2018 General Rate Case Rebuttal Testimony · 2017. 7. 13. · Witnesses: B. Tolentino J. Gooding J. Schellenberg (U 338-E) 2018 General Rate Case Rebuttal Testimony Public Version

Application No.: A.16-09-001 Exhibit No.: SCE-18, Vol. 10 Witnesses: B. Tolentino

J. Gooding J. Schellenberg

(U 338-E)

2018 General Rate Case Rebuttal Testimony

Public Version

Transmission & Distribution (T&D) Volume 10 – Grid Modernization

Before the

Public Utilities Commission of the State of California

Rosemead, California

June 16, 2017

Errata

A

SCE-18, Vol. 10: Transmission & Distribution (T&D) – Grid Modernization

Table Of Contents (Continued)

Section Page Witness

-ii-

c) SCE Must Improve Reliability to Maintain

Adequate Service .........................................................25

d) SCE’s Proposal Will Improve Reliability

Measurably ...................................................................26

e) The CPUC Has Authorized IOUs to

Improve Reliability in Past GRCs ................................27

f) Like Reliability, Safety is an Important Grid

Modernization Benefit .................................................28

3. SCE’s Grid Modernization Program is Cost-

Effective ...................................................................................30

a) SCE’s Grid Modernization Program is

Justified Based on Reliability Benefits

Alone ............................................................................30

b) SEIA-Vote Solar’s Observation on SCE’s

Cost per CMI Is Inconsequential .................................33

c) SCE’s Reliability Value Estimates are Based

on A Study Produced By Nexant .................................34 J. Schellenberg

4. Use of Existing Data Sources Alone Will Not

Provide Sufficient Visibility ....................................................34 B. Tolentino

II. CAPITAL EXPENDITURES ..........................................................................37

A. Distribution Automation ......................................................................37

1. Intervenors’ Positions ..............................................................39

2. SCE’s Rebuttal to Intervenors’ Positions ................................39

a) SCE’s BCA Provides Justification for DA

Program Costs ..............................................................39

b) Intervenors Mistakenly Assert that Only the

Cheapest Option Should be Pursued ............................40

J. Gooding

B. Tolentino

1

I. 1

GRID MODERNIZATION OVERVIEW 2

In Exhibit SCE-02, Volume 10, SCE showed that the current grid must evolve to maintain and 3

improve reliability and safety while meeting changing customer expectations and environmental goals. 4

At its core, SCE’s request is focused on achieving key capabilities of a modern distribution grid. These 5

include near-real time and granular visibility of the power flow on the grid, quick operator decision-6

making and response times, and technologies that protect against physical and cybersecurity threats. In 7

addition, SCE’s Grid Modernization efforts will ultimately enable distributed energy resources (DER) 8

integration and adoption, and allow DERs to realize grid benefits as their volumes continue to grow. 9

But regardless of additional DER penetration, the grid needs these capabilities for reliability purposes 10

today to meet customer expectations and demands. 11

SCE’s Grid Modernization proposal rests on the fact that SCE’s grid is outdated and reliability is 12

declining. At the same time, the pace of policy change, increasing activity on the distribution grid, and 13

customer demands for improved reliability require the exact opposite. A modern grid needs an 14

integrated suite of automation, communication infrastructure and analytics applications. In addition, 15

system planning and grid operations are inextricably linked, as the information that allows system 16

operators to better manage the grid also enables engineers to develop capital projects that more precisely 17

target the problem. Previous limited-scale efforts at improving the grid simply are not enough. As the 18

analogy to a home remodel described in Mr. Payne’s Policy rebuttal shows,1 more piecemeal 19

development and deployment will result in patchwork solutions that cost more in the long-run. For this 20

reason, characterizing SCE’s Grid Modernization as “gold-plating”2 is incorrect and short-sighted. A 21

full-scale grid transformation should begin now. 22

The programs in our request will deliver significant customer value. As just one example, SCE’s 23

proposed distribution automation allows 75% of our customers to be restored within minutes of an 24

outage (a 50% improvement over today) and prevents about a third of the customers on a circuit from 25

1 See Exhibit SCE-17, p. 4. 2 See Exhibit TURN-06, p. 58 (internal citation omitted).

4

Table I-1 Summary of Grid Modernization Capital Expenditures8 9

100% CPUC Jurisdictional – Nominal $000

SCE’s proposal in its September 1, 2016 Application was based on an assessment that 1

considered a number of different factors, including reliability, future growth of DERs, grid flexibility 2

and other, more qualitative benefits anticipated to result from the development of a modern 3

grid. Subsequently, SCE refined its analysis based on additional engineering studies, pilot projects, and 4

8 Forecast includes on Errata filed on November 17, 2016 (November 2016 Errata) and Errata filed on June 16,

2017 (June 2017 Errata). 9 TURN’s Forecast for Worst Circuit Rehabilitation (WCR) Enhanced Distribution Automation is based on an

email SCE received from TURN on May 5, 2017 that identified errata to their forecast. These numbers are different than the Errata TURN filed on June 9, 2017. Due to the timing of the TURN’s errata filing, this information could not be incorporated into our rebuttal at this time.

