2018 General Rate Case

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Application No.: A.16-09- Exhibit No.: SCE-0, Vol. 08 Witnesses: J. R. Goizueta M.

1 Application No.: A Exhibit No.: SCE-0, Vol. 08 Witnesses: J. R. Goizueta M. Flores A (U 338-E) 018 General Rate Case Transmission & Distribution (T&D) Volume 8 - Infrastructure Replacement Before the Errata Public Utilities Commission of the State of California Rosemead, California September 1, 016

2 SCE-0-Transmission & Distribution (T&D) Volume 8 - Infrastructure Replacement Table Of Contents (Cont.) Section Page Witness a) b) Program Necessity...65 Cost Forecast...67 B. c) Justification of Forecast Work...68 Substation Infrastructure Replacement Program...69 M. Flores 1. Transformer Bank Replacement...70 a) b) AA Bank Replacement...71 A Bank Replacement...74 (1) () (3) Program Necessity...74 Cost Forecast...74 Justification of Forecast Work...75 c) B Bank Replacement...78 (1) () Program Necessity...79 Justification of Forecast Work Circuit Breaker Replacement...83 a) b) Bulk Power Circuit Breaker Replacement...84 Distribution Circuit Breaker Replacement...84 (1) () (3) (4) Program Necessity...85 Cost Forecast...85 Justification of Work Forecast...87 Analysis of Circuit Breaker in Other Programs Substation Switchrack Rebuild...9 a) Program Necessity...93 iv

3 1 3 B. Summary of Capital Request The tables below summarize the Distribution and Substation capital activities discussed in this volume, and their associated expenditures. 016=10, =66, =68, =69,976 00=89,13 016=4,85 017=43, =44, =46,64 00=48,1 016=5, =18,36 018=18,85 019=19,416 00=0, =88, =50, =51, =53,1 00=54,84 016=37, =37, =38,9 019=40,085 00=41,63 016=5, =18,36 018=18,85 019=19,416 00=0,033 Table I-1 Infrastructure Replacement Capital Activities Forecast (Total Company Nominal $000) Description Worst Circuit Rehabilitation 137,87 13,106 16,07 130, ,305 Cable Life Extension 1,570 3,40 3,991 4,744 5,530 CIC Replacement 6,58 31,14 41,643 4,949 44,315 Overhead Conductor Program 14,03 136, , , ,466 Underground Oil Switch Replacement 10,93 11,150 1,701 13,099 13,516 Capacitor Bank Replacement 1,005 17,156 17,588 18,140 18,717 Automatic Reclosure Replacement,565,310,368,44,50 PCB Transformer Replacement 1,385 1,413 1,449 1,494 1,54 Substation Transformer Bank Replacement 11,753 66,93 68,601 70,590 89,844 Substation Circuit Breaker Replacement 45,140 46,833 47,994 49,418 51,403 Substation Switchrack Rebuilds 5,44 16,060 16,464 16,981 17,51 Total $57,14 $475,590 $498,50 $513,915 $547, =53,35 017=474,35 018=497,3 Table I- 019=51,58 Infrastructure Replacement Capital Activities 00=546, Forecast (CPUC-Jurisdictional Nominal $000) Description Worst Circuit Rehabilitation 137,87 13,106 16,07 130, ,305 Cable Life Extension 1,570 3,40 3,991 4,744 5,530 CIC Replacement 6,58 31,14 41,643 4,949 44,315 Overhead Conductor Program 14,03 136, , , ,466 Underground Oil Switch Replacement 10,93 11,150 1,701 13,099 13,516 Capacitor Bank Replacement 1,005 17,156 17,588 18,140 18,717 Automatic Reclosure Replacement,565,310,368,44,50 PCB Transformer Replacement 1,385 1,413 1,449 1,494 1,54 Substation Transformer Bank Replacement 90,58 50,999 5,76 53,835 55,455 Substation Circuit Breaker Replacement 39,861 40,957 41,974 43,39 44,544 Substation Switchrack Rebuilds 5,44 16,060 16,464 16,981 17,51 Total $490,69 $453,78 $476,174 $490,980 $506,43 016=486, =45, =474, =489,647 00=505,031

