of gas-fired peakers as a source of firm power.See alsothe discussion of uncertainties regarding natural gas supply in Section 4.3.2.2.4.2.3.3.2 Alternative C Evaluation4.2.3.3.2.1 Technical ConsiderationsAlternative C includes the installation of two transformer banks (230/69 kV) with a capacity of 560 MW (two – 280 MW) and four 69 kV circuits (500 MW) to a new switchyard located within Riverside at the Wildlife/Wilderness site.SeeFigure 18. Alternative C is similar to Alternative A except that two double-circuit lines would be installed rather than three double-circuit lines and one single circuit line, which would limit the total capacity of the Alternative. The two line routes are described in detail in Section 4.2.3.1.1 under Routes A1 and A2 (corresponding to Routes C1 and C2). This Alternative, as configured, would not provide sufficient firm capacity to serve Riverside’s current load or forecast load and would not provide redundancy for the Vista Substation, which is rated at 557 MW. The four 69 kV circuits in Alternative C limit the transfer capability of this Alternative to 500 MW based on the line ratings of 125 MW for normal operation (4 X 125 MW). In order to address the line rating limits of 500 MW, a large utility scale solar project (60 MW) that includes BES (240 MWh) was considered for this Alternative. The 60 MW of solar generation plus BES would provide power, during operating periods as designed, to meet load and to provide peak shaving. However, it would not be firm capacity like the capacity sourced from the Mira Loma substation. Therefore, Alternative C would not provide reliability equivalent to the RTRP Hybrid Proposal. This is discussed further in Sections 4.2.3.3.2.1 and 4.2.3.3.2.4.SCE concluded that a power flow analysis for Alternative C was not necessary. The power flow analysis for Alternative C would be the same as for Alternative A but with an offset of load due to the supplemental Riverside generation. Therefore, power flow analysis for Alternative C would not provide any additional insights.

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The Solar PV/BES capital cost estimate breakdown is as follows:1. 60 MW Solar PV – Crystalline Utility Scale Solar Farm = $84M (60 MW X $1.4M/MW)2. 240 MWh BES (Lithium-Ion Peaker) = $69.6M ($0.29M/MWh X 240 hours)3. One Substation (1 - 69/34.5 kV transformer, 4 - 34.5 kV circuits, 2 – 69 kV line positions, control building, Supervisory Control and Data Acquisition (SCADA), relay & protection, metering, grounding, fencing, foundations, structures and other appurtenant items for a complete installed substation = $8M4. One Double-Circuit 69 kV Line (4 miles) = $8M5. Land Acquisition = $94M (6 acres per MW, 60 MW X 6 acres = 360 acres X $6 square feet[$261,360/acre] = $94,089,600)826. Total cost = $264M ($84M + $70M +$8M + $8M + $94M)The estimates for Solar PV and for the BES were derived from Lazard’s Levelized Cost of Energy Analysis (Capital Cost Comparison) – Version 11.0 and Lazard’s Levelized Cost of Storage Analysis – Version 3.0 (Capital Cost Comparison), respectively.83This solar facility cost estimate does not include costs for permitting, management, legal, regulatory or financing costs.The total cost for Alternative C, including the solar facility is $503.4M.4.2.3.3.2.4 Alternative C is Not Feasible As explained previously with respect to Alternatives A and B, under California law, feasibility is defined as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors,” but may also take into account “other considerations” permitting the rejection of alternatives that are impractical or undesirable from a policy standpoint.84Under CEQA, the selection of project alternatives should be based primarily on the ability of one or more proposed alternatives to reduce significant impacts relative to the proposed project.85As with Alternatives A and B, Alternative C is not capable of being accomplished within the same time period as the RTRP Hybrid Proposal, and, based on the foregoing analysis of technological challenges and environmental impacts, is likely to increase, rather than avoid or reduce, the environmental effects of the project. Alternative C is also more expensive than the RTRP Hybrid Proposal. Alternative C should be rejected as infeasible.82An industry average for how many acres are needed for a solar farm is somewhere between 4 to 8 acres per MW. This Report uses 6.0 acres per MW, which is the mid-range value of the estimates as researched for this Report. 83Lazard’s Levelized Cost of Energy Analysis – Version 11.0 is available at https://www.lazard.com/perspective/levelized-cost-of-energy-2017. If a solar PV project of this size was found to be feasible within the City of Riverside, it could possibly be sited and installed by a third party under a Power Purchase Agreement (PPA). In that situation, the cost to Riverside would be based on a levelized cost per an agreed-upon schedule under the PPA. However, a capital cost estimate is appropriate for comparing the cost of the solar generation facility included in Alternative C with the estimated costs for the other Alternatives and the RTRP Hybrid Proposal.84SeeCEQA Guidelines § 15364; Pub. Resources Code §§ 21061.1, 21081; California Native Plant Soc, 177 Cal.App.4that 1001 (describing acceptable policy-based infeasibility determinations under CEQA).85SeeCEQA Guidelines § 15126.6(b). 103
With respect to timing, Alternative C is expected to increase the timeframe for completion of the project relative to the RTRP Hybrid Proposal. Depending on the extent of subsequently-required engineering and design modifications as well as permitting and related regulatory proceedings, the additional time necessary for the completion of any of the Alternatives could be five years or more.86As described in Section 3.5, these delays would place the reliability of Riverside’s system at continued risk of load shedding and potential distribution system blackout conditions, as SCE and Riverside expect that loading limits on Riverside’s sole existing interconnection to the SCE system at the Vista Substation will continue to be exceeded under normal operating conditions during peak demand periods. Under emergency conditions, including an outage of one of the Vista Substation transformers used to serve Riverside, involuntary load shedding is highly likely. Under both normal and emergency conditions, Riverside will be required to continue to rely on internal, gas-fired peaking units that are vulnerable to fuel supply deficiencies associated with the gas system and usage limitations related to air permitting. It is critical that any Alternative to the RTRP Hybrid Proposal be capable of completion within the same timeframe. Alternative C does not satisfy that criterion. Technological factors render Alternative C infeasible. With respect to the Mira Loma Substation, as explained above, SCE’s current design standards limit the number of transformers at its 230/69 kV substations to four transformers total, rated at 280 MW each. If the final transformer position available at Mira Loma is taken by one of the transformers required for Alternative C, SCE would still be required to acquire additional land to install the second transformer, and this would result in non-compliance with SCE and industry design standards, which could reduce the reliability of service to Riverside.87As explained in Section 4.2.3.1.2.2, SCE’s design standards are adopted to reflect sound engineering practices in order to mitigate reliability and operability concerns. Under Alternative C, SCE would likely face an accelerated need for a new A-Station in order to address capacity and reliability concerns for the Mira Loma service area. Moreover, from a technological perspective, Alternative C is the least effective of the three Alternatives studied in meeting the established Project Objectives, as the reduced number of 69 kV conductors would limit the additional capacity available to Riverside upon completion of the project to only 500 MW, short of Riverside’s needs, and would not provide redundancy for the Vista Substation.With respect to the additional internal generation resources that would be needed if Alternative C is adopted, the large scale solar facility and accompanying BES would not, by virtue of the intermittent nature of solar and the inherent operability limitations of BES, provide Riverside with the firm power that Riverside requires in order achieve the reliability Project Objectives.In addition to technological factors, Alternative C is likely to increase environmental impacts as discussed in Section 4.2.3.3.2.2. Alternative C requires four 69 kV circuits along two separate routes to deliver less energy than provided for under the RTRP Hybrid Proposal. Despite its reduced functionality, this configuration would create new environmental and landowner impacts. The two 69 kV line routes would result in an estimated total of 20.3 line miles versus the 9.7-mile RTRP Hybrid Proposal. Roughly doubling the line mileage correspondingly doubles the environmental impacts. Alternative C would use an increased number of steel structures (409 steel structures needed for 86Seefurther discussion of potential delay in Section 3.5.87SeeSCE Subtransmission Planning Criteria and Guidelines (September 24, 2015). SCE’s standards, subtransmission planning criteria and guidelines are considered proprietary and contain confidential material. Relevant portions of same can be made available upon request provided appropriate safeguards are in place to protect their confidentiality. 104
Alternative C versus 63 for the RTRP Hybrid Proposal) and land parcels (160 for the overhead segments as compared with 71 for the RTRP Hybrid Proposal), which would impact affected landowners and increase the challenges of securing easements. The additional structures would also increase vulnerabilities to damage from, for example, traffic and other environmental conditions. Finally, the likely impacts to wildlife are greater under Alternative C. Installing a large scale solar facility within the Riverside service territory is also likely infeasible. As is discussed in Section 4.3.2.3, Riverside has not identified any locations within the City where a facility of the requisite size – which SCE and Riverside estimate would need to be at least 360 acres for a 60 MW solar facility – could realistically be sited. Attempting to site such a facility outside of the Riverside service territory, even if feasible from an environmental perspective, would still require added transmission facilities to ensure the output of such a facility could be delivered to the Riversidesystem.Social factors also support a finding of infeasibility. The large number of structures and line miles described above in connection with environmental factors will create greater impacts on the communities located adjacent to the Alternative C facilities relative to the impact that the shorter route and reduced number of structures associated with the RTRP Hybrid Proposal will have on communities adjacent to the project. The C1 Line route follows the RTRP Hybrid Proposal route, but line route C2 does not. SCE and Riverside anticipate that new community opposition would arise and that new environmental analyses of the route C2 may be required, with a corresponding delay of the project’s timing. As shown in Table 10, Alternative C is likely to have larger environmental justice impacts on disadvantaged communities.Finally, Alternative C would cost more in terms of total dollars and without respect to any tariff implications than the RTRP Hybrid Proposal. SCE and Riverside currently estimate the cost of Alternative C at $503.4 million, which is $98.1 million (or approximately 24%) above the cost of the RTRP Hybrid Proposal. This added cost does not reflect the potential cost increases associated withdelays and new environmental and permitting processes. The increased total costs contribute to an overall finding of infeasibility based on technological,social, and policy-based considerations regarding prudent electrical system planning and use of ratepayer funds noted above.4.3 Other Interim Solutions ConsideredIn addition to the foregoing lower voltage Alternatives, the ALJ directed that this Report consider and evaluate “other interim solutions available to RPU that would mitigate the electrical system impacts until technological advancements in battery storage and distributed solar are feasible at the project scale.” At this time, it is unknown when technological advancements in battery storage and distributed solar will become feasible at the project scale and could therefore serve as viable permanent alternatives to the RTRP Hybrid Proposal, and attempting to identify a specific year when these circumstances may arise would be speculative. Nonetheless, pursuant to the ALJ’s directive, SCE and Riverside have considered and assessed a variety of potential interim solutions that may mitigate Riverside’s electrical system needs in a manner consistent with the Project Objectives. As discussed below, none of the interim solutions that the parties considered is capable of providing adequate mitigation. 105