Activity 2011 2012 2013 2014 2015 2016Circuit Automation (CA) 4,336$ 3,475$ 5,896$ 6,092$ 7,130$ 6,935$ WCR Enhanced Distribution Automation (WCR-EDA) -$ -$ -$ -$ -$ -$ DER-Focused Enhanced Distribution Automation (DER-FEDA) -$ -$ -$ -$ 374$ 5,122$ Distribution System Efficiency Enhancement Project (DSEEP) 4,192$ 4,924$ 4,077$ 4,518$ 4,314$ 4,293$ Field Area Network (FAN) -$ -$ -$ -$ -$ 1,104$ Common Substation Platform (CSP) -$ -$ -$ -$ 170$ 687$ Wide Area Network (WAN) -$ -$ -$ -$ -$ 597$ System Modeling Tool (SMT) -$ -$ -$ -$ 564$ 3,621$ Distribution Resource Plan External Portal (DRPEP) -$ -$ -$ -$ 539$ 1,303$ Grid Management System (GMS) -$ -$ -$ -$ 471$ 2,257$ SA-3 -$ -$ -$ -$ 186$ 8,456$ Total 8,529$ 8,399$ 9,973$ 10,611$ 13,748$ 34,374$

Recorded

Activity 2017 2018Total

2017-2018 2017 2018Total

2017-2018 Variance 2017 2018Total

2017-2018 VarianceCA 4,607$ -$ 4,607$ 7,058$ 7,227$ 14,285$ 9,678$ n/a n/a n/a n/aWCR-EDA -$ 182,681$ 182,681$ -$ -$ -$ (182,681)$ -$ 65,400$ 65,400$ (117,281)$ DER-FEDA 60,786$ 96,246$ 157,032$ -$ -$ -$ (157,032)$ 60,786$ 11,200$ 71,986$ (85,046)$ DSEEP 6,041$ 6,198$ 12,239$ 4,375$ 4,480$ 8,855$ (3,384)$ 6,041$ 6,199$ 12,240$ 1$ FAN 11,697$ 14,650$ 26,348$ -$ -$ -$ (26,348)$ -$ -$ -$ (26,348)$ CSP 3,933$ 7,513$ 11,446$ -$ -$ -$ (11,446)$ n/a n/a n/a n/aWAN 4,908$ 38,647$ 43,555$ -$ -$ -$ (43,555)$ -$ -$ -$ (43,555)$ SMT 6,457$ 2,467$ 8,924$ -$ -$ -$ (8,924)$ n/a n/a n/a n/aDRPEP 1,836$ 3,641$ 5,477$ -$ -$ -$ (5,477)$ n/a n/a n/a n/aGMS 12,302$ 39,456$ 51,758$ -$ -$ -$ (51,758)$ 12,302$ 20,000$ 32,302$ (19,456)$ SA-3 46,418$ 106,761$ 153,180$ -$ -$ -$ (153,180)$ 46,418$ 6,800$ 53,218$ (99,961)$ Total 158,987$ 498,260$ 657,247$ 11,433$ 11,707$ 23,140$ (634,107)$ (391,646)$

SCE Forecast ORA Forecast TURN Forecast

2018=6,798Total=12,839Variance=600

391,047

9

B. SCE’s Rebuttal to Intervenors’ Positions 1

1. SCE’s Grid Modernization Programs are Primarily Reliability-Driven, 2

Foundational and Should Not Await the DRP 3

a) Grid Modernization is Primarily Driven by Reliability Goals 4

Some Intervenors are under the impression that the primary purpose of SCE’s 5

Grid Modernization program is to meet the goals of the DRP and enable DERs.30 Moreover, they 6

express concern that the costs of Grid Modernization will be attributed to DERs.31 It may be helpful to 7

summarize what our proposal is, why it is necessary, and how SCE expects to address these needs. 8

(1) What is SCE’s Grid Modernization Proposal? 9

At its core, SCE’s Grid Modernization program is aimed at achieving 10

certain key capabilities to address safety and reliability concerns. As mentioned above, these include 11

near-real time and granular distribution grid visibility, quick system operator decision-making and 12

response times, and technologies that protect against physical and cybersecurity threats. These 13

capabilities are necessary to (1) provide grid operators timely information and heightened ability to 14

prevent or respond to outages, (2) provide engineers better data and tools to target capital projects more 15

precisely and identify deferral opportunities, and (3) provide customers timely information as they make 16

decisions about installing DERs. These are not newfangled ideas or nice-to-have capabilities.32 These 17

are essential to manage the grid today, even without proliferation of DERs. 18

(2) Why is SCE’s Proposal Appropriate? 19

Today, system operators and troublemen function without the essential 20

tools of a modern grid. When an outage occurs, operators sometimes only become aware of the outage 21

once the impacted customers report it to SCE, rather than through information at their disposal.33 Once 22

the operator learns of the outage, the troubleman must be dispatched to patrol the length of the circuit, 23

looking for the flashing lights of the two or three fault indicators installed on the circuit to estimate the 24

30 See ORA-09 pp. 12-13, SEIA-Vote Solar pp. 10-11. 31 See ORA-09 p. 35, SEIA-Vote Solar p. 51-52. 32 In fact, similar technologies were included in PG&E’s last GRC. See D.17-05-013, Decision Authorizing

Pacific Gas and Electric Company’s General Rate Case Revenue Requirement for 2017-2019, p. 58 (approving settlement of PG&E’s 2017 rate case, including funding for Fault Location, Isolation, and Service Restoration (FLISR), which is similar to SCE’s DA).

