2018 General Rate Case Rebuttal Testimony Transmission ...FILE/SCE18V06.pdf · 1 1 I. 2 SUBSTATION CONSTRUCTION AND MAINTENANCE REBUTTAL 3 This volume presents SCE’s rebuttal to

Application No.: A.16-09-001 Exhibit No.: SCE-18, Vol. 06 Witnesses: M. Flores

B. Tolentino

(U 338-E)

2018 General Rate Case Rebuttal Testimony

Transmission & Distribution (T&D) Volume 06 – Substation Construction & Maintenance

Before the

Public Utilities Commission of the State of California

Rosemead, California June 16, 2017

SCE-18: Transmission & Distribution (T&D) Volume 06 – Substation Construction & Maintenance

Table Of Contents Section Page Witness

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I. SUBSTATION CONSTRUCTION AND MAINTENANCE REBUTTAL .......................................................................................................1 M. Flores

A. Capital ....................................................................................................4

1. Substation Physical Security – Copper Theft ............................4

a) ORA’s Position ..............................................................4

b) SCE’s Rebuttal to ORA’s Position ................................5

(1) Security Incidents, Including Trespassing, Suspicious Activity, Vandalism, and Theft, Increased in 2016 and Continue to Present Significant Safety and Reliability Risks that the Copper Theft Program can Mitigate. ......................................................5

(2) ORA’s Recommendation is Predicated on an Arbitrary Threshold of Copper Theft Incidents to Determine the Scope of Work in 2017 and 2018. ...................................................7

(3) Copper Prices are Rising in 2017, Which May Cause Greater Criminal Activity at SCE Substations. ..............................9

(4) ORA’s Proposed Scope of Work Only Addresses a Need Based on a Singular Point in Time, and Does Not Consider the Dynamic Nature of Copper Theft and Related Incidents Over Time. .........................................................9

2. Substation Protection & Control Relay Replacement Programs – Substation Automation System (SAS) Infrastructure Replacement ......................................................11

a) TURN’s Position ..........................................................13

b) SCE’s Rebuttal to TURN’s Position ............................14

SCE-18: Transmission & Distribution (T&D) Volume 06 – Substation Construction & Maintenance

Table Of Contents (Continued) Section Page Witness

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(1) The Drivers of the SAS Infrastructure Replacement Program and the Grid Modernization SA-3 Program are Fundamentally Different. ..........................................................14

(2) The Scope of Work for the SAS Infrastructure Replacement Program and the Grid Modernization SA-3 Program are Fundamentally Different. ..........................................................15

(3) SA-3 is the Most Viable and Cost-Effective Replacement Option and TURN’s Proposal is based on Misinterpretations. ...........................................16

(4) The Calculation of TURN’s Recommended Forecast for the SAS Infrastructure Replacement Program is Fraught with Error ........................................16

3. Subtransmission Relay Upgrade Program ...............................17 B. Tolentino

a) ORA’s Position ............................................................18

b) TURN’s Position ..........................................................18

c) SEIA-Vote Solar’s Position .........................................19

d) SCE’s Rebuttal to Intervenors’ Position ......................19

Appendix A Data Requests

Appendix B Workpapers

1

I. 1

SUBSTATION CONSTRUCTION AND MAINTENANCE REBUTTAL 2

This volume presents SCE’s rebuttal to the various recommendations raised by the Office of 3

Ratepayer Advocates (ORA) and intervenors related to SCE’s 2018 GRC forecast for Substation 4

Construction & Maintenance (SC&M). In SCE-02, Volume 6, SCE presented evidence to support its 5

forecast for inspection and maintenance of SCE’s substation equipment, substation and grid control 6

center operating activities, and other substation activities. The activities include: inspecting, 7

maintaining, and replacing protection and control equipment, spare parts, tools and work equipment, 8

improving the physical security of our substations, and modernizing outdated grid control rooms. 9

Justification for this work and associated costs were also provided in detailed workpapers as part of 10

SCE’s 2018 GRC Application. 11

Below, SCE responds to ORA, TURN, and SEIA-Vote Solar's recommendations. Table I-1 12

summarizes SCE’s recorded and forecast expenses in Substation Construction & Maintenance O&M 13

accounts. No party opposes SCE’s O&M forecasts for SC&M. Table I-2 summarizes SCE’s recorded 14

and forecast capital expenditures in the various Substation Construction & Maintenance accounts, as 15

well as the 2017 and 2018 forecasts proposed by ORA, TURN, and SEIA-Vote Solar. 16

2

Table I-1 Summary of Substation Construction & Maintenance O&M Expenses

Constant 2015 $000

GRCAccount Description 2011 2012 2013 2014 2015561.170 Grid Control Center 8,154$ 8,387$ 8,713$ 9,224$ 9,813$

562.150 Inspection and Maintenance of Substation Equipment - Transmission 1,299$ 731$ 1,072$ 1,210$ 1,575$

562.170 Transmission Substation Operations 19,734$ 19,149$ 19,848$ 18,340$ 19,980$

568.150 Transmission Circuit Breaker Inspection and Maintenance 2,445$ 2,465$ 2,567$ 2,360$ 2,175$ Transmission Transformer Inspection and Maintenance 1,469$ 953$ 1,397$ 1,010$ 979$ Transmission Relay Inspection and Maintenance 1,952$ 1,803$ 1,713$ 1,274$ 1,238$ Transmission Miscellaneous Equipment Inspection and Maintenance 1,733$ 1,921$ 1,638$ 1,670$ 1,702$ Transmission Miscellaneous Substation Expenses 2,685$ 2,553$ 2,841$ 1,552$ 1,489$ Transmission Substation Maintenance Crew Supervision 2,418$ 2,404$ 2,686$ 2,147$ 2,011$ Total 568.150 12,703$ 12,099$ 12,842$ 10,013$ 9,595$

582.150 Inspection and Maintenance of Substation Equipment - Distribution 96$ 103$ 171$ 186$ 333$

582.170 Distribution Substation Operations 23,709$ 26,904$ 27,984$ 26,693$ 28,614$

592.150 Distribution Circuit Breaker Inspection and Maintenance 3,154$ 3,146$ 4,141$ 3,154$ 3,477$ Distribution Transformer Inspection and Maintenance 961$ 1,227$ 1,655$ 1,415$ 1,520$ Distribution Relay Inspection and Maintenance 3,092$ 1,676$ 1,722$ 1,898$ 2,008$ Distribution Miscellaneous Equipment Inspection and Maintenance 2,517$ 1,987$ 2,085$ 2,123$ 2,411$ Distribution Miscellaneous Substation Expenses 1,310$ 1,689$ 1,576$ 2,694$ 1,491$ Distribution Substation Maintenance Crew Supervision 2,806$ 2,775$ 3,010$ 2,420$ 2,333$ Total 592.150 13,839$ 12,500$ 14,189$ 13,703$ 13,241$

Total SCE-02, Volume 6 79,533$ 79,874$ 84,819$ 79,369$ 83,150$

Recorded

GRCAccount Description SCE ORA

ORAVariance TURN

TURNVariance

561.170 Grid Control Center 9,813$ 9,813$ -$ -$ -$

562.150 Inspection and Maintenance of Substation Equipment - Transmission 1,575$ 1,575$ -$ -$ -$

562.170 Transmission Substation Operations 17,924$ 17,924$ -$ -$ -$

568.150 Transmission Circuit Breaker Inspection and Maintenance 2,175$ 2,175$ -$ -$ -$ Transmission Transformer Inspection and Maintenance 979$ 979$ -$ -$ -$ Transmission Relay Inspection and Maintenance 1,238$ 1,238$ -$ -$ -$ Transmission Miscellaneous Equipment Inspection and Maintenance 1,702$ 1,702$ -$ -$ -$ Transmission Miscellaneous Substation Expenses 1,489$ 1,489$ -$ -$ -$ Transmission Substation Maintenance Crew Supervision 2,011$ 2,011$ -$ -$ -$ Total 568.150 9,595$ 9,595$ -$ -$ -$

582.150 Inspection and Maintenance of Substation Equipment - Distribution 333$ 333$ -$ -$ -$

582.170 Distribution Substation Operations 25,670$ 25,670$ -$ -$ -$

592.150 Distribution Circuit Breaker Inspection and Maintenance 3,477$ 3,477$ -$ -$ -$ Distribution Transformer Inspection and Maintenance 1,520$ 1,520$ -$ -$ -$ Distribution Relay Inspection and Maintenance 2,008$ 2,008$ -$ -$ -$ Distribution Miscellaneous Equipment Inspection and Maintenance 2,411$ 2,411$ -$ -$ -$ Distribution Miscellaneous Substation Expenses 1,491$ 1,491$ -$ -$ -$ Distribution Substation Maintenance Crew Supervision 2,333$ 2,333$ -$ -$ -$ Total 592.150 13,241$ 13,241$ -$ -$ -$

Total SCE-02, Volume 6 78,150$ 78,150$ -$ n/a n/a

2018 Forecast

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Table I-2 Summary of Substation Construction & Maintenance Capital Expenditures

Total Company – Nominal $000

Activity 2011 2012 2013 2014 2015 2016Substation Capital Maintenance 41,949$ 37,182$ 41,609$ 70,955$ 61,166$ 54,791$ Substation Protection and Control Replacements 28,821$ 19,656$ 19,247$ 17,770$ 21,856$ 25,507$ Subtransmission Relay Upgrade -$ -$ -$ -$ -$ 311$ Operational Facilities 1,296$ 2,677$ 5,985$ 74,697$ 54,482$ 16,342$ Substation Spare Parts (871)$ 3,030$ (384)$ 31,442$ 19,467$ 17,275$ Substation Tools and Work Equipment 2,419$ 3,764$ 7,359$ 7,120$ 5,598$ 6,522$ Substation Physical Security -$ -$ -$ 11,844$ 17,738$ 26,345$ LADWP: NONE - PROVIDE IN SUMMARY TABLE ONLY ( -$ -$ -$ -$ 277$ 10,995$ Total Capital - Substation Construction & Maintenance 73,613$ 66,308$ 73,815$ 213,826$ 180,584$ 158,088$

Recorded

Activity 2017 2018Total

2017-2018 2017 2018Total

2017-2018 VarianceSubstation Capital Maintenance 54,000$ 55,331$ 109,332$ 54,000$ 55,331$ 109,332$ -$ Substation Protection and Control Replacements 41,681$ 55,672$ 97,353$ 41,681$ 55,672$ 97,353$ -$ Subtransmission Relay Upgrade -$ 41,589$ 41,589$ -$ -$ -$ (41,589)$ Operational Facilities -$ -$ -$ -$ -$ -$ -$ Substation Spare Parts 4,549$ 4,664$ 9,213$ 4,549$ 4,664$ 9,213$ -$ Substation Tools and Work Equipment 5,477$ 5,580$ 11,057$ 5,477$ 5,580$ 11,057$ -$ Substation Physical Security 51,617$ 25,641$ 77,258$ 48,296$ 22,111$ 70,407$ (6,851)$ LADWP: NONE - PROVIDE IN SUMMARY TABLE ONLY ( 45,103$ 29,440$ 74,543$ 45,103$ 29,440$ 74,543$ -$ Total Capital - Substation Construction & Maintenance 202,427$ 217,917$ 420,344$ 199,106$ 172,799$ 371,905$ (48,439)$

SCE Forecast ORA Forecast


2017-2018 2017 2018Total

2017-2018 VarianceSubstation Capital Maintenance 54,000$ 55,331$ 109,332$ n/a n/a n/a n/aSubstation Protection and Control Replacements 41,681$ 55,672$ 97,353$ 41,681$ 42,272$ 83,953$ (13,400)$ Subtransmission Relay Upgrade -$ 41,589$ 41,589$ -$ -$ -$ (41,589)$ Operational Facilities Maintenance -$ -$ -$ n/a n/a n/a n/aSubstation Spare Parts 4,549$ 4,664$ 9,213$ n/a n/a n/a n/aSubstation Tools and Work Equipment 5,477$ 5,580$ 11,057$ n/a n/a n/a n/aSubstation Physical Security 51,617$ 25,641$ 77,258$ n/a n/a n/a n/aLADWP: NONE - PROVIDE IN SUMMARY TABLE ONLY ( 45,103$ 29,440$ 74,543$ n/a n/a n/a n/aTotal Capital - Substation Construction & Maintenance 202,427$ 217,917$ 420,344$ (54,989)$