4.3.1 Minimum Interim Power NeedsThe Vista Substation source to Riverside has a loading limit of 557 MW. For planning purposes, Riverside’s total current internal generation capacity is 180 MW (RERC 3 X 48 = 144 MW + Springs 36 MW) under single-contingency conditions that would shut down a RERC unit.88Thus, Riverside’s total current capacity to serve load (comprised of Riverside’s existing internal generation resources plus the Vista Substation transformers) is 737 MW (557 MW + 144 MW + 36 MW).Riverside’s Power Resource Planning group projects a peak load of 669 MW by 2023 and 734 MWby 2038.SeeSection 3.4.2.3. At a minimum, any interim solution would need to be able to address all of Riverside’s power needs in the event power from the Vista Substation was unavailable. Any interim solution providing less than 489 MW by 2023 would notconstitute an equivalent, redundant source of reliable energy in the event power from SCE’s Vista Substation was interrupted. Assuming Riverside’s internal generation capacity of 180 MW (144 MW + 36 MW) under contingency conditions of one RERC unit out-of-service remains constant, this capacity is assumed equivalent to Riverside’s forecast need in 2023 (669 MW), less Riverside’s internal generation capacity (180 MW)under contingency conditions, or 489 MW. If the interim solution remains in place until 2038, the minimum needed capacity for any interim solution is equivalent to the forecast need in 2038 (734 MW), less Riverside’s internal generation capacity (180 MW) under contingency conditions, or 554 MW. In order to satisfy the Project Objective of reducing dependence on Vista Substation and increasing overall reliability, this Report assumes any given interim solution would need to supply a minimum of 489 MW of capacity by 2023, ramping up to 554 MW by 2038.The analysis of interim solutions set forth below focuses primarily on whether any of the interim solutions is realistically capable of supplying a minimum of 489 MW of capacity by 2023 (and correspondingly, 554 MW of capacity by 2038). As shown below, the interim solutions are not adequate substitutes for the RTRP Hybrid Proposal, even as a temporary bridge to a future time period in which technological advancements may permit reliance on battery storage and/or distributed solar facilities. Even under severely reduced capacity figures that reflect the elimination of the RTRP Hybrid Proposal’s policy goal of mitigating current reliability risks arising from Riverside’s dependence on a sole point of interconnection to the SCE system – removal of which is viewed as unreasonable and unrealistic by Riverside and SCE given the Project’s intended purpose – none of the interim solutions meets Riverside’s system needs.4.3.2 Analysis of Interim Solutions The interim solutions that SCE and Riverside evaluate below include:Energy Storage System facilities (Battery, Pumped Hydro and Compressed Air).Local Generation (Gas-Fired Combustion Turbines & Utility Scale Solar Facility).Distributed Energy Resources.Renewable Generation.Energy Conservation programs.These technologies and programs have different attributes that, in concept, can help Riverside manage its electric system reliably and efficiently, and Riverside is already availing itself of some of these programs and technologies. For example, the interim solutions that generate power could potentially provide capacity to meet Riverside load and could be used for peak shaving. Indeed, this is exactly how Riverside’s existing gas-fired generation and distributed generation is operated and functions 88In this context, the contingency condition refers to the loss of a single RERC generating unit. 106
within the Riverside electric system today. Similarly, Riverside’s energy conservation programs are key components of Riverside’s retail service offerings and provide benefits to Riverside in terms of offsets to load. The interim solutions that SCE and Riverside have evaluated can provide support in the form of additional capacity to the baseload power that Vista Substation provides Riverside, although, as discussed below, none of the solutions can be deployed on an interim basis on a sufficient scale to either obviate the need for the RTRP Hybrid Proposal entirely or provide an adequate temporary bridge to an unknown future date when battery storage and distributed solar may fully replace the need for the RTRP Hybrid Proposal. Despite their varying degrees of incremental capacity benefits, none of these interim solutions would adequately mitigate the risk of an interruption or outage of Riverside’s sole interconnection to the SCE system at the Vista Substation. None of the interim solutions is capable of replacing the total power that would be lost due to an interruption or outage at the Vista Substation, and Riverside would continue to face the very real risk of load shedding and/or distribution system blackouts that the RTRP Hybrid Proposal is intended to avoid.4.3.2.1 Energy Storage SystemsESS encompasses a range of technologies and may include:Electrochemical (battery) storage.Pumped-hydro storage.Compressed-air storage.Generally speaking, while a BES could provide benefits to Riverside’s electrical system, and Riverside is actively exploring the deployment of pilot programs in order to understand and potentially expand usage of BES within its electric system, BES is not an adequate substitute for the RTRP Hybrid Proposal, even on an interim basis. Primarily due to constraints related to the scale and cost of battery technology at this time, the deployment of batteries cannot reasonably be expected to offset the 489 MW of load that is needed in order to provide comparable levels of reliability to the RTRP Hybrid Proposal.First, with respect to the potential scale of BES deployment, the currently-effective storage procurement targets imposed under State law (Assembly Bill 2514) by the CPUC on the California-jurisdictional investor-owned electric utilities (including SCE, Pacific Gas and Electric Company, and San Diego Gas & Electric Company or “SDG&E”) total 1,325 MW of ESS,89plus an additional 500 MW pursuant to Assembly Bill 2868.90Assuming that Riverside could obtain, test, install, and operationally deploy 489 MW of BES by 2023 is especially unrealistic when viewed in light of the 89See, e.g., CPUC Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy Storage Systems (R.10-12-007), Decision Adopting Energy Storage Procurement Framework and Design Program(D.13-10-040),available at:http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M079/K533/79533378.PDF, at 2, 15 (requiring initial procurement of ESS by SCE and PG&E of 580 MW and 165 MW by SDG&E consistent with AB 2514);California Assembly Bill 2514 (2010, Skinner), available at:http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200920100AB2514, (requiring the CPUC to pen a proceeding to determine appropriate targets for ESS); California Assembly Bill 2868 (2016, Gatto), available at: http://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=201520160AB2868, (requiring an additional 500 MW of distributed energy storage systems distributed equally among the utilities). 90While these requirements do contain some technology and locational specifications, not all of the procured ESS is required to consist of battery technologies. 107
significantly lower (in relative terms) procurement targets established for the California-jurisdictional electric utilities under State law. Notably, none of these utilities has been directed to obtain sufficient BES to serve an anticipated 73.1% share of its projected peak load, which is what a 489 MW BES procurement target would be equivalent to with respect to Riverside. Even at lower procurement levels that, as discussed above, would not meet the reliability Project Objectives, Riverside would need to procure BES well in excess of required levels for the California investor-owned utilities as a share of peak load. For example, a 60 MW BES project represents approximately 9.0% of Riverside’s projected peak load in 2023, whereas SCE’s State procurement requirement represents only approximately 2.3% of its 2023 peak load.91Riverside’s current procurement target for energy storage, established in September 2017, is 6 MW by 2020, representing 1% of its peak load.Also with respect to scale, a 489 MW procurement target is also unrealistic in view of current levels of BES deployment nationally. A 2016 study summarizing the then-current status of grid-scale BES deployments throughout the United States based upon reported data in the Department of Energy’s Global Energy Storage Database found that, as of the first quarter of 2016, only 400 MW of grid-scale BES (consisting of 205 projects ranging in size from 4 kW to 36 MW) were deployed throughout the United States, excluding non-operational facilities and projects then under some phase of development and/or construction.92A 489 MW procurement target of BES for Riverside would exceed the installed grid-scale BES capacity throughout the entire United States as of the first quarter of 2016.Second, in addition to scale, BES continues to represent an expensive technology, particularly at the quantities needed to provide a viable interim alternative solution to the RTRP Hybrid Proposal. Recently-published studies by Lazard Frères & Co. LLC reflect that the capital cost of lithium-ion energy storage ranges from $1.2 million/MW to $1.7 million/MW for the purpose of gas peaker replacement and $2.3 million/MW to $3.3 million/MW for the purpose of distribution system augmentation.93This compares to an average capital cost of $1.0 million/MW for gas peakers and a capital cost of $0.7 million/MW for the RTRP Hybrid Proposal. Although the costs for lithium-ion technology may decrease in the near term,94it is unlikely that projected cost decreases in the next five years would be adequate to render this technology economically viable as an alternative to the RTRP Hybrid Proposal.Third, BES is incapable of providing the same reliability benefits of the Project and would not obviate the need for a second interconnection to ensure reliability. Even if the scale and cost did not render BES highly impractical, BES simply cannot perform the same functions of the RTRP HybridProposal, and Riverside’s electric system would continue to be vulnerable to the loss of the Vista Substation interconnection. Assuming BES could be deployed in sufficient quantities, current BEStechnology limits discharging to a specified number of hours. For example, a 240 MWh BES would provide 60 MW of capacity over four hours. This limited capability does not obviate the need for the 91SCE’s forecast for 2023 is 24,726 MW. SeeCalifornia Energy Commission, 2017 Integrated Energy Policy Report (Docket # 17-IEPR-01), available at: http://www.energy.ca.gov/2017_energypolicy/. 580 MW of ESS as required under D.13-10-040 is approximately 2.3% of SCE’s total 24,726 MW of predicted 2023 load.92David Hart and Alfred Sarkissian, Deployment of Grid-Scale Batteries in the United States at 8 & n.8 (2016), available athttps://energy.gov/sites/prod/files/2017/01/f34/ Deployment%20of%20Grid-Scale%20Batteries%20in%20the%20United%20States.pdf.93Lazard, Levelized Cost of Storage Analysis – Version 3.0 (2017) at 15, available at https://www.lazard.com/perspective/levelized-cost-of-storage-2017/. 94The Lazard analysis (id.at 16) predicts a 36% decrease in lithium-ion costs over the next five years. 108
RTRP Hybrid Proposal within the five year timeframe and would leave the Riverside electric system vulnerable to contingencies involving the Vista Substation.Further, Riverside’s existing distribution system would need to be modified and/or upgraded to be able to offer sufficient connectivity for charging capacity in the vicinity of installed BES locations. Battery storage solutions involve both charging and discharging; when discharging, a battery is a resource, and when charging, it is a load. To accommodate charging and discharging for a large BES project, Riverside would need to plan and potentially perform upgrades to its distribution system in order to ensure that the reliability impacts would be manageable and any effects of the BES on the transmission system outside of Riverside are studied, well-understood by SCE and the CAISO, and mitigated if necessary. While SCE and Riverside are committed to exploring BES further outside of this proceeding and to meeting all applicable State policy mandates relating to storage procurement, BES deployment is not an adequate interim mitigation. At this time, SCE and Riverside are unaware of BES deployments on a comparable scale elsewhere in the United States for the specific purpose of transmission upgrade deferral, and BES would not, in the use case presented here, remove the need for a second point of interconnection between the SCE and Riverside systems. For all of the reasons stated above, the scale, cost, and technological limitations of BES make BES infeasible as an interim alternative to the RTRP Hybrid Proposal.Beyond BES, other storage systems such as Pumped-Hydro and Compressed-air storage are not feasible within the City of Riverside at any size. There are siting, environmental, economic, and technical challenges with these technologies as they pertain to Riverside:a. A pumped-hydro energy storage system would require a water source and two large-capacity reservoirs at different elevations. It could require hundreds of acres of land for sufficient reservoir capacity to provide over 500 MW of capacity, and the two reservoirs would have to be at different elevations. These features do not exist within the City. A pumped-storage facility located outside of the City likely would require a high voltage transmission line similar to what is currently proposed as part of the RTRP Hybrid Proposal, as the energy would have to be delivered to Riverside to meet the Project Objectives. Given that a large scale pumped storage facility has not been installed within the United States in the past ten years, it is impractical to assume that a pumped storage facility could be sited and constructed (including associated transmission lines) in order to provide any level of capacity to Riversideby 2023.95b. Compressed-air storage systems are being constructed with large capacities (100+ MW), but they require some form of underground geologic formation (abandoned mine, porous rock, etc.) in order to store the compressed air. No such formation exists within the City of Riverside. Additionally, a high voltage transmission line similar to what is currently proposed as part of the RTRP Hybrid Proposal likely would be required for a compressed-air storage facility located outside of the City.4.3.2.2 Gas-Fired GenerationA gas-fired generation alternative would not meet the Project Objectives of the RTRP Hybrid Proposal. Adding more local gas-fired generation would result in greater environmental (footprint and 95SeeHart at 17 (“It is worth noting that no new pumped hydro capacity has been added in the U.S. in more than a decade.”). 109
air quality) and economic impacts (costs to Riverside ratepayers), operational permit requirements, and reliability risks due to uncertainty of available fuel sources.As noted elsewhere, the sole source of external bulk energy supply for Riverside is through the 230/69 kV transformers at the Vista Substation. Riverside’s electrical demand has exceeded the available 557 MW of capacity from Vista Substation since 2006, and this was a primary driver in Riverside’s decision to develop local generation resources – the RERC units – capable of meeting Riverside’s energy needs during peak load conditions.96These local generation resources were constructed within Riverside in part to mitigate the capacity limits of Vista Substation until a second point of interconnection could be established. In effect, Riverside has already undertaken the installation of peaking capacity as an interim solution pending completion of the RTRP Hybrid Proposal.While the RERC units reduce the power that must flow through the transformers at Vista Substation to Riverside by generating and supplying it locally, they are “Peaker” units. As such, the number of hours these units can operate is limited by the permit requirements issued by the SCAQMD. The permit requirements issued by the District are very stringent. Each of the four turbines at RERC (48 MW each) and the Springs Generation (36 MW) is restricted to rolling 1,200 and 1,550 equivalent hours, respectively, of operation per year. If one turbine is unavailable for a long time, another one can be used for the remaining hours of the one that is down. Note that hours are determined based on pounds of emissions that the generators emit. The turbines’ starts are limited to no more than two per day for a total of 1,200 operating hours per year. Typically these units are not run for more than four hours a day.It is not feasibleto install additional gas-fired generation in Riverside’s service area due to air quality issues as well as siting, operational, and economic considerations. In light of the significant number of MWs required (up to 489 MW), the use of Peakers as an interim solution would: (1) be less cost effective than the RTRP Hybrid Proposal; (2) suffer from reliability risks due to uncertainties in the availability of natural gas fuel sources; (3) likely be impossible to site within the City of Riverside;97and (4) not represent prudent utility planning in that it would defer transformer capacity additions by continued installation of peaking units.With regard to fuel supply uncertainties, the well-documented and ongoing limitations at the Aliso Canyon natural gas storage facility, which is a source of natural gas supply for the Riverside Peaker units as well as other natural gas units throughout southern California, suggest that utilities should not look toward the expansion of natural gas Peakers as a means of addressing reliability needs, at least until the long-term status of the Aliso Canyon facility is clarified. As the Energy Division is likelyaware, the CAISO, working in conjunction with its stakeholders, the CPUC, and Southern California Gas Company has adopted various measures intended to mitigate the risks to the electric system stemming from use-limitations at Aliso Canyon over the period of impaired Aliso Canyon operations. In connection with those efforts, Riverside determined that because of the capacity limitations at the Vista Substation and its dependence on the RERC Peakers during times when demand is at its highest to avoid distribution system blackouts, Riverside would be disproportionately impacted if its use of the RERC units during a high load period coincided with a natural gas curtailment. Riversideexplained in comments to the CAISO that, “as a result of these local constraints [referring to the import limitation at Vista] [Riverside] must utilize [its] internal gas-fired resources to prevent 96As noted elsewhere, Riverside’s 36 MW Springs Generating Plant is rarely used due to operating constraints and because it is not as economical as the RERC units.97Riverside estimates that it would have to find at least a 42 acre site, which is highly unlikely within Riverside. 110
blackouts
” and that the gas company’s curtailment requirements would, for this reason, have an “unduly harsh impact,” including, potentially, load-shed events.98For all of the reasons previously described to the CAISO, installation of additional natural gas units within Riverside would only worsen Riverside’s vulnerability to gas system limitations.4.3.2.3 Large Scale Solar There are no large scale PV solar projects – defined for the purpose of this Report as 25 MW or greater – within the City of Riverside. Currently, the largest solar installation (Tequesquite) that Riverside has interconnected within its distribution system is 7.3 MW. While a large scale solar facility could help mitigate capacity concerns within the Riverside system during the hours when the facility is operating (thereby helping to provide both baseload capacity and peak shaving), such a facility is not an adequate substitute for an additional point of interconnection with the SCE system, because it would not provide the continuous power than the RTRP Hybrid Proposal could provide.Moreover, there would be significant siting and cost challenges associated with such interim mitigation.As an initial matter, installation of a large scale solar facility to meet 489 MW of demand by 2023 is technically infeasible due to siting constraints for such facilities within or near the City of Riverside. Acreage estimates for a large scale solar project typically range from 4 to 8 acres per MW of project output, which, for 489 MW of large scale solar capacity, results in a range of 1,956 to 3,912 acres.99This is roughly equivalent to 3 to 6 square miles. The City of Riverside currently has a total area of 81.4 square miles, and Riverside would therefore need to dedicate approximately 4-7% of the land within the City to large scale solar facilities in order to provide adequate interim capacity as compared with the RTRP Hybrid Proposal. A screening of contiguous, undeveloped areas that are not dedicated to parks/open space within the City of Riverside reveals that procuring an approximately 360-acre site large enough to accommodate even a much smaller 60 MW solar farm is infeasible, let alone the minimum of 1,956 acres that would be needed to support 489 MW of solar capacity. Any available sites adjacent to the City would necessitate an equivalent amount of land and, most fundamentally for purposes of providing an interim alternative to the RTRP Hybrid Proposal, would also require a second point of interconnection in order to ensure that the capacity would be deliverable, with all of the costs and environmental impact challenges that would accompany attempting to site another such transmission facility in lieu of the RTRP Hybrid Proposal.Additionally, attempting to install large scale solar facilities as an interim alternative to completing the Project is not cost effective. SCE and Riverside estimate that a facility that would meet Riverside’s need for 489 MW of capacity would cost approximately $684.6 million,100and that is beforeincluding the estimated costs for any accompanying BES, which would be a critical component of any large scale solar facility in order to provide an adequate level of functionality given the intermittent nature of solar.98SeeComments on Behalf of the Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California on the Aliso Canyon Gas-Electric Coordination Issue Paper, Cal. Indep. Sys. Operator Corp., Aliso-Canyon Gas-Electric Coordination Phase 1 – Issue Paper (Mar. 30, 2016) available at http://www.caiso.com/informed/Pages/StakeholderProcesses/AlisoCanyonGasElectricCoordination.aspx.99In contrast, the RTRP Hybrid Proposal requires a total of approximately 100 acres for ROW.100SeeLazard’s Levelized Cost of Energy Analysis – Version 11.0 at 11 (489 MW X $1.4M/MW = $684.6 million). 111
One or more smaller scale PV facilities may be more feasible to site and integrate into the City’s electrical grid than a large scale solar project, but smaller quantities of solar capacity would not meet the reliability Project Objectives or, potentially, the capacity Project Objectives of the RTRP Hybrid Proposal and would likewise not be cost-effective. For example, if the size of the solar facility were reduced to 60 MW, the costs of large scale solar plus associated BES technology remain extremely high, especially when viewed in light of the diminished reliability associated with such an alternative.For all of these reasons, SCE and Riverside do not believe that large scale solar facilities, whether or not accompanied by BES, could provide adequate interim mitigation.4.3.2.4 Distributed GenerationA DG resource is typically less than 5.0 MW in net generating capacity, customer owned, net metered, and connected to the electrical distribution system through the customer’s service connection. Examples of DG include rooftop solar, fuel cells, micro turbines, photovoltaic, wind, landfill gas, and digester gas. Since 2008, Riverside has offered incentives for business and residential photovoltaic installations. Through this program, which Riverside implemented pursuant to the requirements of Senate Bill 1,Riverside has funded over $17.3 million in commercial and residential customer rebates associated with 1,845 solar installations within the City. These installations are capable of producing up to 11 MW of customer-generated solar energy during the hours in which they are operating.Including the capacity of solar DG resulting from the solar rebate program, Riverside’s current estimated installed capacity of DG within its system is less than 30 MW, and the power produced by the DG has not been sufficient to compensate for the observed peak load growth in the Riversidesystem. Expected incremental DG capacity is not sufficient to compensate for the predicted load growth for the Riverside system and would not allow Riverside to meet the RTRP Project Objectivesin a timely manner due to the comparatively small capacity of DG systems. Moreover, deployment of significant quantities of DG may require unknown quantities of upgrades to Riverside’s distribution system.In addition to having a relatively small capacity compared to Riverside’s forecasted electrical needs, DG and, particularly, rooftop solar, has a relatively high cost. For example, residential rooftop systems ranging in size from 3 kW to 10 kW have a total capital cost of $2.80 per watt DC, which is more than double the capital cost for utility scale solar.101Similar to utility scale solar projects, it would not be cost-effective to develop 489 MW of DG comprised, in significant part, of residential photovoltaic resources, which is the predominant form of DG deployment within the Riversideservice territory. As a general matter, DG capacity is limited and, in addition to not materially impacting Riverside’s required capacity needs, would not address the reliability need for the RTRP Hybrid Proposal to provide a second point for importing energy to Riverside. While Riverside is committed to reliable, efficient, and economic deployment and management of DG throughout its system, Riverside is likewise committed to procurement of renewable energy consistent with State laws and policies, and, for the reasons discussed above relating to large scale solar, this necessarily includes procurement of renewable energy from sources outside of Riverside. To ensure adequate deliverability of these resources, Riverside must have sufficient and reliable import capability into its system. Because Riverside does not anticipate that all of its energy needs are reasonably capable of 101SeeFu, Ran, Feldman, David, Margolis, Robert, Woodhouse, Mike, and Ardani, Kristen. 2017. U.S. Solar Photovoltaic System Cost Benchmark: Q1 2017. National Renewable Energy Laboratory. NREL/PR – 6A -68580 at 8. Available at https://www nrel.gov/docs/fy17osti/68580.pdf. 112
being met through DG, in addition to technical and logistical concerns, distributed generation is not a feasible interim alternative to satisfy Riverside’s electricity needs in lieu of the RTRP Hybrid Proposal.4.3.2.5 Conservation/Demand Response ProgramsEnergy Conservation and Load Management measures were also reconsidered as possible interim mitigation measures. Consistent with the findings of the 2013 FEIR, reliance on energy conservation and load management is not anticipated to be a viable interim solution to Riverside’s electrical needs in lieu of the RTRP Hybrid Proposal.Riverside, like most electric utilities in California, offers a variety of “demand-side management” programs and incentives, including energy efficiency, demand response, and, as discussed above, DG. In Riverside’s service territory, annual increases in load growth have exceeded the reductions in energy consumption from energy efficiency programs resulting in annual net increases in electrical demand that are reflected in Riverside’s peak load forecasts. Some of the above-mentioned alternatives to the RTRP were considered in the 2013 FEIR and were dismissed, because their capacity is limited, and they would not meet the Project Objectives such as providing a second point for importing bulk 230 kV energy for reliability purposes. Demand response programs such as “demand-side management” programs and incentives are not considered for system planning purposes in part because participants can opt out of participation at any time. 113