4 Distribution Table II-3, Average Age of Underground Cable, illustrates the degree at which SCE s underground cable is continuing to age. Figure II-3, Time-Dependent Failure Rate, illustrates that with increasing age will come an increasing volume of cable reaching the end of its service life. This increasing volume of cable reaching the end of its service life will increase the number of inservice failures and resultant circuit outages. These cable outages, which are typically protracted, will negatively affect system reliability and customer satisfaction. SCE performed a probabilistic analysis to forecast the impact of cable aging on system reliability. This probabilistic analysis simulated SCE system reliability if existing infrastructure replacement programs cease beginning in 015, and cable is treated with a run-to-failure strategy for the next 0 years. The results are shown in Figure III-4 and Figure III-5. Continued from the previous page interruptions. Outages recorded as cable, elbow/junction bar, or cable splice contributed 0.18 interruptions, or approximately 1% of the system total. 14

5 Option Figure III-15 summarize the revenue requirement for Option 1 and Option Scenarios A and B describe above. The graph shows the revenue requirement analysis results for when the Option scenarios breakeven with Option 1. On a revenue requirement basis Option 1 Scenario A requires cable that passes the test to last an average of approximately another 14 years. The analysis also shows that Option Scenario B is not cost effective at any time in the analysis timeframe. Figure III-15 Summary of Mainline Testing Cost/Benefit Analysis From this analysis, SCE has concluded that mainline cable testing as part of the WCR Program would not be cost-justified. Figure III-14 shows that under the more optimistic Option Scenario A, mainline cable that tests good must survive another 15 years beyond the test data to break even with Option 1. Under the more conservative Option Scenario B, even if cable that tested good survived another 9 years beyond the test date, it would still be less expensive on a present value revenue requirement basis to not test the cable. Based on a sample of approximately 80 conductor miles of WCR-targeted mainline cable from the 016 scoping year, the average age of cable replaced under WCR is 4

6 Figure III-0 Underground Oil Switch Failure Rates This reliability analysis concludes that the mean-time to wear-out of mainline oil switches is about 35 years. As of the end of 015, SCE had 1,883 mainline oil-filled switches, with 181 older than 35 years. There is a relatively low number of mainline subsurface oil switches older than 35 years results due to recent infrastructure replacement efforts that focused on addressing these before radial switches. The mean-time to wear-out of radial switches is assumed to be comparable to that of mainline switches. As of the end of 015, SCE had 9,666 radial oil-filled subsurface switches still in service, with 1,49 of them older than 35 years. The relatively large number of radial switches older than 35 years indicates that previous IR program efforts did not target radial subsurface switches for preemptive replacement as the program was focused on mainline switches due to their larger potential 56

7 Table III Historical and Forecast Spending for Capacitor Bank Replacement Year Number of Capacitor Bank Forecast Unit Cost of Capacitor Bank Replacement (Nominal dollars x 1,000) Recorded/Forecast Cost of Capacitor Bank (Nominal dollars x 1,000) $7, $6, $8, $7, $8, $48 $1, $49 $17, $50 $17, $5 $18, $53 $18, Refer to WP SCE-0, Vol. 08, pp (Cap Bank unit costs). 58

8 69,976 Figure III-7 Substation Transformer Bank Replacement 68,003 (AA-Bank, A-Bank, & B-Bank) 50 66,349 Multiple WBS Elements 51 Recorded /Forecast ,13 10,066 (Total Company Constant 015 and Nominal $000) 118,69 63,903 79,78 63,903 63, Refer to WP SCE-0, Vol. 08, pp WBS elements include: CET-ET-IR-TB and a portion CIT-00-OP-NS. 7