33 Outages that result in an open circuit breaker will be reported to the Outage Management System (OMS).

32

utilities and the U.S. overall. Based on this analysis, the outage costs in SCE’s service territory are 1

higher than PG&E’s. More specifically, the energy intensity in SCE’s service territory is 165% of the 2

U.S. average, compared to 160% for PG&E’s service territory.102 It is therefore reasonable for SCE to 3

use the upper bound CMI value (representing PG&E data) for its BCA. Updating the BCA with this 4

CMI value results increases the benefit-cost ratio from 1.20 to 1.51 for the WCR circuits and from 1.09 5

to 1.37 for the WCR and DER-driven circuits.103 6

Third, SCE’s forecast reliability improvements relied on 2013-2015 reliability 7

performance. As noted earlier, SCE’s reliability has been declining. The most recent three-year average 8

SAIDI for 2014-2016 increased (meaning reliability declined) from the three year average SAIDI for 9

2013-2015. Updating the BCA with the most recent reliability data yields approximately 10% more 10

avoided CMI, increasing the benefit-cost ratio from 1.51 to 1.66 for the WCR circuits and from 1.37 to 11

1.51 for the combined WCR and DER-driven circuits.104 12

Figure I-8 summarizes the adjustments to SCE’s BCA described above. The 13

analysis confirms that even after correcting for the data error identified by SEIA-Vote Solar, SCE’s 14

proposed DA, GMS and communications technologies produce reliability benefits that exceed the 15

associated costs by 45-59%.105 16

102 See Appendix E – Reliability Improvement Calculations, GDP per kWh_MSA Cluster Comparison.xlsx, pp.

E-151 to E-154. See supra text accompanying note 3 on accessing Appendix E Excel files. 103 See Appendix E – Reliability Improvement Calculations, SCE reliability technology BCA_Model 2_PG&E

Values, tab 1. Summary, pp. E-155 to E-158. SCE’s analysis of the GDP/non-residential energy consumption also supports updating the value of each avoided momentary customer interruption (MI). SCE has therefore also updated the value of each avoided MI from $91.05 to $114.10. See supra text accompanying note 3 on accessing Appendix E Excel files.

104 See Appendix E – Reliability Improvement Calculations: SCE reliability technology BCA_Model 3_Incorporate 2016 Reliability Performance.xlsx, tab 1. Summary, pp. E-159 to E-162. See supra text accompanying note 3 on accessing Appendix E Excel files.

105 Figure I-8 summarizes the adjustments to SCE’s BCA described above. The WCR Circuits section represents deployment scenario 1 (WCR) in SCE’s response to TURN-26 question 55, and the WCR & DER-driven Circuits section represents deployment scenario 3 (WCR and DER). Deployment scenarios 2 (WCR+) and 3 (WCR & DER+) are excluded since these included conductor upgrade costs, which SCE removed from its request, as discussed on page 6 of this rebuttal testimony.

comparable

1

4

_v2

37

II. 1

CAPITAL EXPENDITURES 2

In this Section, SCE responds to the issues raised by Intervenors with respect to the specific 3

capital projects in SCE’s Grid Modernization program. 4

A. Distribution Automation 5

SCE’s DA program includes three distinct elements: 6

1. Historical Circuit Automation, 7

2. Worst Circuit Rehabilitation (WCR) Enhanced Distribution Automation on 600 circuits 8

over this GRC period, and 9

3. DER-Focused Enhanced Distribution Automation (DER-driven upgrades) on 63 circuits 10

experiencing organic DER growth, 126 circuits to promote optimal DER locations, and 11

74 circuits as part of SCE’s deferral pilots over this GRC period. 12

The DA program will continue to improve upon SCE’s Historical Circuit Automation program 13

by installing automatic switches, circuit connections, sensors, and communication equipment on 14

distribution circuits. This program (1) provides near real-time visibility to distribution system operators, 15

with telemetry data points throughout the circuits that will help identify issues quickly and accurately, 16

(2) facilitates remote fault isolation and service restoration, thereby decreasing outage duration and area 17

of impact, and (3) increases operational flexibility with appropriately-sized line sections for circuit 18

switching, which will minimize outages during planned maintenance and unplanned outages. 19

The DA proposed in this GRC differs from the Historical Circuit Automation by scope and scale. 20

In particular, SCE proposes upgrading its circuits to a 3 mid and 3 tie configuration (3-3), as opposed to 21

the 1-1 configuration utilized in the Historical Circuit Automation. This 3-3 configuration will provide 22

near real-time visibility across SCE’s system with 95% accuracy, which is needed for system planners 23

and operators to perform their jobs without relying on conservative assumptions or risking outages.119 A 24

119 See SCE-02 Vol 10 Workpaper at 109, in Appendix B – Workpapers, p. B-1. SCE defines near-real time

visibility as the level needed to operate the system, without having to make conservative assumptions or avoid switching operations based on lack of knowledge of load conditions. Specifically, operators need to achieve visibility with an accuracy of ±5% (state estimator). This margin of error is based on SCE’s standard of limiting loading on any component to 550 amps during a 1 in 10 heat storm to prevent each component from ever exceeding the design threshold of 600 amps. With the addition of real and reactive power telemetry from two normally closed automated switches and supplemental telemetry from RFIs (a 2-2 scheme), the expected overall accuracy of the state estimator rises to 94.7%. With the addition of real and reactive power telemetry

