UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION ) ) ) EXHIBIT SCE-1

Transcription

1 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC EXHIBIT SCE-1 PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER ON BEHALF OF SOUTHERN CALIFORNIA EDISON COMPANY APRIL 15, 2015

2 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER ON BEHALF OF SOUTHERN CALIFORNIA EDISON COMPANY (EXHIBIT SCE-1 APRIL 15, 2015

3 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC SUMMARY OF THE PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER (EXHIBIT SCE-1 In Exhibit SCE-1, Mr. Shearer provides an overview of Southern California Edison Company s ( SCE transmission and distribution system in support of the Application of Southern California Edison Company For Factual Determination That The Indicated 115 kv Facilities Are Used In Local Distribution ( Application. Mr. Shearer describes each of SCE s 115 kv systems and facilities at-issue and how they function as part of SCE s local distribution facilities. Using the functional tests developed in prior Commission decisions and rulings, and under applicable Commission precedent, Mr. Shearer discusses the appropriate treatment and classification of these 115 kv Facilities. Finally, Mr. Shearer discusses the immaterial impact of the systems and facilities to the reliability of the Bulk Power System.

4 PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER (EXHIBIT SCE-1 Table of Contents Section Page I. PURPOSE OF TESTIMONY... 3 II. OVERVIEW OF FILING... 4 III. DESCRIPTION OF SCE S TRANSMISSION NETWORKS... 5 IV. SCE S NON-INTEGRATED LOCAL DISTRIBUTION FACILITIES... 6 V. DETAILED DESCRIPTIONS OF THE 115 KV LOCAL DISTRIBUTION FACILITIES VI. FERC FUNCTIONAL TESTS VII. ANALYSIS OF THE SYSTEMS AND FACILITIES AT-ISSUE IN THIS MATTER USING THESE FERC FUNCTIONAL TESTS A. Seven Factor Test Factor One - Proximity of facilities to retail customers Factor Two - Primarily radial in character Factor Three - Power flows into local distribution systems Factor Four - When power enters a local distribution system, it is not reconsigned or transported onto some other market Factor Five - Consumption of power entering the distribution system is in a restricted area Factor Six - Meters are based at the transmission/local distribution interface to measure flow into the local distribution system Factor Seven - Local distribution will be of reduced voltage B. Mansfield Test i -

5 PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER (EXHIBIT SCE-1 Table of Contents (Continued Section Page 1. Mansfield Factor One - The facilities are operated radially and do not loop back into the integrated transmission system Mansfield Factor Two - Energy will flow primarily from the transmission system to local load Mansfield Factor Three - Transmission provider provision of transmission service to itself or other transmission customers Mansfield Factor Four - The facilities do not provide benefits to the transmission grid in terms of capability or reliability, and the facilities cannot be relied on for coordinated operation of the grid Mansfield Factor Five - An outage on the Facilities does not impact the integrated transmission network C. Conclusion of Seven Factor Test and Mansfield Test Analyses VIII. TECHNICAL ANALYSIS DEMONSTRATING IMMATERIAL IMPACT ii -

6 Docket No. RC Exhibit SCE-1 Page 1 of 46 BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC PREPARED DIRECT TESTIMONY OF JONATHAN M. SHEARER ON BEHALF OF SOUTHERN CALIFORNIA EDISON COMPANY Q. Please state your name and business address for the record. A. My name is Jonathan M. Shearer, and my business address is 3 Innovation Way, Pomona, California Q. Briefly describe your educational and professional background. A. I received a Bachelor of Science degree in electronics and computers engineering technology from California State Polytechnic University at Pomona in June 2009, a Master of Business Administration with dual concentration in strategy and global management from Claremont Graduate University in May 2012, and am currently engaged in a course of study towards receipt of a Master of Arts in economics from the California State University at Fullerton. My degree conferral is expected in May of I joined SCE s transmission planning department as an Engineer Trainee in January Currently, I am a Project & Product Manager in the Transmission Planning Compliance group within the Transmission & Interconnection Planning group of the Transmission and Distribution organizational unit at SCE, an investor-owned electric utility company serving 4.9 million customers in Southern California.

7 Docket No. RC Exhibit SCE-1 Page 2 of Q. Briefly describe your present responsibilities at Southern California Edison Company ( SCE. A. My primary responsibilities include providing technical analysis and policy guidance supporting SCE s efforts to plan for advancements in its transmission system and compliance with the North American Electric Reliability Corporation ( NERC Reliability Standards applicable to transmission planning. During my tenure with the Transmission & Interconnection Planning group, my responsibilities have involved performing a host of technical analyses on power flow, demand, and generation in Southern California and the whole of the Western Interconnection. 1 My job also involves performing semi-technical and functional analyses on whether specific facilities function as part of the integrated transmission network or function as local distribution facilities. In addition to this work, I also provide analysis and guidance on systems that function as local distribution facilities and are not classified as part of SCE s transmission system, and I monitor and review technical analyses demonstrating immaterial impact of local distribution facilities to the reliability of the Bulk Power System. Q. Have you submitted testimony to the Commission previously? A. No. 1 The Western Interconnection is a physically- and electrically-defined area that encompasses the infrastructure components of the Bulk Electric System. The area extends from Canada to Mexico and includes Alberta and British Columbia, all or parts of the 14 Western states, and northern Baja California.

8 Docket No. RC Exhibit SCE-1 Page 3 of I. PURPOSE OF TESTIMONY Q. What is the purpose of your testimony in this proceeding? A. The purpose of my testimony is to: (1 provide an overview of SCE s transmission and distribution systems; (2 provide a description of each of the systems that comprise the 115 kv Facilities; 2 (3 provide an overview of the seven indicators of local distribution ( Seven Factor Test developed by the Commission in Order No and the five factors the Commission established in Mansfield 4 for determining integrated facilities; (4 provide the analysis of the Facilities through application of the Seven Factor Test and Mansfield test; and (5 provide technical reliability information to support SCE s Application and aid the Commission in making the factual determination whether the 115 kv Facilities discussed herein are used in local distribution of energy and, as such, do not fall within the revised definition of the Bulk Electric System ( BES SCE s 115 kv systems and facilities at issue in this Application comprise a subset of SCE s local distribution systems, and include all facilities within six of SCE s 115 kv systems and certain 115 kv facilities north of SCE s Lugo substation. In SCE s Application and supporting exhibits, these systems and facilities are collectively referred to as the 115 kv Facilities or the Facilities. 3 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. 31,036 (1996, order on reh g, Order No. 888-A, FERC Stats. & Regs. 31,048, order on reh g, Order No. 888-B, 81 FERC 61,248 (1997, order on reh g, Order No. 888-C, 82 FERC 61,046 (1998, aff d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000, aff d sub nom. New York v. FERC, 535 U.S. 1 ( Mansfield Municipal Electric Dept., 97 FERC 61,130 (2001, reh g denied, Opinion No. 454-A, 98 FERC 61,115 (2005. ( Mansfield.