SCE Forecast TURN Forecast


2017-2018 2017 2018Total

2017-2018 VarianceSubstation Capital Maintenance 54,000$ 55,331$ 109,332$ n/a n/a n/a n/aSubstation Protection and Control Replacements 41,681$ 55,672$ 97,353$ n/a n/a n/a n/aSubtransmission Relay Upgrade -$ 41,589$ 41,589$ -$ -$ -$ (41,589)$ Operational Facilities Maintenance -$ -$ -$ n/a n/a n/a n/aSubstation Spare Parts 4,549$ 4,664$ 9,213$ n/a n/a n/a n/aSubstation Tools and Work Equipment 5,477$ 5,580$ 11,057$ n/a n/a n/a n/aSubstation Physical Security 51,617$ 25,641$ 77,258$ n/a n/a n/a n/aLADWP: NONE - PROVIDE IN SUMMARY TABLE ONLY ( 45,103$ 29,440$ 74,543$ n/a n/a n/a n/aTotal Capital - Substation Construction & Maintenance 202,427$ 217,917$ 420,344$ (41,589)$

SCE Forecast SEIA-Vote Solar

4

A. Capital 1

1. Substation Physical Security – Copper Theft 2

SCE substations are situated to best serve customer loads and are often visible within 3

public domains. This renders our substation equipment vulnerable to trespassing, vandalism, theft, and 4

even terrorism. One issue that SCE continues to address is the theft of copper from our substations. 5

These thefts create safety and reliability issues that can result in unnecessary customer outages, property 6

damage, and monetary costs that must be safeguarded. SCE’s Copper Theft Program is designed to 7

minimize the threat of copper thefts at substations. 8

SCE’s Copper Theft Program is one component of an overall programmatic effort to 9

improve the Physical Security of our substations. Table I-3 shows the proposed 2017-2018 forecasts for 10

SCE’s Physical Security Program from SCE and ORA, as well as the 2017-2018 forecasts by the sub-11

programs, including SCE’s Copper Theft Program. 12

Table I-3 Substation Physical Security1

Total Company - Nominal $000

a) ORA’s Position 13

ORA recommends a forecast lower than SCE’s request in 2017 and 2018 14

primarily due to the decline in number of incidents of copper theft from 2013 to 2016.2 ORA also 15

contends that non-copper theft security incidents, such as all other theft, trespassing, suspicious 16

activities, and vandalism, should not be the basis for SCE’s Copper Theft Program forecast in this 17

1 SCE recorded reflects Errata served on June 16, 2017. 2 See Exhibit ORA-11, p. 10, lines 20-22.

Activity 2011 2012 2013 2014 2015 2016Substation Physical Security -$ -$ -$ 11,844$ 17,738$ 26,345$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceSubstation Physical Security 51,617$ 25,641$ 77,258$ 48,296$ 22,111$ 70,407$ (6,851)$

Copper Theft 8,321$ 8,530$ 16,851$ 5,000$ 5,000$ 10,000$ (6,851)$ Tier 1: Pre-CIP-014 & CIP-014 42,550$ 9,052$ 51,602$ 42,550$ 9,052$ 51,602$ -$

Tier 2-4 746$ 8,059$ 8,805$ 746$ 8,059$ 8,805$ -$


5

GRC.3 Further, ORA suggests that since 30% of all copper theft incidents in 2013 occurred in only six 1

of SCE’s substations, SCE’s forecast should not be adopted.4 Lastly, ORA suggests that its forecasts 2

will allow for Edison to install substation fencing and lighting upgrades at ten of the substations that 3

experienced substantial thefts in 2013.5 4

b) SCE’s Rebuttal to ORA’s Position 5

(1) Security Incidents, Including Trespassing, Suspicious Activity, 6

Vandalism, and Theft, Increased in 2016 and Continue to Present 7

Significant Safety and Reliability Risks that the Copper Theft 8

Program can Mitigate. 9

SCE developed the Copper Theft Program to address the public and 10

employee safety and system reliability risks created by unauthorized and malicious intrusions into 11

substations.6 ORA is mistaken that SCE’s Copper Theft Program should only consider copper theft 12

incidents in the development of the program’s forecast, as the general scope of work for this program 13

focuses on lighting and fencing replacement/upgrades.7 These upgrades are effective not only at 14

preventing copper thefts, but also minimizing the threat of trespassing, general thefts, and non-theft 15

security breaches. SCE treats all security incidents of equal importance because of the potential safety 16

and reliability risk outcomes. 17

3 See Exhibit ORA-11, p. 14, lines 1-4. 4 See Exhibit ORA-11, p. 14, lines 17-22. 5 See Exhibit ORA-11, p. 15, lines 1-3. 6 SCE-02, Vol. 6, p. 42, lines 24-27. 7 See response to ORA-SCE-207-YNL, Q.01-c on Appendix A p. A-1 – A-4.

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Table I-4 Non-Copper Theft Security Incidents8

As seen in Table I-4 above, there has been a decline in general theft 1

incidents since 2014. However, all other incidents have increased drastically in 2016. SCE finds it 2

reasonable to consider many of these non-theft occurrences (trespassing, suspicious activity, and 3

vandalism) as potential unsuccessful copper theft events. As such, the growing number of these 4

incidents is problematic and poses security risks at SCE’s substations. 5

Further, SCE disagrees with ORA’s elevated focus on general theft and 6

vandalism incidents and apparent lack of consideration for trespassing and suspicious activity incidents.9 7

SCE maintains that any intrusion incident has the potential to impact public or employee safety and 8

cause customer outages. As indicated above, SCE also finds it reasonable to assume that trespassing and 9

suspicious activity could be precursors for future copper theft. ORA has not presented any evidence to 10

the contrary and did not consider the reliability impacts.10 Between 2007 and 2013, SCE experienced a 11

total of 347 outages that were caused by copper theft with an average outage duration of 11 hours.11 As 12

a result of this significant impact that copper theft can cause to our customers, and the safety risks posed 13

to the intruder, SCE takes all incidents seriously within our substations, which are, or could lead to, 14

copper theft. 15

8 See Exhibit ORA-11, p. 12, lines 9-11 (Table 11-7) and see response to ORA-SCE-154-YNL, Q.16-c on

Appendix A pp. A-5 – A-6. 9 See Exhibit ORA-11, p. 13, lines 4-6. 10 See response to SCE-ORA-008, Q.2 on Appendix A pp. A-7 – A-8. 11 SCE-02, Vol. 6, p. 42.

7

The attack on PG&E’s Metcalf substation in 2013 further reinforces the 1

urgency for SCE to take preventative actions to improve substation security, as PG&E’s Metcalf 2

substation was reported to have a record of copper theft, trespassing, and equipment failures prior to the 3

sniper event it experienced. As indicated in SCE’s direct testimony, the attack on the Metcalf substation 4

resulted in over $15 million in damage,12 underscoring the importance and cost effectiveness of 5

preventative measures, such as the ones SCE intends for its substations. 6

ORA’s assertion that SCE did not provide sufficient information arises 7

from the fact that SCE does not track vandalism incidents by the value of the property vandalized.13 8

Again, the primary objective of SCE’s Copper Theft Program is to provide security upgrades to 9

substations that are prone to physical attacks in order to minimize customer interruptions and prevent 10

injuries or death. Monetary losses due to equipment theft and damage is a secondary objective that 11

should be considered, but not solely utilized, in the development of future scope for this program. 12

(2) ORA’s Recommendation is Predicated on an Arbitrary Threshold of 13

Copper Theft Incidents to Determine the Scope of Work in 2017 and 14

2018. 15

ORA states that 11 substations accounted for 44.5% of all incidents in 16

2013.14 Since SCE has already performed upgrades at one of these 11 substations, ORA develops 17

forecasts for 2017 and 2018 such that SCE will have enough funds to install substation fencing and 18

lighting upgrades at the ten remaining substations that experienced substantial thefts in 2013 over the 19

two year period.”15 20

This approach is flawed. ORA draws an arbitrary line to determine the 21

threshold for the number of incidents that should be considered “High Frequency Copper Thefts by 22

Substation.”16 ORA queried data provided by SCE to compile a list of substations that have had a “high 23

frequency” of incidents in 2013-2016, which it determines to be four or more. ORA then applies the 24

12 SCE-02, Vol. 6, p. 43, lines 10-11. 13 See Exhibit ORA-11, p. 14, lines 1-4. 14 See Exhibit ORA-11, p. 14, lines 17-20. 15 See Exhibit ORA-11, p. 15, lines 1-3. 16 See Exhibit ORA-11, p. 14, lines 12-13 (Table 11-8).

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average cost for substation fencing/lighting upgrades to the substations meeting this criteria to determine 1

the Copper Theft Program forecast for 2017-2018. 2

Figure I-1 2013 Copper Theft Counts17

SCE queried the same data set from highest to lowest number of copper 3

theft incidents in 2013-2016, as illustrated in Figure I-1 above. ORA’s final selection of the eleven 4

substations with highest frequency of copper thefts in 2013-2016 includes substations with incidents 5

ranging from 13 events per year down to four events per year. SCE does not understand or agree with 6

ORA’s threshold of four incidents per year. ORA offers no explanation as to the merits of this threshold 7

either. 8

This arbitrary threshold has direct implications to the forecast for the 9

Copper Theft Program. For example, if “high frequency” is considered to include all substations with 10

two or more recorded copper thefts in 2013-2016, then the number of substations meeting the criteria 11

would rise from 11 to 45 and ORA’s forecast would rise to $27.5 million in each year, 2017 and 2018. 12

Alternatively, if the threshold is three or more recorded copper thefts in 2013, then the number of 13

17 See response to ORA-SCE-207-YNL, Q.01-a on Appendix A p. A-9 – A-12.

9

substations in would rise from 11 to 27, and ORA’s forecast would rise to $13.5 million per year for 1

2017 and 2018. Both scenarios result in higher annual forecasts than the $8 million in SCE’s request. 2

(3) Copper Prices are Rising in 2017, Which May Cause Greater 3

Criminal Activity at SCE Substations. 4

The number of recorded copper theft incidents at SCE substations has 5

declined from 152 in 2013 to 15 in 2016.18 From January 2011 to January 2016, the price of copper has 6

dropped by 53%.19 SCE believes that the price of copper can have a direct influence on the decision for 7

thieves to steal it. It would seem logical that someone attempting theft of copper within the confines of 8

an electrical substation would consider the potential monetary gains against the safety risks of the 9

proposition. While copper prices declined from 2011 through the middle of 2016, the price of copper 10

has since risen by approximately 28% from January 2016 to April 2017.20 Further, Citi Research 11

predicts that supply concerns and market expectations will drive up the price of copper by another 33% 12

by 2020.21 As a result, SCE finds it reasonable to expect an increase in copper thefts, or at a minimum, 13

attempted copper thefts, due to the upward trend and forecast for the price of copper. 14

(4) ORA’s Proposed Scope of Work Only Addresses a Need Based on a 15

Singular Point in Time, and Does Not Consider the Dynamic Nature 16

of Copper Theft and Related Incidents Over Time. 17

As illustrated in Figure I-2, Copper Theft incidents can exhibit a general 18

geographic pattern due to the substation location, type, and other characteristics, but actual occurrences 19

are typically unpredictable from year to year. ORA’s proposal only addresses the substations that 20

received four or more copper theft incidents in 2013-2016, and leaves the balance of SCE’s unmitigated 21

substations vulnerable to theft, vandalism, and malicious intrusions. While ORA’s forecast is based 22

solely on activity from a singular year four years ago, SCE’s 2017-2018 forecast is based on remediating 23

current safety and reliability issues using data and information available in the present. SCE’s forecast 24

is more appropriately based on multiple considerations, including but not limited to, recorded theft or 25

18 See Exhibit ORA-11, p. 11, lines 23-25. 19 See response to ORA-SCE-207-YNL, Q.02-c on Appendix A p. A-13. 20 See updated Figure 11-3 from ORA’s response to SCE-ORA-012, Q.1 on Appendix A pp. A-14 – A-16. 21 See response to ORA-SCE-207-YNL, Q.02-c on Appendix A p. A-13.