9 Table III-19 5 A and B Banks Historical/Forecast Unit Costs 53 Year Voltage Class Number of A & B- Bank Transformer Forecast Unit Cost of A & B-Bank Transformer Replacement (Nominal dollars x 1,000) Recorded/Forecast Cost of A & B-Bank Transformer (Nominal dollars x 1,000) 011 0kV 3 115kV 8 66kV 16 33kV 6 16kV 1kV 1 Total 33 $68, kV 4 115kV 3 66kV 13 33kV 5 16kV 4 1kV Total 7 $67, kV 3 115kV 0 66kV 0 33kV 16kV 4 1kV 4 Total 30 $63, kV 5 115kV 4 66kV 14 33kV 6 16kV 4 1kV 1 Total 9 $70, kV 115kV 6 66kV 18 33kV 16kV 3 1kV 4 Total 33 $7, kV 11 $5,085 $55,93 115kV 1 $1,68 $1,68 66kV 14 $1,56 $17,588 33kV 3 $1,138 $3,414 16kV 6 $1,1 $7,34 1kV 4 $1,174 $4,695 Total 8 $90, kV 3 $5,198 $15, kV 1 $1,66 $1,66 66kV 15 $1,8 $19,36 33kV 3 $1,16 $3,485 16kV 5 $1,46 $6,30 1kV 4 $1,198 $4,793 Total 8 $50, kV 3 $5,36 $15, kV 1 $1,704 $1,704 66kV 15 $1,315 $19,71 33kV 3 $1,191 $3,573 16kV 5 $1,77 $6,387 1kV 4 $1,8 $4,913 Total 8 $5, kV 3 $5,466 $16, kV 1 $1,757 $1,757 66kV 15 $1,356 $0,339 33kV 3 $1,8 $3,685 16kV 5 $1,317 $6,587 1kV 4 $1,67 $5,067 Total 8 $53, kV 3 $5,609 $16,88 115kV 1 $1,813 $1,813 66kV 15 $1,399 $0,986 33kV 3 $1,67 $3,80 16kV 5 $1,359 $6,797 1kV 4 $1,307 $5,9 Total 8 $55,455 5 A bank operational dates assume 4 in 016, 8 in 017, 4 in 018, 4 in 019, and 3 in Refer to WP SCE-0, Vol. 08, pp (A & B Bank Unit Costs). 73

10 Corrected Values shown in red Table III-19 5 A and B Banks Historical/Forecast Unit Costs 53 Year Voltage Class Number of A & B- Bank Transformer Forecast Unit Cost of A & B-Bank Transformer Replacement (Nominal dollars x 1,000) Recorded/Forecast Cost of A & B-Bank Transformer (Nominal dollars x 1,000) 011 0kV 4 115kV 10 66kV 13 33kV 6 16kV 1kV 1 Total 36 $68, kV 115kV 6 66kV 11 33kV 3 16kV 3 1kV 1 Total 6 $67, kV 5 115kV 0 66kV 18 33kV 16kV 4 1kV 4 Total 33 $63, kV 3 115kV 0 66kV 11 33kV 4 16kV 4 1kV 1 Total 3 $70, kV 115kV 4 66kV 15 33kV 16kV 3 1kV 3 Total 9 $7, kV 11 $4,946 $54, kV 1 $1,64 $1,64 66kV 14 $1,6 $17,674 33kV 3 $1,16 $3,485 16kV 6 $1,1 $7,34 1kV 4 $1,091 $4,365 Total 39 $88, kV 3 $5,056 $15, kV 1 $1,677 $1,677 66kV 15 $1,89 $19,330 33kV 3 $1,186 $3,557 16kV 5 $1,46 $6,30 1kV 4 $1,114 $4,456 Total 31 $50, kV 3 $5,180 $15, kV 1 $1,719 $1,719 66kV 15 $1,31 $19,817 33kV 3 $1,16 $3,647 16kV 5 $1,77 $6,387 1kV 4 $1,14 $4,568 Total 31 $51, kV 3 $5,317 $15, kV 1 $1,773 $1,773 66kV 15 $1,363 $0,438 33kV 3 $1,54 $3,761 16kV 5 $1,317 $6,587 1kV 4 $1,178 $4,711 Total 31 $53,1 00 0kV 3 $5,456 $16, kV 1 $1,89 $1,89 66kV 15 $1,406 $1,088 33kV 3 $1,94 $3,881 16kV 5 $1,359 $6,797 1kV 4 $1,15 $4,861 Total 31 $54,84 A bank operational dates assume 4 in 016, 8 in 017, 4 in 018, 4 in 019, and 3 in Refer to WP SCE-0, Vol. 08, pp (A & B Bank Unit Costs) a