9 Docket No. RC Exhibit SCE-1 Page 4 of 46 1 II. OVERVIEW OF FILING Q. Please provide a brief overview of SCE s Application. A. The purpose of the Application is to seek a factual determination from the Commission confirming that the 115 kv Facilities do not fall within the revised definition of the Bulk Electric System because these systems and facilities are used exclusively for the local distribution of energy and are not operated in parallel with the Bulk Electric System. Q. Please identify each exhibit attached to the Application. A. A listing of the exhibits is as follows: Exhibit SCE-1: Prepared Direct Testimony of Jonathan M. Shearer; Exhibit SCE-2: Map of SCE Service Territory; Exhibit SCE-3: Diagram of SCE Local Distribution Systems; Exhibit SCE-4: Diagram of the Devers 115 kv System; Exhibit SCE-5: Diagram of the El Casco 115 kv System; Exhibit SCE-6: Diagram of the Mirage 115 kv System; Exhibit SCE-7: Diagram of the Valley 115 kv System; Exhibit SCE-8: Diagram of the Victor 115 kv System; Exhibit SCE-9: Diagram of the Vista 115 kv System; Exhibit SCE-10: Diagram of the Radial 115 kv Facilities North of Lugo Substation; Exhibit SCE-11: Detailed Diagram of the Control 115/55 kv Subsystem (CEII; Exhibit SCE-12: Detailed Diagram of the Inyokern 115 kv Subsystem (CEII; Exhibit SCE-13: SCE 115 kv Local Distribution Impact to Bulk Electric System Study Report Dated March 24, 2015; Exhibit SCE-14: BES Interface Substations Line & Bus Arrangements (CEII; and

10 Docket No. RC Exhibit SCE-1 Page 5 of 46 1 Exhibit SCE-15: Notices. 2 3 III. DESCRIPTION OF SCE S TRANSMISSION NETWORKS Q. What voltages comprise SCE s transmission network? A. SCE s integrated transmission network delivers bulk power from around the Western Interconnection and is operated by the California Independent System Operator ( CAISO. The voltages of SCE s transmission network consists of 500 kv, 220 kv, 161 kv A.C. and 1000 kv D.C. Additionally, SCE has a limited number of 115 kv, 66 kv, and 55 kv lower voltage facilities, which are operated in parallel with the integrated transmission network, and therefore are treated as part of the Bulk Electric System. Q. Please describe the attributes of SCE s transmission network. A. The reliability of SCE s transmission network hinges on the resiliency of the integrated network s response to disturbances, while providing customers access to affordable and reliable energy from within SCE s transmission network and from the Western Interconnection. SCE s integrated transmission network, comprised mainly of parallel 220 kv and 500 kv transmission lines, accommodates the transfer and importation of energy to SCE s geographically diverse service territory, as depicted in Exhibit SCE-2. SCE s service territory, which covers nearly one-third of the land area of the state of California, includes service to customers within portions, or the entirety of, fourteen California counties. Of these counties, seven are within the top 100 most populous

11 Docket No. RC Exhibit SCE-1 Page 6 of counties in the United States according to the 2010 U.S. Census Report. 5 In order to meet the needs of Southern California s large and varied electrical demand, SCE s 500 kv and 220 kv transmission network reliably delivers high voltage energy to SCE s lower voltage local distribution facilities. To ensure the reliability of the transmission network and to provide for distribution system operational flexibility, SCE operates its local distribution systems radially from the high voltage integrated transmission network. 7 8 IV. SCE S NON-INTEGRATED LOCAL DISTRIBUTION FACILITIES Q. What voltages comprise SCE s local distribution facilities? A. SCE s local distribution facility voltages consist of 115 kv, 66 kv, 55 kv, 33 kv, 16 kv, 12 kv, and 4 kv AC. Q. Is it common in the US to use this many different distribution voltages? A. Voltages used are the product of history and regional differences in need, costs, available technology, and equipment standards over time. SCE is not excluded from this, given its 125 years of operation, and as described below, SCE s historical evolution to its current service territory has resulted in the unique blend of distribution voltages SCE uses today. Q. Can you elaborate on what role regional differences play? 5 United States Census Bureau Census of Population and Housing,

12 Docket No. RC Exhibit SCE-1 Page 7 of A. Regional differences include differences in terrain and population patterns, and may warrant the use of voltages as low as 69 kv for transmission facilities (such as in the Eastern Interconnection 6 where load centers are in close proximity to one another, in contrast to the use of voltages higher than 100 kv for distribution (as in the Western Interconnection where distribution facilities must travel long distances to reach customers. SCE is not excluded from this, given its 125 year history of operation. The Commission has explicitly recognized the effect of regional differences. In its Order denying the City of Holland s appeal of its facilities BES status, it distinguished the City s facilities from those of systems in the Western region, where distribution lines are designed with comparatively high voltage levels due to the large distances that must be traversed in serving retail load. 7 I do not mean to imply that a particular voltage is specifically transmission or distribution because of its location, but I am merely illustrating that regional differences exist. This is why it is necessary to have semitechnical/functional tests to determine the actual function of a facility irrespective of exact voltage. Q. Is the use of 115 kv and 66 kv for local distribution facilities common? 6 The Eastern Interconnection reaches from Central Canada Eastward to the Atlantic coast (excluding Québec, South to Florida and West to the foot of the Rockies (excluding most of Texas. 7 City of Holland, Michigan Board of Public Works, Order Denying Appeal, 139 FERC 61,055 (2012, at P 42.

13 Docket No. RC Exhibit SCE-1 Page 8 of A. Other utilities have constructed their systems in a manner such that 115 kv and 66 kv are part of the integrated network, and are not local distribution. This is certainly the case in California, as both Pacific Gas and Electric Company ( PG&E and San Diego Gas & Electric Company ( SDG&E include facilities with similar voltages in the transmission network, rather than local distribution. Q. Please explain why SCE s system is structured in the unique manner you have described. A. In the Western Interconnection, population centers are widespread over long geographical distances. Higher voltages permit more efficient transmission of electrical energy and have additional economic benefits including higher utilization rates, lower energy losses. It also requires less equipment to operate and maintain for serving the same magnitude of electric demand. SCE s current service territory, shown in Exhibit SCE-2, was developed through several different electric utility mergers and acquisitions over the last 125 years. Prior to 1964, the California Electric Power Company ( Cal Electric served the area from Tonopah, Nevada to Palm Springs, California. In January of 1964, SCE and Cal Electric merged. The 115 kv Facilities at issue in this filing are the legacy Cal Electric 115 kv local distribution systems and facilities (see Exhibit SCE-3 which are not operated in parallel with, but instead radially from, the integrated transmission system. Functionally, the 115 kv Facilities operate exactly like SCE s 66 kv local distribution systems; the only differences are the operating voltage and densities of the populations served. The 115 kv Facilities are local distribution systems which serve rural population centers in desert areas of the eastern half of SCE s service territory as depicted in Exhibit SCE-3. The higher voltage of these local distribution facilities

14 Docket No. RC Exhibit SCE-1 Page 9 of increases efficiency of providing energy to these rural communities within SCE s desert territory. Q. Please describe the unique attributes of SCE s local distribution facilities. A. As noted above, SCE operates the 115 kv Facilities radially from the high voltage integrated transmission network. This is a key design factor and an important reliability feature of the SCE system because under this configuration a single substation serves as the interface between the integrated transmission network and the local distribution system radiating from the transmission network. Maintaining electrical isolation between SCE s radial local distribution systems allows SCE to reduce the impacts of unforeseen forced outage situations and the durations of service interruptions experienced by our customers. Q. Why is it significant that the 115 kv Facilities at issue in this Application are operated radially from the transmission network? A. Unlike transmission facilities, SCE s local distribution facilities do not operate in parallel with the integrated transmission network (i.e., are not looped with the transmission network. This is a very important design feature that eliminates the possibility of power flowing into the local distribution facilities and back onto the transmission network, and thus prevents the local distribution facilities from negatively affecting the reliability of the integrated transmission network. All parallel facilities share and balance the flow of electricity as determined by relative impedances and power flow-controlling devices between sources of electricity and the end-use consumers of electricity. Unlike the 115 kv Facilities, a facility that is