43

Figure II-9 Summary of DA Proposals

d) ORA’s Payback Analyses are Incorrect 1

ORA challenges SCE’s conclusion that its 2018 DA program has a payback 2

period of less than five years. ORA argues instead that the payback period would exceed 13 years if the 3

costs of necessary supporting technologies, such as WAN, FAN and GMS, are considered.135 ORA also 4

argues that a hypothetical +1+1136 scheme would yield most of the reliability benefits provided by 5

135 See Exhibit ORA-09, p. 105. 136 In its Table 9-13, ORA attempts to quantify the reliability of a 1-1 scheme, as compared to SCE’s 3-3 scheme.

In formulating that table, ORA used data from ORA-SCE-28-TCR, Question 10.a. ORA-SCE-28-TCR, Question 10a states: “The analysis on pages 116-120 of the workpapers provides a conclusion assuming the worst 200 circuits were upgraded to the ‘3-mids 3-ties automation scheme.’ Provide the results of a comparable analysis except where only one mid and tie are added.” (Emphasis added). SCE understood this to mean an increment of 1-1, not necessarily going from 0-0 to 1-1, as SCE’s response made clear: “This table indicates the reliability improvement due to a hypothetical automation program which adds only one

6.0

9.9

7. Includes benefit of proposed ADMS on circuits with existing automation

50

output onto the system, in the event the load drops. For purposes of operating our system safely and 1

reliability, SCE must take this worst case scenario into account. Similarly, SCE’s assumptions about 2

circuit minimum loads reflect reasonable and appropriately-conservative values.151 3

Finally, SEIA-Vote Solar criticizes SCE for a forecast in PV growth that “is 4

significantly higher than what market analysts expect in California in the 2018-2020 period.”152 5

However, as shown in our response to a TURN data request, SCE’s past forecasts for DER growth have 6

been extremely accurate.153 Moreover, SEIA actually predicts much greater DER growth over the next 7

decade, predicting double the growth that SCE forecasts for 2020 and double-digit growth by 2022.154 8

SCE’s Grid Modernization proposals will address long-term DER growth, and SEIA-Vote Solar appears 9

to agree that, in the long run, there will be significant DER growth. Moreover, as of June 6, 2017, 10

SCE’s cumulative total of approved NEM was well above what SEIA-Vote Solar predicts for 2016.155 11

The necessary use of conservative assumptions to mitigate against system issues 12

caused by DERs will be obviated by real-time visibility and analytical tools such as the GMS. With 13

these tools, SCE will know the direction of power flow on the circuit at any given moment, and will not 14

have to use conservative assumptions to mitigate risks. Moreover, SCE operators can shift towards 15

depending on DERs to meet load requirements, rather than treating these reverse flows as sources of 16

reliability risk. 17

g) ORA’s Criticisms Regarding the Pace of SCE’s DA Program are Based on a 18

Misunderstanding 19

ORA states that SCE’s DA program proposed for 2018-2020 should be denied, in 20

part, because work completed under SCE’s Historical Circuit Automation program fell short of targets 21

forecast in SCE’s 2015 GRC, and because SCE is not forecasting a ramp-up in the WCR program that 22

151 See SCE-18, Volume 3 Section IV.B and responses to SEIA-SCE-008 Q.8.1 – 8.4 in Appendix A on pp. A-

112 to A-118, 123. 152 See Exhibit SEIA-Vote Solar (Volkmann), p. 29. 153 See response to TURN-SCE-123, Q. 9c, on Appendix A, pp A-130 to A-131. 154 See Exhibit SEIA-Vote Solar (Volkmann), pp. 12-13. 155 See SCE-18, Vol. 3, T&D System Planning, p. 35 n. 96 and n. 97.

52

Table II-6 Communication Capital Expenditures160

100% CPUC Jurisdictional – Nominal $000

1. Field Area Network (FAN) and Distribution System Efficiency Enhancement 1

Project (DSEEP) 2

The FAN is a secure, Internet Protocol (IP)161 based, data transmission system that 3

enables information to be sent between the distribution automation devices on circuits to transmitters in 4

substations and then to the grid control center. The FAN will replace the existing NetComm radio 5

system, which is over 20 years old and at the end of its useful service life. The FAN will provide a 6

modern wireless radio system capable of supporting the capacity, speed, connectivity, and security needs 7

of existing and future distribution field devices and DERs for at least the next 15 to 20 years.162 8

160 SCE forecast based on June 2017 Errata. See response to CUE-SCE-001 Q.79 and ORA-SCE-215-TCR Q.01

Supplemental on Appendix, pp. A-132 to A-134. 161 Internet Protocol is the principal communications protocol or method by which data is sent from one

computer to another over the internet. IP is the most widely adopted protocol used today to communicate information over communications networks.