5. Summary and Conclusion As is more fully documented in Section 3.5 above, the need for the RTRP Hybrid Proposal to address ongoing reliability risks arising from Riverside’s dependence on its sole existing interconnection to the SCE transmission system is acute. In response to the ALJ’s directive that SCE, Riverside, and the CAISO consider and evaluate lower voltage design alternatives that may, in full or in part, meet the Project Objectives of the RTRP Hybrid Proposal, SCE and Riverside identified and studied both lower voltage Alternatives and interim solutions that may provide an adequate “bridge” to a time period when BES and distributed generation are feasible at the project scale. After careful evaluation of the identified lower voltage Alternatives as described in this Report, Riverside and SCE have determined that, in addition to being more costly than the RTRP Hybrid Proposal, none of the Alternatives is capable of satisfying the Project Objectives, and none of them is expected to have a reduced environmental impact. With respect to potential interim options, SCE and Riverside assessed a number of approaches that Riverside could temporarily adopt instead of the RTRP Hybrid Proposal, and none of these interim solutions represents a reasonable mitigation alternative to the RTRP Hybrid Proposal. Based on their analyses as fully documented in Section 4 of this Report, SCE and Riversidehave concluded that the lower voltage Alternatives and interim solutions are unsuitable and infeasible and should not be adopted.The analysis in the Report demonstrates that:The Alternatives evaluated in this Report would not satisfy most of the specified Project Objectives identified in Section 3.1.The lower voltage Alternatives would have greater environmental impacts than the RTRP Hybrid Proposal and therefore would be unsuitable as a threshold matter. Table 13 depicts these impacts.The lower voltage Alternatives are not feasible alternatives to the RTRP Hybrid Proposal; i.e., they are not “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social, and technological factors” and “other considerations” permitting the rejection of alternatives that are impractical or undesirable from a policy standpoint.102Adopting any of the Alternatives potentially would impose years of delay to a project that is already more than ten years past its initial CAISO approval date and that has been, and continues to be, crucial to addressing serious reliability risks.As summarized in Table 14 below, Alternatives A, B, and C are all more expensive than the RTRP Hybrid Proposal.The CEQA Guidelines (Section 15126.6(b)) stress that the selection of project alternatives must be based primarily on the ability to reduce significant impacts relative to the proposed project. None of the Alternatives would reduce environmental impacts as compared to the RTRP Hybrid Proposal, as summarized in Table 13.102SeeCEQA Guidelines § 15364; Pub. Resources Code §§ 21061.1, 21081; California Native Plant Soc., 177 Cal.App.4th at 1001 (describing acceptable policy-based infeasibility determinations under CEQA).

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APPENDICESAPPENDIX A PHOTOGRAPHS FOR ALTERNATIVE CORRIDORSAPPENDIX B SCE ENVIRONMENTAL SCREENING REPORTAPPENDIX C POWER ENGINEERS QUALIFICATIONS

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APPENDIX A PHOTOGRAPHS FOR ALTERNATIVE CORRIDORSSeeFigure 7, Figure 11 and Figure 17 for Photo Locations.

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Photo 1:School and residential conflicts: 68thStreet.

Photo 2:Residential Conflicts: Jurupa Avenue

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Photo 3: East of Mira Loma Substation.

Photo 4:Adjacent to Jurupa Valley High School.

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Photo 5: Adjacent to Mira Loma Middle School
Photo 6: Residential Conflicts: Limonite Avenue

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Photo 7:Railroad, Residential and Commercial Conflicts: Van Buren Blvd.

Photo 8: Residential Conflicts: Clay St.

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Photo 9: Residential Conflicts: Limonite Avenue.

Photo 10: Etiwanda Ave. / Santa Ana St.

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Photo 11: Magnolia Ave. / Grant St.

Photo 12:Hamner Ave / 5thSt.

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Photo 13: N. McKinley St. / Parkview Dr.