15 Docket No. RC Exhibit SCE-1 Page 10 of operated in parallel specifically with the transmission network (i.e., looped facility, can at any point in time see a shift in power flow direction across the looped facilities as a result of generation and demand fluctuations in the transmission network without any changes to the demand or generation within the looped facilities. This is because the looped facilities act as an alternative path between generation sources and end-use consumers outside of the looped facilities. In direct contrast, facilities that are operated radially from the transmission network will only see a shift in power flow direction as a result of fluctuations in generation and demand within the radial facilities themselves. Facilities which are operated radially from the transmission network can be connected by a single circuit or transformer bank or by parallel facilities so long as at no other point downstream is there another connection to the transmission network. In other words, the distinction between being operated in parallel with versus radially from the transmission network is that the source of power for the radial facilities is only a single electrical node serves as the source of power for the end-use customer, as opposed to looped facilities with multiple electrical nodes that can provide alternate sources of power for the end-use customer. Likewise, when radially-operated facilities experience a condition where the generation sources exceed the local load, there is only a single electrical node by which the excess generated energy can be delivered into the transmission network. Since SCE s 115 kv Facilities are operated radially from the integrated transmission network, power flows in only one direction between the Bulk Electric System and the local distribution facilities. Changes in the power system conditions of the integrated transmission network do not change the flow between the Bulk Electric

16 Docket No. RC Exhibit SCE-1 Page 11 of System and SCE s 115 kv Facilities. The radial nature of SCE s 115 kv Facilities is more fully addressed in the analysis of the 115 kv Facilities under the Seven Factor Test and Mansfield test in Section VII of this testimony. Q. Please briefly describe how operational control was determined for SCE s local distribution facilities. A. During the formation of the California energy market, SCE s facilities that made up the integrated transmission network were transferred to the CAISO s operational control, because the CAISO would need operational control of all facilities that operated in parallel to the transmission facilities for the purposes of safety, efficiency, and reliability. 8 Pursuant to the Transmission Control Agreement ( TCA between SCE and the CAISO, the Commission approved the exclusion of SCE s 115 kv radially-operated facilities from CAISO operational control and their classification as local distribution facilities due to the radial operation and functional nature of the facilities. 9 SCE s 115 kv and below facilities that are operated in parallel with the transmission network were turned over to the operational control of the CAISO; 10 SCE is not seeking to change the classification or operational control of these facilities and this 8 See, e.g. California Public Utilities Decision (D (January 21, Order Granting Petition For Declaratory Order In Part, issued October 30, 1996 in Docket No. EL (77 FERC 61, Two portions of SCE s system are operated at 115 kv or below and are operated in parallel with the transmission network: (1 SCE s Neenach 66kV substation and facilities operated in parallel with SCE s integrated 220 kv transmission network; and (2 certain facilities covering long distances between lower density population centers within distribution systems north of SCE s Lugo substation, which are operated in parallel with SCE s 220 kv integrated transmission network, Los Angeles Department of Water and Power s 230 kv network, and Sierra Pacific Power s system in Nevada (as shown in red on Exhibit SCE-10.

17 Docket No. RC Exhibit SCE-1 Page 12 of Application specifically excludes those facilities from the factual determination it seeks. SCE s Application does not seek any action on lower voltage facilities currently operated in parallel with the transmission network. SCE s transmission facilities currently under CAISO operational control are used to transmit and transform bulk power that is then sold to or used by retail and wholesale customers across the state. Similarly, other CAISO Participating Transmission Owners, 11 specifically PG&E and SDG&E have lower voltage systems that are under CAISO operational control due to the parallel operation of those facilities with the integrated transmission network. Ultimately, CAISO operational control has always encompassed only the facilities that are operated in parallel with the transmission network V. DETAILED DESCRIPTIONS OF THE 115 KV LOCAL DISTRIBUTION FACILITIES Q. Please list SCE s 115 kv local distribution systems and facilities at-issue in this filing. A. The following six systems in their entirety are at issue: 1. Devers 115 kv system, 2. El Casco 115 kv system, 3. Mirage 115 kv system, 4. Valley 115 kv system, 11 Entities for which the California ISO is the Balancing Authority and Transmission Service Provider sign Participating Transmission Owner agreements per the Fifth CAISO Approved Tariff.

18 Docket No. RC Exhibit SCE-1 Page 13 of Victor 115 kv system, and 6. Vista 115 kv system. The remaining facilities at issue in this Application are certain 115 kv radial facilities in the region north of SCE s Lugo substation (radial substations and facilities within the Control 115 kv subsystem, Kramer 115 kv subsystem and Inyokern 115 kv subsystem shown in Exhibit SCE-10. These are collectively referred to in the Application as North of Lugo, and are discussed in more detail below. Q. Please provide a description of the Devers 115 kv system. A. The Devers 115 kv system, depicted in Exhibit SCE-4, is comprised of eleven ( kv load-serving substations and thirteen ( kv generation-interconnection substations. The substations and 188 circuit miles of power lines support approximately 511 MW of peak load. Approximately 8% of the peak load is modeled as large nonconforming loads; these large load customers include a bottling plant and a military base. The Devers 115 kv system covers approximately 1,120 square miles of service area, serving portions of Riverside County and San Bernardino County including the cities of Cathedral City (pop. 51,200; Palm Springs (pop. 44,552; Desert Hot Springs (pop. 25,938; Twentynine Palms (pop.25,048; Yucca Valley (pop. 20,700; and Joshua Tree (pop. 7,414. Currently, market and Qualified Facility intermittent wind resources equate to 752 MW of installed generation capacity in the Devers 115 kv system, and a dispatchable gas-fired generating station can provide as much as 136 MW of generation to the system. Q. Please provide a description of the El Casco 115 kv system.

19 Docket No. RC Exhibit SCE-1 Page 14 of A. The El Casco 115 kv system, depicted in Exhibit SCE-5, is comprised of 7 substations and 82 circuit miles that support approximately 188 MW of peak load. Almost 95% of the load is modeled as conforming retail customers. Approximately 6% of the peak and 10% of the off-peak are modeled as large non-conforming loads; these comprise two of Metropolitan Water District s pumping facilities. The El Casco 115 kv system covers approximately 50 square miles of service area around the cities of Banning and Beaumont. According to the 2010 census, the El Casco 115kV system serves an aggregate population of approximately 60,000 people. There are no generating facilities with a gross individual nameplate rating greater than 20 MVA or where the gross plant aggregate nameplate rating is greater than 75 MVA located within the El Casco 115 kv system. Q. Please provide a description of the Mirage 115 kv system. A. The Mirage 115 kv system, depicted in Exhibit SCE-6, is comprised of five (5 115 kv load-serving substations and one (1 115 kv generation-interconnection substation. The substations and 78 circuit miles support approximately 480 MW of peak load. There are no non-conforming load customers in the Mirage 115 kv system. The Mirage 115 kv system covers approximately 112 square miles of service area, serving a portion of Riverside County including the cities of Palm Desert (pop. 48,445; Rancho Mirage (pop. 17,218; Thousand Palms (pop. 7,715; Bermuda Dunes (pop. 7,282; and Indian Wells (pop. 4,958. One SCE generation customer provides 20 MW of intermittent wind generation to the Mirage System. Q. Please provide a description of the Valley 115 kv system.