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security incidents, copper price forecast, substation location, area crime, recorded outage due to thefts, 1

and potential impact on system reliability and public and employee safety.”22 2

The Copper Theft Program offers prevention and deterrents that are 3

essential in protecting both the public and SCE's electric system, and should not be compromised. 4

Those substations with security enhancements since program’s start in 2013 have had zero security 5

incidents to date.23 Not securing the requested capital will greatly hinder our ability to execute the 6

number of substations that need to be protected. 7

22 See response to ORA-SCE-207-YNL, Q.01-d on Appendix A p. A-17. 23 See response to ORA-SCE-207-YNL, Q.01-a, on Appendix A p. A-9 – A-12.

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Figure I-2 Copper Theft Incidents 2013-201524

Distribution Map

2. Substation Protection & Control Relay Replacement Programs – Substation 1

Automation System (SAS) 25 Infrastructure Replacement 2

SCE’s Substation Protection and Control System Replacement program identifies and 3

replaces protection and control equipment approaching the end of its service life, that contain 4

components known to be problematic or no longer available, or that can no longer be maintained in a 5

cost effective manner. The Substation Protection and Control System Replacement program has four 6

primary work activities, 26 which are shown in Table I-5 below: 7

24 See response to ORA-SCE-207-YNL, Q.01-a, on Appendix A p. A-9 – A-12. 25 In SCE’s Exhibit SCE-02, vol. 6, p. 30, SCE refers to the “SA-3” (Substation Automation) system. TURN

also refers to the same system as the “SA-3” (Substation Automation), TURN-06, p. 41. The SAS program refers to the Substation Automation System program, which the SA-3 system is a part of.

26 SCE-02, Vol. 6, p. 30. See also Table I-13 in SCE-02, Vol. 6, p. 32.

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Table I-5 Substation Protection & Control Relay Replacement Sub-Programs

For purposes of the rebuttal testimony that follows, SCE will focus only on the fourth 1

work activity, SAS Infrastructure Replacement, as this is the only sub-program that one party (i.e., 2

TURN) opposed. However, before SCE discusses TURN’s position and SCE’s rebuttal to TURN, it 3

would be prudent and necessary to first provide context to the SAS Infrastructure Replacement program 4

relative to a similar, but different, request in another area of SCE’s GRC request, namely within SCE-5

02, Volume 10 – Grid Modernization. 6

SA-3 is discussed in two places in SCE’s testimony: 7

1) SCE-02, Volume 6: The SAS Infrastructure Replacement program in this volume acts 8

as a traditional infrastructure replacement program that identifies and replaces existing SAS 9

infrastructure that is approaching the end of its service life, that contain components known to be 10

problematic or no longer available, or that can no longer be maintained in a cost effective manner. 11

Typically, this will involve replacing SA-1 equipment with SA-3 equipment.27 12

2) SCE-02, Volume 10: SCE’s Grid Modernization program requests to implement SA-13

3 equipment, in concert with Common Substation Platform (CSP) equipment and other advanced tools, 14

to address issues caused by higher penetrations of distributed energy resources (DERs). 15

It should be clear that while SCE requests funds to implement SA-3 equipment in two 16

different areas, the drivers and scope for each implementation are very different and will be discussed 17

below. The SAS Infrastructure Replacement program is driven by equipment failure,28 whereas the Grid 18

Modernization program request is driven by DER penetration. 19

27 SA-1 is SCE’s first generation of Substation Automation. The SA-1 equipment targeted for replacement

under SCE-02, Vol. 6’s SAS Infrastructure Replacement Program are ABB (Asea Brown Boveri) relays with obsolete model type DPU/TPU and their associated control computers. SA-3 is SCE’s current generation of substation automation system.

28 WP SCE-02, Vol. 6, pp. 192-193 (2010-2015 TPU/DPU Relay Failure Rate) on Appendix B pp. B-1 to B-2.

Non-Bulk Relay Replacement - 115kV & BelowBulk Relay Replacement - 220kV & 500 kV

Digital Fault Recorders ReplacementSAS Infrastructure Replacement

13

a) TURN’s Position 1

TURN believes that SCE is requesting to replace the exact same technology, 2

which TURN states as “SA-3/CSP,” in both the SAS Infrastructure Replacement Program and Grid 3

Modernization program.29 Under this belief, TURN recommends rejecting SCE’s request for the SA-3 4

component in both programs. TURN cites three reasons for this position: (1) The need to change 5

substation breaker settings to accommodate grid reconfigurations is extremely rare; (2) There is no risk 6

of PV solar systems contributing to fault current, and therefore no need to adjust breaker settings due to 7

the presence of PV solar; and (3) Even if it were necessary to adjust substation breaker settings, or other 8

equipment settings, remotely and dynamically, there are much less expensive ways to do so.30 9

TURN recommends a reduction to the SAS Infrastructure Replacement program 10

forecast in 2017 and 2018. TURN calculates this reduction by multiplying the average SAS-3 cost per 11

substation by the number of substations included in SCE’s forecast. However, TURN then adds back to 12

SCE’s forecast allowances for the deployment of CSP at those substations.31 Table I-6 below shows the 13

recorded and forecast expenditures for the Substation Protection and Control Program. As discussed 14

above, the only proposed modification to this program is TURN’s recommended reductions to the SAS 15

Infrastructure Replacement sub-program. 16

Table I-6 Substation Protection & Control Total Company- Nominal $000

29 See Exhibit TURN-06, p. 41, lines 5-13. 30 See Exhibit TURN-06, pp. 44-46. 31 See Exhibit TURN-06, pp. 48-49. As seen on TURN’s table on page 49 of TURN-06 and Table I-6 in this

rebuttal testimony, TURN’s proposal results in a reduction of $13.4 million to the costs that SCE forecasts for Substation Protection and Control.

Activity 2011 2012 2013 2014 2015 2016Substation Protection and Control Replacements 28,821$ 19,656$ 19,247$ 17,770$ 21,856$ 25,507$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceSubstation Protection and Control Replacements 41,681$ 55,672$ 97,353$ 41,681$ 42,272$ 83,953$ (13,400)$


14

b) SCE’s Rebuttal to TURN’s Position 1

(1) The Drivers of the SAS Infrastructure Replacement Program and the 2

Grid Modernization SA-3 Program are Fundamentally Different. 3

As stated very simply above, the SAS Infrastructure Replacement program 4

is driven by equipment failure; whereas the Grid Modernization program request is driven by DER 5

penetration. TURN misunderstands this, and draws the erroneous conclusion that there is no 6

justification in SCE-02, Volume 6 for the SAS Infrastructure Replacement program. TURN states that 7

“the company provides no rationale whatsoever for replacing the existing SAS.”32 SCE disagrees. SCE 8

has provided sufficient evidence through both its direct testimony and through the discovery process 9

stating its position that SCE’s SAS Infrastructure Replacement Program is driven by increasing failure 10

rates of existing SA-1 relays.33 For example, SCE states, “The Substation Protection and Control 11

System Replacement program identifies and replaces protection and control equipment approaching the 12

end of its service life, that contain components known to be problematic or no longer available, or that 13

can no longer be cost-effectively maintained.”34 SCE also provided evidence that the computer-based 14

components require more frequent upgrade or replacement, that almost half of the existing protection 15

and control systems on SCE’s system are no longer supported by the manufacture, and most have no 16

cost-effective hardware/software upgrade solution.35 Thus, the vendor no longer supports the software 17

for the operator interface and SCE currently has a depleted DPU/TPU spare parts inventory. 18

In addition, through several data requests, SCE provided a thorough 19

analysis showing the failure rates and life expectancy of the existing SA-1 equipment, which includes 20

Distribution Protection Units (DPU) and Transmission Protection Units (TPU).36 SCE has provided 21

evidence that the DPU/TPU relay failures have been consistently increasing since 2009. Using 22

historical data and a linear function model, we forecast the DPU/TPU relay failure rate as a function of 23

32 See Exhibit TURN-06, p. 45. 33 See response to TURN-SCE-026, Q.55, attachment “SA-3 Study.pdf and SAS-1_DPU_TPU Failure

Trend.xlsx” on Appendix A, pp. A-18 – A-33. 34 SCE-02, Vol. 6, p. 30. 35 SCE-02, Vol. 6, p. 30. 36 See response to TURN-SCE-026, Q.55, attachment “SA-3 Study.pdf and SAS-1_DPU_TPU Failure

Trend.xlsx” on Appendix A pp. A-18 – A-33.

15

remaining population will increase from 4.7% in 2017 to 20.4% by 2025 as the technology ages.37 This 1

forecast is relatively conservative as it assumes a linear failure rate. In reality, it is likely that failures 2

will increase exponentially, a profile that is more characteristic of aging grid assets beyond their 3

expected service life. Therefore, it is imperative that SCE increase its efforts to proactively replace 4

problematic DPU/TPU relays now. 5

(2) The Scope of Work for the SAS Infrastructure Replacement Program 6

and the Grid Modernization SA-3 Program are Fundamentally 7

Different. 8

TURN states that, “All of the Company’s justifications are actually 9

presented in its Volume 10 (Grid Modernization) testimony, though I address them here as the proposed 10

technology is the same.”38 TURN is mistaken – the scope of proposed technologies deployed under 11

each program is unequivocally different. The SAS Infrastructure Replacement Program in SCE-02, 12

Volume 6 does not include the full scope of work for SA-3 upgrades that is proposed in SCE-02, 13

Volume 10. SCE describes this difference below. 14

The SAS Infrastructure Replacement Program replaces aging SA-1 15

equipment with SA-3.39 16

The Grid Modernization SA-3 Program replaces the existing SA-1 17

equipment on different substations with SA-3 equipment, AND installs 18

additional Grid Modernization equipment such as CSP and Mechanical 19

Electrical Equipment Room (MEER) buildings. 20

37 See response to TURN-SCE-26, Q.55 on Appendix A pp. A-23. 38 See Exhibit TURN-06, p. 46. 39 The scope of the Substation Protection & Control Program consists of upgrading some or all of the following

major components—1) SA-1 Human Machine Interface (HMI) and Programmable Logic Controller (PLC) to SA-3 to alleviate the proprietary communication protocol issues; 2) Failing/obsolete DPU/TPU relays; and 3) Communication protocol converter and associated equipment to facilitate open standard communications.

16

(3) SA-3 is the Most Viable and Cost-Effective Replacement Option and 1

TURN’s Proposal is based on Misinterpretations. 2

Using historical project costs, SCE has concluded that the cost for 3

upgrading a substation from RTU/SA-1 to SA-2 is comparable to an RTU/SA-1 to SA-3 upgrade.40 Due 4

to concerns with the proprietary technology used in SA-1, SCE has determined that SA-3 is the more 5

cost-effective option to mitigate operational issues.41 SA-3 utilizes an open-standards design that is 6

compatible with multiple vendors and is scalable and adaptable to new technologies. Additionally SA-3 7

provides an invaluable standardized way for manufacturers to allow their products to interact with other 8

devices. SA-3 helps SCE increase its ability to meet current technology requirements,42 rather than a 9

non-cost-effective “piece meal” approach such as an “advanced SA-2”43 that TURN suggests. The relay 10

replacements proposed within this program are designed so that the equipment replaced under the 11

Substation Protection and Controls program can also be utilized and incorporated into future automation 12

needs.44 13

TURN’s recommended approach also does not address the increased 14

failure rate of the existing relays or the cost of proprietary technology concerns. Finally, it is important 15

to reiterate that this program targets SA-1/Remote Terminal Unit -Programmable Logic Controller 16

(RTU-PLC) replacements (only on ABB TPU/DPU relays and SAS-1/RTU control computers) driven 17

by equipment failures similar to an Infrastructure Replacement Program. 18

(4) The Calculation of TURN’s Recommended Forecast for the SAS 19

Infrastructure Replacement Program is Fraught with Error 20

It is clear to see that TURN’s proposal does not make sense in the context 21

of SCE’s SAS Infrastructure Replacement program request. TURN not only confuses the drivers and 22

scope of work of this program with those of the Grid Modernization SA-3 program, but it then uses the 23

40 See response to TURN-SCE-123, Q.02-a on Appendix A pp. A-34 – A-36 and TURN-SCE-026, Q.35 on

Appendix A pp. A-37 – A-40. The cost to upgrade from SA-1/RTU to SA-2 is approximately $3.5-$4.9 million whereas an upgrade from SA-1/RTU to SA-3 is around $2.5-$3.1 million (full upgrades).

41 See response to TURN-SCE-026, Q.55, attachment “SA-3 Study.pdf” on Appendix A pp. A-18 to A-33. 42 See response to ORA-SCE-83-TCR, Q.30 on Appendix A p. A-41. 43 See Exhibit TURN-06, p. 51. 44 See response to TURN-SCE-061, Q.10 on Appendix A p. A-42.