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APPENDIX B SCE ENVIRONMENTAL SCREENING REPORT
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SCE Environmental Screening Report
Area of Interest (AOI) InformationArea : 2,097.08 acres 10/23/2017
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SummaryName Count Area (acres) Length (mi)BIO - Species Points 161 N/A N/ABIO - Species Polys 4 0.88 N/ABIO - Bird Nest Points 33 N/A N/ABIO - Desert Tortoise Points 0 N/A N/ABIO - Habitat Polys 24 536.58 N/ACNDDB Poly May 2017 41 5280.74 N/ACFWO Species Occurrence 24 411.18 N/AJD Waters ESA 106 18.58 N/AFEMA Flood Zones 52 2567.99 N/ALocal Coastal Plan (LCP) 0 0 N/AGovernment Land, 2016 1 59.74 N/AMPO Capital Project Footprint 4 840.19 N/AUSFWS Critical Habitat -Polygon Features2 182.7 N/AUSFWS Critical Habitat - LinearFeatures0 N/A 0AQMD Districts 2 2097.09 N/ABIO - Species Points 10/23/2017
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# Species Name Common Special Status Type Occurrence Date Project Name1 Least Bell's Vireo FE: Federally Endangered August 28, 2016Riverside TransmissionReliability Project2 Least Bell's Vireo FE: Federally Endangered May 8, 2016Riverside TransmissionReliability Project3 Least Bell's Vireo FE: Federally Endangered June 16, 2016Riverside TransmissionReliability Project4 Least Bell's Vireo FE: Federally Endangered May 27, 2016Riverside TransmissionReliability Project5 Least Bell's Vireo FE: Federally Endangered June 5, 2016Riverside TransmissionReliability Project6 Least Bell's Vireo FE: Federally Endangered May 16, 2016Riverside TransmissionReliability Project7 Least Bell's Vireo FE: Federally Endangered July 1, 2016Riverside TransmissionReliability Project8 Least Bell's Vireo FE: Federally Endangered July 17, 2016Riverside TransmissionReliability Project9 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 27, 2016Riverside TransmissionReliability Project10 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJuly 1, 2016Riverside TransmissionReliability Project11 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 28, 2016Riverside TransmissionReliability Project12 California Ground Squirrel No Special Status Type May 1, 2016Riverside TransmissionReliability Project13 Least Bell's Vireo FE: Federally Endangered July 28, 2016Riverside TransmissionReliability Project14 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 5, 2016Riverside TransmissionReliability Project15 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 5, 2016Riverside TransmissionReliability Project16 Least Bell's Vireo FE: Federally Endangered June 15, 2016Riverside TransmissionReliability Project17 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 16, 2016Riverside TransmissionReliability Project18 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 19, 2016Riverside TransmissionReliability Project19 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 19, 2016Riverside TransmissionReliability Project20 Willow Flycatcher SE: State Endangered June 7, 2016Riverside TransmissionReliability Project21 Least Bell's Vireo FE: Federally Endangered May 26, 2016Riverside TransmissionReliability Project22 Least Bell's Vireo FE: Federally Endangered May 17, 2016Riverside TransmissionReliability Project23 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 15, 2016Riverside TransmissionReliability Project24 Least Bell's Vireo FE: Federally Endangered June 19, 2016Riverside TransmissionReliability Project 10/23/2017
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25 Yellow-Breasted Chat SSC: California Species ofSpecial ConcernJune 15, 2016 Riverside TransmissionReliability Project26 Least Bell's Vireo FE: Federally Endangered June 6, 2016Riverside TransmissionReliability Project27 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 27, 2016Riverside TransmissionReliability Project28 Least Bell's Vireo FE: Federally Endangered June 30, 2016Riverside TransmissionReliability Project29 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 30, 2016Riverside TransmissionReliability Project30 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 26, 2016Riverside TransmissionReliability Project31 California Ground Squirrel No Special Status Type June 22, 2016Riverside TransmissionReliability Project32 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 26, 2016Riverside TransmissionReliability Project33 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJuly 28, 2016Riverside TransmissionReliability Project34 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 18, 2016Riverside TransmissionReliability Project35 Brown-Headed Cowbird No Special Status Type June 5, 2016Riverside TransmissionReliability Project36 Least Bell's Vireo FE: Federally Endangered June 7, 2016Riverside TransmissionReliability Project37 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 16, 2016Riverside TransmissionReliability Project38 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 16, 2016Riverside TransmissionReliability Project39 Willow Flycatcher SE: State Endangered May 16, 2016Riverside TransmissionReliability Project40 Least Bell's Vireo FE: Federally Endangered May 28, 2016Riverside TransmissionReliability Project41 Least Bell's Vireo FE: Federally Endangered May 7, 2016Riverside TransmissionReliability Project42 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 28, 2016Riverside TransmissionReliability Project43 California WalnutCRPR 4: Plants of LimitedDistribution - A Watch ListJune 29, 2016Riverside TransmissionReliability Project44San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernNovember 21, 2010Tehachapi RenewableTransmission Project45 Loggerhead ShrikeSSC: California Species ofSpecial ConcernAugust 3, 2010Tehachapi RenewableTransmission Project46 Loggerhead ShrikeSSC: California Species ofSpecial ConcernJanuary 25, 2012Tehachapi RenewableTransmission Project47 Northern HarrierSSC: California Species ofSpecial ConcernDecember 14, 2011Tehachapi RenewableTransmission Project48 Peregrine Falcon SE: State Endangered December 14, 2011Tehachapi RenewableTransmission Project49 Loggerhead ShrikeSSC: California Species ofSpecial ConcernDecember 7, 2011Tehachapi RenewableTransmission Project50 Loggerhead ShrikeSSC: California Species ofSpecial ConcernNovember 30, 2011Tehachapi RenewableTransmission Project51 Northern HarrierSSC: California Species ofSpecial ConcernAugust 11, 2011Tehachapi RenewableTransmission Project 10/23/2017
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52 San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJuly 26, 2011 Tehachapi RenewableTransmission Project53San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJune 29, 2011Tehachapi RenewableTransmission Project54 Northern HarrierSSC: California Species ofSpecial ConcernDecember 7, 2010Tehachapi RenewableTransmission Project55 Loggerhead ShrikeSSC: California Species ofSpecial ConcernFebruary 25, 2014Tehachapi RenewableTransmission Project56 Prairie Falcon No Special Status Type December 26, 2013Tehachapi RenewableTransmission Project57 Cooper's Hawk WL: CDFW Watch List October 21, 2013Tehachapi RenewableTransmission Project58 Cooper's Hawk WL: CDFW Watch List June 22, 2016Tehachapi RenewableTransmission Project59 Cooper's Hawk WL: CDFW Watch List March 24, 2016Tehachapi RenewableTransmission Project60 White-Faced Ibis No Special Status Type December 2, 2015Tehachapi RenewableTransmission Project61 Loggerhead ShrikeSSC: California Species ofSpecial ConcernApril 7, 2015Tehachapi RenewableTransmission Project62 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 6, 2016Riverside TransmissionReliability Project63 California Ground Squirrel No Special Status Type May 2, 2016Riverside TransmissionReliability Project64 Least Bell's Vireo FE: Federally Endangered May 18, 2016Riverside TransmissionReliability Project 10/23/2017
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# Count1 142 113 94 95 86 87 68 69 410 411 412 413 314 315 316 317 318 319 320 221 222 223 224 225 226 227 228 129 130 131 132 133 134 135 136 137 138 139 140 141 142 1 10/23/2017
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43 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 1BIO - Species Polys# Species_Name_Common Special_Status_Type Occurrence_Date Project_Name1 Paniculate TarplantCRPR 4: Plants of LimitedDistribution - A Watch ListMay 21, 2017Riverside TransmissionReliability Project# Area (acres)1 0.88BIO - Bird Nest Points 10/23/2017
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# Species_Name_Common Special_Status_Species Observation_Date Project_Name1 Black Phoebe No March 24, 2016Tehachapi RenewableTransmission Project2 Black Phoebe No April 7, 2014Tehachapi RenewableTransmission Project3 Black Phoebe No May 27, 2013Tehachapi RenewableTransmission Project4 Western Kingbird No April 4, 2013Tehachapi RenewableTransmission Project5 Black Phoebe No March 31, 2013Tehachapi RenewableTransmission Project6 House Sparrow No June 3, 2012Tehachapi RenewableTransmission Project7 Black Phoebe No May 23, 2012Tehachapi RenewableTransmission Project8 Northern Mockingbird No August 17, 2016Tehachapi RenewableTransmission Project9 House Finch No June 28, 2016Tehachapi RenewableTransmission Project10 Hooded Oriole No June 15, 2016Tehachapi RenewableTransmission Project11 Western Kingbird No May 24, 2016Tehachapi RenewableTransmission Project12 Black Phoebe No May 24, 2016Tehachapi RenewableTransmission Project13 Cassin's Kingbird No April 12, 2016Tehachapi RenewableTransmission Project14 American Crow No April 3, 2016Tehachapi RenewableTransmission Project15 House Finch No March 28, 2016Tehachapi RenewableTransmission Project16 House Finch No March 25, 2016Tehachapi RenewableTransmission Project17 Killdeer No March 19, 2014Tehachapi RenewableTransmission Project18 House Sparrow No March 17, 2016Tehachapi RenewableTransmission Project19 Black Phoebe No February 28, 2016Tehachapi RenewableTransmission Project20 Northern Mockingbird No April 19, 2015Tehachapi RenewableTransmission Project21 House Sparrow No May 7, 2014Tehachapi RenewableTransmission Project22 Black Phoebe No March 4, 2012Tehachapi RenewableTransmission Project23 House Finch No August 9, 2011Tehachapi RenewableTransmission Project24 Cassin's Kingbird No June 26, 2011Tehachapi RenewableTransmission Project25 House Sparrow No May 10, 2011Tehachapi RenewableTransmission Project26 Black Phoebe No May 3, 2011Tehachapi RenewableTransmission Project27 American Crow No April 25, 2011Tehachapi RenewableTransmission Project 10/23/2017
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28 Northern Mockingbird No April 20, 2011Tehachapi RenewableTransmission Project29 House Sparrow No April 7, 2011Tehachapi RenewableTransmission Project30 House Sparrow No March 10, 2011Tehachapi RenewableTransmission Project31 Say's Phoebe No March 9, 2011Tehachapi RenewableTransmission Project32 American Crow No March 9, 2011Tehachapi RenewableTransmission Project33 American Crow No February 23, 2011Tehachapi RenewableTransmission Project 10/23/2017
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# Count1 12 13 14 15 16 17 18 19 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 1BIO - Habitat Polys 10/23/2017
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# Habitat_Type Habitat_Category Determination_Date Project_Name1 Delhi Sands Flower-Loving Fly Suitable July 31, 2015Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project2 Other Suitable June 6, 2016Riverside TransmissionReliability Project3 Delhi Sands Flower-Loving Fly Suitable June 7, 2016Riverside TransmissionReliability Project4 Other Suitable June 1, 2016Riverside TransmissionReliability Project5 Delhi Sands Flower-Loving Fly TBD October 5, 2016Riverside TransmissionReliability Project6 Vernal Pool Branchiopods Suitable February 26, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project7 Vernal Pool Branchiopods Suitable January 6, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project8 Delhi Sands Flower-Loving Fly Suitable October 5, 2016Riverside TransmissionReliability Project9 Vernal Pool Branchiopods Suitable February 3, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project# Area (acres)1 413.772 62.993 33.324 21.835 1.926 1.237 0.848 0.649 0.04CNDDB Poly May 2017 10/23/2017
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# Common Name Scientific Name Area (acres)1 Delhi Sands flower-loving fly Rhaphiomidas terminatus abdominalis 4105.72 western mastiff bat Eumops perotis californicus 3503 least Bell's vireo Vireo bellii pusillus 138.444 California glossy snake Arizona elegans occidentalis 109.175 yellow-breasted chat Icteria virens 107.276 yellow warbler Setophaga petechia 107.277 burrowing owl Athene cunicularia 102.188Southern Cottonwood Willow RiparianForestSouthern Cottonwood Willow RiparianForest88.849Southern California Arroyo Chub/SantaAna Sucker StreamSouthern California Arroyo Chub/SantaAna Sucker Stream53.1110 Santa Ana sucker Catostomus santaanae 49.9311 arroyo chub Gila orcuttii 44.5612 Lawrence's goldfinch Spinus lawrencei 12.9513 Santa Ana speckled dace Rhinichthys osculus ssp. 3 11.1414 Swainson's hawk Buteo swainsoni 0.0515 pocketed free-tailed bat Nyctinomops femorosaccus 0.0516 Busck's gallmoth Carolella busckana 0.0517 western yellow bat Lasiurus xanthinus 0.05CFWO Species Occurrence# Common Name Scientific Name Area (acres)1 least Bell's vireo Vireo bellii pusillus 406.212 Santa Ana sucker Catostomus santaanae 4.96JD Waters ESA# Name ESA Type Area (acres)1 NHD Red 18.58FEMA Flood Zones# Flood Zone Area (acres)1 X 2286.392 AE 205.253 0.2 PCT ANNUAL CHANCE FLOOD HAZARD 41.774 A 34.57Government Land, 2016# Agency Name Agency Area Name Area (acres)1 ST Hidden Valley 59.74MPO Capital Project Footprint 10/23/2017
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# Capital Project Name EPM COMP_LEVEL Area (acres)1 RTRP/Wildlife Substation Gary BusteedStage 04: ApplicationProduction751.912 TRTP 500 kV UG Jenny McGee Revegetation 42.473 Circle City Alisa KrizekStage 04: ApplicationProduction42.054 TRTP 4 -11 Jenny McGee Revegetation 3.75USFWS Critical Habitat - Polygon Features# Common Name Scientific Name Area (acres)1 Least Bell's vireo Vireo bellii pusillus 105.772 Santa Ana sucker Catostomus santaanae 76.93AQMD Districts# District Name Area (acres)1 South Coast 2097.09Southern California Edison (SCE) 10/23/2017
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SCE Environmental Screening Report
Area of Interest (AOI) InformationArea : 2,162.24 acres 10/23/2017
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SummaryName Count Area (acres) Length (mi)BIO - Species Points 100 N/A N/ABIO - Species Polys 1 0.09 N/ABIO - Bird Nest Points 34 N/A N/ABIO - Desert Tortoise Points 0 N/A N/ABIO - Habitat Polys 66 648.93 N/ACNDDB Poly May 2017 41 4854.59 N/ACFWO Species Occurrence 20 213.26 N/AJD Waters ESA 37 8.44 N/AFEMA Flood Zones 60 3151.45 N/ALocal Coastal Plan (LCP) 0 0 N/AGovernment Land, 2016 1 14.77 N/AMPO Capital Project Footprint 5 560.36 N/AUSFWS Critical Habitat -Polygon Features2 118.41 N/AUSFWS Critical Habitat - LinearFeatures0 N/A 0AQMD Districts 2 2162.38 N/ABIO - Species Points 10/23/2017
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# Species Name Common Special Status Type Occurrence Date Project Name1 Unknown No Special Status Type November 29, 2016 Lugo-Mira Loma No. 32 Unknown No Special Status Type November 29, 2016 Lugo-Mira Loma No. 23 Least Bell's Vireo FE: Federally Endangered August 28, 2016Riverside TransmissionReliability Project4 Least Bell's Vireo FE: Federally Endangered June 16, 2016Riverside TransmissionReliability Project5 Least Bell's Vireo FE: Federally Endangered May 16, 2016Riverside TransmissionReliability Project6 Least Bell's Vireo FE: Federally Endangered May 8, 2016Riverside TransmissionReliability Project7 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 28, 2016Riverside TransmissionReliability Project8 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 19, 2016Riverside TransmissionReliability Project9 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 19, 2016Riverside TransmissionReliability Project10 Least Bell's Vireo FE: Federally Endangered July 17, 2016Riverside TransmissionReliability Project11 Willow Flycatcher SE: State Endangered June 7, 2016Riverside TransmissionReliability Project12 Least Bell's Vireo FE: Federally Endangered June 5, 2016Riverside TransmissionReliability Project13 Least Bell's Vireo FE: Federally Endangered July 1, 2016Riverside TransmissionReliability Project14 Least Bell's Vireo FE: Federally Endangered June 19, 2016Riverside TransmissionReliability Project15 Least Bell's Vireo FE: Federally Endangered July 28, 2016Riverside TransmissionReliability Project16 Least Bell's Vireo FE: Federally Endangered May 27, 2016Riverside TransmissionReliability Project17 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJuly 1, 2016Riverside TransmissionReliability Project18 Least Bell's Vireo FE: Federally Endangered May 17, 2016Riverside TransmissionReliability Project19 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 5, 2016Riverside TransmissionReliability Project20 Least Bell's Vireo FE: Federally Endangered May 28, 2016Riverside TransmissionReliability Project21 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 28, 2016Riverside TransmissionReliability Project22 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 5, 2016Riverside TransmissionReliability Project23 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 27, 2016Riverside TransmissionReliability Project24 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 27, 2016Riverside TransmissionReliability Project25 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJuly 28, 2016Riverside TransmissionReliability Project26 Yellow-Breasted Chat SSC: California Species ofSpecial ConcernMay 17, 2016 Riverside TransmissionReliability Project 10/23/2017
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27 Least Bell's Vireo FE: Federally Endangered June 7, 2016Riverside TransmissionReliability Project28 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 16, 2016Riverside TransmissionReliability Project29 Least Bell's Vireo FE: Federally Endangered June 29, 2016Riverside TransmissionReliability Project30San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernNovember 21, 2010Tehachapi RenewableTransmission Project31 Loggerhead ShrikeSSC: California Species ofSpecial ConcernAugust 3, 2010Tehachapi RenewableTransmission Project32 Loggerhead ShrikeSSC: California Species ofSpecial ConcernJanuary 25, 2012Tehachapi RenewableTransmission Project33 Northern HarrierSSC: California Species ofSpecial ConcernDecember 14, 2011Tehachapi RenewableTransmission Project34 Brown-Headed Cowbird No Special Status Type June 5, 2016Riverside TransmissionReliability Project35 Loggerhead ShrikeSSC: California Species ofSpecial ConcernDecember 7, 2011Tehachapi RenewableTransmission Project36 Loggerhead ShrikeSSC: California Species ofSpecial ConcernNovember 30, 2011Tehachapi RenewableTransmission Project37 Northern HarrierSSC: California Species ofSpecial ConcernAugust 11, 2011Tehachapi RenewableTransmission Project38San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJuly 26, 2011Tehachapi RenewableTransmission Project39San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJune 29, 2011Tehachapi RenewableTransmission Project40 Northern HarrierSSC: California Species ofSpecial ConcernDecember 7, 2010Tehachapi RenewableTransmission Project41 Loggerhead ShrikeSSC: California Species ofSpecial ConcernFebruary 25, 2014Tehachapi RenewableTransmission Project42 Prairie Falcon No Special Status Type December 26, 2013Tehachapi RenewableTransmission Project43 Cooper's Hawk WL: CDFW Watch List October 21, 2013Tehachapi RenewableTransmission Project44 Cooper's Hawk WL: CDFW Watch List June 22, 2016Tehachapi RenewableTransmission Project45 Cooper's Hawk WL: CDFW Watch List March 24, 2016Tehachapi RenewableTransmission Project46 White-Faced Ibis No Special Status Type December 2, 2015Tehachapi RenewableTransmission Project47 Loggerhead ShrikeSSC: California Species ofSpecial ConcernApril 7, 2015Tehachapi RenewableTransmission Project48 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJuly 1, 2016Riverside TransmissionReliability Project49 Peregrine Falcon SE: State Endangered December 14, 2011Tehachapi RenewableTransmission Project 10/23/2017
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# Count1 82 83 74 65 56 47 48 39 310 311 312 313 214 215 216 217 218 219 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 1 10/23/2017
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43 144 145 146 147 148 149 1BIO - Species Polys# Species_Name_Common Special_Status_Type Occurrence_Date Project_Name1 Paniculate TarplantCRPR 4: Plants of LimitedDistribution - A Watch ListMay 21, 2017Riverside TransmissionReliability Project# Area (acres)1 0.09BIO - Bird Nest Points 10/23/2017
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# Species_Name_Common Special_Status_Species Observation_Date Project_Name1 House Sparrow No March 17, 2016Tehachapi RenewableTransmission Project2 Black Phoebe No April 7, 2014Tehachapi RenewableTransmission Project3 Black Phoebe No May 27, 2013Tehachapi RenewableTransmission Project4 Western Kingbird No April 4, 2013Tehachapi RenewableTransmission Project5 Black Phoebe No March 31, 2013Tehachapi RenewableTransmission Project6 House Sparrow No June 3, 2012Tehachapi RenewableTransmission Project7 Black Phoebe No May 23, 2012Tehachapi RenewableTransmission Project8 Northern Mockingbird No August 17, 2016Tehachapi RenewableTransmission Project9 House Finch No June 28, 2016Tehachapi RenewableTransmission Project10 Hooded Oriole No June 15, 2016Tehachapi RenewableTransmission Project11 Western Kingbird No May 24, 2016Tehachapi RenewableTransmission Project12 Black Phoebe No May 24, 2016Tehachapi RenewableTransmission Project13 Cassin's Kingbird No April 12, 2016Tehachapi RenewableTransmission Project14 American Crow No April 3, 2016Tehachapi RenewableTransmission Project15 House Finch No March 28, 2016Tehachapi RenewableTransmission Project16 House Finch No March 25, 2016Tehachapi RenewableTransmission Project17 Black Phoebe No March 24, 2016Tehachapi RenewableTransmission Project18 Killdeer No March 19, 2014Tehachapi RenewableTransmission Project19 Black Phoebe No February 28, 2016Tehachapi RenewableTransmission Project20 Northern Mockingbird No April 19, 2015Tehachapi RenewableTransmission Project21 House Sparrow No May 7, 2014Tehachapi RenewableTransmission Project22 Black Phoebe No March 4, 2012Tehachapi RenewableTransmission Project23 House Finch No August 9, 2011Tehachapi RenewableTransmission Project24 Cassin's Kingbird No June 26, 2011Tehachapi RenewableTransmission Project25 House Sparrow No May 10, 2011Tehachapi RenewableTransmission Project26 Black Phoebe No May 3, 2011Tehachapi RenewableTransmission Project27 Northern Mockingbird No April 20, 2011Tehachapi RenewableTransmission Project 10/23/2017
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28 House Sparrow No April 7, 2011Tehachapi RenewableTransmission Project29 House Sparrow No March 10, 2011Tehachapi RenewableTransmission Project30 Say's Phoebe No March 9, 2011Tehachapi RenewableTransmission Project31 Common Raven No February 28, 2011Tehachapi RenewableTransmission Project32 American Crow No February 23, 2011Tehachapi RenewableTransmission Project33 Unknown TBD November 29, 2016 Lugo-Mira Loma No. 234 Unknown TBD November 29, 2016 Lugo-Mira Loma No. 3 10/23/2017
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# Count1 12 13 14 15 16 17 18 19 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 1BIO - Habitat Polys 10/23/2017
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# Habitat_Type Habitat_Category Determination_Date Project_Name1 Delhi Sands Flower-Loving Fly Suitable July 31, 2015Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project2 San Bernardino Kangaroo Rat Suitable December 27, 2016 Lugo-Mira Loma No. 23 Delhi Sands Flower-Loving Fly Suitable December 27, 2016 Lugo-Mira Loma No. 24 San Bernardino Kangaroo Rat Suitable December 27, 2016 Lugo-Mira Loma No. 35 Delhi Sands Flower-Loving Fly Suitable December 27, 2016 Lugo-Mira Loma No. 36 Other Suitable June 6, 2016Riverside TransmissionReliability Project7 Other Suitable June 1, 2016Riverside TransmissionReliability Project8 Coastal California Gnatcatcher Suitable December 27, 2016 Lugo-Mira Loma No. 29 Coastal California Gnatcatcher Suitable December 27, 2016 Lugo-Mira Loma No. 310 Delhi Sands Flower-Loving Fly Suitable June 7, 2016Riverside TransmissionReliability Project11 Vernal Pool Branchiopods Suitable February 26, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project12 Vernal Pool Branchiopods Suitable January 6, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project13 Delhi Sands Flower-Loving Fly TBD October 5, 2016Riverside TransmissionReliability Project14 Delhi Sands Flower-Loving Fly Suitable October 5, 2016Riverside TransmissionReliability Project15 Vernal Pool Branchiopods Suitable February 3, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project# Area (acres)1 257.642 76.993 76.994 74.845 74.846 29.427 17.78 13.29 13.210 10.9311 1.2312 0.8113 0.5714 0.5515 0.04CNDDB Poly May 2017 10/23/2017
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# Common Name Scientific Name Area (acres)1 Delhi Sands flower-loving fly Rhaphiomidas terminatus abdominalis 4141.522 western mastiff bat Eumops perotis californicus 160.293 California glossy snake Arizona elegans occidentalis 144.024 orange-throated whiptail Aspidoscelis hyperythra 86.145 burrowing owl Athene cunicularia 53.986 least Bell's vireo Vireo bellii pusillus 50.497 yellow-breasted chat Icteria virens 49.658 yellow warbler Setophaga petechia 49.659Southern Cottonwood Willow RiparianForestSouthern Cottonwood Willow RiparianForest32.7110 Los Angeles pocket mouse Perognathus longimembris brevinasus 19.9511Southern California Arroyo Chub/SantaAna Sucker StreamSouthern California Arroyo Chub/SantaAna Sucker Stream16.6212 Santa Ana sucker Catostomus santaanae 15.6113 Lawrence's goldfinch Spinus lawrencei 12.6814 arroyo chub Gila orcuttii 9.115 coast horned lizard Phrynosoma blainvillii 6.7516 Swainson's hawk Buteo swainsoni 1.3617 pocketed free-tailed bat Nyctinomops femorosaccus 1.3618 Busck's gallmoth Carolella busckana 1.3619 western yellow bat Lasiurus xanthinus 1.36CFWO Species Occurrence# Common Name Scientific Name Area (acres)1 Los Angeles pocket mouse Perognathus longimembris brevinasus 135.872 least Bell's vireo Vireo bellii pusillus 74.173 Santa Ana sucker Catostomus santaanae 3.21JD Waters ESA# Name ESA Type Area (acres)1 NHD Red 8.44FEMA Flood Zones# Flood Zone Area (acres)1 X 2559.462 0.2 PCT ANNUAL CHANCE FLOOD HAZARD 408.943 AE 157.994 A 24.925 AH 0.13Government Land, 2016# Agency Name Agency Area Name Area (acres)1 DOD Department Of Defense 14.77 10/23/2017
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MPO Capital Project Footprint# Capital Project Name EPM COMP_LEVEL Area (acres)1 RTRP/Wildlife Substation Gary BusteedStage 04: ApplicationProduction339.832Falcon Ridge 66/12kVSubstationMarcus ObregonStage 05: PreConstructionPlanning150.493 Circle City Alisa KrizekStage 04: ApplicationProduction37.114 TRTP 500 kV UG Jenny McGee Revegetation 21.035 TRTP 4 -11 Jenny McGee Revegetation 11.9USFWS Critical Habitat - Polygon Features# Common Name Scientific Name Area (acres)1 Least Bell's vireo Vireo bellii pusillus 84.062 Santa Ana sucker Catostomus santaanae 34.35AQMD Districts# District Name Area (acres)1 South Coast 2162.38Southern California Edison (SCE) 10/23/2017
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SCE Environmental Screening Report
Area of Interest (AOI) InformationArea : 1,427.17 acres 10/23/2017
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SummaryName Count Area (acres) Length (mi)BIO - Species Points 146 N/A N/ABIO - Species Polys 4 0.83 N/ABIO - Bird Nest Points 33 N/A N/ABIO - Desert Tortoise Points 0 N/A N/ABIO - Habitat Polys 26 391.82 N/ACNDDB Poly May 2017 23 2657.49 N/ACFWO Species Occurrence 22 363.82 N/AJD Waters ESA 95 15.52 N/AFEMA Flood Zones 34 1796.48 N/ALocal Coastal Plan (LCP) 0 0 N/AGovernment Land, 2016 1 64.82 N/AMPO Capital Project Footprint 4 779.87 N/AUSFWS Critical Habitat -Polygon Features2 153.07 N/AUSFWS Critical Habitat - LinearFeatures0 N/A 0AQMD Districts 2 1427.2 N/ABIO - Species Points 10/23/2017
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# Species Name Common Special Status Type Occurrence Date Project Name1 Least Bell's Vireo FE: Federally Endangered August 28, 2016Riverside TransmissionReliability Project2 Least Bell's Vireo FE: Federally Endangered May 8, 2016Riverside TransmissionReliability Project3 Least Bell's Vireo FE: Federally Endangered June 16, 2016Riverside TransmissionReliability Project4 Least Bell's Vireo FE: Federally Endangered May 27, 2016Riverside TransmissionReliability Project5 Least Bell's Vireo FE: Federally Endangered May 16, 2016Riverside TransmissionReliability Project6 Least Bell's Vireo FE: Federally Endangered July 17, 2016Riverside TransmissionReliability Project7 Least Bell's Vireo FE: Federally Endangered July 1, 2016Riverside TransmissionReliability Project8 Least Bell's Vireo FE: Federally Endangered June 5, 2016Riverside TransmissionReliability Project9 Least Bell's Vireo FE: Federally Endangered July 28, 2016Riverside TransmissionReliability Project10 Least Bell's Vireo FE: Federally Endangered June 15, 2016Riverside TransmissionReliability Project11 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJuly 1, 2016Riverside TransmissionReliability Project12 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 19, 2016Riverside TransmissionReliability Project13 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 27, 2016Riverside TransmissionReliability Project14 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 5, 2016Riverside TransmissionReliability Project15 California Ground Squirrel No Special Status Type May 1, 2016Riverside TransmissionReliability Project16 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 28, 2016Riverside TransmissionReliability Project17 Least Bell's Vireo FE: Federally Endangered June 6, 2016Riverside TransmissionReliability Project18 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 26, 2016Riverside TransmissionReliability Project19 Willow Flycatcher SE: State Endangered June 7, 2016Riverside TransmissionReliability Project20 Least Bell's Vireo FE: Federally Endangered June 19, 2016Riverside TransmissionReliability Project21 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernMay 16, 2016Riverside TransmissionReliability Project22 Least Bell's Vireo FE: Federally Endangered May 17, 2016Riverside TransmissionReliability Project23 Least Bell's Vireo FE: Federally Endangered May 26, 2016Riverside TransmissionReliability Project24 Least Bell's Vireo FE: Federally Endangered June 30, 2016Riverside TransmissionReliability Project25 American Yellow Warbler BCC: US Fish and WildlifeService Bird of ConservationJune 5, 2016 Riverside TransmissionReliability Project 10/23/2017
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Concern26 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 15, 2016Riverside TransmissionReliability Project27 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 15, 2016Riverside TransmissionReliability Project28 Loggerhead ShrikeSSC: California Species ofSpecial ConcernJanuary 25, 2012Tehachapi RenewableTransmission Project29 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 28, 2016Riverside TransmissionReliability Project30 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 6, 2016Riverside TransmissionReliability Project31 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 27, 2016Riverside TransmissionReliability Project32 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 26, 2016Riverside TransmissionReliability Project33 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 6, 2016Riverside TransmissionReliability Project34 Least Bell's Vireo FE: Federally Endangered June 7, 2016Riverside TransmissionReliability Project35 Least Bell's Vireo FE: Federally Endangered May 18, 2016Riverside TransmissionReliability Project36 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernMay 18, 2016Riverside TransmissionReliability Project37 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 16, 2016Riverside TransmissionReliability Project38 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 19, 2016Riverside TransmissionReliability Project39 Least Bell's Vireo FE: Federally Endangered June 29, 2016Riverside TransmissionReliability Project40 American Yellow WarblerBCC: US Fish and WildlifeService Bird of ConservationConcernJune 30, 2016Riverside TransmissionReliability Project41 Least Bell's Vireo FE: Federally Endangered May 7, 2016Riverside TransmissionReliability Project42 Yellow-Breasted ChatSSC: California Species ofSpecial ConcernJune 30, 2016Riverside TransmissionReliability Project43 California WalnutCRPR 4: Plants of LimitedDistribution - A Watch ListJune 29, 2016Riverside TransmissionReliability Project44San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernNovember 21, 2010Tehachapi RenewableTransmission Project45 Loggerhead ShrikeSSC: California Species ofSpecial ConcernAugust 3, 2010Tehachapi RenewableTransmission Project46 Least Bell's Vireo FE: Federally Endangered May 28, 2016Riverside TransmissionReliability Project47 Northern HarrierSSC: California Species ofSpecial ConcernDecember 14, 2011Tehachapi RenewableTransmission Project48 Peregrine Falcon SE: State Endangered December 14, 2011Tehachapi RenewableTransmission Project49 Loggerhead ShrikeSSC: California Species ofSpecial ConcernDecember 7, 2011Tehachapi RenewableTransmission Project50 Loggerhead ShrikeSSC: California Species ofSpecial ConcernNovember 30, 2011Tehachapi RenewableTransmission Project51 Northern Harrier SSC: California Species of August 11, 2011 Tehachapi Renewable 10/23/2017
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Special Concern Transmission Project52San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJuly 26, 2011Tehachapi RenewableTransmission Project53San Diego Black-TailedJackrabbitSSC: California Species ofSpecial ConcernJune 29, 2011Tehachapi RenewableTransmission Project54 Northern HarrierSSC: California Species ofSpecial ConcernDecember 7, 2010Tehachapi RenewableTransmission Project55 Loggerhead ShrikeSSC: California Species ofSpecial ConcernFebruary 25, 2014Tehachapi RenewableTransmission Project56 Prairie Falcon No Special Status Type December 26, 2013Tehachapi RenewableTransmission Project57 Cooper's Hawk WL: CDFW Watch List October 21, 2013Tehachapi RenewableTransmission Project58 Cooper's Hawk WL: CDFW Watch List June 22, 2016Tehachapi RenewableTransmission Project59 Cooper's Hawk WL: CDFW Watch List March 24, 2016Tehachapi RenewableTransmission Project60 White-Faced Ibis No Special Status Type December 2, 2015Tehachapi RenewableTransmission Project61 Loggerhead ShrikeSSC: California Species ofSpecial ConcernApril 7, 2015Tehachapi RenewableTransmission Project62 Least Bell's Vireo FE: Federally Endangered July 16, 2016Riverside TransmissionReliability Project63 California Ground Squirrel No Special Status Type May 2, 2016Riverside TransmissionReliability Project64 California Ground Squirrel No Special Status Type June 22, 2016Riverside TransmissionReliability Project 10/23/2017
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# Count1 122 103 74 75 76 67 68 69 410 311 312 313 314 315 316 317 318 219 220 221 222 223 224 225 226 227 228 129 130 131 132 133 134 135 136 137 138 139 140 141 142 1 10/23/2017
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43 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 1BIO - Species Polys# Species_Name_Common Special_Status_Type Occurrence_Date Project_Name1 Paniculate TarplantCRPR 4: Plants of LimitedDistribution - A Watch ListMay 21, 2017Riverside TransmissionReliability Project# Area (acres)1 0.83BIO - Bird Nest Points 10/23/2017
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# Species_Name_Common Special_Status_Species Observation_Date Project_Name1 Black Phoebe No March 24, 2016Tehachapi RenewableTransmission Project2 Black Phoebe No April 7, 2014Tehachapi RenewableTransmission Project3 Black Phoebe No May 27, 2013Tehachapi RenewableTransmission Project4 Western Kingbird No April 4, 2013Tehachapi RenewableTransmission Project5 Black Phoebe No March 31, 2013Tehachapi RenewableTransmission Project6 House Sparrow No June 3, 2012Tehachapi RenewableTransmission Project7 Black Phoebe No May 23, 2012Tehachapi RenewableTransmission Project8 Northern Mockingbird No August 17, 2016Tehachapi RenewableTransmission Project9 House Finch No June 28, 2016Tehachapi RenewableTransmission Project10 Hooded Oriole No June 15, 2016Tehachapi RenewableTransmission Project11 Western Kingbird No May 24, 2016Tehachapi RenewableTransmission Project12 Black Phoebe No May 24, 2016Tehachapi RenewableTransmission Project13 Cassin's Kingbird No April 12, 2016Tehachapi RenewableTransmission Project14 American Crow No April 3, 2016Tehachapi RenewableTransmission Project15 House Finch No March 28, 2016Tehachapi RenewableTransmission Project16 House Finch No March 25, 2016Tehachapi RenewableTransmission Project17 Killdeer No March 19, 2014Tehachapi RenewableTransmission Project18 House Sparrow No March 17, 2016Tehachapi RenewableTransmission Project19 Black Phoebe No February 28, 2016Tehachapi RenewableTransmission Project20 Northern Mockingbird No April 19, 2015Tehachapi RenewableTransmission Project21 House Sparrow No May 7, 2014Tehachapi RenewableTransmission Project22 Black Phoebe No March 4, 2012Tehachapi RenewableTransmission Project23 House Finch No August 9, 2011Tehachapi RenewableTransmission Project24 Cassin's Kingbird No June 26, 2011Tehachapi RenewableTransmission Project25 House Sparrow No May 10, 2011Tehachapi RenewableTransmission Project26 Black Phoebe No May 3, 2011Tehachapi RenewableTransmission Project27 American Crow No April 25, 2011Tehachapi RenewableTransmission Project 10/23/2017
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28 Northern Mockingbird No April 20, 2011Tehachapi RenewableTransmission Project29 House Sparrow No April 7, 2011Tehachapi RenewableTransmission Project30 House Sparrow No March 10, 2011Tehachapi RenewableTransmission Project31 Say's Phoebe No March 9, 2011Tehachapi RenewableTransmission Project32 American Crow No March 9, 2011Tehachapi RenewableTransmission Project33 American Crow No February 23, 2011Tehachapi RenewableTransmission Project 10/23/2017
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# Count1 12 13 14 15 16 17 18 19 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 1BIO - Habitat Polys 10/23/2017
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# Habitat_Type Habitat_Category Determination_Date Project_Name1 Delhi Sands Flower-Loving Fly Suitable July 31, 2015Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project2 Other Suitable June 6, 2016Riverside TransmissionReliability Project3 Delhi Sands Flower-Loving Fly Suitable June 7, 2016Riverside TransmissionReliability Project4 Other Suitable June 1, 2016Riverside TransmissionReliability Project5 Delhi Sands Flower-Loving Fly TBD October 5, 2016Riverside TransmissionReliability Project6 Vernal Pool Branchiopods Suitable February 26, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project7 Vernal Pool Branchiopods Suitable January 6, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project8 Delhi Sands Flower-Loving Fly Suitable October 5, 2016Riverside TransmissionReliability Project9 Vernal Pool Branchiopods Suitable February 3, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project10 Vernal Pool Branchiopods Suitable January 7, 2016Circle City Substation and MiraLoma-JeffersonSubtransmission Line Project# Area (acres)1 295.562 55.383 21.464 14.595 1.926 1.237 0.888 0.769 0.0410 < 0.01CNDDB Poly May 2017 10/23/2017
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# Common Name Scientific Name Area (acres)1 Delhi Sands flower-loving fly Rhaphiomidas terminatus abdominalis 1944.42 western mastiff bat Eumops perotis californicus 191.443 least Bell's vireo Vireo bellii pusillus 109.554Southern Cottonwood Willow RiparianForestSouthern Cottonwood Willow RiparianForest78.915 yellow warbler Setophaga petechia 72.986 yellow-breasted chat Icteria virens 72.987 burrowing owl Athene cunicularia 44.878Southern California Arroyo Chub/SantaAna Sucker StreamSouthern California Arroyo Chub/SantaAna Sucker Stream42.999 Santa Ana sucker Catostomus santaanae 41.4710 arroyo chub Gila orcuttii 35.4211 Lawrence's goldfinch Spinus lawrencei 12.712 Santa Ana speckled dace Rhinichthys osculus ssp. 3 9.78CFWO Species Occurrence# Common Name Scientific Name Area (acres)1 least Bell's vireo Vireo bellii pusillus 362.272 Santa Ana sucker Catostomus santaanae 1.54JD Waters ESA# Name ESA Type Area (acres)1 NHD Red 15.52FEMA Flood Zones# Flood Zone Area (acres)1 X 1577.292 AE 182.393 0.2 PCT ANNUAL CHANCE FLOOD HAZARD 21.374 A 15.43Government Land, 2016# Agency Name Agency Area Name Area (acres)1 ST Hidden Valley 64.82MPO Capital Project Footprint# Capital Project Name EPM COMP_LEVEL Area (acres)1 RTRP/Wildlife Substation Gary BusteedStage 04: ApplicationProduction708.022 Circle City Alisa KrizekStage 04: ApplicationProduction34.433 TRTP 500 kV UG Jenny McGee Revegetation 34.234 TRTP 4 -11 Jenny McGee Revegetation 3.19 10/23/2017
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USFWS Critical Habitat - Polygon Features# Common Name Scientific Name Area (acres)1 Least Bell's vireo Vireo bellii pusillus 88.232 Santa Ana sucker Catostomus santaanae 64.84AQMD Districts# District Name Area (acres)1 South Coast 1427.2Southern California Edison (SCE) C-1