20 Docket No. RC Exhibit SCE-1 Page 15 of A. The Valley 115 kv system, depicted in Exhibit SCE-7, is comprised of 25 substations and close to 387 circuit miles that support approximately 1,825 MW peak load. Approximately 2.5% of the load customers are modeled as large non-conforming retail load customers. These large customers include a technology manufacturing facility and a water company which each connect directly at 115 kv. The Valley 115 kv system also serves many smaller retail load customers. The total Valley 115 kv service area covers around 844 square miles of Riverside County. According to the 2010 census, the aggregate population of the largest cities served by the Valley 115 kv system is approximately 595,000 people. Some of these cities are Hemet, Lake Elsinore, Murrieta, Menifee, Temecula, and Perris. There are no generating facilities with a gross individual nameplate rating greater than 20 MVA or where the gross plant aggregate nameplate rating is greater than 75 MVA located within the Valley 115 kv system. Q. Please provide a description of the Victor 115 kv system. A. The Victor 115 kv system, depicted in Exhibit SCE-8, is comprised of 14 substations and close to 200 circuit miles that support approximately 750 MW of peak load. Approximately 15% of the load customers are modeled as large non-conforming retail load customers. These large customers include a cement plant and mining facilities which connect to the Victor system directly at 115 kv. The Victor system also serves many smaller retail load customers. The total Victor 115 kv service area covers around 300 square miles in San Bernardino County. According to the 2010 census, the aggregate population of the largest cities served by the Victor system is approximately 290,000 people. Some of these cities are Victorville, Hesperia, Lucerne Valley, and Apple Valley. There are no generating facilities with a gross individual nameplate rating greater

21 Docket No. RC Exhibit SCE-1 Page 16 of than 20 MVA or where the gross plant aggregate nameplate rating is greater than 75 MVA located within the Victor 115 kv system. Q. Please provide a description of the Vista 115 kv system. A. The Vista 115 kv system, depicted in Exhibit SCE-9, is comprised of 11 substations and 136 circuit miles that support approximately 435 MW of peak load. Almost 100% of the peak and off peak loads are modeled as conforming retail customers. The Vista 115 kv system covers approximately 90 square miles of service area around the cities of Rialto, San Bernardino, areas North to the city of Lake Arrowhead, and south to Moreno Valley. According to the 2010 census, the Vista 115 kv system serves an aggregate population of approximately 300,000 people. In addition, there are also two generating facilities residing in the Vista 115 kv system: Mojave Siphon (34.5 MW and Devil Canyon (280 MW. These generating units are powered by the water movement of the California Aqueduct system. Q. Please provide a description of the radial 115 kv facilities north of Lugo substation. A. Three 115 kv subsystems and several radial substations, depicted in Exhibit SCE-10, operate north of SCE s Lugo 500/220 kv substation. The 115 kv subsystems are the Inyokern 115 kv, Kramer 115 kv, and Control 115 kv subsystems, and a portion of each subsystem is integrated with the transmission network and is under the operational control of the CAISO; SCE is not seeking any Commission determinations regarding these portions, and they are not at-issue in this Application. The SCE-controlled radial portions of the Inyokern, Kramer, and Control subsystems and the North of Lugo radial substations in total are comprised of 14

22 Docket No. RC Exhibit SCE-1 Page 17 of substations and include over 1400 circuit miles that support approximately 290 MW of peak load. Approximately 16% of the load customers are modeled as large nonconforming retail load customers. These large customers include a cement plant, glass manufacturer, military facility, and aerospace manufacturer that connect directly at 115 kv. The North of Lugo region also serves many smaller retail load customers. The total SCE-controlled North of Lugo 115 kv service area is approximately 400 square miles and includes portions of San Bernardino, Kern, Inyo, Tulare, and Mono Counties. Currently, there is MW of cogeneration and 54.6 MW of hydro generation connected to the Facilities located throughout the North of Lugo region VI. FERC FUNCTIONAL TESTS Q. Please briefly describe the Seven Factor Test from FERC s Order 888 that is used to determine the function of electric facilities.

23 Docket No. RC Exhibit SCE-1 Page 18 of A. In Order 888, 12 the Commission outlined a Seven Factor Test to determine whether facilities function as transmission facilities or are used for the local distribution of energy. The indicators of local distribution in the Commission s Seven Factor Test are that: (i local distribution facilities are normally in close proximity to retail customers; (ii local distribution facilities are primarily radial in character; (iii power flows into local distribution systems, and rarely, if ever, flows out; (iv when power enters a local distribution system, it is not reconsigned or transported onto some other market; (v power entering a local distribution system is consumed in a comparatively restricted geographic area; (vi meters are based at the transmission/local distribution interface to measure flow into the local distribution system; and (vii local distribution systems will be of reduced voltage. 12 Order 888, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats & Regs 31,036 at 31,771 (1996 (subsequent history omitted ( Order 888.

24 Docket No. RC Exhibit SCE-1 Page 19 of Q. Please briefly describe the five-factor test from the Commission s Mansfield decision that is used to determine the level of integration of electric facilities. A. In Mansfield, the Commission addressed the issue of whether certain facilities were or were not integrated with the relevant transmission provider s transmission system and, as such, could properly be included for rolled-in transmission charges. The Commission affirmed the Presiding Judge s adoption of the five Mansfield factors. 13 I understand the five factors to be: 1 Whether the facilities are radial, or whether they loop back into the transmission system; 2 Whether energy flows only in one direction, from the transmission system to the customer over the facilities, or in both directions, from the transmission system to the customer, and from the customer to the transmission system; 3 Whether the transmission provider is able to provide transmission service to itself or other transmission customers over the facilities in question; 4 Whether the facilities provide benefits to the transmission grid in terms of capability or reliability, and whether the facilities can be relied on for coordinated operation of the grid; and 5 Whether an outage on the facilities would affect the transmission system VII. ANALYSIS OF THE SYSTEMS AND FACILITIES AT-ISSUE IN THIS MATTER USING THESE FERC FUNCTIONAL TESTS 19 Q. Describe how the analysis was conducted. 13 Mansfield at 61,

25 Docket No. RC Exhibit SCE-1 Page 20 of A. The Seven Factor Test and Mansfield test were applied to each of the systems separately. Since the functional nature of each system for which SCE is seeking a Commission determination is the same, the results of the analyses are presented jointly for all systems and facilities at issue. Where any additional information regarding a specific system contributes to the analysis, it is noted separately in this testimony. A. Seven Factor Test 1. Factor One - Proximity of facilities to retail customers The Facilities, in aggregate, are comprised of 87 substations that support approximately 4,479 MW of peak load. The aggregate territory covers only 2,916 square miles in contrast to the SCE service territory depicted in Exhibit SCE-2, which totals more than 50,000 square miles. Owing to the generally rural nature of the areas served by the 115 kv Facilities, the occasional pockets of urban and suburban development, and the comparatively small total area of each system, the 115 kv Facilities are in close proximity to the retail customers. The single interface substations (the sole source of energy from the integrated transmission system into each local distribution system bring power into the distribution system from the transmission. The design is not different from SCE s 66 kv local distribution systems, which are fed power from single interface substations connected to the 220 kv network. This is the first indication that the 115 kv Facilities are used for the local distribution of energy. 2. Factor Two - Primarily radial in character The use of 115 kv and lower voltages to build a local distribution network that is served via one transmission source substation is pivotal to the design of SCE s distribution systems. At no point can the energy delivered from the integrated transmission network into any of the 115