17

scope of work and associated costs for the latter program to develop its forecast for the former. This 1

presents a fundamental lack of understanding of SCE’s SAS Infrastructure Replacement Program. 2

For example, TURN arbitrarily eliminates the entire forecast for SAS 3

Infrastructure Replacement cost in exchange for funding to implement CSP at 22 substations in 2018, 4

and 65 substations over the 2016-2018 period.45 The SAS Infrastructure Replacement Program46 does 5

not include CSP installation in its scope to begin with. It appears that TURN has a misunderstanding of 6

the program scope of the SAS Infrastructure Replacement Program and carries it into its evaluation and 7

recommendation. 8

Further, SCE’s forecast is derived from a compilation of specific project 9

list, as shown in its workpaper,47 which contains the execution cost and schedule for the identified 65 10

substations over years 2018-2020. Neither the assumptions nor calculations used in TURN’s reduction 11

proposal match what SCE has presented in the testimony or discovery. As stated in workpapers, the 12

forecast for the SAS Infrastructure Replacement Program is developed on a per-project basis. Cost 13

estimates are developed using a combination of assumptions, including: historical project costs, 14

engineering expertise for the type of commodity being replaced, site-specific evaluations from job 15

walks, and a general project cycle of two to three years. TURN’s proposal utilizes an average cost 16

developed for the full SA-3 upgrades which, as discussed above, is incongruent with the scope of work 17

for this program. 18

3. Subtransmission Relay Upgrade Program 19

SCE’s Subtransmission Relay Upgrade Program will replace those 66kV and 115kV line 20

protection relay devices identified as potentially unreliable under the condition of load encroachment 21

caused by additional Distributed Energy Resources (DER) generation. Recorded and forecast costs for 22

this program from SCE, TURN, and SEIA-Vote Solar are summarized in the Table I-7 below. 23

45 See Exhibit TURN-06, pp. 48-49. 46 SCE02 Vol 6, p. 30, Section I.2-a). 47 Refer to WP SCE-02, Vol. 06, p. 171 and p. 175 on Appendix B pp. B-3 to B-5.

18

Table I-7 Subtransmission Relay Upgrade Program

Total Company - Nominal $000

a) ORA’s Position 1

ORA recommends $0 for SCE’s 2018 Subtransmission Relay Upgrade request, 2

and suggests SCE track any costs for this program in a memorandum account. ORA considers this 3

program to be part of SCE’s Grid Modernization efforts, and as such, recommends no authorization in 4

this GRC as other relevant proceedings currently open before the Commission have yet to provide 5

guidance on Grid Modernization.48 6

b) TURN’s Position 7

TURN recommends rejecting the entirety of the Subtransmission Relay Upgrade 8

Program for three reasons: (1) TURN is not aware of any instances in which reverse power flows from 9

PV solar inverters have caused relays to remain closed when they should have opened; (2) SCE has not 10

experienced an instance in which a load encroachment condition by a PV solar inverter caused a relay to 11

remain closed during an outage condition, nor could it cite examples of any equipment damage or any 12

outages; and (3) there are multiple studies which confirm that PV solar inverters contribute insignificant 13

current in fault conditions.49 14

48 See Exhibit ORA-11, p. 16. 49 See Exhibit TURN-06, pp. 42-44.

Activity 2011 2012 2013 2014 2015 2016Subtransmission Relay Upgrade -$ -$ -$ -$ -$ 311$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceSubtransmission Relay Upgrade -$ 41,589$ 41,589$ -$ -$ -$ (41,589)$



2017-2018 2017 2018Total




2017-2018 2017 2018Total


SCE Forecast SEIA-Vote Solar Forecast

19

c) SEIA-Vote Solar’s Position 1

SEIA-Vote Solar recommends that the Commission not adopt SCE’s 2018-2020 2

request for $129 million for subtransmission relay replacements, and only authorize expenditures for 3

replacement of distance relays where SCE has conducted sufficient engineering analysis to demonstrate 4

the potential risk of load encroachment over the 2018-2020 GRC period. SEIA-Vote Solar claims that 5

SCE’s request is premature, as it has not conducted the engineering analysis to confirm the risk of load 6

encroachment is real.50 7

d) SCE’s Rebuttal to Intervenors’ Position 8

SCE’s original request was based on industry studies applied to the general 9

characteristics of SCE’s relays and circuits using conservative assumptions. Since then SCE has 10

performed focused in-house evaluations using actual circuit characteristics and has determined that our 11

circuits are more robust than earlier believed. These evaluations confirmed that increasing penetration 12

of DERs on circuits will at some point create the load encroachment challenges described in our 13

Integrated Distributed Energy Resources & Protection Systems Upgrades report.51 However, we now 14

believe that these challenges are unlikely to occur during this GRC cycle. As such, SCE agrees with 15

Parties’ forecast for this activity.16

50 See Exhibit SEIA-Vote Solar-01, p. 15. 51 Refer to WP SCE-02 Vol. 06, pp. 178-188 (Integrated Distributed Energy Resources & Protection System

Upgrades) on Appendix B pp. B-6 to B-16.

Appendix A

Data Requests

Southern California Edison2018 GRC A.16-09-001

DATA REQUEST SET ORA-SCE-207-YNL

To: ORA, ORAPrepared by: Lynn TsaiTitle: Project Manager

Dated: 03/01/2017

Received Date: 02/28/2017

Question 01.c:

Originated by: Yakov LaskoExhibit Reference: SCE-02, Vol. 06SCE Witness: Alan VarvisSubject: T&D – Transmission Construction & Maintenance

Please provide the following:

1. Referring to SCE’s response to data request ORA-SCE-154-YNL, Q.9, ORA-SCE-154-YNL,Q.16.a, and ORA-SCE-154-YNL, Q.16_metal theft update Excel file, please:

c. Please provide a breakdown of the $3.33 million expense by each substation.Furthermore, please provide a cost breakdown for each substation based on the workperformed at each substation to upgrade security.

Response to Question 01.c:

Please see the attached excel file, ORA-SCE-207-YNL_Q1c_cost breakdown.xlsx, for recorded 2015 and 2016 costs by substation broken out by labor, material, contract, and other costs. The total 2015 recorded cost corresponds to Copper Theft in Table I-17 as shown in SCE-02, Vol. 6. The general work at each of the substations include lighting and fencing replacement/upgrades. The actual cost for each site depends on specific site conditions, such as substation size, location, and design.

ORA-SCE-207-YNL_Q1c_cost breakdown.xlsxORA-SCE-207-YNL_Q1c_cost breakdown.xlsx

��

Cost�in�$�NominalSubstation�Mask�Number LMCO 2015 2016Substation�1 CONTRACT 335,622�� 30,901��

LABOR 24,790�� (277)��MATERIAL 106,296�� 12,320��OTHERS 66,281�� 4,630��

532,989�� 47,574��Substation�6 CONTRACT 68,544�� 1,033,555��

LABOR 16,591�� 35,428��MATERIAL 47,519��OTHERS 12,239�� 166,267��

97,373�� 1,282,769��Substation�9 CONTRACT 277,926�� 72,407��

LABOR 12,561�� 9,134��MATERIAL 73,625�� 1,084��OTHERS 46,541�� 14,891��

410,653�� 97,516��Substation�28 CONTRACT 103�� 681,749��

LABOR 15,341�� 48,472��MATERIAL 182,078��OTHERS 862�� 181,763��

16,306�� 1,094,062��Substation�30 CONTRACT 57,860��

LABOR 1,309�� 828��MATERIAL 1,230�� 808��OTHERS 8,448�� 319��

68,847�� 1,954��Substation�37 CONTRACT 201,528�� 10,450��

LABOR 21,201�� 1,983��MATERIAL 34,175�� (734)��OTHERS 37,144�� 7,663��




LABOR 8,083�� 10,871��MATERIAL 20,376�� (761)��OTHERS 12,372�� 25,589��

75,095�� 147,644��Substation�55 CONTRACT ��

LABOR 472��MATERIAL (21,365)��OTHERS (6,391)��

(27,284)��

ORA�SCE�207�YNL_Q1c_cost�breakdown.xlsxORA�207�Q1c ��

Substation�62 CONTRACT 9,499��LABOR 13,150��MATERIALOTHERS 3,477��

�� 26,126��Substation�119 CONTRACT 52,794�� 597,584��




176,155�� 887,565��Substation�141 CONTRACT 79,337��

LABOR 1,216�� 511��MATERIAL 2,583��OTHERS 11,279�� 71��

94,415�� 581��Substation�162 CONTRACT 71,278�� 613,644��






46,646�� 747,171��Substation�172 CONTRACT 74,197�� 1,479,261��


96,644�� 2,395,489��Substation�173 CONTRACT 70,340�� 437,044��



LABOR 25,326�� 118��


MATERIAL 159,453��OTHERS 89,116�� 6,502��

768,759�� 44,929��

Program�Recorded�Total 3,329,611�� 9,705,102��




To: ORAPrepared by: Lynn Tsai/Roxanne Contreras

Title: Project Manager/Prin. Advisor-Security ProgramsDated: 01/20/2017


Question 16.c:

Originated by: Yakov LaskoExhibit Reference: SCE-02, Vol. 06 SCE Witness: Alan VarvisSubject: T&D – Substation Construction & Maintenance


16. Referring to Exhibit SCE-02, Vol. 06, page 46, Table I-17 and SCE’s Copper Theft Record on pages 223-229, please provide the following:

c. Please provide a new table such as the one requested in 16.b cataloguing non-copper theft security incidents based on a substation physical security tiered program. Please provide supporting documentation in Excel file, similar to the update requested in 16.a cataloguing these incidents and identify the substations that were targeted and under what Tier the non-copper theft security incident occurred.


SCE does not track non-copper theft security incidents based on a substation physical security tiered program. Please refer the table below for the count of security incidents in year 2012-2016. Please note the theft incident numbers listed in the following table only include ones that have a case outcome from investigation.

2012 2013 2014 2015 2016 TOTAL

Theft 56 9 60 29 29 183

Trespassing 3 2 12 14 49 80

SuspiciousActivity 2 0 9 5 21 37

��

Vandalism 24 12 24 20 38 118

��


DATA REQUEST SET SCE-ORA-008

To: ORA

Dated: 04/20/2017

Question 01-04:

Please provide the following items related to ORA-11:

Questions:

1. Please provide detailed workpapers and analyses that show how ORA derived its forecast of $5 million for the Copper Theft Program in 2017 and 2018.

2. How did ORA assess the impact on reliability from its proposed reductions to the Copper Theft Program?

3. How does ORA incorporate the future price of copper in its evaluation of the number of future copper thefts?

4. Please provide the calculations and basis for the statement on ORA-11, page 14 lines 14-17: “The average cost for substation fencing/lighting upgrades is approximately $1 million per site. Therefore, based on SCE’s forecasts for 2017 and 2018 for the copper theft substation physical security enhancement programs, Edison will be able to upgrade security at 16-17 sites.”

Response to Question 01-04:

ORA Response:A.1Please refer to workpaper “ORA-154 Q16_metal theft update_revised for ORA- 207”. ORA used an Excel sort & filter function on the “Total By Location” column that sums the number of incidents from 2013-2016 and found that there were only eleven substations that experienced four or more total copper theft incidents from

2013-2016. According to the Excel file referenced above, the substation mask numbers are: 15, 22, 30, 55, 56, 116, 120, 134, 141, 150 and 169.

Given that SCE already incurred $784,000 in costs for Substation 169 and that the average cost

��

for substation fencing/lighting upgrades is approximately $1 million per site, ORA forecast that $5 million for the Copper Theft Program in 2017 and 2018 is an appropriate estimate to address security needs at the other ten substations that experienced a high frequency of copper theft incidents. Those ten substations are referenced above by their substation mask numbers, except for Substation 169.

ORA did not develop a separate workpaper for this calculation.

ORA Response:A.2ORA did not assess the impact on reliability from its proposed reductions to the Copper Theft Program. ORA’s assessment was primarily based on the frequencyof copper thefts (four or more) at certain substation locations over 2013-2016 period and the decline in copper thefts over time from 2013 to 2016.

ORA Response:A.3ORA did not incorporate the future price of copper in its evaluation of the number of future copper thefts. ORA focused on historical and verifiable trends in the price of copper as the future price of copper would be difficult to predict as it is a globally traded commodity.