APPENDIX C POWER ENGINEERS QUALIFICATIONS
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ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS
BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 1 On the following pages we provide a representative sample of POWER’s experience with major transmission system programs, as well as other types of transmission line projects. The project summaries include experience with CPUC GO95, CPUC GO 131-D, CPUC licensing, environmental permitting and other subjects.These high-profile and schedule-sensitive projects frequently involve complex issues such as:Environmental sensitivities.Multiple stakeholders;Stringent regulatory directives and public agency requirements;Need for strong community relations to improve public acceptance;Complex permitting requirements, involving federal, state and local permits;Challenging and rugged terrain;Aggressive budgets and schedules that were met or improved upon.PACIFICORPYreka-Weed 115 kV Transmission Line Upgrade PEA, CaliforniaPOWER was responsible for producing the PEA for PacifiCorp's proposed 115 kV transmission line project in Siskiyou County, near the Oregon border. The project consisted of approximately 17 miles of transmission line rebuild, two miles of new transmission line, and the upgrade of three substations. POWER was responsible for all environmental studies and impact assessment for the PEA. Coordination with the California Public Utilities Commission (CPUC) was completed to aid in preparing and filing the PEA on a fast-track schedule to ensure the in-service date for this very important electrical capacity project. POWER provided support with surveys and data requests to the CPUC during the preparation of a Mitigated Negative Declaration for the rebuild portion of the project and an EIR for the new transmission line segment of the project. POWER also provided environmental training and construction monitoring for the entire project.