26 Docket No. RC Exhibit SCE-1 Page 21 of kv Facilities re-enter the transmission network, since the Facilities are not looped with the transmission network. Within the non-integrated 115 kv local distribution systems radiating from the integrated transmission network are parallel circuits to maintain reliable service for both load and generation within a local distribution system, consistent with SCE distribution planning practices. The radial nature of the local distribution system is unchanged as none of these parallel circuits are looped with the integrated transmission network. Additionally, there are normally-open circuit breakers which maintain the radial operation of each local distribution system and are marked in the diagrams of each system (Exhibit SCE-4 through Exhibit SCE-10. These normally-open circuit breakers exist solely for use in an emergency to permit SCE operators to roll, i.e. transfer, load to a neighboring system as needed. However, the systems are not planned or designed to form parallel paths between the systems, as doing so would potentially create exposure to localized thermal overloads under contingency. Rolling load between the systems is only performed utilizing standard drop and pick up operating procedures, 14 which are standard throughout all other SCE distribution systems, in order to avoid this exposure. Because of the normally-open breakers, the 115 kv local distribution systems remain radial in character. Each of the 115 kv systems or radial facilities north of Lugo draws power from the integrated transmission network when the load in that system exceeds the total power generated 14 Electrical service must first be disconnected and remain disconnected before a customer, circuit, substation, etc. is reconnected to a separate local distribution system than the original system.

27 Docket No. RC Exhibit SCE-1 Page 22 of locally. In SCE s Devers 115 kv system (Exhibit SCE-4, which encompasses part of the desert region of California, loads are higher and the wind-produced power is lower during the daytime. Power flows through the single interface into the Devers 115 kv system. When the local wind generation levels exceed the load in the Devers system, the power flows from the 115 kv system into the integrated transmission network much like a generation tie-line. As stated by the Commission in its Orders on Cabazon and Whitewater, 15 the occasional flow into the transmission system does not change the radial nature of the system. Furthermore, at no point is the power simultaneously entering and exiting the Devers 115 kv local distribution system, or any of the 115 kv Facilities. 3. Factor Three - Power flows into local distribution systems As with any radial distribution system with interconnected generation, the flow at the point of interconnection with the transmission system is unidirectional, but its direction can vary based on system conditions. As discussed before, the flow is, in most cases, always inbound from the integrated transmission network to the 115 kv Facilities. As explained in the second factor for the Devers 115 kv system, the flow direction reverses when the local generation exceeds the load, mostly during winter nights, but the 115 kv lines and 220/115 kv transformers in the Devers 115 kv system do not functionally change. The fact that power may flow to the transmission system from the distribution system as a result of increased generation on the 15 Cabazon Wind Partners, LLC, v. So. Cal. Edison Co., 117 FERC 61,212 (2006 ( Cabazon ; Opinion No. 487, So. Cal. Edison Co., 117 FERC 61,103 (2006 ( Whitewater. See also, Northeast Texas Electric Cooperative, Inc., et al., 100 FERC 63,033 (2002, aff d Opinion No. 474, 108 FERC 61,084 (2004.

28 Docket No. RC Exhibit SCE-1 Page 23 of distribution system does not mean that such distribution system has the characteristics of an integrated transmission system. Such a condition results in the distribution system behaving like generation tie-lines which are also facilities that are not integrated with the transmission network. 4. Factor Four - When power enters a local distribution system, it is not reconsigned or transported onto some other market In all of the 115 kv Facilities, power entering from the integrated transmission grid - operated by the CAISO - will remain within the respective system or radial facilities. The radial nature prevents this power from being transported back to the integrated transmission grid for consignment to another market. The CAISO is the transmission service provider for SCE. Generator owners interconnected to any of SCE s distribution facilities (including the 115 kv Facilities are provided distribution service from the point of interconnection to the CAISO-controlled grid where it can then be transported through the CAISO system to the ultimate buyer of the resource. This is the case even if the amount of load is more than the amount of generation. While actual power from local generation offsets local system or substation load, the delivery of the power to the ultimate buyer is provided by the CAISO even if the buyer is the same entity whose load is offset. The role of the 115 kv Facilities with respect to this factor, however, remains unchanged. Under the system conditions where power enters any radial 115 kv system or facilities, the local load exceeds the level of generation, if any. This power has been procured to serve customers located within the respective system or radial facilities and is not reconsigned or transported onto some other market. Further, neither SCE nor the CAISO relies upon bi-directional flows on any of the 115 kv Facilities to either serve SCE area load or the load of other transmission customers.

29 Docket No. RC Exhibit SCE-1 Page 24 of Factor Five - Consumption of power entering the distribution system is in a restricted area Power entering into the 115 kv Facilities is consumed in a comparatively restricted geographical area, as evidenced by the proximity of these 115 kv Facilities to customers. Under the design of SCE s local distribution systems, power entering the Facilities is unable to serve load outside the Facilities respective areas; all power entering is used within the system or respective radial facilities. 6. Factor Six - Meters are based at the transmission/local distribution interface to measure flow into the local distribution system SCE s local distribution systems are metered at or near the point of interconnection to the CAISO-controlled integrated transmission network. The meters between the integrated transmission network and the 115 kv Facilities are necessary to enable reliable transfer of energy between the operational control jurisdictions of the CAISO and SCE. The meters are connected to the transformer banks for each of the 115 kv systems and measure the flow into or out of the 115 kv system depending on system conditions. Radial facilities north of Lugo substation meter flow at the substation or switchrack at the interface with the CAISO-controlled transmission network as shown in Exhibit SCE-10. All interface meters are shown on the detailed diagrams as shown in Exhibit SCE-4 through Exhibit SCE-10.

30 Docket No. RC Exhibit SCE-1 Page 25 of Factor Seven - Local distribution will be of reduced voltage The Commission found that certain SCE 115 kv facilities are used in the local distribution of energy and thereby accepted that, for SCE, 115 kv qualifies as reduced voltage; 16 the Commission has confirmed its finding in subsequent proceedings. 17 The voltage level of the 115 kv Facilities has not changed nor has the function changed since the revision to the Bulk Electric System definition. I submit that 115 kv, in the context of the higher transmission voltages used in the Western Interconnection is of reduced voltage. More importantly, SCE has historically used, and continues to use, 115 kv as a local distribution voltage class. However, when lower voltage facilities are normally operated in parallel with the transmission network regardless of the voltage of those facilities SCE ensures those facilities are in compliance with applicable NERC Reliability Standards and treated as part of SCE s transmission network. Specifically, the 55 kv lines between SCE s Control substation and Sierra Pacific Power s Silverpeak substation (Exhibit SCE-10, Antelope-Neenach-Bailey 66 kv line, and 115 kv facilities north of Lugo that are integrated with the transmission network and are held to NERC Reliability Standards and classified as part of transmission SCE s transmission network. 16 Commission s Order Granting Petition For Declaratory Order In Part, issued October 30, 1996 in Docket No. EL (77 FERC 61, Cabazon Wind Partners, LLC, v. So. Cal. Edison Co., 117 FERC 61,212 (2006 ( Cabazon ; Opinion No. 487, So. Cal. Edison Co., 117 FERC 61,103 (2006 ( Whitewater. See also, City of Holland, Michigan Board of Public Works, 145 FERC 61,054, at P 30 (2013 ( City of Holland.