ORA Response:A.4The average cost for substation fencing/lighting upgrades is based on SCE’s response to data request ORA-SCE-207-YNL, Q.2d where SCE stated that “[t]he average cost for this type of projects is approximately $1 million per site, and the details can be found in workpaper ‘Confidential_WPSCE-02V06-Substation Tiered Physical Security Forecast.xlsx’, tab ‘Copper Theft Forecast’.”

Referring to Ex. SCE-02, Volume 06, page 46, Table I-17, SCE requests$8,321,000 and $8,530,000 for 2017 and 2018 for its copper theft program. The total request for 2017-2018 is therefore $16.851 million. Considering SCE’s response to the above-mentioned data request, ORA deduced that based on the average cost of substation security upgrades, Edison will be able to upgrade security at 16-17 sites for those two years if Edison’s request is approved.

ORA did not develop a workpaper for this calculation.

SCE Outbound DR - Substation Construction & Maintenance - Set 1.docxSCE Outbound DR - Substation Construction & Maintenance - Set 1.docx

ORA Data Response to SCE-ORA-008.pdfORA Data Response to SCE-ORA-008.pdf

��




Dated: 03/01/2017


Question 01.a:



1. Referring to SCE’s response to data request ORA-SCE-154-YNL, Q.9, ORA-SCE-154-YNL, Q.16.a, and ORA-SCE-154-YNL, Q.16_metal theft update Excel file, please:

a. Confirm that all seven bold substations in the Excel file received physical security updates in 2015. If not, please provide the completed date for each substation’s physical security updates.

Response to Question 01.a:

Please see the revised file with the correct substations that have completed physical security enhancements (fencing and lighting) and were completed and in service in 2014-2015. To help clarify this correction, substations that had costs recorded for metal theft security upgrades in 2014-2015 are bolded with recorded dollars and in-service year information shown. The 2015 recorded costs correspond to Copper Theft in Table I-17 of SCE-2, Vol. 6. Those have in-service date in 2016 are shown in bold and highlighted per request in ORA-SCE-207-YNL question 3c. Additional columns from column L thru AD show the substation zip code and non-metal theft incidents at each site between 2012-2015 per request in ORA-SCE-207-YNL, question 3a, 3b, and 3d.

ORA-154 Q16_metal theft update_revised for ORA-207.xlsxORA-154 Q16_metal theft update_revised for ORA-207.xlsx

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To: ORA, ORAPrepared by: Lynn Tsai/Randy White

Title: Project Manager/Principal Manager, SecurityDated: 03/01/2017


Question 02.c:



2. Referring to SCE’s response to data request ORA-SCE-154-YNL, Q.16.a and ORA-154 Q16_metal theft update Excel file, please:

c. Explain any reasons to SCE’s knowledge for a decrease in the total annual metal theft record from 2013 (152 incidents) to 2016 (15 incidents).


SCE cannot provide full analysis and exact predictions on metal theft behavior, but traditional drivers include the market price of the materials, effectiveness of theft deterring installations, heightened awareness of electrical grid security and associated safety risks, public education, and local law enforcement activities.

In addition, copper is the metal most often stolen from our substations. From Jan 2011 to Jan 2016, the price of copper dropped by 53%. Combined with our increased security measures, this led to a significant decrease in metal theft. However, the price of copper is rising again (Tan, Huileng. "China Will Help Drive 33% Increase in Global Copper Prices by 2020: Citi." CNBC .CNBC, 19 Feb. 2017. Web. 08 Mar. 2017). From Jan 2016 to Jan 2017, the price of copper rose 28%, and the forecasts are for copper prices to return to near 2011 levels by 2020 with an expected significant increase in metal theft, vandalism, and resulting outages (if accurate this will be a nearly 80% increase over the price of copper in Jan 2016). No substation receiving metal theft security enhancements has had a theft of metal, equipment vandalized, or an outage resulting from theft or vandalism.

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DATA REQUEST SET SCE-ORA-012

To: ORA

Dated: 04/24/2017

Question 01-02:

1. In ORA-11, page 12, Figure 11-3, ORA charted the price of copper based on values SCE provided in the file “ORA-154 Q10_copper price.xlsx", in our response to ORA-SCE-154, Q. 10. Please:a. Provide an updated Figure 11-3 with 2017 YTD monthly copper prices as listed in the

referenced website provided in the file. b. Provide clarification, calculation, and/or description on how information in Figure

11-3 was used in ORA’s development of 2017-2018 forecast for Copper Theft program and ORA’s position in “B. Copper Theft Has Been on the Decline”.

2. Referring to page 14, line 9, please provide documentation showing where ORA identified the five substations that each had 4 copper theft incidents in 2013. Also, please provide the Substation ID numbers that correspond to these five substations, as depicted in SCE’s response to ORA-SCE-207-YNL, Q. 1a.

Response to Question 01-02:

ORA Response:A.1.aThe 2017 YTD COMEX Monthly average prices are provided in the table below from http://www.iwgcopper.com/price-history?year=2017:

COMEX Copper 2017 Monthly Average Price YTDJanuary $2.6186February $2.6943March $2.6412April $2.5863

Updated Figure 11-3 with 2017 YTD monthly copper prices:

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In ORA-11, page 12, Figure 11-3, ORA charted the price of copper based on values SCE provided in the file “ORA-154 Q10_copper price.xlsx", in our response to ORA-SCE-154,

ORA Response:A.1.bAs SCE pointed out in its response to data request ORA-SCE-207-YNL, Q.2.c, the “traditional drivers [of exact predictions on metal theft behavior] include the market price of the materials, effectiveness of theft deterring installations, heightened awareness of electrical grid security and associated safety risks, public education and local law enforcement activities.”

The information in Figure 11-3 was presented to illustrate one of the factors identified in SCE’s response to ORA’s data request above (the market price of the materials).

ORA’s assessment and development of 2017-2018 forecast for Copper Theft program was primarily based on the frequency of copper thefts (four or more) at certain substation locations over the 2013-2016 time period and the decline in copper thefts over time from 2013 and 2016. Please refer to ORA’s response to data request SCE-ORA-008, Q.1 for further explanation.

A.2

ORA Response:Based on SCE’s response to data request ORA-SCE-207-YNL, Q. 1a, there are five substations that each had 4 copper theft incidents over 2013-2016 time period. Their Substation ID numbers are: 22, 56, 116, 120 and 169. However, there is only one substation that experienced 4 copper theft incidents in 2013. Its Substation ID number is22. ORA will address the discrepancy in its testimony at a later date.

SCE Outbound DR - Substation Construction & Maintenance - Set 2.docxSCE Outbound DR - Substation Construction & Maintenance - Set 2.docx

ORA Data Response to SCE-ORA-012.pdfORA Data Response to SCE-ORA-012.pdf

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Dated: 03/01/2017


Question 01.d:



1. Referring to SCE’s response to data request ORA-SCE-154-YNL, Q.9, ORA-SCE-154-YNL, Q.16.a, and ORA-SCE-154-YNL, Q.16_metal theft update Excel file, please:

d. Please provide an explanation as to why SCE chose these seven particular substations for physical security updates.

Response to Question 01.d:

SCE substation engineering chose these substations to receive fencing/lighting upgrades based on multiple considerations, including but not limited to recorded theft or security incidents, substation location, area crime, recorded outage due to thefts, and potential impact on system reliability.

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DATA REQUEST SET TURN-SCE-026

To: TURNPrepared by: Brandon Tolentino

Title: Principal ManagerDated: 01/11/2017


Question 55:

These questions all refer to SCE02v10, “Grid Modernization”. The word “customers” is used throughout to mean average SCE customers (not customers who are also prospective or existing DER owners).

55. Please provide a copy of the study or studies that SCE has conducted to prove or illustrate the business case in favor of the Grid Modernization proposal as a whole and/or for any of its individual components.

Response to Question 55:

Besides what has already been presented in testimony and workpapers, SCE has continued to perform various analyses to validate and refine benefits and costs associated with each of the programs and projects associated with Grid Modernization. In response to this question, we are providing a summary of the business case for each of the programs/projects along with the underlying analysis supporting the business case.

The business case for Distribution Automation (DA), Grid Management System (GMS), �

Field Area Network(FAN), Wide Area Network (WAN) and Common Substation Platform (CSP) are combined. Though each of these programs and projects have specific benefits associated with them, these work together as an integrated solution and have been developed and designed as such for deployment.

- The benefits quantified are limited to reliability only, specifically in terms of reduction in Customer Minutes of Interruption (CMI) for unplanned outages

- Safety is inextricably linked to reliability. Therefore all of these projects and programs are also expected to reduce safety risks, but these benefits have not been quantified.

- Attachment "DA FAN WAN GMS CSP Study.pdf" summarizes the business case for this set of projects and programs- Attachment "SCE reliability technology BCA.xlsx" provides the Cost Benefit Analysis (CBA).

The business case for the System Modeling Tool (SMT) is provided in attachment "System �

Modeling Tool Study.pdf" along with the calculations to estimate additional resource needs

��

using current tools SMT in attachment "SMT Study Calculations.xlsx."The business case for DRP External Portal (DRPEP) is provided in attachment "DRP �

External Portal Study.pdf" along with the calculations to estimate additional resource needs with the current interconnection analysis and processing system in attachment "DRPEP Avoided Labor Costs.xlsx."The business case for Substation Automation (SAS-3) is summarized in attachment "SA-3 �

Study.pdf", along with the calculations to estimate DPU/TPU relay failure rates and the associated reliability impacts in attachment "SA-1_DPU_TPU Failure Trend.xlsx."Though cybersecurity associated with Grid Modernization is not included in SCE-02, �

Volume 10, it is a foundational capability required to address the existing and additional vulnerabilities associated with automation schemes and additional devices being deployed. It is also essential that cybersecurity capabilities be planned and designed in conjunction with the other projects and programs instead of being bolted on later to facilitate potential risks being mitigated in a coherent manner. We have not quantified cybersecurity benefits as cyber breaches are expected to be low frequency high magnitude events. For this reason, while the impact could be extreme and although the cybersecurity benefits are great, they are not readily quantifiable. Attachment "Cybersecurity.pdf" summarizes our business case for Grid Modernization related cybersecurity projects.

Please note that each of the projects and programs have associated benefits that have not been quantified and may not be quantifiable. These are enumerated in the individual business case documents along with qualitative analyses.

In summary, the Grid Modernization is an extension of existing technology and automation programs to (1) address current safety and reliability performance, (2) minimize further degradation to reliability and grid performance as we integrate DERs, and (3) meet the requirements as specified in the Distribution Resource Plan proceeding. SCE’s system and technology is aging and critical elements need to be replaced and upgraded to address not only performance degradation, but improve performance and enhance cyber security capability.

Program/project development approach:Integrate the deployment of new technologies with current utility annual programs so that we �

can execute necessary Grid Modernization work as efficiently as possible. Develop solutions that address current and forecast issues (for example performance �

degradation due to aging infrastructure, limitations of current circuit configurations and telecommunication networks, DER driven challenges, cybersecurity risks at device and network level)Implement solutions that provide foundational capability, increased capacity, forward �

compatibility and flexibility to accommodate future technology, potentially changing needs, and increasing demand.

DA FAN WAN GMS CSP Study.pdfDA FAN WAN GMS CSP Study.pdf SCE reliability technology BCA.xlsxSCE reliability technology BCA.xlsx

DRP External Portal Study.pdfDRP External Portal Study.pdf DRPEP Avoided Labor Costs.xlsxDRPEP Avoided Labor Costs.xlsx

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System Modeling Tool Study.pdfSystem Modeling Tool Study.pdf SMT Study Calculations.xlsxSMT Study Calculations.xlsx SA-3 Study.pdfSA-3 Study.pdf

SA-1_DPU_TPU Failure Trend.xlsxSA-1_DPU_TPU Failure Trend.xlsx Cybersecurity.pdfCybersecurity.pdf

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Substation Automation System - Version 3 IIntroduction Many of the first-generation automation devices installed at SCE’s substations are becoming outdated, are prone to failure, and rely on proprietary (rather than open standard) systems (SCE-02, Volume 10 starting on page 58). SCE has proposed to install SCE’s latest standard of SAS-3 (also referred to in testimony as “SA-3”) to mitigate many of these issues. This study summarizes the primary drivers for replacing our legacy substation telemetry and automation systems (RTU/SAS) with SA-3. It includes 1) quantification of the outage impact to our customers as a result of an increasing rate of certain relay failures, and 2) and derivation for the proposed accelerated rate of Full SAS-3 deployment needed to avoid these failures.