Identifying and developing engineering solutions is one of our core competencies.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 2 LOS ANGELES DEPARTMENT OF WATER AND POWERBarren Ridge EIS/EIR, CaliforniaPOWER conducted a joint federal and state environmental review under NEPA and CEQA, including an EIS/EIR, for the Barren Ridge Renewable Transmission Project. To provide access to wind- and solar-generated electricity in the Tehachapi Mountain and Mojave Desert regions, the proposed double-circuit 230 kV facilities would improve the reliability of LADWP's electric delivery system and help the City of Los Angeles meet its Renewable Portfolio Standard obligations mandated by the State of California and the City. The project included a new transmission line from the existing Barren Ridge Switching Station to a proposed Haskell Canyon Switching Station, added a circuit on an existing line from Haskell Canyon to the Castaic Power Plant, and replaced conductors on the Owens Gorge to Rinaldi line, covering approximately 200 miles of lines. The Forest Service and BLM are federal co-lead agencies and LADWP is the lead state agency. POWER was responsible for all environmental and land use analyses for the EIS/EIR: biological and cultural field studies, visual, land use, agriculture, transportation, earth and water resources, and noise and socioeconomics. The project area provided habitat for several special status species, including the California red-legged frog, arroyo toad, desert tortoise and California condor. An agency-directed avian risk assessment will examine the relationship between the project's existing and proposed transmission lines and resident and migratory species in Mojave Desert and other habitats. POWER also conducted an extensive public outreach and scoping program. Supporting public involvement efforts, POWER360, a web-based interactive application linked to the project website, allowed real-time mapping of a property in relation to the proposed transmission line. Interested parties could view basic project information and leave comments directly related to the project for consideration along with comments gathered during onsite public meetings.POWER prepared all of the pre-construction plans for the project including the Plan of Development for the BLM and the Construction, Operations and Maintenance Plan for the USFS. We also conducted pre-construction cultural resources data recovery, pre-construction surveys, environmental monitoring.