31 Docket No. RC Exhibit SCE-1 Page 26 of B. Mansfield Test 1. Mansfield Factor One - The facilities are operated radially and do not loop back into the integrated transmission system The first Mansfield factor is identical to the second factor of the Seven Factor Test. My analysis as presented for Factor Two above applies equally for this first Mansfield factor. In summary, the 115 kv Facilities operate radially and do not loop back into the integrated transmission system. At no point in any of the respective systems or radial facilities is there a second interface with the transmission network. Rather, a single substation acts as the sole source for energy delivery at times when the local load exceeds the local generation (if any, and it acts as the sole interface when the local generation exceeds the load (as with the Devers system shown in Exhibit SCE-4. No looping with the transmission system exists and the 115 kv Facilities are operated radially. As such, the first Mansfield factor for the 115 kv Facilities indicates that they are not integrated with the transmission network. 2. Mansfield Factor Two - Energy will flow primarily from the transmission system to local load Similarly, the second Mansfield factor is identical to the third factor of the Seven Factor Test. Likewise, my analysis presented for Factor Three above supports this factor. In summary, the analysis shows that on the 115 kv Facilities, flows are expected to normally be inbound from the integrated transmission network. As noted previously, there are times when the local intermittent wind generation within the Devers 115 kv system exceeds the local load and the Devers 115 kv system (Exhibit SCE-4 acts similar to that of a radial generation tie-line; but, this situation is not the normal mode of operation. The fact that power may flow to the transmission system from the distribution system as a result of higher generation levels on the

32 Docket No. RC Exhibit SCE-1 Page 27 of distribution system does not mean that such distribution system has the characteristics of being integrated with transmission system. Accordingly, the second Mansfield factor indicates the 115 kv Facilities are not integrated with the transmission network. 3. Mansfield Factor Three - Transmission provider provision of transmission service to itself or other transmission customers Of highest importance for the third Mansfield factor is that the CAISO is the transmission provider for the SCE service territory. The 115 kv Facilities are not under the operational control of the CAISO and do not provide any transmission service for SCE or any other entity. For SCE s retail customers located in areas served by the 115 kv Facilities, distribution service is provided pursuant to SCE s retail tariff subject to the jurisdiction of the California Public Utilities Commission. For wholesale generators or loads, distribution service is provided pursuant to SCE s Wholesale Distribution Access Tariff subject to the jurisdiction of the Commission. The transmission provider, the CAISO, is unable to use the Facilities to provide transmission service. Under the independent system operator construct in California, the CAISO provides transmission service only over the integrated transmission grid that is subject to its operational control. Distribution Providers, such as SCE, provide distribution service to or from the CAISO-controlled grid over the distribution facilities that are subject to SCE s operational control. As such, the third Mansfield factor indicates the 115 kv Facilities are not integrated with the transmission network.

33 Docket No. RC Exhibit SCE-1 Page 28 of Mansfield Factor Four - The facilities do not provide benefits to the transmission grid in terms of capability or reliability, and the facilities cannot be relied on for coordinated operation of the grid The 115 kv Facilities cannot be relied upon for coordinated operation of the integrated transmission network because they do not operate in parallel with the integrated transmission network and are under SCE s operational control. As a result, under normal conditions, 18 the radial 115 kv systems and facilities will not add to the capability of the integrated transmission grid. Consequently, there will be no benefit to the integrated transmission system in terms of capability or reliability. The radial 115 kv systems and facilities each have only a single point of interconnection to the CAISO grid and do not materially impact the integrated transmission grid in terms of capability or reliability. As such, the fourth Mansfield factor indicates the 115 kv Facilities are not integrated with the transmission network. 5. Mansfield Factor Five - An outage on the Facilities does not impact the integrated transmission network Outages of any element within the 115 kv Facilities do not impact the integrated transmission network because the system does not operate in parallel with the integrated transmission network. Outages in the radial 115 kv systems or on the radial facilities do not impact the reliability of the integrated transmission network and vice-versa. An outage of facilities internal to any of the six radial systems or on the radial facilities north of Lugo results 18 One SCE operating procedure allows for the parallel operation of the Valley and Vista 115 kv systems under very specific and limiting circumstances.

34 Docket No. RC Exhibit SCE-1 Page 29 of in localized impacts internal to the respective system or radial facilities and does not propagate to the integrated transmission network. The Facilities also do not impact the ability of the CAISOcontrolled grid to transmit energy over the integrated transmission network as outages of 115 kv Facilities do not significantly change flows on the integrated transmission network. As such, the fifth Mansfield factor indicates that the 115 kv Facilities are not integrated with the transmission network. C. Conclusion of Seven Factor Test and Mansfield Test Analyses In conclusion, my analysis of SCE s 115 kv Facilities using both the Seven Factor Test and Mansfield test shows that the Facilities continue to function as local distribution facilities and are not integrated with the transmission network VIII. TECHNICAL ANALYSIS DEMONSTRATING IMMATERIAL IMPACT Q. Describe the technical analysis conducted to demonstrate immaterial impact to the integrated transmission network. A. Recognizing that part of the purpose of revising the Bulk Electric System definition was to ensure facilities which may not have previously been classified as part of the Bulk Electric System yet have a material reliability impact on the Bulk Power System are included as part of the Bulk Electric System, SCE conducted several studies that go beyond what is required by the NERC Transmission Planning (TPL reliability standards. As a starting point, SCE sought first to identify a benchmark for the term impact and how best to demonstrate with appropriate certainty if facilities have any material impact to the reliability of the Bulk Power System. Concurrently, WECC started its own efforts to respond to Recommendation 17of the Arizona-Southern California

35 Docket No. RC Exhibit SCE-1 Page 30 of Outages on September 8, 2011 report, 19 which recommended that WECC develop guidelines or criteria for identifying sub-100 kv facilities that may have a reliability impact on the Bulk Power System. The BES Inclusion Guideline ( Guideline, approved by the WECC Planning Coordination Committee on July 1, in response to Recommendation 17, became the basis by which SCE examined the potential impact of the 115 kv Facilities. The fundamental purpose of the Guideline identified a list of situations that could potentially warrant inclusion into the Bulk Electric System. SCE s interpretation of the Guideline describes the situations listed as either descriptive or technical situations. The three descriptive situations are: Non-BES elements identified as a significant contributing causal factor in an event analysis report (e.g., disturbance report. Non-BES elements that are part of a monitored facility of a major transfer path. Non-BES elements identified as part of a blackstart cranking path or a Nuclear Plant Off-site Power Supply The two technical situations are: 19 Recommendation 17: WECC, as the RE, should lead other entities, including TOPs and BAs, to ensure that all facilities that can adversely impact BPS reliability are either designated as part of the BES or otherwise incorporated into planning and operations studies and actively monitored and alarmed in RTCA systems. Arizona-Southern California Outages on September 8, 2011 report. 20 The BES Inclusion Guideline was approved by the WECC Planning Coordination Committee on July 1, The document was reformatted and re-published on January 15, 2015 without material change

36 Docket No. RC Exhibit SCE-1 Page 31 of 46 Where a BES element s single-contingency outage causes on any non- BES element: o A change in flow of more than 10 percent of the non-bes o element s continuous rating, and A subsequent flow above 90 percent of the non-bes element s continuous rating. 21 Non-BES elements (e.g. generators, transformers, lines where a single- contingency outage of that element causes a change in flow on any BES element that is more than 10 percent of the BES element s continuous rating None of the 115 kv Facilities meets any of the descriptive situations in the BES Inclusion Guideline and so only the technical situations were of most significance. SCE developed three scenarios of varied power system conditions to test and screen for the two technical situations that would warrant a more detailed analysis into potential impact to the Bulk Power System. The technical situations look for the electrical relationship between the Bulk Electric System and non-bulk Electric System facilities by proxy of power flow changes with respect to continuous thermal ratings. The idea is that if an outage of either BES or non-bes elements causes the marginal shift in power flow on the other, there is an electrical correlation between the elements. SCE aligned its screening with this 21 SCE took a more conservative approach to its technical screening and did not require that subsequent flow be above 90% of the non-bes element s continuous rating as indicated in the WECC BES Inclusion Guideline. SCE screened all flow changes on SCE s non-bes elements and further analyzed any elements whose flow change exceeded 10% irrespective of subsequent percent-loading.