Problem Statement In the 1980s, SCE installed RTUs, which are electronic devices that provide basic remote monitoring and control of circuit breakers, and capture and transmit operational data (SCADA data) to system operators. SCE has approximately 450 substations with RTUs in service today.

In 1997, SCE installed its first generation of substation automation (SAS-1) to replace the RTU technology. SAS-1 added certain capabilities including: (1) acquiring/transmitting non-operational data (such as apparatus oil temperatures); (2) programming for automatic functions (such as timed or condition-based capacitor bank switching); and (3) a graphical user interface for ease of human interaction with intelligent equipment at substation. SCE has approximately 250 distribution substations with SAS-1 systems in service today. SAS-1 is a proprietary solution comprised mainly of ABB-only relays called DPU and TPU relays1 and an ABB-only Human Machine Interface (HMI).

In 2005, SCE began installing the second generation of substation automation system (SAS-2), which continued the use of a proprietary design, but accommodated modern enhanced relays manufactured by different vendors, enabled faster communication protocols (TCP/IP-based), and were more easily expandable to interact with new monitoring devices being added to the substation. SCE currently has approximately 80 SAS-2 installations at distribution substations.

In 2015, SCE developed the third generation of substation automation (SA-3) to address the needs and shortcomings of the previous Substation Automation Systems.

The primary difference between proprietary systems and open standard systems is the reliance on specific manufacturers to supply equipment. For example, SAS-1 substations with ABB-only relays that are no longer manufactured or supported. Thus, there is a decreasing supply of relays that can be used to replace failed units over time. New generation SA-3 are designed with a universal standard IEC 61850 that can accommodate equipment from multiple manufacturers, avoiding reliance on proprietary equipment supplies.

SCE’s SAS-1 and RTU systems are outdated; replacing these legacy systems is necessary to mitigate the following issues and risks:

Unique to SAS-1

1 DPU: Distribution Protection Unit, TPU: Transformer Protection Unit

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� Proprietary DPU/TPU relays for SAS-1 have high failure rates and can cause customer outages upon failure

� These DPU/TPU relays have been discontinued and are no longer manufactured � Vendor no longer supports proprietary HMI � We have a depleted DPU/TPU inventory

Unique to RTU

� Legacy RTUs are obsolete and there is no vendor support RTUs and SAS-1

� Both systems have limited remote control capabilities, including the inability to remotely access critical substation equipment and records, thus requiring a physical visit to the substation by a test technician, as described further in SCE-02, Volume 10 page 59

� Limited ability to record and communicate telemetry data necessary to optimize DER generation and minimize challenges to reliability (e.g., no indication of equipment failure to grid operators), as described in SCE-02, Volume 10 page 59

� Lack of adequate cybersecurity protection for substation equipment control

AAnalysis In support of the identified problem of DPU/TPU relay failures associated with SAS-1, below is a table detailing the historical and forecast number of failed relays per year from 2009 through 2030. When one of these relays fail, we replace it with a salvaged equivalent unit if inventory is available, or we begin converting the substation to SA-3. This is reflected in the declining population of DPU/TPU relays.

Table 1 - Annual Count of SAS-1 DPU/TPU Relay Failures

Year

Remaining Population of

DPU/TPU Relays

Number ofDPU/TPU Relay

Failures per Year2009 6434 16 2010 6418 52 2011 6366 108 2012 6258 133 2013 6125 161 2014 5964 164 2015 5800 180 2016 5574 226 2017 5321 253 2018 5040 281 2019 4732 308 2020 4397 335 2021 4034 363 2022 3644 390 2023 3226 418 2024 2781 445 2025 2308 473

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2026 1808 500 2027 1280 528 2028 725 555 2029 142 583 2030 0 142

DPU/TPU relay failures have been consistently increasing since 2009. Using the historical data and a linear function model, we forecast the DPU/TPU relay failure rate as a function of remaining population will increase from 4.7% in 2017 to 20.4% by 2025 – this reflects the aging nature of this technology. This forecast failure rate is relatively conservative as it assumes no exponential increase in failure rate, a profile that is more characteristic of aging grid assets beyond their expected service life as discussed in the Infrastructure Replacement Testimony.2

Figure 1 - Comparison of Forecasted SAS-1 �� SAS-3 Substation Conversion Schedule vs Failure Driven SAS-1 Substation Conversions

In the figure above the orange bars represent the estimated equivalent number of SAS-1 substations affected by DPU/TPU failures, and the blue bars represent the number of SAS-1 substations we would convert to SAS-3 each year. The ideal plan would be just-in-time replacement right before the relays fail in a substation. Though we are confident about forecasting the total number of system-wide relay failures, in reality, it is difficult to predict which exact equipment or substations will be impacted. Therefore it would be prudent to target additional substations for preemptive replacement each year to reduce the probability of in-service failure. SCE currently has approximately 270 SAS-1 stations that need to be converted by 2030 given the forecasts shown in Table 1. Our current plan is to levelize this workload from 2018 to 2028 at 23 full SAS-3 conversions per year.

Value of service lost for each unplanned outage occurrence Relay failures have a direct impact on reliability. Relays are used to protect against failed equipment, and used to operate protective circuit breakers to de-energize circuits and transformers.

2 Figure II-2: Time Dependent Failure Rate, SCE-02, Volume 8, Page 8

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An example of such impacts occurred at Fair Oaks Substation on December 18, 2016. The first TPU relay at the substation failed earlier in 2016. Since there was no available TPU relay to replace the failed unit, the transformer bank was left out of service for an extended period of time. Subsequently, another TPU failed causing a forced outage on the second (and only other) transformer bank. This caused loss of all distribution circuits at the substation and outages for every customer served from this substation. These customers experienced an outage due to a relay misoperation that lasted approximately 1 hour until service could be restored.

The economic cost of a typical substation outage on our customers was estimated at more than $1 million as presented in Table 2 below.3 The outage in the example could have been longer, but for immediate availability of personnel in the area. More commonly, we would expect service restoration for outages of this nature to have a minimum time of 1.5 hours. The table below summarizes the economic impact to our customers each time one of the DPU/TPU failures occur.

Table 2 - Economic Impact to Customers When a DPU or TPU Relay Failure Causes an Outage4

TPU Relay Failure Misoperation Event

DPU Relay Failure Misoperation Event

Total Customer Minutes of Interruption (CMI) 495,000 66,000Value of Service ($2.32 per CMI) $1,148,400 $ 153,120PG&E Value of Service ($2.91 / CMI) $1,440,450 $192,060

PProposed Solution & Alternatives Based on the aforementioned problems, SCE proposes to proactively replace aging SAS-1 and RTU systems with a modern and open-standards based substation automation system (SAS-3). Our assessment demonstrates this is a better approach than waiting for older relays to fail. The capabilities and design of this proposed solution are detailed in Volume 10 beginning on page 65. Additional details are provided in the Qualitative Benefits section of this response.

SCE considered alternatives to full SAS-3 conversion, such as converting SAS-1 and RTU systems to SAS-2 or a gradual conversion to SAS-3.

Option 1: Convert substations using SAS-2 technology

While SAS-2 solves the DPU/TPU relay failure problem by allowing utilization of non-proprietary relays, it was not selected because of (1) cybersecurity vulnerabilities, (2) it continues to use proprietary standards, (3) uses a communication protocol with limited flexibility, (4) has high license and maintenance fees, (5) no longer has vendor support for the HMI (Volume 10 testimony, page 64). For

3 We used a base case value of $2.32 per avoided customer minute of interruption. This value represents conservative assumptions since it reflects a simple average of PG&E values and national average values. The cost of living and doing business in SCE’s service territory is comparable to PG&E’s. These values are based on the Nexant study also included in workpapers for SCE-02, Vol 10, starting on page 122. 4 Please see separate spreadsheet attachment “SA-1_DPU_TPU Failure Trend.xlsx” for detailed calculations.

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these reasons described, we have already internally updated our standards to make all future substation automation upgrades as SAS-3.

Option 2: Convert substations partially to SAS-3, and replace relays as they fail (gradual SAS-3 conversion referred to in SCE-02, Vol 6) SAS-3

While this option will enable DPU/TPU relay problems to be addressed upon failure, the gradual conversion to SAS-3 cost over time is estimated to be comparable to upfront conversion to full SAS-3. For SAS-1 substations where additional capabilities are not necessary in the foreseeable future, a gradual conversion of DPU/TPU relays can be more cost effective. Adding future capabilities at a future date however, would make the gradual approach more expensive in the long run. These considerations conclude that a piecemeal deployment of technologies at substation facilities is not preferred when future capability requirements are known and anticipated. This concept of facility readiness and preference to simultaneous deployment of technologies is discussed in the facility readiness and dependency portions of the grid modernization work papers.5

Option 3: Full SAS-3 Conversion (selected)

This preferred option solves the proprietary and vendor support problems associated with the DPU/TPU relays by installing all new units and using an open-standards based communications network. The cost of a full SAS-3 Conversion is comparable to both SAS-2 and Gradual SAS-3 Conversion options. Finally, the full SAS-3 conversion option also provides many other immediate benefits which are described in the qualitative section below.

QQuantitative Benefits of full SAS-3 Conversion The primary quantitative benefit is the ability to avoid reactively replacing DPU/TPU relays from now through 2025, with each failed relay replacement requiring an ad-hoc substation outage. The risk to reliability is described in the problem statement section above. Considering the average SAS-1 distribution substation contains 23 relays, each of which presents this reliability risk, it is much more efficient for SCE to conduct one planned sequence of substation outages to upgrade the relays, HMI and communications protocol all at once.

Qualitative Benefits of full SAS-3 Conversion

The SAS-3 platform enables open standards-based communications, automated configuration of substation devices, and an enhanced system design. SAS-3 includes the following applications and benefits: Open-standards based substation automation system – Solves the existing problems associated with SAS-1 proprietary systems.

� Adoption of an open standards-based communications architecture enables interoperability between multiple manufacturer devices that implement this standard. The result of this is greater options for future upgrades, no longer tied to a single vendor. Please see Volume 10 testimony page 66

� IEC 61850 standard for substation system configurations and communications. This standard provides data driven configuration capabilities which will reduce levels of human intervention

5 SA3 & CSP Deployment plan is discussed in Volume 10 workpapers starting on page 141.

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that is necessary today with the traditional HMI systems. This is expected to demonstrably reduce errors, omissions and anomalies which are experienced today. Please see Volume 10 testimony page 66

� The IEC 61850 data structures are designed to be technology independent. This results in easier transition to new technologies as they become available.

Device-Specific Cyber Security - Aside from the Cyber Security benefits mentioned in the Cybersecurity Study, there are device-specific cyber security features that SAS-3 solution provides.

� The SAS-3 Design takes cyber security as part of its design, and includes features currently unavailable in existing legacy systems such as

o Device Password management o Role based access o Active configuration monitoring o Firmware and Patch management

Remote Access Features – Improves safety and operational efficiencies by providing the capability to remotely retrieve, set, and validate protective relay settings with modern cybersecurity

� Automated fault/event file retrieval features o SAS-3 monitors and collects relay event records to a centralized repository. This

automated relay record collection reduces the need to send personnel out to the substation to manually retrieve these records for analysis

o Configuration Management o Automated monitoring of substation device configurations for automated record

keeping provides a simple mechanism for device restoration in case of failure

Supports the realization of DER potential

� Automation program to enable operators to protect equipment, quickly recover from unplanned outages, manage planned outages, and optimize DER utilization all as DERs connect to the grid cannot be fully realized, as detailed further in Volume 10 testimony page 66

� Dedicated communications channels (from to the substation to the Data Historian) provides operational efficiencies by enabling collection of non-operational data without additional burden to system operators. The additional non-operational data enables applications such as just in-time equipment maintenance

� SAS-3 in combination with the common substation platform enable both open standard protocols and secure integration between substation devices and field devices. This enables future applications within the Grid Management System (GMS) which must interact with substation and distribution automation, as well as key DERs. This will be required to support Smart Grid applications and Integrated Systems of the Future.

Additional Benefits

� Data driven configuration processes that enhance operational efficiencies � Data driven HMI configuration process that takes minutes, providing significant improvement

compared with the existing manual process, which takes several weeks.