162 See response to ED-SCE-002, Q.B.6, on Appendix A, pp. A-8 to A-55.

Activity 2011 2012 2013 2014 2015 2016DSEEP 4,192$ 4,924$ 4,077$ 4,518$ 4,314$ 4,293$ Field Area Network (FAN) -$ -$ -$ -$ -$ 1,104$ Common Substation Platform (CSP) -$ -$ -$ -$ 170$ 687$ Wide Area Network (WAN) -$ -$ -$ -$ -$ 597$ Total Communication 4,192$ 4,924$ 4,077$ 4,518$ 4,484$ 6,681$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceDSEEP 6,041$ 6,198$ 12,239$ 4,375$ 4,480$ 8,855$ (3,384)$ Field Area Network (FAN) 11,697$ 14,650$ 26,348$ -$ -$ -$ (26,348)$ Common Substation Platform (CSP) 3,933$ 7,513$ 11,446$ -$ -$ -$ (11,446)$ Wide Area Network (WAN) 4,908$ 38,647$ 43,555$ -$ -$ -$ (43,555)$ Total Communication 26,579$ 67,008$ 93,587$ 4,375$ 4,480$ 8,855$ (84,732)$

SCE Forecast ORA Forecast


2017-2018 2017 2018Total

2017-2018 VarianceDSEEP 6,041$ 6,198$ 12,239$ 6,041$ 6,199$ 12,240$ 1$ Field Area Network (FAN) 11,697$ 14,650$ 26,348$ -$ -$ -$ (26,348)$ Common Substation Platform (CSP) 3,933$ 7,513$ 11,446$ n/a n/a n/a n/aWide Area Network (WAN) 4,908$ 38,647$ 43,555$ -$ -$ -$ (43,555)$ Total Communication 26,579$ 67,008$ 93,587$ (69,902)$

SCE Forecast TURN Forecast

2018=6,798Total=12,839Variance=600

69,303

66

1. ORA’s Position 1

ORA criticizes SCE’s proposal to replace existing DMS and OMS systems with GMS, 2

given that DMS and OMS were refreshed in 2016.209 As with SCE’s other Grid Modernization projects, 3

ORA considers the association between GMS and Grid Modernization as justification for denying 4

expenditures in 2017 and 2018. ORA also rejects GMS on grounds of “the lack of recent 5

expenditures”210 in GMS, but then recommends authorizing 2016 recorded expenditures. 6

2. SCE’s Rebuttal to ORA’s Position 7

As ORA points out, SCE has made recent investments in DMS and OMS systems.211 8

While this is true, the DMS expenditures in 2016 are associated with completion payments of the last 9

milestones and phases of the original DMS project.212 That work started in 2013, prior to the 10

development of many regulatory and industry drivers of grid modernization, as noted below. The OMS 11

expenditures for 2016 and 2017 are related to the existing OMS refresh project that the Commission 12

approved as part of SCE 2015 GRC decision, D.15-11-021.213 The existing OMS infrastructure had last 13

been refreshed in 2008 and hardware and software required a system refresh to help ensure continuity of 14

critical grid operations functions. Moreover, the vendor was no longer supporting the previous version 15

of software, creating a significant operating risk. 16

These refresh projects are proving useful. In fact, since GMS implementation will not 17

begin until the first quartile of 2019 and since DMS/OMS cannot be decommissioned until the ADMS is 18

implemented in the third quarter of 2019, DMS and OMS will continue to be needed during the planning 19

and design phases of GMS.214 20

The current DMS was not designed to support the forecast quantities of behind-the-meter 21

DERs and distribution and substation devices.215 Likewise, the DMS does not have the necessary logic 22

209 See Exhibit ORA-09, p. 118-19. 210 See Exhibit ORA-09, p. 119. 211 See Exhibit ORA-09, p. 119. 212 See SCE response to TURN-SCE-052, Q3.b.ii, on Appendix A, pp. A-171 to A-173, 176. 213 See 2018 GRC IT Volume 2, p. 33 – p. 34. 214 See SCE response to TURN-SCE-123, Q.17, and attachment TURN-SCE-123-Q17_GMS Phase 1.pdf on

Appendix A, A-124 to A-125. 215 See SCE response to TURN-SCE-026, Q.65, on Appendix A, pp. A-174 to A-175.

72

have on system operation. DER may have a major impact on feeder protection, but the level at which 1

this would occur depends on how the DER is distributed along the feeder.”237 2

Protection systems are the last line of defense caused by fault current against 3

equipment damage and threats to public safety. While it is easy for TURN to dismiss fault current as a 4

hypothetical problem,238 it is SCE that is responsible for making sure such problems do not materialize. 5

SA-3 provides the foundational infrastructure that supports remote and more frequent protection 6

configuration changes to the field. SA-3 will also work with the Adaptive Protection System under the 7

GMS to ensure that SCE can adequately engineer and maintain configurations of protection systems as 8

the grid changes over time. 9

c) Delaying SA-3 Would Not Be Prudent 10

It would be a mistake to delay SA-3 to await a DRP decision in Track 3. SA-3’s 11

remote access and control capabilities will enable operators to quickly recover from unplanned outages, 12

manage planned outages, and will utilize data driven configuration processes that enhance operational 13

efficiencies. Additionally, as higher levels of DERs are incorporated into the distribution system, DERs 14

will have a significant impact on the capability of the electric system, including substations that are 15

essential to provide safe and reliable electrical service. 16

237 See Exhibit TURN-06, p. 46. 238 See Exhibit TURN-06, pp. 88, 89, and 91.

Id.

pg. 55

See A-87a

There are additional pressures on reliability besides aging equipment. DERs are imposingadditional complexities on our ability to manage outages.