37 Docket No. RC Exhibit SCE-1 Page 32 of consideration by developing the three scenarios to bookend the range of power system conditions of each 115 kv system or region, North of Lugo, under analysis. Power flow across transmission and distribution assets is dictated by the sources of power, demand for power, and the relative impedance paths between the two. Risks to the reliability of the integrated transmission network are typically highest when power flows across transmission and distribution assets are at their highest. The three scenarios captured these factors by assuming: 1 maximum local load (demand and maximum local generation (sources; 2 maximum local load and zero local generation; and 3 minimum local load and maximum local generation. These three scenarios adequately encompass the range of reasonable assumptions for higher power flow conditions within a radial system or group of radial facilities. Assuming minimum local load and zero generation would be a lower flow scenario than that already captured by the maximum load and zero generation case. Any potential for impact to the reliability of the Bulk Electric System would be comprehensively identified in these three scenarios. Only if a potential for impact was identified by elements exceeding the flow change threshold was a detailed analysis performed to consider the full range of impact possible as indicated in the WECC BES Inclusion Guideline. SCE used a TPL-like analysis for further inspection of elements exceeding the 10% flow change thresholds. In SCE s detailed analysis each local distribution element that was flagged by the screens was simulated as a forced outage, and the resultant Bulk Electric System performance

38 Docket No. RC Exhibit SCE-1 Page 33 of was examined in accordance with the performance criteria identified in the WECC System Performance TPL-001-WECC-CRT-2.1 Regional Criterion 22 for single contingency outages. Steady-state thermal loading and voltage deviation analysis; dynamic frequency and voltage stability analysis for key SCE and Western Interconnection integrated transmission network buses; dynamic angular stability analysis; and tests for positive reactive power margin were all part of the detailed study work SCE conducted to examine the elements identified as having a potential impact on the Bulk Electric System as these analysis methods are common good utility practices for ensuring the reliability of the integrated transmission network. Although these elements, as local distribution facilities, are not required to comply with the NERC TPL Reliability Standards, the further analysis conducted treated the elements similar to as if a forced outage required SCE to adhere to similar performance requirements. This is why SCE is referring to its more detailed analysis as TPL-like. In addition to screening SCE s 115 kv Facilities and undertaking further analysis as determined by the screens, SCE sought to demonstrate the reliability of those systems, or facilities within North of Lugo, with underlying interconnected generation above the 75 MVA threshold used for automatic exclusion under the revised Bulk Electric System definition s Exclusion E1 and Exclusion E3 for Radial Facilities and Local Networks respectively. Using the two relevant scenarios 23 from the screening analysis, a loss of all SCE s evaluation of theoretically losing all interconnected generation within a local distribution system would not (Continued

39 Docket No. RC Exhibit SCE-1 Page 34 of underlying interconnected generation was simulated to analyze the impact to the reliability of the Bulk Electric System, if any, and the subsequent power drawn into the respective local distribution systems or facilities where the generation was serving local load. Q. What were the results of the technical analysis? A. Screening all 115 kv Facilities resulted in six 115 kv circuits, five generation facilities, and six transformer banks being identified for further analysis under TPL-like performance requirements. All seventeen elements are located in the North of Lugo region. The respective North of Lugo subsystems are identified for each flagged element listed below. Although SCE is not requesting exemption for any generation facilities connected to the 115 kv Facilities, SCE ran the generator facility forced outages as a means of identifying if the related 115 kv circuits or transformer banks are necessary for the reliability of the Bulk Electric System. Equally relevant, all of the transformer banks identified fall well below the revised Bulk Electric System definition thresholds and are not at-issue. However, SCE studied these elements and determined that the shifts in power flow above the screening thresholds were due to the generation facilities connected at or beyond the transformer bank that was flagged for further study. For Continued from the previous page need the scenario where generation is assumed offline within the local area of study. Additionally, only the Devers 115 kv system, Vista 115 kv system, and 115 kv facilities north of Lugo substation had aggregate generation above the 75 MVA threshold.

40 Docket No. RC Exhibit SCE-1 Page 35 of completeness in analysis, SCE studied all seventeen flagged elements under TPL-like performance requirements to ensure the reliability of the Bulk Electric System if the Commission determines that these facilities (including all 115 kv Facilities are used for the local distribution of energy. The 17 elements flagged for further analysis are: Circuits: 1. Control-Casa Diablo-Sherwin 115 kv (Control Subsystem 2. Casa Diablo-Rush Creek 115 kv (Control Subsystem 3. Lee Vining-Rush Creek 115 kv (Control Subsystem 4. Inyokern-Searles-Downs-McGen 115 kv (Inyokern Subsystem 5. Inyokern-Searles-McGen 115 kv (Inyokern Subsystem 6. Kramer-Holgate 115 kv (Kramer Subsystem Generation Facilities: 1. Casa Diablo (Control Subsystem 2. KERRMGEE (Inyokern Subsystem 3. Rush Creek (Control Subsystem 4. Bishop Creek Units 2, 5, & 6 equivalent model (Control Subsystem 5. Bishop Creek Units 3 & 4 equivalent model (Control Subsystem Transformer Banks: 1. Casa Diablo 34.5/4.16 kv (Control Subsystem 2. Rush Creek 115/2.3 kv (Control Subsystem 3. Searles 115 kv/kerrmgee 13.8 kv (Inyokern Subsystem

41 Docket No. RC Exhibit SCE-1 Page 36 of Searles 115/34.5 kv (Inyokern Subsystem 5. Control 55 kv/bishop Creek [Units 2, 5, 6 equivalent] 2.2 kv (Control Subsystem 6. Control 115 kv/bishop Creek [Units 3, 4 equivalent] 2.2 kv (Control Subsystem For all 17 elements studied, no impact to the reliability of the Bulk Electric System was identified. For Bulk Electric System facilities: 1 no thermal overloads were observed as a result of a loss of any of these elements, 2 all dynamic events were positively damped and did not cause voltage or frequency deviations and dips to exceed WECC limits, and 3 steady-state post-contingency recovering voltages 24 were within acceptable limits. Additionally, all connected generators maintained synchronism, and positive reactive power margin was observed, for select Bulk Electric System buses in the region north of SCE s Lugo substation. For simulating the loss of all the underlying generation within the system of study, there is not a specific performance requirement with which to adhere. SCE, however, chose to compare performance results with that of Category C requirements in the currently effective TPL-003 NERC Reliability Standard and associated WECC Performance Criteria. For all three systems exceeding 75 MVA in aggregate generation 24 Also, commonly referred to as post-transient voltage deviation. This part of the analysis assumed postcontingency automatic voltage and power regulation devices operated but prior to any operator action such as nonautomatic switchable shunt devices or generator re-dispatch (generally covering the time period a few minutes after the event but before fifteen minutes after.