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� The use of SCE’s centralized configuration tool enables template driven configuration of substation devices with proven configurations eliminating errors and omissions typically found during testing.

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To: TURNPrepared by: Jeremy Califano

Title: Lead Sr. Project EngineerDated: 04/06/2017


Question 02.a:

(SCE02, various volumes)

2. Refer to SCE02v10, starting on page 59, regarding the SA-3/CSP proposal generally.a. Please estimate the cost of upgrading an “RTU” substation to an SAS-2 substation as

the SAS-2 standard exists today. Please provide all estimates, assumptions, and calculations used to arrive at this cost.

Response to Question 02.a:

An average cost of converting an RTU/PLC substation to a SAS-2 substation is based on historical project recorded costs from 2012 to 2016. Please refer to the attached spreadsheet for a list of these historical projects with similar scope that were then averaged as shown in below table. SA-3, however, has become SCE’s latest and current automation standard being implemented in all new green field substations and existing automation upgrades.

New Drop-in MEER Without New Drop-in MEER

Average cost $4,927,467 $3,520,419

Previous Automation Upgrade Cost Estimates.xlsxPrevious Automation Upgrade Cost Estimates.xlsx

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To: TURNPrepared by: Nathan Todaro

Title: PMDated: 01/11/2017


Question 35:

These questions all refer to SCE02v10, “Grid Modernization”. The word “customers” is used throughout to mean average SCE customers (not customers who are also prospective or existing DER owners).

35. Please refer to table III-4 on page 35, which proposes $359.839 million worth of nominal capital investment on SA-3/CSP from 2018 to 2020, inclusive. Per the Figure III-23 on page 68, 93 substations are being proposed for upgrades at an average cost of $3.869 million per substation. Please provide the cost breakdown for a single circuit’s capital investment by filling in the table below:

Equipment Installation Commissioning Design/Other TotalSA-3hardwareSA-3softwareSA-3 otherCSPhardwareCSPsoftwareCSP otherTotals $3.869

million


Given that SA-3 EPC projects have a 3-year project cycle from beginning to end, simply dividing the nominal 2018 to 2020 capital investment of $359.839 million by 93 projects will not

��

produce an accurate average cost per substation (including CSP). Also, SCE would like to clarify that SA-3 and CSP projects occur at the substation level, therefore it is more accurate to provide costs at that level instead of the requested circuit level. Further, SCE would like to clarify that the number of SA-3 (including CSP) projects with 2018 to 2020 operational dates is 92 projects, per Figure III-23 on page 68.

Using the nominal 2018 to 2020 capital investment of $359.839 million as the numerator fails to accurately consider the 3-year cost distribution for SA-3 projects referenced on page 132 of SCE-02, Vol. 10 SA-3 cost work paper: Year 1) 2% for job walks and scoping; Year 2) 38% for engineering and material procurement; and Year 3) 60% for construction and commissioning. As an example, the nominal 2018 capital investment of $114.340 million generally fails to account for job walk and scoping costs in 2016, as well as engineering and material procurement costs in 2017, which artificially reduces the average cost per substation.

For SA-3, there are two types of projects that will be deployed during the referenced operational years: 1) SA-3 w/New Drop-In Mechanical Electrical Equipment Room (MEER); and 2) SA-3 w/o New Drop-in MEER. Each project has its own unique average cost per substation. For CSP, SCE is providing a detailed average unit cost per based on the total 5-year nominal forecast for CSP divided by the number of CSPs deployed.

Based on the aforementioned reasons, SCE believes it’s more appropriate to provide in response to this data request a detailed unit cost breakdown (2015 constant) per SA-3 project and CSP. See below.

Common Substation Platform (Average Unit Cost) Costs

Project Management $11,147

Deployment Labor $10,885

Hardware $92,750

Software $47,781

Architecture, Data/System Integration & other support $30,763

��

SA-3 w/New Drop-in MEER

Costs Notes

VendorContract

$2,230,000

Reduced EPC cost estimate based on anticipated economies of scale savings from future contractors due to clustering bid strategy

SCE Labor $223,000

Reduced 10% multiplier against PO value due to SCE responsibilities described above being transferred to the EPC contractors

ProcurementServices

$16,190

0.66% provided by Operational Finance

Overheads(7.1%)

$158,330

7.1% division overheads provided by Operational Finance

Contingency(20%)

$525,504

20% contingency used due to the fact that these EPC SA-3 projects are still being piloted

Total $3,153,024

SA-3 w/o New Drop-in MEER

Costs Notes

VendorContract

$1,730,000

Reduced EPC cost estimate based on anticipated economies of scale savings from future contractors due to clustering bid strategy

SCE Labor $173,000

10% multiplier against PO value based on best judgement and the fact that the SCE responsibilities described above will have transferred to the EPC contractors

ProcurementServices

$12,560

0.66% provided by Operational Finance

Overheads(7.1%)

$122,830

7.1% division overheads provided by Operational Finance

Contingency(20%)

$407,678

20% contingency used due to the fact that these EPC SA-3 projects are still being piloted

Total $2,446,068

��

Please refer to ORA-SCE-079-TCR, Q19 for the estimated number of units of SA-3 with or without new drop-in MEERs.

��


DATA REQUEST SET ORA-SCE-083-TCR

To: ORAPrepared by: Mehrdad Vahabi

Title: EngineerDated: 12/19/2016


Question 30:

Originated by: Tom Roberts

Exhibit Reference: SCE-2, volume 10PG&E Witness: R. RagsdaleSubject: Electric T&D, Grid Modernization, Substation Automation (SA) functionality

Special Instruction: All Excel spreadsheets provided in response to these questions should have all formulas and links active, such that calculation methodologies can be viewed. If this is not possible, contact the originator within 5 working days.


30. What is the expected useful life of the SA-3 system? (Note that a prior data request question asked about SA-3 components, but this question refers to the SA-3 system as a whole.)


SCE does not have a forecast of the expected life of the entire SA-3 system, particularly because the SA-3 is based on the latest Substation Automation Standard, which uses open standards where available. Having an open standards based system enables easier integration and migration, and allows it to be updated to newer technologies in the future with minimal impact. Please see ORA-SCE-079-TCR, Q4 for the expected useful life for engineering and operational purposes and depreciation life for key components of SA-3.

��



To: TURNPrepared by: Joel Karzen

Title: Project ManagerDated: 02/28/2017


Question 10:

10. Refer to the SA-3 testimony in Volume 10 and the “Replace SAS Infrastructure” line in table IV-13 (page 32).

a. Please confirm that these are essentially the same activitiesb. If these are essentially the same activities, please explain the difference between the activities in Volume 6 and the activities in Volume 10.c. If these are not essentially the same activities, please explain the difference.


Part (a): Yes these are essentially the same activities.

Part (b): As stated in SCE02V06 page 30 beginning on line 7, the “The Substation Protection and Control System Replacements and Subtransmission Relay Upgrades may occur at the same substations under the Grid Modernization Automation program.” When this does occur, the relays and other equipment replaced under the Substation Protection and Control System Replacements program will be used when the substation undergoes full automation within the Grid Modernization Automation program (Grid Mod), thus reducing the scope of those specific Grid Mod projects.

While the equipment and technology used in both programs is essentially the same, the necessity of the programs are different. The Substation Protection and Control System Replacements program focuses on the age and performance of the protections systems involved, while the Grid Mod program focuses not only on the performance of the relay systems, but also what is needed to meet the goals of the Distribution Resources Plan (DRP).

Part (c): As stated in part a, these are essentially the same activities.

��

Appendix B

Workpapers

Workpaper – Southern California Edison / 2018 GRC

Exhibit No. SCE-02 / Vol. 06 Witness: M. Flores

�

�

�

�

�

�

�

Workpaper Title: 2010-2015 TPU/DPU Relay Failure Rate

192

��



�2010�2015�TPU/DPU�Relay�Failure�Rate

2010�2015�TPU/DPU�Relay�Failure�RateTPU�=�Transformer�Protection�UnitDPU�=�Distribution�Protection�Unit

ABB�DPU/TPU�Failure�Data TPU DPU Notes

Relay�Failure�with�Warranty�Repairs�(6�Years) 168 317

ABB�recorded�repairs��Relay�failures�reported�to�ABB�through�formal�RMA�process�

Relay�Failure�without�Warranty�Repairs�(6�Years) 103 422

Recorded�number�of�nonwarranty�emergency�spares�shipped�from�SCE�warehouse��Relay�failures�not�reported�to�ABB�

Total 271 739Total�Failures�(Both�TPU�and�DPU) 1,010�� from�2010�2015

Average�number�of�failures1 168 per�year10%�adjustmet2 185 per�year

Use 180 approximate�relay�failures�per�yearNotes:1)�Average�number�of�failures�per�year�=�Total�Failures�2010�2015/6�years2)�10%�adjustment�added�to�capture�unrecorded�repairs�due�to�lack�of�formal�RMA�notification�process

SCE�02,�Vol.�6�Workpaper2010�2015�TPU/DPU�Relay�Failure�RatePage�1�of�1

193

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�

�

�

�

�

�

�

Workpaper Title: Substation Protection & Control Forecast

170

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Substation�Protection�Controls�Forecast

Substation�Protection�&�Control�2016�2020�Forecast�Summary(Nominal�$000)

2016 2017 2018 2019 2020Replace�Non�Bulk�Relays��115kV�&�Below 9,978$�� 3,369$�� 3,661$�� 3,770$�� 3,883$��Replace�Bulk�Relays��220kV�&�500kV 4,249$�� 7,874$�� 17,248$�� 17,703$�� 9,083$��Replace�SAS�Infrastructure 6,731$�� 20,662$�� 26,366$�� 27,193$�� 28,058$��Replace�Digital�Fault�Recorders�(DFRs) 5,602$�� 6,907$�� 5,828$�� 5,981$�� 6,138$��Telecom�connection�for�relay�replacements 1,445$�� 2,869$�� 2,569$�� 2,569$�� 2,569$��Total 28,005$�� 41,681$�� 55,672$�� 57,216$�� 49,731$��

Replace�Non�Bulk�Relays��115kV�&�BelowReplace�Bulk�Relays��220kV�&�500kVReplace�SAS�InfrastructureReplace�Digital�Fault�Recorders�(DFRs)

1,728$��827$��458$��

61346540

SCE�derives�the�total�forecast�by�using�historic�cost�and�engineering�experience�on�the�type�of�commodity�being�replaced.��For�each�of�the�listed�location/substation�sites,�as�job�walks�are�performed�and�more�details�becoming�available,�project�forecasts�are�adjusted�and�spread�out�across�a�2�to�3�year's�span�based�on�design�and�execusion�schedule.��Telecom�work�are�added�to�the�forecast�to�support�the�telecommunication�connection�and�upgrades�necesary�to�support�the�relay�installation.

SCE�tracks�and�executes�these�projects�on�a�3�year�basis.��Beyond�2018,�SCE�anticipates�the�same�level�of�activity�to�continue�through�out�2019�2020.��The�only�exception�is�an�anticipated�reduction�of�number�of�projects�on�bulk�relay�replacement�on�220kV�&�500kV�due�to�much�smaller�total�number�of�these�relays�in�the�system.