Proposed Solutions Deploy field sensors to increase visibility of real time power flow and system conditions as well

as switching capabilities to add operational flexibility and control Faster communication from telemetry to provide two way communications between system

operators and field devices Operating tools to automate the analysis and process, and to assist operators in making

decisions regarding switching to isolate faults and restore serviceBy employing this proposed solution, SCE expects that reliability will be improved markedly, as shown inFigure 2.

Figure 2: System Level SAIDI due to Unplanned Outages on the Distribution System per the IEEEReliability Survey of 2013 data. Figure demonstrates longer SAIDI metrics in 2013 vs 2016.

Benefit Cost Analysis (BCA) MethodologyIn order to determine projected benefits and corresponding costs for Grid Modernization technologiesassociated with reliability the Distribution Automation, Grid Management System, and the enablingcommunications technologies referred to throughout this document—SCE has conducted an assessmentof average power outage restoration, breaking down the sequence of events between the start of anoutage and the time it takes to restore customers outside of the impacted location. Below is a diagramof the typical outage response times of system operators and first responders (Troublemen) withtoday’s systems.

100 Minutes SAIDI

Rebuttal Calculations Filename 1. BCA

1a. BCA Models that Support Waterfall Charts at the end of Section I

1. SCE reliability technology BCA_Model 1_TURN 26 Q55.xlsx 2. SCE reliability technology BCA_Model 2_PG&E Values.xlsx 3. SCE reliability technology BCA_Model 3_Incorporate 2016

Reliability Performance.xlsx 4. SCE reliability technology BCA_Model 4_Correct Outage

Data.xlsx

1a. Analysis of GDP per unit of non-residential energy consumption

1. GDP per kWh_MSA Cluster Comparison.xlsx

2. SAIDI Improvements2a. ORA Proposal 1. Reliability Benefits +1+1 2016 Reliability data 160 RCSs per

yr.xlsx 2b. TURN Proposal 1. Reliability Benefits of TURN 2M-1T DA on 110 WCR ckts w no

tie 2016 data.xlsx 2. CMI Summary Recalc w 2014-2016 DA on 54 Organic Growth

ckts.xlsx3. Value of RFIs on 490 WCR Circuits.docx

2c. SCE Proposal 1. CMI Summary Recalc w 2014-2016 3-3 WCR & DER.xlsx 2. Reliability Benefits SCE 3-3 WCR & DER ckts 2014-2016

data.xlsx3. S-55-1 ReliabilityImprovementAsFunctionOfDA WCR+DER

TURN-026 Q4i.xlsx 4. S-55-4 RFI Benefits to Automated Circuits.docx 5. S-55-4A Averaged RFI Benefits in CMI.xlsx 6. S-55-5 GMS Benefits on Non-WCR and Non-DER Automated

ckts.xlsx7. S-55-6 Ageing Impacts on DER Ckts.xlsx

3. MAIFI Improvement3a. SCE Proposal 1. MAIFI Benefit Updated to reflect 2014-2016 Reliability Data.xlsx

4. Payback Period Analysis 4a. Payback period analysis 1. Corrected ORA Payback Period Analyses.xlsx 4b. Reliability benefits under 3-

31. S-55-8 MAIFI Benefits.xlsx 2. MAIFI Benefit Updated to reflect 2014-2016 Reliability Data.xlsx 3. CMI Summary Recalc w 2014-2016 3-3 WCR & DER.xlsx 4. Reliability Benefits SCE 3-3 WCR & DER ckts 2014-2016

data.xlsx4b. Reliability benefits under

+1+11. ReliabilityImprovementAsFunctionOfDA_ORA-SCE-

028_Q10.xlsx 2. Reliability Benefits of +1+1 w RFIs 2016 data.xlsx 3. RFI Benefits on 600 WCR ckts no DA 2016 reliability data.xlsx 4. Reliability Benefits of +1+1 w RFIs 2016 data.xlsx

GDP per kWh_MSA Cluster Comparison.xlsx

Fips Area (MSA & County)GDP

$ millions1

Non-ResidentialEnergy Use

(million kWh) 2GDP/kWh

SCE TERRITORY12540 Bakersfield, CA (Metropolitan Statistical Area) 5,374$

Kern County3 1,916 2.80$

31080 Los Angeles-Long Beach-Anaheim, CA (Metropolitan Statistical Area) 930,817$ Los Angeles County 49,296 Orange County 14,092

63,387 14.68$

37100 Oxnard-Thousand Oaks-Ventura, CA (Metropolitan Statistical Area) 48,220$ Ventura County 3,859 12.49$

40140 Riverside-San Bernardino-Ontario, CA (Metropolitan Statistical Area) 140,637$ Riverside County 8,773 San Bernardino County 10,237

19,010 7.40$

42200 Santa Maria-Santa Barbara, CA (Metropolitan Statistical Area) 10,758$ Santa Barbara County4 1,006 10.69$

All MSAs in SCE Territory 1,135,806$ 89,179 12.74$ United States 18,222,800$ 2,354,894 7.74$