For nearly a decade, POWER has provided high-quality support for LADWP’s Barren Ridge Renewable Transmission Project.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 3 SAN DIEGO GAS AND ELECTRICValley-Rainbow 500 kV Interconnect PEA, CaliforniaPOWER completed environmental siting and permitting services and preliminary engineering for the proposed Valley-Rainbow 500 kV Interconnect Project. The project included plans for a new 35-mile 500 kV transmission line, a new substation, 52 miles of 230 kV transmission upgrades, a new 7-mile 69 kV transmission line, and five substation upgrades. The project was conceived as a way to bolster transmission capacity in San Diego and Riverside counties, one of the fastest growing areas of the United States. ENVIRONMENTAL SITING AND PERMITTINGPOWER was responsible for a siting study, preparation of the multi-disciplinary environmental planning studies, PEA), special status wildlife species surveys, botanical surveys, Biological Assessment, ethnographic studies, cultural surveys and report, wetland delineations and mitigation studies, and other consultations and permits for the new transmission line. Nearly 200 miles of alternative routes were identified, and POWER provided an analysis considering route opportunities and constraints. The studies, including the PEA, were prepared during the 2000/2001 energy crisis in California in less than nine months and submitted to the CPUC. POWER was also responsible for facilitating public scoping meetings, and assisted the CPUC and BLM in preparing the EIR/EIS for the project.PRELIMINARY ENGINEERING POWER performed preliminary engineering services for approximately 35 miles of new 500 kV transmission line as well as the associated transmission line and substation upgrades. Design services included foundation design and preliminary routing and design in PLS-CADD. RAINBOW SUBSTATION POWER provided preliminary engineering services for the new 500 kV Rainbow Substation associated with the project. The preliminary engineering supported permitting and major equipment procurement for the new substation. The design included a 1120 MVA autotransformer bank and new 230 kV breaker and one half yard. The 40-acre site presented extensive geotechnical and grading design challenges. UNDERGROUND FEASIBILITY STUDY As a result of the public comment process, POWER conducted an evaluation of constructing the line underground for the entire 35 miles in a relatively rural environment. Shorter sections were also considered for some road and river crossings. Self-contained fluid-filled (SCFF) and cross linked polyethylene (XLPE) 500 kV cable systems were examined to determine technical merit and reliability. Several cable manufacturers submitted engineering, cost, and reliability data for these cable types. Simple line models were prepared in PTI’s PSSE format for computer analysis to determine conductor size, reactive compensation and voltage drop for the two types of circuits. Environmental aspects were POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 4 considered such as right of way width, ground disturbance, land use and esthetics, health and noise issues, vegetation clearing, and erosion control. Cost estimates and a comparison of the impacts and benefits (technical, environmental, and maintenance) of the two underground installations were summarized in a report. GISPOWER provided GIS mapping and analysis services to determine the optimal location for the 500 kV transmission line. The project included obtaining data from Riverside and San Diego counties and conducting various forms of geospatial analysis to help prepare the PEA. POWER’s GIS and Environmental teams mapped sensitive species, land use, wetlands, soils, and geology, and also determined sensitivity levels for each resource and impact that the potential transmission line would have on them. Viewshed analysis was conducted on the transmission line for recreational, residential, and scenic quality impacts. Final delivery included 200 sets of resource and impact maps totaling 10,000 maps. PROJECT WEB SITE The project included development of an interactive web site to facilitate public interaction and comment. The web site was designed to keepfederal, state and local agencies, utilities and business owners and residents in Riverside and San Diego counties informed about every aspect of the project. The web site served to answer questions and alleviate concerns about the impacts of the project on the communities and the environment. This was accomplished using up-to-date project status reports, a FAQ (frequently asked questions) section, posting of public involvement opportunities, project documents including descriptions and maps of the proposed route and permit applications, and links to resources and personnel contacts for further information. The web site also served as a central source of information for all members of the project team.RIVERSIDE PUBLIC UTILITIESRiverside Transmission Reliability Project, CaliforniaPOWER is providing environmental, engineering, and engineering procurement and construction support services for the Riverside Transmission Reliability Project (RTRP), a major upgrade to the City of Riverside’s electric system. The project will add a second interconnection to the SCE transmission grid. During Phase I of the RTRP, POWER conducted a routing study to identify four alternative routes for the 230 kV and 69 kV transmission lines and determined that an EIR would need to be developed. During Phase II, POWER provided the city with a Final EIR, Certificate of Public Convenience and Necessity, substation and transmission line design, and construction of 230 kV and 69 kV systems to bring additional power into Riverside Public Utilities’ electric system.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 5 POWER is providing conceptual and detailed engineering for many of the components of the RTRP, including the new 230-69 kV Wilderness Substation, four new double circuit 69 kV transmission line segments; and upgrades to eight existing 69 kV substations. POWER has completed and submitted the design to upgrade Harvey Lynn and Freeman substations, which included breaker replacement work. In addition to design, POWER is providing procurement, contractor selection assistance, and engineering support during construction.SAN DIEGO GAS AND ELECTRICMission-Miguel 230 kV Transmission Line PEA, CaliforniaPOWER assisted SDG&E in the preparation of the Proponent’s Environmental Assessment for a 35-mile-long transmission line upgrade. The project involved placing a new 230 kV conductor on a vacant position on an existing steel pole and relocating 69 kV and 138 kV conductors from an existing lattice tower to a new steel or wood double circuit 69/138 kV pole to be placed in the existing right of way. A 230 kV circuit was also constructed on the existing 69/138 kV lattice tower. The project crossed sensitive open space parks, recreation areas, golf courses and the Otay Sweetwater National Wildlife Preserve. The PEA was necessary to complete the Certificate of Public Convenience and Necessity (CPCN) application to the CPUC, which acted as the Lead Agency.PACIFICORPLassen Substation PEA, CaliforniaPOWER prepared a PEA to be used in an application for a Permit to Construct from the CPUC. The project includes a new 115/69 kV substation that would replace the original substation. POWER managed the public involvement process which included soliciting comments from interested agencies and the public. This included coordination of a public meeting and evaluation of public comments with regard to identifying and selecting a proposed substation site. Preparation of the PEA focused on habitat assessments, wetland assessments/delineations, and adjacent land uses, including potential visual impacts for local residences. POWER also prepared several simulations for public meetings and the PEA.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 6 RENEWABLE RESOURCES GROUPBlythe Mesa Solar EIR and EA, CaliforniaPOWER was the third-party contractor for the Renewable Resources Group, Riverside County, and the BLM California Desert District, hired to prepare a joint EIR and EA (CEQA and NEPA) document for a 485 MW solar photovoltaic project. In addition to the solar PV panels, the project will include up to three substations, up to two O&M buildings and an approximate 4.8-mile, 230 kV transmission line connecting the generating facility to SCE’s Colorado River Substation. The project site and transmission right-of-way contain approximately 3,660 acres. A portion of the interconnection line would cross federal land managed by the BLM. POWER provided assistance in all phases of the environmental process, including the Notice of Preparation, scoping meetings, technical studies, and preparation of Draft and Final EIR/EA.Key biological issues addressed include burrowing owl, desert tortoise, rare plants, and Mojave fringe-toad lizard. A Phase I cultural resources survey was completed and a technical report prepared. A glint and glare study, visual analysis and visualizations, transportation study, water supply assessment, socioeconomic study, and air quality were also conducted. Due to project proximity to the Blythe Airport, a computer animation was prepared to simulate the landing sequence of an aircraft over solar panels. The animation was used to demonstrate to the Riverside County Airport Land Use Commission that glint and glare from the solar panels would not be a public hazard.RENEWABLE RESOURCES GROUPPalo Verde Mesa Solar, CaliforniaPOWER supported Renewable Resources Group and Riverside County in preparing an EIR for the 470 MW Palo Verde Mesa Solar PV Project, which will connect to SCE’s Colorado River Substation. POWER provided assistance in all phases of the environmental process, including support in preparation of technical reports required for the project.PROJECT FEATURES3,250-acre solar facility, including collector substations and O&M buildings to be constructed on the siteSeveral interior access roadsSystem of underground interior collection power lines located between inverters and substationsProposed 14.5-mile 230 kV transmission line placed within a 100-foot-wide right-of-wayPOWER’S SERVICESPreparation of Draft EIRBiological and cultural surveysSupporting documentation for visual impacts, glint and glare, traffic, and air quality concernsThird-party contractor for the preparation of the Draft EIR POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 7 LOS ANGELES DEPARTMENT OF WATER AND POWERSouthern Owens Valley Solar Ranch EIR, CaliforniaPOWER prepared an EIR for an LADWP solar project located on City-owned lands within the Owens Valley in Inyo County, CA. The Southern Owens Valley Solar Ranch Project will be a 200 MW solar photovoltaic (PV) project on approximately 3,000 acres. POWER prepared technical studies to evaluate proposed and alternative project sites. A range of technical studies were prepared including visual simulations from nearby scenic vantage points and intensive cultural resource evaluations. POWER assisted with project scoping by coordinating public outreach and notification aimed at stakeholders, local land owners, Native Americans, public agencies and the interested public.LOS ANGELES DEPARTMENT OF WATER AND POWERScattergood Olympic Transmission Line EIR, CaliforniaPOWER prepared an EIR for the proposed Scattergood-Olympic Transmission Line Project. The project included the construction of a new underground 230 kV electric transmission line for a distance of approximately 12 miles connecting the existing Scattergood Generating Station and Olympic Receiving Station. POWER was responsible for conducting technical analyses to address biological and cultural resources, land use, earth and water resources, noise and socioeconomics. The new transmission line involved crossings at Ballona Creek and Centinella Creek, and the study area included habitat for the federally endangered El Segundo Blue Butterfly. POWER also conducted an extensive public outreach and scoping program for this project.LOS ANGELES DEPARTMENT OF WATER AND POWERSylmar Ground Return System Replacement Project EIR, CaliforniaPOWER is preparing an EIR for the Sylmar Ground Return System Replacement (SGRS) Project. LADWP is proposing to replace the existing underground and marine electrical cables and the existing marine electrode portions of the SGRS to correct system deficiencies.The SGRS is a vital component of the Pacific Direct Current Intertie Transmission Line, which transmits bulk power between Los Angeles and the Pacific Northwest. The replacement project is proposed to maintain the reliability and stability of the power generation and delivery system for Southern California.In addition to working with LADWP to prepare a Draft EIR, POWER has also supported technical studies. Key issues focus on construction-related impacts to traffic, noise, and air quality in western Los Angeles and Santa Monica and to the marine environment in Santa Monica Bay.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 8 LOS ANGELES DEPARTMENT OF WATER AND POWERScattergood Generating Station Unit 3 Repowering EIR, CaliforniaPOWER prepared environmental technical reports and a Final Environmental Impact Report for LADWPs Scattergood Generating Station Unit 3 Repowering Project. The EIR was prepared with the LADWP serving as the Lead Agency. POWER also prepared and distributed the Initial Study and Notice of Preparation of Draft EIR. The project consists of replacing the capacity of Scattergood Generating Station Unit 3 with natural gas-fired combustion turbines and heat recovery steam generator(s) operating in both combined and simple cycle configuration. The EIR included a full air quality analysis and an evaluation of the impact of wastewater changes relative to the existing discharge permit. Several other issues that were addressed include aesthetics (visual impacts), biological resources (focused on El Segundo Blue Butterfly), potential for historic resources, paleontological resources, noise generation, wastewater issues, and traffic and transportation.SOUTHERN CALIFORNIA EDISONKimball Substation Air Quality Analysis, CaliforniaPOWER conducted the air quality analysis and construction emissions estimates for a PEA to obtain a Permit to Construct from the CPUC for the new Kimball Substation near Chino. In addition to the new substation, the project included a new 66 kV subtransmission line and a fiber optic communication network. The project is located within the South Coast Air Quality Management District.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 9 We offer specialized expertise with transmission projects, and a proven project approach refined over forty-plus years in the industry. Our transmission and distribution work has earned us a top five rankingfrom Engineering News Recordand a repeat business rate of nearly 80%. With this depth of experience, we can execute the most challenging projects to the highest technical and regulatory standards. On the following pages we provide a representative sample of our engineering experience with major transmission system programs. The project summaries are focused on engineering work. However, we have also included project summaries where GO95, CPUC Licensing, environmental permitting and other relevant subjects that may come into play. Some of our engineering work comes in the form of Owner’s Engineer and Program Manager contracts, which are also included.These high-profile and schedule-sensitive projects frequently involve complex engineering and construction challenges, such as:High-profile projects with multiple stakeholders;Multiple projects executed in parallel;Hundreds of Millions of dollars in capital costs;Stringent regulatory directives and public agency requirements;Need for strong community relations to improve public acceptance;Complex permitting requirements, involving federal, state and local permits;Extensive outage and construction planning;Flexible team approach with project owner;Full compliance with owner-led safety programs; andAggressive schedules and budgets that were met or improved upon.SOUTHERN CALIFORNIA EDISONTransmission Line Rating Remediation (TLRR) Strategic Execution Plan,CaliforniaFaced with thousands of discrepancies on its transmission system as a result of NERC rating, Southern California Edison (SCE) hired POWER to develop a Strategic Execution Plan (SEP) to identify and recommend the needed planning, engineering, regulatory, and construction strategies, requirements, and milestones to support SCE’s remediation timelines.PROJECT FEATURESStrategic Execution Plan for a 15-year program to remediate SCE’s bulk power and radial systemsProgram budget of $1.5 billion262 circuits from 66 kV to 500 kV with 10,000+ discrepancies identified Transmission line projects have been a cornerstone of our business for over 40 years. Our staff includes some of the most respected P.E.’s in the industry.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 10 CHALLENGES/ACCOMPLISHMENTSSignificant percentage of remediation required Permit to Construct (PTC) or Certificate of Public Convenience and Necessity (CPCN) licensing approvals from the California Public Utilities Commission (CPUC).Majority of remediation required permits or authorizations from federal land or resource management agencies.Developed a scoping template that facilitated prioritization criteria for circuit requirements, schedule, cost, and sequencing. Grouped project packages by geographical location, licensing, permitting, outages, and other factors, to streamline scheduling.Worked closely with SCE Subject Matter Experts to facilitate plan development. POWER360®was successfully used as the collaboration tool for the source documents and SEP development with 1,253 total logins and 3,955 documents downloaded.SERVICESStrategic execution plan developmentScheduling and cost estimates for 262 circuitsProject sequencingResource requirement recommendationProgram reporting via POWER360®Upon completion of the SEP, additional "follow-on" services were requested by SCE to support their team through the next project planning stagesSOUTHERN CALIFORNIA EDISONTransmission Line Rating Remediation (TLRR) North of Magunden Segment, CaliforniaSouthern California Edison (SCE) hired POWER to evaluate, engineer, and provide construction drawings for discrepancy remediation of four existing 220 kV transmission circuits. The transmission circuits requiring remediation are Magunden-Vestal Numbers 1&2 and Rector-Vestal Numbers 1&2. The total length of the circuits is 137.6 miles with total of 289 discrepancies. The Project required revalidation from the GO-131D committee which avoids Licensing with the California Public Utility Commission (CPUC). In order for SCE to approach the GO-131D committee with a highly confident mitigation solution POWER completed the following: Discrepancy revalidationProposal for three (3) new conductor evaluations to mitigate the identified discrepancies. Conductor were selected based on their high ampacity and low sag characteristicsCreation of a high level Cost Estimating tool for each of the three (3) conductor alternatives to give an overall cost for each option. This included present cost support and future conductor line loss cost support. Each option proved was a feasible solution to maintain We have designed and permitted hundreds of miles of transmission lines in California and across the Southwest.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 11 the requirements set by the GO-131D Committee, with actual design completed. Creation of construction stringing and setup sites, foundation boring locations, access road and pad grading provided to SCE as KMZ’s and Shape File, such that SCE could create the Project’s Strip Map for the GO-131D presentation. Preliminary GO-131D meeting support with SCE environmental and TPD crews to vet out construction and environmental issues that may become Project showstoppers.After SCE GO-131D “Conditional Approval” (waiting final environmental approval), POWER supported this Project with the following final construction documentation for all four (4) line segments:Joint support with SCE and POWER to ensure that SCE and GO-95.This task was extremely important to maintain Code Standards for the 90+ Year old towers, which were designed as 151kV structures but are currently being operated at 221 kV. PLS-CADD modeling with M4 Structures Construction SpecificationsGeneral Arrangement DrawingsPlan and Profile DrawingsTower Data SheetAccess Road and Tower Pad Grading PlansFoundation Design and DrawingStructure Framing DrawingProject Bill of Material List (BOM)Assembly Drawing and creation which was imported into PLS-CADD to create the BOM. (This approach was new to SCE but the efficiency of this approach was noted)Lattice Tower and Tubular H-Frame procurement Sag and Tension Drawings Use of DBE Contractors for supportConstruction SupportThis Project successfully utilized POWER360®(POWER’s robust proprietary communication and project management tool). The application allowed POWER and SCE share information and effectively manage the following Project Documentation as a shared approach:Project Scope Budget Schedule RFI’sMeeting MinutesStatus ReportField Visit Photos integrated into the map systemEnvironmental Constraints which need to be considered in the designProject Submittal Documentations POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 12 POWER’s Project Team worked closely with SCE Engineering and Drafting to create a group which efficiently reacted to the dynamic project characteristics for both the GO-131D and construction documentation requirements. Many of the key personnel involved in the TLRR Strategic Execution Plan (above) were proposed for the North of Magunden Engineering Services Project, maximizing continuity of activities in the TLRR Program and minimizing the amount of ramp-up time getting the engineering work started and completed; and POWER360®, our proprietary robust communication and project management tool was proposed as an integral part of our engineering proposal. This leverages the previous and current POWER360®activity on the Strategic Execution Plan project. POWER included a DBE subcontract strategy in the delivery of this project. Our DBE subcontractor for access roads and civil design has SCE experience and will help contribute to SCE’s DBE spending goals.SCOPE EFFICIENCY STUDYThe Scope Efficiency Study was developed considering design requirements, optimal cost, minimal project disturbance area, permitting, and avoiding the need for licensing. SCE identified a list of remediation approaches which are listed below from most preferred to least preferred.1. Grade2. Re-Tension Wire3. Re-Insulate Hardware4. Re-Conductor5. Lower Crossing Wire6. Nip / Tuck7. Raise with Body Extension8. Replace Structure9. Interset Structure10. Rebuild Entire CircuitComponent 1:The design requirement portion will review each remediation approach and estimate the maximum discrepancy magnitude correction. Many of the wire and hardware modification’s maximum correction magnitude will be less than three feet. A large portion of discrepancies have a magnitude greater than three feet which would require either reconductor option or one of the structure modification approaches. The type of structure and age of structure / wire will be a consideration in this review.Component 2: A relative cost comparison estimation spreadsheet will be developed that estimates the cost differential between each remediation option. The POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 13 estimates will not consider costs that are common to each approach (mobilization, access and environmental restrictions). The estimates will provide general guidance on identifying the most economical options. Unique situations during the design process may require specific cost comparisons to determine the more economical solution.Component 3:A general disturbance impact review will be done for each remediation option. Unique situations during the design process may require specific disturbance comparisons to determine the least disturbance impact solution.Component 4:Minimizing the permitting and licensing requirements is the fourth component of this study. A quick design review will be completed to determine how many potential remediation options are needed to define if permits or licenses are required. POWER will identify guidelines and determine overall remediation approaches for discussion with SCE. The Scope Efficiency Study included the four components mentioned above. These items were discussed with SCE and an approach / flow chart was developed and become part of the Scope Efficiency Study.RIGHT OF WAY ACTIVITIESPOWER is supporting SCE on right of way studies (rights check). POWER will provide maps or .kmz files showing existing alignment and access roads. SCE will utilize maps or .kmz files for the right of way study. SCE will provide POWER any special access for updating the maps. The access maps will become part of the construction documents. PERMITTING ACTIVITIESIdentify airports near project and prepare an FAA Analysis for SCE’s use. The analysis will list structures within 20,000 feet of airport andthose structure heights. The structure’s elevations will be reviewed to determine if the structure is in the airport’s approach / clear zone. POWER will review the project area and prepare a list of utility crossings. Also prepare permit drawings with crossing recommendation for SCE’s use. Caltrans’s major highway crossing permits may require sealed engineering drawings for guard structure arrangement. POWER will provide these designs and sealed drawings.POWER will review the project and identify a list of contractor supplied permits. Discussions will be held with SCE to determine if there are schedule advantages to SCE providing some of the identified permits. A list of the contractor required permits will be part of the construction documents.DISTURBANCE CALCULATIONSPOWER will provide estimated disturbance areas for each remediation. Construction areas will be defined using desktop information and POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 14 information from the field visit. The areas will be used by SCE calculating disturbance areas.OTHER KEY TASKS FOR SCE NOM PROJECT:PLS-CADD line modelingConductor designStructure designFoundation designAccess road designCost estimate supportDesign documentationMaterial list - BOMSCE construction drawings POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 15 CONFIDENTIAL CLIENTTransmission Line Rating Services - NERC Compliance, Phase I,Multiple StatesPOWER provided the ratings assessment for 1,600 transmission line circuit miles of our client's system in California, Utah, Wyoming, Washington, and Oregon to ensure compliance with the NERC Recommendation to Industry for Facility Ratings Analysis. The scope of this project was to review our client’s ratings methodologies and determine if existing lines had NESC clearance violations on lines rated 115 kV, 230 kV, 345 kV, and 525 kV. The project used a client-obtained LiDAR survey to identify all structure locations and conductor spans within specified corridors. The LiDAR survey detected structure types, pole heights, conductor/shieldwire attachment points, and conductor/shield wire sag conditions as they exist in the field. The LiDAR data also captured topographical data located near or within the right-of-way including: ground elevations, vegetation, man-made structures, line crossings, etc. POWER reviewed and modeled the data collected in PLS-CADD, then analyzed it so that clearances to ground, vegetation, other conductors, other utilities, and encroachments were identified. POWER also identified the impact of each violation by determining the transmission line's electrical rating in its current condition. The project enabled our client to define where line modifications were required for the circuit to achieve the desired rating.SOUTHERN CALIFORNIA EDISONTransmission Line Rating Remediation (TLRR) Strategic Execution Plan,CaliforniaThis project is described above. A key portion of the work was to perform a high-level total project cost estimate for over 200 circuits. POWER and SCE developed an estimating tool (Excel spreadsheet) for rapid estimating of remediation options and overall project costs. POWER’s base costs for project labor, materials and equipment blended well with the costs SCE is experiencing.SOUTHERN CALIFORNIA EDISONTransmission Line Rating Remediation (TLRR) North of Magunden Segment, CaliforniaThis project is described above. POWER is doing detailed cost estimates for each alternative being considered for the project. The alternatives involved new low sag conductors. QA/QCWe use a comprehensive set of processes, beginning with the definition of work scope, schedule, and budget and ending with detailed checking of project deliverables. These management practices define processes to ensure a consistent level of quality for all project deliverables.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 16 AMERENNERC Remediation Program, Multiple StatesAfter performing compliance analysis in response to NERC’s 2010 Facility Ratings Recommendation, Ameren had a capital project portfolio of $160 million per year through 2022, averaging 25 major transmission upgrade projects per year to meet NERC reliability ratings on the existing network. POWER has developed and implemented a Project Execution Plan to manage the program and is performing the engineering for the upgrade projects. ACCOMPLISHMENTSStreamlined project planning and execution – Established a proactive project planning process, schedule and milestone points, which produced a clear critical path and improved progress tracking.Program “playbook” – Developed program execution processes, or a playbook, for how the extended program team would work together. By addressing safety, program and project management, change management, risk management, program controls, document controls, construction management and Ameren functional interfaces, the “playbook” has increased productivity by clarifying team roles and key program processes. Integrated master schedule plan – Developed an integrated master schedule planning process for all Ameren’s capital projects to enable a two-year rolling planning window and a change process. This plan clarifies the best use of outage windows and leveling of contractor resource requirements through the planning period, and enables efficient “what if” scenario planning to support changes.Engineering integration – Seamless integration between POWER’s program and POWER's engineering teams has streamlined the engineering interface in project design, material coordination with a third-party material manager, and construction support. Real-time progress reporting – Provided daily and weekly progress status reports directly into POWER360®. Information transfer through POWER's program management information system included contractor scheduling, cost estimating and progress reporting. MAJOR FEATURES7,600 circuit miles of 138 kV, 161 kV, 230 kV and 345 kV transmission linesSERVICESEngineeringProgram management and project managementProgram cost and schedule controls and execution processesIntegrated master scheduleCost estimating servicesBudgeting, including cash flows and contractor purchase ordersRisk managementProgram management information system (POWER360®)Engineering inspection POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 17 AMERICAN ELECTRIC POWERTransmission Line Rerating Program, Multiple StatesAEP undertook one of the largest, most complex projects in its history when PJM Interconnection, a regional transmission operator, required it to re-rate approximately 2,000 miles of transmission line to accommodate increased demands caused by regional retirement of coal-fired generation. Faced with a tight four-year time frame, AEP hired POWER to oversee the effort, identify areas of concern and recommend innovative, cost-effective design solutions that were implemented in time to meet PJM’s deadline.ACCOMPLISHMENTSSaved more than $3 billion by remediating, not replacing, the lines. Overall project costs were $72.6 million, and a complete rebuild had been estimated to cost $4 billion. As a result, AEP was able to pay for the remediation in a single year, due to the sale of additional power capacity created by the fixes.Avoided costly replacement of approximately 37 lattice towers by modifying tower height, installing floating dead-ends and removing swing-angle brackets to fix the clearance issues.Kept project on track by using standard materials as much as possible, reducing lead time and meeting a tight schedule.Made complex outage schedule visible at a glance by developing an overlay for AEP’s transmission GIS program. Reduced delays by assembling all permits before the start of construction.FEATURES2,000 miles of 138 kV and 345 kV transmission line with 302 locations of concern Installed 282 new steel poles and 117 new catenary weightsCleared vegetation issues on 547 spansResolved 48 right of way encroachments Line locations in Indiana bat habitat and wetland areas, requiring surveys and SWPPP preparationPOWER’S SERVICESSag studies and line modelingDetailed engineeringProject management and program management servicesCost estimating servicesOutage coordinationEnvironmental studies, permitting and compliance POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 18 TACOMA POWERLaGrande 115 kV Line Uprating Study, WashingtonPOWER provided modeling and thermal capacity analysis of an existing 115 kV transmission line. LiDAR survey data, provided by the client, was processed to develop a rational, high quality PLS-CADD terrain model. Obstructions were identified and line structures and conductors accurately placed in the model. A report was prepared that indicated which structures were overloaded and what reinforcements were required to comply with NESC standards. The current rating of the line was established and all NESC clearance violations identified. The second phase of the project consisted of preliminary engineering and cost estimating and analysis to determine various uprating alternatives for the line. These ranged from an alternative with minimal capital investment (intermediate structures and re sag/tension existing conductors) to restringing new conductor up to the capacity of the existing structures.SOUTHERN CALIFORNIA EDISONEldorado-Ivanpah 220 kV Transmission Line Project, CaliforniaSouthern California Edison’s Eldorado-Ivanpah 220 kV Transmission Line and Substation project will deliver up to 1,400 MW from renewable resources in California and Nevada to load sources in southern California. POWER performed transmission line design for a 35-mile double circuit 220 kV transmission line. Where the new line crosses higher voltage lines, special tubular H structures were designed to route the circuits in a horizontal configuration under the existing lines. The new 220 kV line uses an existing 115 kV line right of way. Similar services are being provided for a secondary communications line which will require overhead ground wire on the Eldorado Lugo 500 kV Line to be replaced with optical ground wire. The change out requires structural modifications to the 500 kV towers and outage management. POWER is also providing owner’s engineering and construction management services for the project.SAN DIEGO GAS AND ELECTRICCleveland National Forest Power Line Replacement, CaliforniaSDG&E operates and maintains electrical facilities within and outside the Cleveland National Forest (CNF). This power line replacement project was required as part of SDG&E’s effort to increase the safety and reliability of existing electric facilities within CNF, including the design of fire-resistant steel poles in this active wildfire region. It requires the replacement of nine 12 kV and 69 kV power lines spread over approximately 880 square miles in eastern San Diego County.POWER is providing an extensive and experienced engineering staff to perform the engineering as well as bringing on, and managing, seven subcontract firms to meet the 40% DBE participation target. POWER POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 19 also provided an experienced Project Manager, Project Controls Manager and Document Control Manager to work closely with SDG&E to form an integrated team.POWER’S SERVICESProject ManagementSupport for CPUC filingsVisualizations and simulationsDetailed engineering design for overhead transmission anddistribution linesDetailed engineering design for underground distribution linesBill of materialsSteel pole inspection at manufacturer’s facilitiesMicropile installation supervisionComplete construction specificationsConstruction support during constructionAs-built drawingsACCOMPLISHMENTSDesigned project approach with seamless transitions from preliminary to final design and constructionDesign of fire-resistant steel polesWork in difficult mountainous terrainEndangered animalsPOWER identified six major tasks (Mobilization, Performance Management, Project Controls, Document Management, Subcontract Management, and Closeout) to verify engineering, permitting, procurement, and construction activities accounted for the restrictions and limitations while staying on scheduleProject is currently on schedule and within budgetExceeding diversity goalsPROJECT FEATURESReplace approximately 2,100 existing wood poles with fire-resisting, self-weathering steel poles to meet USFS permitting requirements and minimize visual impactsEnhance the safety and reliability of the systemMinimize environmental impacts during constructionSupport combining more than 70 individual permits for operating and maintaining the system within CNF into one Master Special Use Permit with the USFSAggressive schedule with environmental and seasonal restrictionsSeventeen separate design engineering and construction packages69 kV subtransmission with 12 kV distribution underbuild and 12 kV distribution standalone facilitiesRemoval of 22 miles of existing overhead lines and access roadsApproximately 26 miles of new underground distribution and 122 miles of overhead transmission and distribution.For the Riverside Transmission Reliability Project POWER is providing conceptual and detailed engineering, procurement, contractor selection assistance, and engineering support during construction.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 20 RIVERSIDE PUBLIC UTILITIES/SOUTHERN CALIFORNIA EDISONRiverside Transmission Reliability Project, CaliforniaPOWER is providing environmental licensing, engineering, and engineering procurement, property acquisition, and construction support services for the Riverside Transmission Reliability Project, a major 230kV and 69 kV upgrade to the City of Riverside’s electric system. The project will add a second 230 kV transmission line interconnection to the Southern California Edison transmission grid. During Phase I of the RTRP, POWER conducted a routing study to identify four alternative routes for the 230 kV and 69 kV transmission lines within the highly urban areas of western Riverside and San Bernardino Counties. The POWER environmental team in close coordination with SCE and city staff determined that an Environmental Impact Report would need to be developed with the City of Riverside acting as CEQA Lead Agency. Phase II provided the city with a certified Final Environmental Impact Report that was approved by city council with CPUC acting as a Responsible Agency under CEQA. POWER has also provided substation and transmission line design, and construction support for the 69 kV systems within Riverside Public Utilities’ electric system. To comply with GO No. 131-D requirements, a Certificate of Public Convenience and Necessity (CPCN) for the 230 kV transmission line and new 230 kV Wildlife substation will be applied for by SCE utilizing the certified EIR prepared by POWER. This process and approach, developed by the team, avoided the need for SCE to develop a separate Proponent’s Environmental Assessment (PEA) which would have put the CPUC as lead agency dictating routing and environmental review, including mitigations, and would likely have lengthened the licensing schedule. POWER is providing conceptual and detailed engineering for many of the components of the RTRP, including the new 230-69 kV Wildlife/Wilderness Substation, four new double circuit 69 kV transmission line segments; and upgrades to eight existing 69 kV substations. POWER has completed and submitted the design to upgrade Harvey Lynn and Freeman substations, which included breaker replacement work. In addition to design, POWER is providing procurement, contractor selection assistance, and engineering support during construction.The RTRP project received over 200 pages of public comments on the Draft Environmental Impact Report. POWER worked to diligently and quickly respond to all comments and prepared a defensible Final Environmental Impacts Report that was approved by the City Council and also withstood a CEQA challenge in Los Angeles County court.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 21 TURLOCK IRRIGATION DISTRICTFairground to Industrial 69/12 kV Transmission Line Project, CaliforniaTurlock Irrigation District hired POWER to perform design and engineering services for Turlock’s Fairground to Industrial 0.5-mile double-circuit 69 kV line. The structures needed to accommodate double-circuit 12 kV distribution and ADSS underbuild. POWER coordinated with Turlock to accommodate existing distribution service feeders and taps as well as permitting for a crossing of Highway 99. FEATURESAngle structures comprised engineered structures on reinforced concrete pier foundations. Tangent and distribution tap structures consisted of light duty steel structures with direct embedded foundations and engineered soil backfill.POWER’S SERVICESStructure spotting Detailed design and engineeringMaterial procurement documents and supportConstruction supportPermitting supportSOUTHERN CALIFORNIA EDISONEldorado-Ivanpah Transmission Project Owner's Engineer & Construction Management, Multiple StatesThe Eldorado-Ivanpah Transmission Project (EITP) was needed to get a highly visible solar client’s energy to the electrical grid. The project included modifications to an existing 500 kV line and a new double-circuit, self-supporting lattice, 220 kV transmission line constructed through a very environmentally sensitive area and along two state boundaries. California and Nevada environmental oversight was extreme, focusing on SWPPP, dust control, water restrictions, and protection of endangered species, such as the desert tortoise. As SCE’s Owner’s Engineer/Construction Manager, POWER provided oversight and coordination of the construction process to meet challenging in-service deadlines, promote a culture of safety, and prevent environmental violations. ACCOMPLISHMENTSDeveloped new models to manage linear projects, using special tooling, tracking, and problem-solving methods approach.Mobilized our signature POWER360®management and collaboration tool to communicate daily project status and share GIS-linked bird nesting areas and bird buffers, map-linked field pictures, detailed reporting and action items.Used an innovative GPS-based helicopter navigation system to automate communication of latitude/longitude locations of next locations and buffers.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 22 Completed the project successfully on time and under budget, despite unexpected delays, to meet the accelerated in-service schedule that had been cut by 8 months.Achieved a low safety incident record well below industry levels, with no fatalities or serious injuries.Achieved a no-take record of protected plants and species.Leveraged key partnerships with DVBE and DBE businesses to assist SCE in achieving specific regulatory and company goals.Submitted helicopter plans to gain permits for a Sikorsky S-64 Sky Crane and McDonnell Douglas 530FF for use during construction.PROJECT FEATURESDemolition of existing 35-mile historical 115 kV transmission line.New construction of 35-mile double circuit 220 kV transmission line, and OPGW installation.Communications wire change-out requiring structural modifications to 500 kV towers.Micropile foundations used in difficult rocky conditions.POWER’S SERVICESDesign engineering Owner’s engineerPermit supportConstruction managementInspectionMaterial vendors’ assessment/oversightEnvironmental coordinationProject and program reporting through POWER360®Change managementRisk managementSchedule oversight and problem resolutionConstruction specification and RFP creationContractor selection supportSafety reportingSOUTHERN CALIFORNIA EDISONTehachapi Renewables Project 500 kV and 220 kV Transmission Lines,CaliforniaThe Tehachapi Renewable Transmission Project (TRTP) is the first major transmission project in California being constructed specifically to access multiple renewable generators in a remote renewable-rich resource area. The project is driven by California’s aggressive renewable energy mandates. The TRTP includes 250 miles of new and upgraded 500 kV and 220 kV transmission facilities and substations and is being constructed in phases. POWER is providing final design engineering and construction documents for the new Mesa to Mira Loma 500 kV (Segment 8) transmission line. This part of the overall TRTP includes constructing nearly 33 miles of new single- and double-circuit 500 kV transmission line, removing several miles of 220 kV line structures and constructing approximately 7 miles of new double-circuit 220 kV line.

POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 23 Final design engineering includes final structure spotting, plan and profile drawings, outage and temporary construction planning, foundation design and drawings, detailed access road planning, design and drawings, load drawings and specifications for tubular steel poles, material lists, tower data sheets and preparation and compilation of the complete construction drawing package. For several other project phases POWER has provided cost estimating, preliminary engineering, structure spotting, access road layout, disturbance area identification, impact calculations, and expert witness testimony to support the Proponent’s Environmental Assessment for the California Public Utilities Commission.SOUTHERN CALIFORNIA EDISONDevers to Valley 500 kV Transmission Line, CaliforniaSouthern California Edison contracted with POWER Engineers to complete all of the engineering for 60 miles of 500 kV and seven miles of 220 kV lines from the SCE Devers substation to the Valley substation. The line design included all of the SCE lattice tower families and some tubular self- supporting poles. Included in the project was creation of required crossing drawing road access drawings and FAA information for SCE submittal to the different agencies. The project was completed on time and on budget. SERVICESPreliminary and final transmission line designCost estimatesStructure spottingFoundation designConstruction bid packages and IFC drawingsConstruction supportRecord drawings and documentsSupport for environmental issues and complianceGeotechnical plan and boringsExpert witness testimony to the CPUCCIVIL/STRUCTURAL PROJECT DELIVERABLESAll access road and grading construction drawings, including:Construction and permanent roadsSpur roadsStructure padsMaterial staging areasConductor stringing set-up areasDisturbance areasCut and fill quantitiesImpact calculationsSupporting environmental complianceExpert witness testimony to the CPUC POWER ENGINEERS, INC.

BOI 194-124372.001 RPU ENV/ENG QUALS (11.27.2017) BS ENVIRONMENTAL AND ENGINEERING QUALIFICATIONS | 24 SOUTHERN CALIFORNIA EDISONDevers to Palo Verde #2 500 kV Transmission Line, CaliforniaPOWER provided construction cost estimates and air quality analysis to support SCE in its supplemental information submittal to the California Public Utilities Commission (CPUC) as part of the Proponent's Environmental Assessment (PEA) evaluation process. The project includes the construction of a new 227-mile, 500 kV transmission line between California and Arizona, within SCE's existing transmission corridor and parallel to an existing transmission line. POWER provided cost estimates for 500 kV lattice tower transmission lines and met with SCE engineering personnel to evaluate potential material and construction costs (vehicles, equipment, materials, etc.) based on SCE design and construction standards.POWER also investigated the effects of construction practices on air quality to support the PEA by supplying various equipment tables and schedules that demonstrated typical equipment used on the projects, amounts of emissions that would typically be emitted into the atmosphere, the amount of usage and number of trips on various roads, as well as the durations of usage for each equipment type used for construction.

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