Average�Cost�per�Site Total�Number�of�Location�(2016�2018)558$��

SCE�02,�Vol.�6�WorkpaperSubstation�Protection�Control�ForecastPage�1�of�7

171

$28360

$89033

��



Substation�Protection�Controls�Forecast

SAS�Infrastructure�Replacement�Project�ForecastUpgrade�based�on�Automation�hybrid�solution�or�SA3,�eliminate�TPU�and�DPU�relays(Nominal�$000)Locations 2016 2017 2018 Total�per�Site

NAPLES �$�� $�� 2,623$�� 2,623$��NOGALES �$�� $�� 500$�� 500$��NORTH�OAKS 43$�� $�� $�� 43$��ORMOND �$�� 500$�� 125$�� 625$��PALOS�VERDES �$�� $�� 500$�� 500$��POMONA �$�� $�� 500$�� 500$��PUENTE �$�� 500$�� 125$�� 625$��REDONDO �$�� 942$�� 487$�� 1,430$��SAN�BERNARDINO �$�� $�� 1,598$�� 1,598$��SAN�MIGUEL 385$�� 315$�� 30$�� 730$��SANTA�CLARA 578$�� 551$�� 10$�� 1,139$��SAWTELLE 14$�� $�� $�� 14$��SEPULVEDA 177$�� $�� $�� 177$��SHAWNEE �$�� 500$�� 125$�� 625$��TAHITI �$�� 443$�� 862$�� 1,305$��TAMARISK �$�� $�� 500$�� 500$��TENNESSEE �$�� $�� 500$�� 500$��TORRANCE �$�� 1,190$�� 297$�� 1,487$��VICTORIA �$�� 1,162$�� 290$�� 1,452$��WALTERIA �$�� 385$�� 315$�� 700$��WAVE �$�� 500$�� 125$�� 625$��WIMBLEDON �$�� 942$�� 487$�� 1,430$��WINDSOR �$�� 500$�� 125$�� 625$��WRIGHTWOOD 34$�� $�� $�� 34$��Total 6,731$�� 20,662$�� 26,366$�� 53,758$�

Average�Cost�per�Location 827$��Total�#�of�Location 65

Note:Average�cost�excludes�the�telecom�work

SCE�02,�Vol.�6�WorkpaperSubstation�Protection�Control�ForecastPage�5�of�7

175

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�

�

�

�

�

�

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Workpaper Title: Integrated Distributed Energy Resources & Protection

System Upgrades

178

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�4�

�

� �

�Vik�Trehan,�P.E.�Senior�Manager,�SC&M,�T&D�Southern�California�Edison�

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179

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1�|�P a g e ��

INTEGRATED�DISTRIBUTED�ENERGY�RESOURCES�&�PROTECTION�SYSTEM�UPGRADES�

Table�of�Contents��

1� IImpact�of�Distributed�Energy�Resources�(DERs)�on�Power�System�–�....�2�

2� IImpact�of�DERs�on�a�Distribution�Network��..........................................�2�

2.1� CChallenges�with�Legacy�Electromechanical�Relays��.........................�4�

2.2� MMitigation�Strategy�with�Distribution�Relay�Upgrades��...................�4�

3� IImpact�of�DERs�on�a�Transmission�Network��........................................�4�

3.1� MMitigation�Strategy�with�Transmission�Relay�Upgrades�–�................�7�

4� FFirst�Generation�Substation�Automation�System�(SAS)�Challenges�–�....�8�

4.1� MMitigation�Strategy�for�SAS�Substations�–�........................................�9�

5� CConclusion�–�...........................................................................................�9��

� �

180

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1 Impact�of�Distributed�Energy�Resources�(DERs)�on�Power�System�–��

The�DERs�interconnection�creates�technical�challenges�in�a�power�system�design�where�one�or�more�generators�are�connected�to�a�distribution�feeder.�The�installation�of�a�DER�on�a�distribution�network�adds�multiple�layers�of�complexities�due�to�its�dynamic�characteristics�to�both�distribution�and�transmission�network.��

2 Impact�of�DERs�on�a�Distribution�Network��

Conventional�distribution�systems�are�designed�and�configured�to�protect�against�faults�based�on�a�unidirectional�or�radial�power�flow.�The�increase�in�DER�interconnections�will�create�a�situation�where�fault�currents�will�flow�in�directions�not�expected�by�the�existing�protection�system,�causing�the�relays�to�under�reach�or�over�reach.�In�addition,�the�DERs�connected�to�the�main�electric�grid�may�cause�voltage�fluctuations�and�unbalancing�of�the�power�grid.�System�transients�and�harmonics�can�be�generated�due�to�continuous�detachment�or�reconnection�of�the�DERs�that�can�penetrate�into�the�power�system.�The�penetration�of�such�disturbances�into�the�electric�grid�can�lead�to�synchronization�problems,�thereby�greatly�impacting�system�stability.��

The�trouble�when�integrating�DERs�with�the�presented�electrical�network�is�that�the�distribution�systems�are�mainly�designed�as�a�passive�network,�that�is,�carrying�the�power�from�the�substations�to�downstream�load�centers.�With�DERs�on�the�grid,�energy�can�flow�in�either�direction.�This�can�majorly�impact�the�functionality�of�a�distribution�protection�system,�which�is�otherwise�designed�for�a�radial�system�with�no�bidirectional�flows.�This�may�affect�the�power�system�in�a�number�of�ways.�The�overall�performance,�reliability,�and�stability�of�a�system�may�greatly�be�compromised�if�the�protection�systems�are�not�enhanced�for�such�applications.�Additional�complexities�due�to�a�DER�on�a�distribution�system�include,�loss�of�relay�coordination,�voltage�regulation,�voltage�transients,�relay�desensitization,�current�reversal,�islanding,�system�resonance,�etc.�

�

�

181

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As�a�result�of�the�aforementioned�challenges,�a�protection�system�can�fail�to�operate�correctly�in�the�following�two�ways�–��

1. Reverse�power�flow�leading�to�a�misoperation�as�shown�in�Figure�1.��

�

�

2. Fail�to�trip�condition�for�downstream�faults,�when�the�fault�current�contribution�from�the�substation�is�decreased�due�to�paralleling�of�the�source�impedances�of�the�substation�and�the�DER;�the�fault�is�primarily�composed�on�DER�current�as�shown�in�Figure�2.�

�

Figure�1��Misoperation�of�CB�1�Due�to�Reverse�Power�Flow

Figure�2 � CB�1�Fail�to�Trip�on�Downstream�Faults

182

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2.1 Challenges�with�Legacy�Electromechanical�Relays��

The�legacy�electromechanical�relays’�lack�of�advanced�protection�functions�make�them�very�susceptible�to�DER’s�dynamic�system�response.�Furthermore,�the�inability�of�the�electromechanical�relays�to�execute�appropriate�operation�due�to�complex�system�disturbances�such�as�DC�offsets,�harmonics�and�transients,�downed�conductor,�current�reversal,�etc.�imposes�increased�safety�hazards�and�risks�to�personnel�and�property.��

2.2 Mitigation�Strategy�with�Distribution�Relay�Upgrades��

Advanced�protection�schemes�must�be�implemented�on�the�distribution�system�with�the�increased�numbers�of�DER�interconnections.�The�protection�system�must�be�capable�of�successfully�detecting�and�differentiating�between�faulty�conditions�and�dynamic�load�response.�

The�increased�number�of�installations�of�DERs�on�SCE’s�distribution�grid�necessitates�the�implementation�of�microprocessor�based�protective�relaying�with�advanced�protection,�automation�and�control�functions,�and�precise�selectivity,�sensitivity,�security,�and�speed.��

With�a�microprocessor�based�control�and�power�quality�monitoring�system,�effects�of�over�and�under�voltage�conditions,�transients,�and�harmonics�can�be�detected,�recorded,�analyzed,�and�mitigated.��

3 Impact�of�DERs�on�a�Transmission�Network��

The�integration�of�DERs�in�the�distribution�system�poses�technical�constraints�to�the�legacy�transmission�protection�systems,�and�can�challenge�the�historical�design�assumptions�and�settings�principles.�

Typically,�distance�relays�are�designed�to�protect�transmission�line�faults�by�using�the�method�of�step�distance�protection.�The�protection�elements�of�a�distance�relay�utilizes�line�impedances�to�determine�the�zones�of�protection,�where�each�zone�is�set�as�a�predetermined�percentage�of�the�line�impedance.�Refer�to�Figure�3�&�4.�The�load�flowing�through�a�transmission�line�also�appears�as�impedance�to�the�distance�relay,�typically�known�as�“load�impedance”.�The�

183

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5�|�P a g e ��


load�and�the�load�impedance�have�an�inverse�relationship,�therefore,�as�the�load�on�the�transmission�line�increases�the�load�impedance�decreases.��

�

�

�

�

With�increased�DER�interconnection�and�penetration�into�the�transmission�system,�the�load�on�the�transmission�line�is�expected�to�sufficiently�increase,�thus�reducing�the�load�impedance�to�a�point�of�encroachment�on�the�relay’s�zone�of�protection.�Non�intelligent�Electromechanical�and�Solid�State�distance�relays�will�identify�this�encroachment�as�a�fault�and�will�lead�to�an�

Figure�3�� Transmission�System�without�a�DER

Figure�4��Distance�Relay�MHO�Characteristics�showing�typical�Load�Point�without�DERs�

184

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�

6�|�P a g e ��


unexpected�relay�operation.�This�undesirable�operation�will�cause�a�heavily�loaded�line�to�be�taken�out�of�service�with�no�actual�faults.�A�widespread�system�outage�can�be�caused�with�multiple�misoperations�with�similar�conditions.�Refer�to�Figure�5�&�6�below.��

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Figure�5�–�Transmission�System�with�DER�Penetration

Figure�6��Distance�Relay�MHO�Characteristics�showing�impact�to�Load�Point�due�to�DER�Penetration�

185

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3.1 Mitigation�Strategy�with�Transmission�Relay�Upgrades�–��

Legacy�electromechanical�and�solid�state�distance�relays�must�be�replaced�with�intelligent�microprocessor�relays�with�load�encroachment�functionality�on�the�transmission�system.�The�load�encroachment�element�measures�the�apparent�positive�sequence�impedance�being�supplied�by�the�feeder.�If�the�measured�positive�sequence�impedance�falls�within�the�load�encroachment�region�shown�in�Figure�7,�the�load�encroachment�logic�blocks�the�distance�elements�from�tripping,�hence�preventing�the�misoperation.��

�

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Figure�7�–�Intelligent�Microprocessor�Relay�MHO�Characteristics�with�Load�Encroachment�

186

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4 First�Generation�Substation�Automation�System�(SAS)�Challenges�–�

Southern�California�Edison’s�(SCE)�first�generation�SAS�substations�currently�presents�a�variety�of�unforeseen�challenges�and�system�reliability�risks.�Legacy�SAS�relays�use�a�proprietary�and�obsolete�serial�(ModBus+)�communication�protocol,�and�are�incapable�of�communicating�with�newer�intelligent�microprocessor�relays�that�utilize�modern�protocols,�such�as�IEC�61850.�Optimum�inter�relay�communication�is�very�significant�for�successful�operation�of�integrated�protection�and�automation�schemes�that�involve�taking�inputs�from�multiple�intelligent�electronic�devices,�such�as�relays,�Programmable�Logic�Controllers�(PLC),�Human�Machine�Interface�(HMI),�etc.��

The�reliability,�safety,�and�financial�risks�are�further�amplified�by�recent�obsolescence�of�these�equipment�types�and�enhanced�failure�rate�as�shown�in�Figure�8.�With�the�cascading�effect�of�multiple�simultaneous�system�wide�failures�and�a�limited�availability�of�critical�spares,�the�grid�can�likely�be�subjected�to�extreme�abnormal�conditions,�such�as�DER�curtailments,�widespread�equipment�outages,�etc.��

�

�

��

16

52

108

133

161 164180

2009 2010 2011 2012 2013 2014 2015

Number�of�SAS�Relay�Failures

187

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4.1 Mitigation�Strategy�for�SAS�Substations�–��Legacy�SAS�relays�must�be�proactively�replaced�with�modern�and�intelligent�microprocessor�relays�that�provide�advanced�protection�and�Supervisory�Control�and�Data�Acquisition�functions.�Added�benefits�of�these�relays�include�faster�and�reliable�communication�with�other�intelligent�electronic�devices�both�within�the�parameters�of�the�substation�and�external�devices�in�the�field,�thus�facilitating�implementation�of�advanced�integrated�protection�schemes�for�a�greater�grid�reliability.��

5 Conclusion�–�SCE’s�goal�is�to�deliver�power�in�a�protected,�consistent,�and�efficient�way.�The�power�system�relaying�makes�the�overall�system�safe�and�secure.�The�advanced�relays�will�sense�and�react�to�emerging�faults�with�minimum�or�no�loss�to�consumers�or�equipment.�Additionally,�the�advanced�relays�will�not�operate�for�normal�system�conditions�and�will�not�limit�the�system’s�capability�to�carry�load.�With�the�capability�of�providing�advanced�protection,�automation�and�control�functions,�disturbance�data�monitoring�and�recording,�and�operating�on�the�principles�of�precise�selectivity,�sensitivity,�security�and�speed,�intelligent�microprocessor�relays�is�the�key�solution�to�SCE’s�ever�evolving�grid.��

�

188

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Documents

2018 General Rate Case Rebuttal Testimony Transmission ...FILE/SCE18V06.pdf · 1 1 I. 2 SUBSTATION CONSTRUCTION AND MAINTENANCE REBUTTAL 3 This volume presents SCE’s rebuttal to