11 74 Workpaper Southern California Edison / 018 GRC b) A Bank Replacement A-Bank transformers are in major substations where electricity at the 0kV transmission level is transformed down to a subtransmission voltage, either 115kV or 66kv. The SIR program identifies and replaces A-Bank transformers approaching the end of their service lives, which contain parts known to be problematic or are no longer available, or that can no longer be costeffectively maintained. (1) Program Necessity An in-service failure of an A-Bank transformer can be catastrophic. A- Bank transformers typically supply power to large portions of SCE s distribution system servicing hundreds of thousands of customers. While a certain amount of redundancy is built into the A-Bank system, an in-service failure of one piece of equipment would place the system into an N-1 condition, wherein a second failure or system disturbance could cause a massive blackout affecting significantly large areas. So severe are the consequences of such a blackout that SCE believes every reasonable precaution must be taken to prevent it. Although infrequent, in-service failures of A-Bank transformers can be violent. These transformers are oil-filled. Catastrophic failures and ensuing fires can endanger the safety of SCE employees and the operability of nearby equipment. Inspections are helpful in identifying many incipient failures. However, because of the speed at which failure mechanisms can arise and progress, inspections cannot prevent all failures. Therefore, planned preemptive replacements under controlled conditions of transformers approaching the end of their service lives is a prudent and responsible action to minimize the risk of in-service failures. () Cost Forecast Table III-19 above indicates the number of A-Bank transformers replaced and the recorded spend from 011 through 015 and SCE s forecast work and spend from 016 through 00. In , all forecast A-Bank replacements are under CPUC jurisdiction Exhibit No. SCE-0 / Vol. 08 Witness: J. R. Goizueta

12 4,85 43,875 44,943 46,64 Figure III-3 Circuit Breaker Replacement Program (0kV.4kV) 60 WBS Element CET-ET-IR-CB Recorded /Forecast (Total Company Constant 015 and Nominal $000) 48, a) Bulk Power Circuit Breaker Replacement 41,57 4,05 Bulk power circuit breakers interrupt the flow of electricity in transmission lines, typically at the 500kV and 0kV voltage levels. 4,173 The SIR program identifies and 4,498 replaces bulk power circuit breakers approaching the end of their service lives that contain parts known to be problematic or no longer available, or that can no longer be cost-effectively 4,10 maintained. The replacement of bulk power circuit breakers is under FERC jurisdiction and is, therefore, not discussed further in this testimony. b) Distribution Circuit Breaker Replacement Distribution circuit breakers are typically located in residential and commercial area substations ( B substations) where electricity is transformed from a subtransmission level voltage, 60 Refer to WP SCE-0, Vol. 08, pp

13 Year Table III-3 61 Circuit Breakers Historical/Forecast Unit Costs Voltage Class Number of Distribution Circuit Breaker Forecast Unit Cost of Distribution Circuit Breaker Replacement (Nominal dollars x 1,000) Recorded/Forecast Cost of Distribution Circuit Breaker (Nominal dollars x 1,000) kV kV 31 Total 113 $8, kV kV 5 Total 90 $4, kV kV 94 Total 108 $35, kV kV 17 Total 53 $60, kV kV 180 Total 17 $47, kV 36 $78 $9, kV 184 $16 $9,868 Total 0 $39, kV 37 $83 $10, kV 184 $166 $30,474 Total 1 $40, kV 37 $90 $10, kV 184 $170 $31,7 Total 1 $41, kV 38 $300 $11, kV 18 $175 $31,857 Total 0 $43, kV 39 $309 $1, kV 180 $181 $3,493 Total 19 $44, Refer to WP SCE-0, Vol. 08, pp (CB Unit Costs). 86