42 Docket No. RC Exhibit SCE-1 Page 37 of (Devers 115 kv, Vista 115 kv, and 115 kv facilities north of Lugo substation, no reliability performance violations were observed on the Bulk Electric System under Category C TPL-003 performance requirements and WECC Performance Criteria. For Bulk Electric System facilities: 1 no thermal overloads were observed as a result of the simulated loss of all local generation, 2 dynamic stability was positively damped and did not have voltage or frequency deviations and dips that exceeded WECC limits, and 3 steady-state post-contingency recovering voltages were within acceptable limits. Additionally, all connected generators exhibited positively damped angular stability and maintained synchronism. Q. What are your conclusions given the results of the technical analysis? A. None of the radial 115 kv Facilities has a material impact to the reliability of the Bulk Electric System. With the exception of seventeen elements in the North of Lugo region, all 115 kv Facilities passed the screens for potential impacts and no further analysis was required. Those elements that did not pass the screens in the North of Lugo region underwent further investigation where each was assessed, found to have no negative impact to the reliability of the integrated transmission network, and verified to have no widespread impact on the Western Interconnection. After thorough analysis of the systems in which the aggregate generation exceeds 75 MVA (Devers, Vista, and North of Lugo areas, it is evident that a loss of all local generation within these local areas does not cause performance violations on the Bulk Electric System. As the technical analysis SCE conducted demonstrates via the three technical screens, the TPL-like more detailed analysis, and the loss of all local generation, all of the 115 kv Facilities have no impact on the Bulk Electric System or the Western Interconnection.

43 Docket No. RC Exhibit SCE-1 Page 38 of Q. What technical factors affecting the City of Holland s NERC registration appeal did you include in your analysis? A. In consideration of the technical factors that led the Commission, in part, to its decision in the City of Holland s NERC registration appeal, 25 SCE analyzed the115 kv Facilities for technical similarities or differences. In the analysis, SCE identified two subsystems within the North of Lugo region whose configuration resembles the arrangement described in the Holland Decision. However, this resemblance is minimal and is where the similarity ends. More specifically, the line and bus configuration of the substations serving as the interface between the Bulk Electric System and each subsystem resembles the arrangement described in the Holland Decision, i.e., each subsystem is served by two lines connected to different bus sections separated by bus-sectionalizing circuit breakers, but the remaining Holland factors do not apply. The first subsystem resembling the arrangement described in the Holland Decision emanates from SCE s Control 115 kv substation (Exhibit SCE-11 and the second subsystem emanates from SCE s Inyokern 115 kv substation (Exhibit SCE-12. Each of these subsystems is connected to the Bulk Electric System via two lines. Since the Control and Inyokern 115 kv buses are integrated with the transmission network, they have been and will continue to be treated as part of the Bulk Electric System. Starting from each pair of lines, the lines and downstream radial facilities have been 25 City of Holland, Michigan Board of Public Works, 145 FERC 61,054, at P 30 (2013 ( Holland Decision.

44 Docket No. RC Exhibit SCE-1 Page 39 of designated as local distribution facilities since the formation of the CAISO. Upon evaluation, the Control 115 kv East and West buses and the Inyokern 115 kv East and West buses share one common attribute similar to that of the Black River substation owned and operated by the Michigan Electric Transmission Company, LLC. For each pair of lines connecting SCE s local distribution facilities with Control and Inyokern substations respectively, the pair of lines is connected on opposite buses separated by one or two circuit breakers as was the arrangement described for Black River substation. Specifically, each of SCE s two 115 kv buses at Control substation is protected from faults on the other by two bus-sectionalizing circuit breakers, and likewise, each of SCE s two 115 kv buses at Inyokern substation is protected from faults on the other via a single bus-tie circuit breaker. Three key factors distinguish SCE s two subsystems (Control and Inyokern from the system described in the Holland Decision and support the continued treatment of these subsystems as used in the local distribution of energy and not part of the Bulk Electric System. First, the magnitude of load and local generation within each subsystem is small. The Control 115 kv subsystem serves 27 MW of peak load out of Casa Diablo substation and less than two (2 MW of load on the Sherwin transformer bank. Casa Diablo also interconnects approximately 30 MW of generation facilities from the underlying voltages. Three small hydro generation facilities are also connected via a radial line out of Casa Diablo substation totaling 20.9 MW of maximum output on the 115 kv facilities and 3.7 MW on the Control subsystem 55 kv facilities.

45 Docket No. RC Exhibit SCE-1 Page 40 of Similarly, the Inyokern 115 kv subsystem normally serves 43 MW of peak load at Downs substation, 28 MW of peak load at Searles substation (including a cogeneration customer that supplies its own load with generation, and a switchyard at McGen that is only used for station light and power and other low demand needs now that the generator customer has retired commercial operation. The cogeneration customer (load and generation is connected to the Inyokern subsystem 33 kv circuits out of Searles substation and is not shown on Exhibit SCE-10. A second key distinction from the system described in the Holland Decision is that in both the Control and Inyokern 115 kv subsystems, the two lines terminate at a single substation. A bus fault on either Control 115 kv bus or either Inyokern 115 kv bus does not cause the same kind of bidirectional flows to occur that contributed to the Commission s reasoning in the Holland Decision. In the Control subsystem, when the load exceeds the generation, the direction of power flow is from Control substation into the Sherwin transformer and Casa Diablo substation. In the event of a bus fault, the power flow direction continues to be from Control substation to Sherwin and Casa Diablo for a fault on the East bus, and only the segment between Casa Diablo and Sherwin sees a small shift in power flow direction to serve the 2 MW of load now radial out of Casa Diablo. For the Inyokern 115 kv subsystem, a bus fault does not change the direction of flow. If the cogeneration customer produces excess generation, the flow direction is from Searles substation into Inyokern substation. Similarly, if the customer produces less energy than needed, flow direction is from Inyokern into Searles. Furthermore, in the event of a bus fault, the flow direction does not change; only the magnitudes adjust based on changing relative impedances between Searles and Inyokern. For both the Control

46 Docket No. RC Exhibit SCE-1 Page 41 of and Inyokern 115 kv subsystems the radial nature is unchanged, in direct contrast to the situation that was described in the Holland Decision. The third and final factor that distinguishes these two SCE subsystems from the facilities described in the Holland Decision is that SCE s protection systems associated with each pair of lines do not present the reliability gap identified by the Commission. First of all, both operating ends of the pairs of lines are SCE facilities. Control and Casa Diablo substations are SCE-owned, as are the Inyokern and Searles substations. There are no protection coordination issues similar to those identified in the Commission s reasoning in the Holland Decision, but rather SCE has exclusive control over all protection settings. In other words, no reliability gap exists with respect to PRC Secondly, the protection systems on these lines or any of the facilities that interface with the Bulk Electric System do not meet any of the applicability requirements of PRC Therefore, no reliability gap exists with respect to PRC Q. Does this conclude your testimony? A. Yes. 16

47

48 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC EXHIBIT SCE-2 MAP OF SCE SERVICE TERRITORY APRIL 15, 2015

49 Placer County El Dorado County Southern California Edison Company Territory Alpine County Amador County Calaveras County Tuolumne County Mono County N evada Mariposa County Merced County Madera County Fresno County Inyo County Monterey County Tulare County Kings County A rizon a San Luis Obispo County C alifornia Kern County San Bernardino County Santa Barbara County Ventura County Los Angeles County PP aa cc ii ff ii cc Riverside County Orange County OO cc ee aa nn San Diego County Mapping Prepared by: Operations Support Business Unit Real Properties Division Survey and Mapping Section Southern California Edison Company Territory Imperial County 25 MILES N 09/01/2010

50 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Southern California Edison Company Docket No. RC EXHIBIT SCE-3 DIAGRAM OF SCE LOCAL DISTRIBUTION SYSTEMS APRIL 15, 2015

51 SCE Service Territory and Local Distribution Voltages