SCE v. U.S. 165%

2015

GDP per kWh_MSA Cluster Comparison.xlsx GDP per kWh

See E152a-154a



$ millions1



2015

PG&E TERRITORY12540 Bakersfield, CA (Metropolitan Statistical Area) 30,455$


17020 Chico, CA (Metropolitan Statistical Area) 7,559$ Butte County 770 9.82$

23420 Fresno, CA (Metropolitan Statistical Area) 38,830$ Fresno County 4,958 7.83$

25260 Hanford-Corcoran, CA (Metropolitan Statistical Area) 5,407$ Kings County 1,407 3.84$

31460 Madera, CA (Metropolitan Statistical Area) 4,962$ Madera County 1,237 4.01$

32900 Merced, CA (Metropolitan Statistical Area) 8,348$ Merced County 2,208 3.78$

33700 Modesto, CA (Metropolitan Statistical Area) 19,110$ Stanislaus County 3,059 6.25$

34900 Napa, CA (Metropolitan Statistical Area) 9,363$ Napa County 684 13.69$

39820 Redding, CA (Metropolitan Statistical Area) 5,933$ Shasta County 826 7.18$

40900 Sacramento--Roseville--Arden-Arcade, CA (Metropolitan Statistical Area) 118,822$ El Dorado County 448 Placer County 1,520 Sacramento County 6,097 Yolo County 1,174

9,238 12.86$

41500 Salinas, CA (Metropolitan Statistical Area) 21,980$ Monterey County 1,964 11.19$

41860 San Francisco-Oakland-Hayward, CA (Metropolitan Statistical Area) 431,704$ Alameda County 7,291 Contra Costa County 6,593 Marin County 696 San Francisco County 4,337 San Mateo County 2,907

21,825 19.78$

41940 San Jose-Sunnyvale-Santa Clara, CA (Metropolitan Statistical Area) 235,222$ San Benito County 247 Santa Clara County 12,879

13,126 17.92$

42020 San Luis Obispo-Paso Robles-Arroyo Grande, CA (Metropolitan Statistical Ar 13,705$ San Luis Obispo County 1,068 12.83$

42200 Santa Maria-Santa Barbara, CA (Metropolitan Statistical Area) 14,260$ Santa Barbara County4 1,334 10.69$

42100 Santa Cruz-Watsonville, CA (Metropolitan Statistical Area) 11,908$ Santa Cruz County 660 18.03$

42220 Santa Rosa, CA (Metropolitan Statistical Area) 26,052$




$ millions1



2015

Sonoma County 1,639 15.90$

44700 Stockton-Lodi, CA (Metropolitan Statistical Area) 24,606$ San Joaquin County 3,396 7.25$

46700 Vallejo-Fairfield, CA (Metropolitan Statistical Area) 19,646$ Solano County 2,177 9.02$

47300 Visalia-Porterville, CA (Metropolitan Statistical Area) 15,829$ Tulare County 3,360 4.71$

49700 Yuba City, CA (Metropolitan Statistical Area) 5,765$ Sutter County 370 Yuba County 267

637 9.05$ All MSAs in PG&E Territory 1,069,466$ 86,433 12.37$ United States 18,222,800$ 2,354,894 7.74$

PG&E v. U.S. 160%Notes:

2. Energy use represents non-residential energy use by county for 2015 (in millions of kWh). Source: http://ecdms.energy.ca.gov/elecbycounty.aspx. U.S. non-residential energy use was obtained from the U.S. Energy Information Administration (https://www.eia.gov/electricity/data/browser/#/topic/5?agg=0,1&geo=g00000000004&endsec=vg&freq=M&start=200101&end=201702&chartindexed=0&ctype=linechart&ltype=pin&rtype=s&maptype=0&rse=0&pin=)3. Analysis assumes Kern County is split 15%/85% between SCE's and PG&E's service territories (based on the population of the cities within Kern County served by the respective utilities).4. Analysis assumes Santa Barbara County is split 43%/57% between SCE's and PG&E's service territories (based on the population of the cities within Santa Barbara County served by the respective utilities).

1. GDP statistics are from the Buruea of Economic Analysis, 2015, All Industry totals. Source: https://www.bea.gov/iTable/index_nipa.cfm


Gross domestic product (GDP) by metropolitan area (millions of current dollars)


$ millions1

Non-Residential Energy Use

(million kWh)2GDP/kWh

SCE TERRITORY12540 Bakersfield, CA (Metropolitan Statistical Area) 6,091$


20940 El Centro, CA (Metropolitan Statistical Area) 6$Imperial County4 1 7.32$

23420 Fresno, CA (Metropolitan Statistical Area) 78$Fresno County5 10 7.83$

25260 Hanford-Corcoran, CA (Metropolitan Statistical Area) 1,892$Kings County6 492 3.84$

31080 Los Angeles-Long Beach-Anaheim, CA (Metropolitan Statistical Area) 930,817$Los Angeles County 49,296Orange County 14,092

63,387 14.68$

37100 Oxnard-Thousand Oaks-Ventura, CA (Metropolitan Statistical Area) 48,220$Ventura County 3,859 12.49$

40140 Riverside-San Bernardino-Ontario, CA (Metropolitan Statistical Area) 140,637$Riverside County 8,773San Bernardino County 10,237