14 Corrected Values shown in red Year Table III-3 61 Circuit Breakers Historical/Forecast Unit Costs Voltage Class Number of Distribution Circuit Breaker Forecast Unit Cost of Distribution Circuit Breaker Replacement (Nominal dollars x 1,000) Recorded/Forecast Cost of Distribution Circuit Breaker (Nominal dollars x 1,000) kV kV 30 Total 110 $8, kV kV 5 Total 91 $4, kV kV 84 Total 103 $35, kV kV 169 Total 04 $60, kV kV 136 Total 165 $47, kV 36 $56 $9, kV 184 $151 $7,795 Total 0 $37, kV 37 $61 $9, kV 184 $154 $8,340 Total 1 $37, kV 37 $68 $9, kV 184 $158 $9,00 Total 1 $38, kV 38 $76 $10, kV 18 $163 $9,600 Total 0 $40, kV 39 $85 $11, kV 180 $168 $30,164 Total 19 $41,63 61 Refer to WP SCE-0, Vol. 08, pp (CB Unit Costs) a

15 (3) Justification of Work Forecast Prior to 01, SCE identified the volume and specific circuit breakers to be replaced each year largely on the basis of expert judgment, i.e., the judgment of those individuals responsible for inspecting and maintaining the equipment. Beginning in 01, SCE incorporated formal engineering analysis in combination with expert judgment into the evaluation process. Since that time, SCE has been improving the data quality and the data refresh frequency supporting the evaluation process for transformer replacements. circuit breaker Part of that engineering analysis was an evaluation of historical removals and failures of circuit breakers to develop a relationship between age and the probability of in-service failure. That relationship for distribution circuit breakers is shown below in Figure III-33 as a Weibull curve. 6 6 Refer to WP SCE-0, Vol. 08, pp (Circuit Breaker Reliability). 87

16 Table III-6 65 Substation Switchrack Rebuild Historical/Forecast Unit Costs $5,996 $6,11 $6,75 $6,47 $6,678 Year Number of Switchrack Rebuilds Forecast Unit Cost of Switchrack Rebuilds (Nominal dollars x 1,000) Recorded/Forecast Cost of Switchrack Rebuilds (Nominal dollars x 1,000) $ $ $ $ $1, $5,44 $5, $5,353 $16, $5,488 $16, $5,660 $16, $5,840 $17,51 $5,996 $18,36 $18,85 $19,416 $0, Refer to WP SCE-0, Vol. 08, pp (Switchrack Rebuild Unit Costs). 95

17 5,996 18,36 Figure III-36 19,416 Substation Switchrack Rebuild Program 66 WBS Element CET-ET-IR-RB 18,85 Recorded /Forecast (CPUC-Jurisdictional Constant 015 and Nominal $000) 0, ,885 c) Justification of Work Forecast Our process for substation switchrack rebuild projects is: existing projects ( driver projects such as 17,655 17,655 SubIR or load growth) in the current 5-year horizon are reviewed by 17,655 substation engineering for their potential to drive the need for a substation switchrack rebuild. When identified projects are found anticipated to pose switchrack issues, 17,655 jobwalks focused on rebuild evaluation are initiated. These jobwalks are typically organized based on geographic location, include stakeholders such as SC&M, Infrastructure Replacement, Substation Engineering, Civil/Structural Engineering, and Field Engineering. At the jobwalks, the condition of foundations, equipment, structures, and working areas/clearances are evaluated as a whole. 66 Refer to WP SCE-0, Vol. 08, pp

2018 General Rate Case. Transmission & Distribution (T&D) Volume 3 R System Planning

2018 General Rate Case. Transmission & Distribution (T&D) Volume 3 R System Planning Application No.: Exhibit No.: Witnesses: A.1-0- A SCE-0, Vol. 0 R A E. Takayesu (U -E) 01 General Rate Case rd Errata ERRATA Transmission & Distribution (T&D) Volume R System Planning Before the Public