19,010 7.40$

42200 Santa Maria-Santa Barbara, CA (Metropolitan Statistical Area) 11,258$Santa Barbara County7 1,053 10.69$

47300 Visalia-Porterville, CA (Metropolitan Statistical Area) 12,347$Tulare County8 2,621 4.71$

All MSAs in SCE Territory 1,151,346$ 92,605 12.43$United States 18,222,800$ 2,354,894 7.74$

SCE v. US 161%

PG&E TERRITORY12540 Bakersfield, CA (Metropolitan Statistical Area) 29,738$


17020 Chico, CA (Metropolitan Statistical Area) 7,559$Butte County 770 9.82$

23420 Fresno, CA (Metropolitan Statistical Area) 38,752$Fresno County5 4,948 7.83$

25260 Hanford-Corcoran, CA (Metropolitan Statistical Area) 3,515$Kings County6 915 3.84$

31460 Madera, CA (Metropolitan Statistical Area) 4,962$Madera County 1,237 4.01$

32900 Merced, CA (Metropolitan Statistical Area) 8,348$Merced County 2,208 3.78$

33700 Modesto, CA (Metropolitan Statistical Area) 19,110$Stanislaus County 3,059 6.25$

LevelsBureau of Economic AnalysisAll industry total

2015

E-152a



$ millions1




2015

34900 Napa, CA (Metropolitan Statistical Area) 9,363$Napa County 684 13.69$

39820 Redding, CA (Metropolitan Statistical Area) 5,933$Shasta County 826 7.18$

40900 Sacramento--Roseville--Arden-Arcade, CA (Metropolitan Statistical Area) 118,822$El Dorado County 448Placer County 1,520Sacramento County 6,097Yolo County 1,174

9,238 12.86$

41500 Salinas, CA (Metropolitan Statistical Area) 21,980$Monterey County 1,964 11.19$

41860 San Francisco-Oakland-Hayward, CA (Metropolitan Statistical Area) 431,704$Alameda County 7,291Contra Costa County 6,593Marin County 696San Francisco County 4,337San Mateo County 2,907

21,825 19.78$

41940 San Jose-Sunnyvale-Santa Clara, CA (Metropolitan Statistical Area) 235,222$San Benito County 247Santa Clara County 12,879

13,126 17.92$

E-153a



$ millions1




2015

42020 San Luis Obispo-Paso Robles-Arroyo Grande, CA (Metropolitan Statistical A 13,705$San Luis Obispo County 1,068 12.83$

42200 Santa Maria-Santa Barbara, CA (Metropolitan Statistical Area) 13,760$Santa Barbara County7 1,287 10.69$

42100 Santa Cruz-Watsonville, CA (Metropolitan Statistical Area) 11,908$Santa Cruz County 660 18.03$

42220 Santa Rosa, CA (Metropolitan Statistical Area) 26,052$Sonoma County 1,639 15.90$

44700 Stockton-Lodi, CA (Metropolitan Statistical Area) 24,606$San Joaquin County 3,396 7.25$

46700 Vallejo-Fairfield, CA (Metropolitan Statistical Area) 19,646$Solano County 2,177 9.02$

47300 Visalia-Porterville, CA (Metropolitan Statistical Area) 3,482$Tulare County8 739 4.71$

49700 Yuba City, CA (Metropolitan Statistical Area) 5,765$Sutter County 370Yuba County 267

637 9.05$All MSAs in PG&E Territory 1,053,932$ 83,008 12.70$United States 18,222,800$ 2,354,894 7.74$

PG&E v. US 164%

Notes:1. GDP statistics are from the Bureau of Economic Analysis, 2015, All Industry totals. Source: https://www.bea.gov/iTable/index_nipa.cfm2. Energy use represents non-residential energy use by county for 2015 (in millions of kWh). Source: http://ecdms.energy.ca.gov/elecbycounty.aspx. U.S. non-residential energy use was obtained from the U.S. Energy Information Administration (https://www.eia.gov/electricity/data/browser/#/topic/5?agg=0,1&geo=g00000000004&endsec=vg&freq=M&start=200101&end=201702&chartindexed=0&ctype=linechart&ltype=pin&rtype=s&maptype=0&rse=0&pin=)

3. Analysis assumes Kern County is split 17%/83% between SCE's and PG&E's service territories (based on the population of the cities within Kern County served by the respective utilities).

8. Analysis assumes Santa Barbara County is split 45%/55% between SCE's and PG&E's service territories (based on the population of the cities within Santa Barbara County served by the respective utilities).

4. Analysis assumes Imperial County is split 0.1%/99.9% between SCE's and Imperial Irrigation District's service territories (based on the population of the cities within Imperial County served by the respective utilities).5. Analysis assumes Fresno County is split 0.2%/99.8% between SCE's and PG&E's service territories (based on the population of the cities within Fresno County served by the respective utilities).6. Analysis assumes Kings County is split 35%/65% between SCE's and PG&E's service territories (based on the population of the cities within Kings County served by the respective utilities).7. Analysis assumes Tulare County is split 78%/22% between SCE's and PG&E's service territories (based on the population of the cities within Tulare County served by the respective utilities).

E-154a

Documents

2018 General Rate Case Rebuttal Testimony · 2017. 7. 13. · Witnesses: B. Tolentino J. Gooding J. Schellenberg (U 338-E) 2018 General Rate Case Rebuttal Testimony Public Version